bp 

March 14, 2013 

U.S EPA, Region 10 

BP Cherry Point Refinery 

4519 Grandview Road 

Blaine, Washington 98230 

Telephone 360 371-1500 

Office of Air, Waste and Toxics 

1200 6th Avenue, Suite 900, AWT-107 

Seattle, W A 9 810 1 

Subject: NSPS Subpart Ja Flare Management Plan- New #2 Hydrogen Flare 

Dear Sir: 

BP West Coast Products LLC ("BP") is submitting this letter to provide updated information for Cherry Point 

Refinery's new #2 hydrogen flare. This year we will be starting up the new hydrogen flare which is subject to NSPS 

Ja after start-up. Enclosed for your files is our Flare Management Plan (FMP) which includes all of the elements 

described in 40 CFR §60.103a(a). An electronic copy of this FMP was also e-mailed to refmerynsps@spa.gov. 

Only the #2 hydrogen flare will become subject to New Source Performance Standard (NSPS) Subpart Ja upon startup. BP has two other modified flares (HP & LP) which will be subject to NSPS Ja requirement in November of 

2015. 

Please contact me if you have any questions or concerns regarding the FMP at (360) 317-1530. 

Scott Inloes 

Sr. Environmental Engineer 

BP Cherry Point Refinery 

cc: Jeff Chalfant. BP 

Agata Mcintyre, P.E. 

Northwest Clean Air Agency 

1600 South 2nd Street 

Mount Vernon, WA 98273 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies & Programs Division 

U.S. EPA Mailroom (E143-01) 

Attention: Refinery Sector Lead 

109 T.W. Alexander Drive 

Research Park Triangle, NC 27711 
#2 Hydrogen Plant 

Flare Management Plan 

New Source Performance Standard 

Subpart Ja 

Prepared by: 

BP Cherry Point Refinery 

4519 Grandview Road 

Blaine, Washington 98230 

March 2013 
#2 Hydrogen Plant Flare 

Flare Management Plan 

BP Cherry Point Refinery 

TABLE OF CONTENTS 

March2013 

1.0 Introduction ................................................................................................................. 1 

1.1 Revisions to the Flare Management Plan .................................................................... 1 

1.2 Flare Management Plan Contents ............................................................................... 2 

2.0 Flare and Flare System Description (40 CFR §60.103a(a)(1) & (3)) ............................ 3 

2.1 General Description of Subpart Ja Flare (40 CFR §60.103a(a)(3)(i)) .......................... 3 

2.2 Refinery Process Units, Ancillary Equipment and Fuel Gas Systems Connected to 

Subpart Ja Flare (40 CFR §60.1 03a(a)(1 }) ......................................... ........................ .4 

2.3 Simplified Flare System Diagram and Component Design Information (40 CFR 

§60.103a(a)(3)(ii) & (iv)) .............................................................................................. 5 

2.4 Flare Design Parameters (40 CFR §60.1 03a(a)(3)(iii)) ................................................ 5 

2.5 Flare Monitoring System Specifications ( 40 CFR §60.1 03a(a)(3)(v)) ........................... 6 

2.5.1 Vent Gas Flow Rate ............................................................................................................... 6 

2.5.2 Sulfur Content ....................................................................................................................... 7 

3.0 Flare Minimization Assessment (40 CFR §60.103a(a)(2}) ........................................... 8 

3.1 Evaluation of flare gas recovery ..................................................... ........................ ... 12 

3.2 PSA Gas as Refinery Fuel ........................................................................................ 12 

4.0 Baseline Flow Evaluation (40 CFR §60.103a(a)(4)) .................................................. 13 

4.1 Default Baseline Flow Rates (40 CFR §60.103a(a)(4)(i)) .......................................... 13 

4.2 Alternate Baseline Flow Rates (40 CFR §60.103a(a)(4)(ii)) ...................................... 13 

4.3 Procedures to Minimize Flaring While Operating Under an Alternate Baseline Flow 

Rate (40 CFR §60.103a(a)(4)(iii)) ............................................................................. 14 

5.0 Procedures to Minimize Flaring During Planned Start-up and Shutdown (40 CFR 

§60.1 03a(a)(5)) .. ....................................................................................................... 15 

5.1 Shutdown/Startup planning & Shutdown Procedures ................................................ 15 

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6.0 Procedures to Reduce Flaring Due to Fuel Gas Imbalances and Flare Gas Recovery 

Systems (40 CFR §60.103a(a)(6) and (a)(7)) ............................................................ 16 

7.0 Root Cause Analysis and Corrective Action .............................................................. 17 

7.1 Root Cause Analysis ................................................................................................. 17 

7.1.1 RCA- Flow Exceedance ....................................................................................................... 18 

7.2 Corrective Action Analysis ...................................... .................................................. 19 

APPENDIX A- SIMPLIFIED PROCESS FLOW DIAGRAM OF FLARE SYSTEM ...................... 21 

APPENDIX 8- Document Revision Log ..................................................................................... 22 

APPENDIX C- NSPS Ja Regulatory Cross-Reference Table .................................................... 22 

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Glossary of Terms 

The following terms are used throughout this plan: 

March 2013 

Ancillary Equipment (per Subpart Ja): Equipment used in conjunction with or that serve a 

refinery process unit. Ancillary equipment includes, but is not limited to, storage tanks, product 

loading operations, wastewater treatment systems, steam- or electricity-producing units 

(including coke gasification units), pressure relief valves, pumps, sampling vents and continuous 

analyzer vents. 

Baseline Flow (per Subpart Ja): The baseline flow to the flare must be determined after 

implementing the minimization assessment required by Subpart Ja. Baseline flows do not 

include pilot gas flow or purge gas flow provided these flows remain reasonably constant. 

Separate baseline flow rates may be established for different operating conditions provided the 

flare management plan includes: 

• A primary baseline flow rate that will be used as the default baseline for all conditions 

except those specifically delineated in the flare management plan; 

• A description of each special conditions for which an alternative baseline is established, 

including the rationale for each alternative baseline, the daily flow for each alternative 

baseline and the expected duration of the special conditions for each alternative 

baseline; and 

• Procedures to minimize discharges to the affected flare for each alternative baseline, 

unless procedures are already developed for these cases for planned startup and 

shutdown of refiner process units, fuel gas imbalance, and flare gas recovery systems. 

• Baseline flow includes sweep gas on flares without a water seal. 

Cascaded Flare System (per Subpart Ja): A series of flares connected to one flare gas header 

system arranged with increasing pressure set points so that discharges will be initially directed 

to the first flare in the series (i.e., the primary flare). If the discharge pressure exceeds a set 

point at which the flow to the primary flare would exceed the primary flare's capacity, flow will be 

diverted to the second flare in the series. Similarly, flow would be diverted to a third (or fourth) 

flare if the pressure in the flare gas header system exceeds a threshold where the flow to the 

first two (or three) flares would exceed their capacities. 

Emergency Flare (per Subpart Ja): A flare that combusts gas exclusively released as a result of 

malfunctions (and not startup, shutdown, routine operations or any other cause) on four or fewer 

occasions in a rolling 365-day period. For purposes of this rule, a flare cannot be categorized 

as an emergency flare unless it maintains a water seal. 

EPA: The United States Environmental Protection Agency 

Flare (per Subpart Ja): A combustion device that uses an uncontrolled volume of air to burn 

gases. The flare includes the foundation, flare tip, structural support, burner, igniter, flare 

controls, including air injection or steam injection systems, flame arrestors and the flare gas 

header system. In the case of an interconnected flare gas header system, the flare includes 

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BP Cherry Point Refinery 

each individual flare serviced by the interconnected flare gas header system and the 

interconnected flare gas header system. 

March 2013 

Flare Gas Header System (per Subpart Ja): All piping and knockout pots, including those in a 

sub header system, used to collect and transport gas to a flare either from a process unit or a 

pressure relief valve from the fuel gas system, regardless of whether or not a flare gas recovery 

system draws gas from the flare gas header system. The flare gas header system includes 

piping inside the battery limit of a process unit if the purpose of the piping is to transport gas to a 

flare or knockout pot that is part of the flare. 

Flare Gas Recovery System (per Subpart Ja): A system of one or more compressors, piping 

and the associated water seal, rupture disk or similar device used to divert gas from the flare 

and direct the gas to the fuel gas system or to a fuel gas combustion device. 

Fuel Gas (per Subpart Ja): Any gas which is generated at a petroleum refinery and which is 

combusted. Fuel gas includes natural gas when the natural gas is combined and combusted in 

any proportion with a gas generated at a refinery. Fuel gas does not include gases generated 

by catalytic cracking unit catalyst regenerators, coke calciners (used to make premium grade 

coke) and fluid coking burners, but does include gases from flexicoking unit gasifiers and other 

gasifiers. Fuel gas does not include vapors that are collected and combusted in a thermal 

oxidizer or flare installed to control emissions from wastewater treatment units other than those 

processing sour water, marine tank vessel loading operations or asphalt processing units (i.e., 

asphalt blowing stills). 

Fuel Gas Combustion Device (per Subpart Ja): Any equipment, such as process heaters and 

boilers, used to combust fuel gas. For the purposes of this subpart, fuel gas combustion device 

does not include flares or facilities in which gases are combuste.d to produce sulfur or sulfuric 

acid. 

Fuel Gas System (per Subpart Ja): A system of compressors, piping, knock-out pots, mix 

drums, and units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) 

that collects refinery fuel gas from one or more sources for treatment as necessary prior to 

combusting in process heaters or boilers. A fuel gas system may have an overpressure vent to 

a flare but the primary purpose for a fuel gas system is to provide fuel to the refinery. 

lblhr: Pounds per hour. 

MSCFO: Thousands of standard cubic feet per day. 

MMSCFD: Millions of standard cubic feet per day. 

Non-Emergency Flare (per Subpart Ja): Any flare that is not an emergency flare as defined in 

this subpart. 

Petroleum Refinery (per Subpart Ja): Any facility engaged in producing gasoline, kerosene, 

distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through 

distillation of petroleum or through redistillation, cracking or reforming of unfinished petroleum 

derivatives. A facility that produces only oil shale or tar sands-derived crude oil for further 

processing at a petroleum refinery using only solvent extraction and/or distillation to recover 

diluent is not a petroleum refinery. 

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#2 Hydrogen Plant Flare 

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Primary Flare (per Subpart Ja): The first flare in a cascaded flare system. 

March 2013 

Process Upset Gas (per Subpart Ja): Any gas generated by a petroleum refinery process unit 

or by ancillary equipment as a result of startup, shutdown, upset or malfunction. 

Purge Gas (per Subpart Ja): Gas introduced between a flare's water seal and a flare's tip to 

prevent oxygen infiltration (backflow) into the flare tip. For flares with no water seals, the 

function of purge gas is performed by sweep gas (i.e., flares without water seals do not use 

purge gas). 

Reduced Sulfur Compounds (per Subpart Ja): Hydrogen sulfide (H2S), carbonyl sulfide, and 

carbon disulfide. 

Refinery Process Unit (per Subpart Ja): Any segment of the petroleum refinery in which a 

specific processing operation is conducted. 

Root Cause Analysis (per Subpart Ja): An assessment conducted through a process of 

investigation to determine the primary cause, and any other contributing cause(s), of a 

discharge of gases in excess of specified thresholds. 

Secondary Flare (per Subpart Ja): A flare in a cascaded flare system that provides additional 

flare capacity and pressure relief to a flare gas system when the flare gas flow exceeds the 

capacity of the primary flare. For purposes of this subpart, a secondary flare is characterized by 

infrequent use and must maintain a water seal. 

Sweep Gas (per Subpart Ja): The gas introduced in a flare gas header system to maintain a 

constant flow of gas to prevent oxygen buildup in the flare header. For flares with no water 

seals, sweep gas also performs the function of preventing oxygen infiltration (backflow) into the 

flare tip. 

vi 
1.0 Introduction 

The BP Cherry Point Refinery plans to commence operation of a flare associated with the #2 hydrogen 

plant, which will become subject to New Source Performance Standard (NSPS) Subpart Ja upon 

startup. Under this regulation, a Flare Management Plant (FMP) is required to minimize flaring to the 

extent practicable. The FMP must include all of the elements described in 40 CFR §60.1 03a(a). This 

document constitutes the FMP for the BP Cherry Point Refinery. The following flare is subject to the 

provisions of this plan: 

Table 1: Subpart Ja Affected Flare 

Affected Flare Date Upon Which the FMP is 

Applicable 

#2 Hydrogen Plant Flare TBD (upon startup) 

Separate FMPs are being developed for the high pressure and low pressure flares at the BP Cherry 

Point Refinery. 

1.1 Revisions to the Flare Management Plan 

A copy of the current FMP shall be maintained at the refinery. The FMP will be internally reviewed and 

updated as needed to account for changes in the operation of the Subpart Ja flare, including new 

connections to the flare gas header system. It is important to note that not all changes that trigger an 

internal revision of the FMP require re-submitting the revised FMP to the Northwest Clean Air Agency 

(NWCAA), EPA Region 10, and the EPA Office of Air Quality Planning and Standards (OAQPS). The 

rule requires the FMP to be re-submitted for one of the following circumstances: 

• An alternative baseline flow rate is added; 

• The existing baseline flow rates specified in this plan are revised; 

• Flare gas recovery is installed at a flare; or 

• The flare designations and monitoring methods as described in 40 CFR §60.107a(g) are 

changed. 

A Plan Revision History log is included in Appendix B. The log should be utilized to document all 

periodic changes to the FMP, both the internal revisions and the revisions that are submitted to the 

Regulators. 

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Flare Management Plan 

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1.2 Flare Management Plan Contents 

March 2013 

This FMP fulfills the requirements of NSPS Ja regarding the development of a written FMP and has 

been prepared pursuant to the requirements and provisions of the rule. The following information is 

specifically required to be included in or referenced by this Plan: 

• Listing of all process units, ancillary equipment, and fuel gas systems that are connected to the 

flare header system; 

• Descriptions of all flare components and design parameters; 

• Specifications for all required monitoring instrumentation; 

• Flare minimization assessment; 

• Baseline flow evaluation; and 

• Procedures to reduce flaring during planned startup and shutdown, during imbalances of the 

fuel gas system, and during outages of the flare gas recovery system. 

This Plan also includes or references information which is not explicitly required to be included in the 

FMP under NSPS Ja. The inclusion of this supplemental information enables this Plan to fully 

document the management practices and flaring minimization measures and strategies that are in 

place at the refinery. The following supplemental information is provided in or referenced by this Plan: 

• Description of triggering events and compliance timeframes for Root Cause Analyses (RCAs) 

and Corrective Action Analyses and Implementation; 

• Details of the required records, reports, and notifications. 

Any terms used in this Plan are defined in the Glossary. 

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2.0 Flare and Flare System Description (40 CFR §60.103a(a)(1) & (3)) 

This section provides a description of each affected flare and flare system subject to this plan. 

2.1 General Description of Subpart Ja Flare (40 CFR 

§60.103a(a)(3)(i)) 

A general description of the affected flare covered by this plan is provided below. A simplified process 

flow diagram of the flare/flare system described in this plan is provided in Appendix A. 

Table 2: General Description of Subpart Ja Flare 

Flare Description #2 Hydrogen Plant Flare 

Flare Type Elevated 

Flare Height 120ft. 

Assist System Non-Assisted 

Flare Tip Type Simple 

Flare System Type Not Cascaded 

Not Applicable 

Flare Service (flare is not used as backup in a 

cascaded flare system) 

Emergency or Non-Emergency Status Non-Emergency 

Equipped with Flare Gas Recovery No 

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2.2 Refinery Process Units, Ancillary Equipment and Fuel Gas Systems 

Connected to Subpart]a Flare (40 CFR §60.103a(a)(1)) 

The primary function of the #2 Hydrogen Plant flare gas header is to safely accumulate and transfer 

gases to the flare for combustion. In addition to normal sweep gas flow rates, the flare gas header also 

has the capability for equipment depressurization and purging for maintenance activities, such as 

startup, shutdown, and turnaround. 

The flare gas header provides the #2 Hydrogen Plant with a controlled low-pressure outlet for any 

excess vapor flow that originates with high-pressure operations within the process unit. Nearly all 

vapors are flammable, making the flare gas header an essential safety feature of the refinery. The flare 

gas header relieves the pressure of the gas, rendering the gas safe to both equipment and surrounding 

personnel. Table 3 below presents a list of all refinery process units and ancillary equipment connected 

to #2 Hydrogen Plant flare gas header. For reasons discussed in Section 3.1, the #2 Hydrogen Plant 

flare gas header does not have an associated flare gas recovery system. 

Table 3: #2 Hydrogen Plant Flare Connections 

Affected Flare Connected Unit or Unit/Equipment Duration 

Equipment Type 

#2 Hydrogen Plant Process Unit non-continuous 

#2 Hydrogen Plant Pressure Ancillary non-continuous 

Safety Valves (PSVs) Equipment 

#2 Hydrogen Plant #2 Hydrogen Plant Sampling Ancillary non-continuous 

Flare Vents Equipment 

#2 Hydrogen Product Ancillary non-continuous 

Compressor (46-1807) Equipment 

Sweep Gas for Flare Header Ancillary continuous 

Equipment 

No continuous flow rates to the #2 Hydrogen Plant Flare are expected during normal operation, except 

for the continuous sweep gas flow through the flare header and continuous pilot gas flow. A flow rate 

monitor is located on the flare header pipe. 

Sweep gas enters in two spots: (1) at the beginning of the of flare header, and (2) at PSA flare line. 

Appendix A provides a simplified process flow diagram of the #2 Hydrogen Plant Flare and flare header 

system The VOC content of the vents to the flare were evaluated for VOC ( 1 0%) and HAP ( 5%) 

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BP Cherry Point Refinery March2013 

content. Based on an analysis of all relief cases, the VOC and HAP content to the flare were less than 

the triggers in NSPS GGGa and MACT CC. The process vents that are connected to the flare contain 

more than 35% hydrogen. It is worth noting, the #2 Hydrogen Plant Flare is not subject to the 40 CFR 

60.18 or 40 CFR 63.11 control device requirements (Btu content requirements, etc.) because 

connections to the flare do not trigger NSPS or NESHAP control requirements. 1 

2.3 Simplified Flare System Diagram and Component Design 

Information (40 CFR §60.103a(a)(3)(ii) & (iv)) 

A simplified process flow diagram of the flare/flare system described in this plan is provided in 

Appendix A. Additional technical information for each flare subject to Subpart Ja is provided below: 

Table 4: Flare Description 

#2 HYDROGEN PLANT FLARE 

Date Installed August 2012 

Manufacturer Callidus 

Flare Tip Model No. PF-30/42 

Nominal Tip Diameter (in.) 42 

Effective Tip Diameter (in.) Same as nominal tip diameter. 

2.4 Flare Design Parameters (40 CFR §60.103a(a)(3)(iii)) 

Table 5: Summary of Flare Design Parameters 

Flare Description #2 HYDROGEN PLANT FLARE 

Design Vent Gas Flow Rate (lb/hr) a 128,124 

Minimum Sweep Gas Flow Rate (MSCFD) b 32.8 (natural gas) 

Minimum Purge Gas Flow Rate (MSCFD) n/a (no water seal on flare) 

Maximum Supplemental Gas Flow Rate (MSCFD) n/a 

1 February 1, 2011 letter correspondence between Mr. Scott lnloes (BP Cherry Point) and Mr. Dan Mahar 

(Northwest Clean Air Agency). 

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Maximum Pilot Gas Flow Rate (MSCFD) 

Minimum Total Steam Rate (lb/hr) 

Knockout Drum Dimensions c 

Notes: 

March 2013 

9.6 (natural gas) 

n/a (not a steam-assisted flare) 

29" inside diameter by 1 0' 1.6" 

a - Maximum vent gas flow rate based on flare header design basis (#2 Hydrogen Plant 

Technical Manual). 

b- Total sweep gas for #2 Hydrogen Plant Flare. Each of the two sweep gas injection 

points has a maximum flow rate of 16.4 MSCFD. 

c - The knockout drum for the #2 hydrogen plant flare is incorporated into the base of the 

flare stack. BP considers the operating level range of the level transmitters on the base 

of the flare to be the knockout area. This knockout drum design removes a potential 

mechanism for failure because there are no moving pieces associated with the design 

compared to using a separate knockout drum prior to the flare stack. 

2.5 Flare Monitoring System Specifications (40 CFR §60.103a(a)(3)(v)) 

2.5.1 Vent Gas Flow Rate 

NSPS Ja requires the refinery to operate a flow meter that provides a representative measurement of 

the total flow rate discharged to the flare. The flow rate data that is collected will be used to determine 

if flaring events occur that exceed the Root Cause Analysis (RCA) threshold of 500,000 set in a 24-hour 

period above the established baselines. The following standards for the flow meter are required 

pursuant to the rule: 

• Must be located in- a position that is representative of the total gas flow rate, 

• Must have a flow sensitivity of no more than 5% of the flow rate or 10 scfm, whichever is 

greater, 

• Must be maintainable online, and 

• Must continually correct for pressure and temperature and record flow in standard conditions, 

The monitoring system consists of a flow meter and associated pressure and temperature sensors for 

the flare gas header. A GE Digital Flow GF868 flow meter system with single path ultrasonic flow 

transducers will continuously measure the flow rate to the #2 Hydrogen Plant Flare. The flow meter is 

manufactured according to the specifications in the rule, and the refinery has ensured that the flow 

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BP Cherry Point Refinery March 2013 

meter is installed in a representative location of flare gas flow rate, thereby complying with the selection 

and installation of the flow meter. The following table summarizes the specifications of the flow meter. 

FLOW METER IDENTIFICATION INFORMATION 

Make Insertion-Ultrasonic Bias 90 GE Panametrics 

Model No. GF868-2-11-20014FM-O 

Range (Velocity) 0.1 -394ft/sec 

Precision +/- 1% 

Accuracy 3% to 7% 

Details regarding the specifications of the flow meter, including the precision, accuracy, calibration, 

maintenance procedures, and quality assurance procedures are included in the Flow Meter QA/QC 

document maintained by the refinery. Pressure and temperature sensors associated with flow meter 

take readings that are used to automatically correct the raw flow meter reading to standard condition 

flow rates and are reported to the DCS and viewed in the control room. 

2.5.2 Sulfur Content 

Each flare subject to NSPS Ja requires the refinery to operate a monitor to measure the sulfur content 

of the gases combusted in the flare. However, 40 CFR 60.107a(a)(3) exempts inherently low sulfur fuel 

gas streams from the sulfur monitoring requirement. All flows to the #2 Hydrogen Plant Flare are 

inherently low in sulfur content. Process gas associated with the #2 Hydrogen Plant is inherently low in 

sulfur because sulfur will deactivate catalysts used in the hydrogen plant, and is specifically exempted 

in 40 CFR 60.1 07a(a}(3)(iii). In addition, the natural gas used for the flare pilots and sweep gas is also 

inherently low in sulfur and would satisfy the exemption criteria in 40 CFR 60.1 07a(a)(3)(ii) for "fuel gas 

streams that meet a commercial-grade product specification for sulfur content of 30 ppmv or less." Fuel 

gas includes natural gas only when combined and combusted in any proportion with a gas generated at 

a refinery. Therefore, no sulfur monitor or H2S monitor is required to be installed on the #2 Hydrogen 

Plant Flare header. 

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3.0 Flare Minimization Assessment (40 CFR §60.1 03a(a)(2)) 

The #2 Hydrogen Plant flare system is designed to handle start-up venting and excess gases in 

the event of a safety related upset at the #2 Hydrogen Plant. There will be no continuous flaring 

during normal operation, except for natural gas pilots and sweep gas. The process gas that 

may be flared from the #2 Hydrogen Plant would contain minimal volatile organic compound 

(VOC) content, so the primary purpose of the flare would be for the combustion of carbon 

monoxide (CO) in the gas stream. 

The primary gases combusted in the #2 Hydrogen Plant flare will be comprised of hydrogen, 

methane, carbon dioxide and carbon monoxide. For the primary gases, the flare may operate 

for the following scenarios: 

1. Initial #2 Hydrogen Plant Startup (PSA Tune-up}. The #2 Hydrogen Plant will begin 

operations in 2013. All process streams will be vented to the #2 Hydrogen Plant Flare 

during the initial startup to ensure all of the unit equipment is operating correctly and the 

hydrogen generated meets the required quality specifications for use in other refinery 

process units. Process streams generated during this one-time only initial startup may 

be sent to the flare until they can be proven to achieve quality specifications on a 

consistent basis. This will be a multi day activity. The tune up will be done on all shifts 

to minimize the flaring event. 

2. Sweep Gas. The refinery regulates each of the two sweep gas contributions to the 

#2 Hydrogen Plant Flare header with a restriction orifice at the flow rate recommended in 

the design documentation. Each design sweep gas flow rate is a necessary component 

of the flare system to ensure that the flare header is maintained at a positive pressure, 

which prevents oxygen from infiltrating into the flare header and flare stack. Therefore, 

the total sweep gas flow rate cannot be further minimized without introducing a safety 

risk to the entire flare system. 

3. Gas Sampling. Sample points are associated with the #2 Hydrogen Plant to allow 

samples to be taken that ensure the plant is operating correctly. The sample points are 

designed to allow the sample lines to be purged prior to obtaining a sample. Purged gas 

would be sent to the flare. The sample lines associated with each sample point consist 

of one-inch or two-inch piping or tubing. Additionally, the sample points are located in 

close proximity to the process vessel to be sampled. Therefore, the volume of gas 

required to be purged prior to sampling has been minimized by design to the extent 

possible. 

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4. Loss of the PSA beds. This can occur for a few reasons, including an automatic valve 

malfunction. Valve malfunctions on the PSA are anticipated due to the large quantity of 

valves (50 automatic valves) and their frequent operation in cyclical service. The valves 

cycle every few minutes. The malfunction of a PSA automatic valve can cause a set of 

PSA beds to be taken out of service. This, in turn, increases the PSA off gas flow. 

Depending on the dynamics of the increase of PSA off gas flow, it may not always be 

possible to immediately send the additional flow as fuel to the furnace without 

overheating the furnace. Eventually, the natural gas fed to the furnace as fuel is 

reduced to allow for the additional PSA off gas flow. But in the meantime, flaring can 

occur during this disturbance. The estimated flaring from the loss of all PSA beds is 

965,100 cubic feet per hour, but the actual flaring amount would depend on the actual 

event circumstances. 

The hydrogen purification system is designed with pairs of PSA beds, so each PSA bed 

is paired with another PSA bed. If there is a malfunction in one of the PSA beds, the 

pair of PSA beds is removed from service and the remaining 8 beds keep functioning 

without the need for flaring or reducing plant feed rate. This operational design allows 

the hydrogen plant to continue operating at full capacity and prevents one PSA bed 

failure from triggering a flaring event of the entire PSA bed system. Once two pairs of 

PSA beds (four PSA beds total) are removed from service, the remaining six PSA beds 

will not be able to accommodate all of the process gas and flaring of the excess process 

gas would be required until a reduction in plant feed rate occurs to normalize the system. 

This design will minimize flaring because we need 6 beds to operate a full rate while we 

will operate with 8 beds normally. 

5. Sudden change in hydrogen demand. Under normal circumstances, a reduction in 

hydrogen demand will be anticipated and coordinated ahead of time. In this way, 

hydrogen production can be reduced prior to the reduction in demand to avoid flaring. It 

is only under circumstances that are "unplanned" and "beyond reasonable control" that 

the reduction in hydrogen demand can lead to flaring. The hydrogen plant is designed 

so the hydrogen compressor will discharge to the flare until the plant feed rate is cut to 

balance hydrogen demand. BP incorporates rigorous training for their process 

operators, which will prepare each operator for scenarios where there are sudden 

decreases in hydrogen demand at the refinery. We expect that venting excess hydrogen 

to this flare may reduce the issues of hydrogen being recovered by our existing flare gas 

recovery units (HP and LP Flares) and causing issues with our heaters. 

6. Sudden loss of product compressor. Under normal circumstances, shutting down of 

the product compressor will be anticipated and coordinated ahead of time. In this way, 

hydrogen production can be reduced prior to the loss of compression to reduce flaring. 

It is only under circumstances that are "unplanned" and "beyond reasonable control" that 

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the shutting down of the compressor will lead to significant flaring of hydrogen product 

until the plant feed rate can be cut or the compressor can be restarted. 

7. Purging to prepare equipment for maintenance. Some equipment requires that it be 

purged to achieve a safe atmosphere In order to safely do maintenance. Planned 

turnaround maintenance for the #2 Hydrogen Plant is every five years. However, certain 

equipment could require maintenance prior to the five year turnaround. During 

maintenance, the equipment is isolated, depressurized, inerted with nitrogen, repaired, 

and brought back online. An example would be a malfunctioning PSA bed may need to 

be depressurized and purged with nitrogen to allow for repairs. If the piece of equipment 

can be taken down with the remainder of the plant running, gas upstream of the 

equipment is not flared. 

An example of design considerations to limit scheduled maintenance before the five year 

turnaround include sizing the #2 Hydrogen Plant cobalt molybdenum and zinc oxide 

catalyst drums to be large enough that maintenance on the drums would occur once 

every five years (normal turnaround schedule for the hydrogen plant). 

It is estimated that maintenance of the hydrogen product compressor would be 

completed every 2 Y2 years and coincide with turnaround maintenance for major 

hydrogen demand process units at the refinery (i.e. hydrocracker) and the five year 

#2 Hydrogen Plant turnaround. BP would operate the hydrogen plant at minimum feed 

and production rates, then remove the product compressor from service. The hydrogen 

plant design allows BP to send low pressure hydrogen directly from the PSA beds (prior 

to the product compressor) to the 220# header. The low pressure hydrogen demand at 

the refinery is less than the minimum production rate of the hydrogen plant, which will 

require some hydrogen product to be flared during the product compressor 

maintenance. 

During the planned five year turnaround for the #2 Hydrogen Plant, the entire hydrogen 

plant would be taken offline for maintenance. There is a cool down period where 

hydrogen plant equipment is taken offline in a scheduled manner. All equipment will be 

purged with nitrogen to ensure an inert work environment prior to conducting any 

maintenance activities. Each turnaround for the refinery is different and involves 

different process units, which requires developing a specific plan for turnaround activities 

closer to the time period when the turnaround will occur. All turnaround events will 

include measures to minimize flaring. 

8. Pressure Safety Valve Trip. Equipment within the #2 Hydrogen Plant contains pressure 

safety valves (PSVs) to ensure that pressure build up within the equipment (caused by 

upset condition, instrument or equipment failure, etc.) does not result in catastrophic 

failure of the equipment and release of untreated process gases to the atmosphere. The 

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#2 Hydrogen Plant Flare 

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PSVs allow equipment to release gas into the hydrogen plant flare header, where the 

gas is burned and released to atmosphere in a controlled manner. Once a PSV is lifted, 

gas is directed to the flare and operators are alerted of the process conditions. BP trains 

its operators to do everything possible to get relief from the emergency flaring scenario 

and bring the process unit back into normal operation or safely shutdown the unit. 

BP also operates with a maintenance plan for all PSVs to minimize leaks into the flare 

gas header under normal unit operations. The maintenance plan includes scheduled 

visual checks and PSV testing to ensure critical PSVs are functioning as intended. As 

part of the hydrogen plant design, BP reviewed each PSV service and established a 

mitigation plan that includes a range of options to reduce flaring, options for each PSV 

could include: altering PSV operation to remove relief protection from a malfunctioning 

PSV, or including a redundant PSV that could be brought online. Both of these options 

reduce flaring and allow malfunctioning PSVs to be isolated and repaired. BP also 

designed the hot shift reactor to be capable of handling 120 percent of the maximum 

normal operating pressure. This design feature minimizes the potential for PSV leakage 

into the flare header under normal operating conditions. 

BP has also included design features into the #2 Hydrogen Plant to minimize flaring. These additional 

design conditions include: 

• Product Compressor- The hydrogen plant design includes product compression for the 

hydrogen product instead of both feed and product compression. By taking advantage of 

the natural gas pipeline operating pressure for feed into the hydrogen plant, BP was able to 

design the plant with only product compression. Fewer compressors mean less opportunity 

for a compressor failure and fewer compressors to conduct maintenance on. In addition, the 

hydrogen plant is designed so that if the product compressor is offline, the hydrogen is route 

to the low pressure hydrogen header (upstream of the product compressor). The low 

pressure hydrogen header may not have the capacity to handle the entire hydrogen plant 

production rate; thus, it is possible that some flaring of hydrogen product may be required 

until the product compressor is brought back online. 

9. Pressure Swing Absorption (PSA) Gas Combustion -The plant design routes the impurities 

from the hydrogen purification process back to the SMR heater for fuel, which reduces natural 

gas consumption at the plant. Alternatives would be to flare the PSA off gas or install a 

compressor to recover the gas into the refinery fuel gas system. However, as discussed in the 

next section, recovery of the PSA gas will result in very low BTU/high hydrogen content gas and 

would result in flame stability issues with heaters and boilers equipped with ultra-low NOx 

burners (ULNB) elsewhere in the refinery fuel gas system. 

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3.1 Evaluation of flare gas recovery 

March 2013 

As shown by the information below on the composition and characteristics typical of PSA inlet 

gas during startup, the heating value of this gas is extremely low and there is a high percentage 

of inert gas. The ability to use this gas for fuel is very low based on the heating value - most 

burners are not designed for gas of this composition. 

The fact that flare gas is flammable creates safety concerns if large volumes are to be stored. 

Combustion of flammable gases as they are produced, either in process equipment or in a flare 

system, is intrinsically safer than storage, as it minimizes the onsite inventory of combustible 

material. The minimization of onsite storage of combustible gases also addresses Homeland 

Security concerns and the potential for damage from an earthquake. 

The design basis for the hydrogen plant startup (flaring offspec gas) is 8,049 scfm, which 

represents 50% of the typical PSA feed flow rate. The following composition and characteristics 

are typical of PSA inlet gas that may be flared during startup: 

Component Mole 

% 

Hydrogen 75 

Methane 5 

Carbon Monoxide (CO) 4 

Carbon Dioxide ( C02) 16 

Nitrogen -o 

Water -o 

High heating value 310 Btu/SCF 

Low heating value 270 Btu/SCF 

H2S content -o ppm 

3.2 PSA Gas as Refinery Fuel 

The composition of the PSA gas that could be recovered would significantly alter the refinery fuel gas 

composition. Lower BTU content and high hydrogen gas in the refinery fuel gas system would result in 

altered flame patterns and stability in burners used throughout the refinery, which are not designed to 

accommodate this composition of combustion gas. The reliability of the entire fuel gas system would 

be decreased if the PSA gas was recovered. Therefore, BP does not believe flare gas recovery is 

logical for the hydrogen plant flare header. 

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4.0 Baseline Flow Evaluation (40 CFR §60.1 03a(a)(4)) 

March 2013 

This section evaluates the baseline flow for the affected flare. The default and alternate 

baseline flows described in this section are used to determine the conditions under which the 

refinery conducts a Root Cause Analysis (RCA). A RCA is required if vent gas flow exceeds the 

baseline conditions by 500 MSCFD during a 24-hour period. 

The refinery is also required to conduct a RCA, regardless of flow, if the total sulfur dioxide 

emissions from the flaring event exceed 500 lb in a 24-hour period. However, 40 CFR 

60.1 07a(a)(3) specifically exempts inherently low sulfur fuel gas streams from the sulfur 

monitoring requirement. All of the connections to the #2 Hydrogen Plant Flare header are 

considered inherently low in sulfur concentration (i.e., Natural Gas or gas streams from process 

units that are intolerant to sulfur contamination). Therefore, BP is exempt from H2S monitoring 

requirements for the #2 Hydrogen Plant Flare header. 

The baseline flows do not include pilot gas flow because pilot gas is routed directly to the flare 

tip and would not be measured by the flow meter. 

4.1 Default Baseline Flow Rates (40 CFR §60.103a(a)(4)(i)) 

Because the Hydrogen Plant Flare is under construction at the time this FMP is being prepared, 

operational data are not yet available to develop a baseline flow rate for this flare. With 

implementation of the minimization measures discussed in this Plan, the default baseline flow 

rate is anticipated to be solely the flare sweep gas. NSPS Subpart Ja specifically states that the 

baseline flow should not include pilot gas or purge gas flow provided these gases remain 

reasonably constant. Because the sweep gas flow rate for the Hydrogen Plant Flare is 

estimated to be 1 ,400 SCFH, this flow will be used as the default baseline flow rate for purposes 

of NSPS Subpart Ja flaring event evaluations. BP will reevaluate the #2 Hydrogen Plant Flare 

baseline flow rate after at least one year of normal operational data has been collected. 

Baseline flow of 33,600 scf/24 hour- flow of over 533,600 scf/24 hours would trigger a 

RCA. 

4.2 Alternate Baseline Flow Rates (40 CFR §60.103a(a)(4)(ii)) 

Alternate Baseline Flow Rates for the #2 Hydrogen Plant Flare are proposed for the conditions 

listed below. The methodology used to develop projected flow rates for these scenarios is also 

provided below. 

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Table 6: Summary of Alternate Baseline Flow Rates 

Alternate 

Scenario Baseline Flow Flow Rate Estimation Methodology 

Rate 

Based on full process unit operation over a 24 hour 

Initial #2 H2 Plant PSA 40.965 MMSCF/24 period. The initial #2 Hydrogen Plant startup and 

Tuning hours PSA bed tuning will occur once in order to bring the 

process unit online at the refinery. 

Based on sudden loss of hydrogen demand and time 

Hydrogen Long 10 MMSCF/24 requirements to reduce hydrogen production. Flow 

(i.e. Hydrocracker Trip) horus rate based on 2 hours at 1 00 percent product rate and 

8 hours at 50 percent rate. 

4.3 Procedures to Minimize Flaring While Operating Under an Alternate 

Baseline Flow Rate (40 CFR §60.103a(a)(4)(iii)) 

Procedures for minimizing flaring during the conditions described under Section 4.2 were 

described in Section 3.0. Procedures to minimize flaring during start-up, shutdown, and 

maintenance outages are discussed in Section 5.0 and 6.0, respectively. 

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5.0 Procedures to Minimize Flaring During Planned Start-up 

and Shutdown (40 CFR §60.1 03a(a)(5)) 

5.1 Shutdown/Startup planning & Shutdown Procedures 

Procedures for planned startup and shutdown of the #2 Hydrogen Plant are currently in 

development and will be fully implemented by the time the unit will begin operation. The 

operational philosophy at the refinery encourages the minimization of flaring as flaring 

represents lost raw materials and products. The procedures will provide specific steps taken by 

operators to perform a shutdown and a startup in a planned, step-wise manner, while taking 

both operational requirements and safety precautions into consideration. It must be understood 

that despite all efforts to minimize flaring during planned startup and shutdown, it may 

sometimes be necessary for flaring to occur in order to maintain an appropriate level of safety 

and operational integrity. 

Table 7: Summary of Expected Start up/Shutdown Events 

Scenario Expected Flow Flow Rate Estimation Methodology Rate 

Normal #2 H2 Plant Based on process unit operating at half-rate over a 

Startup 20.065 MMSCFD 24 hour period to ensure proper hydrogen purity 

before bringing process unit online. 

#2 H2 Plant Shutdown 

TBD TBD and Purge 

Hydrogen Long Based on planned loss of hydrogen demand and time 

requirements to balance hydrogen production and (i.e. Hydrocracker 1 MMSCFD 

demand. Flow rate based on 1 hour at 25 percent Turnaround) 

product rate. 

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6.0 Procedures to Reduce Flaring Due to Fuel Gas Imbalances 

and Flare Gas Recovery Systems (40 CFR §60.103a(a)(6) and 

(a)(7)) 

The hydrogen plant and associated flare are not incorporated in the refinery fuel gas system; therefore 

fuel gas imbalances will not directly affect the process unit operation or flaring conditions. 

The hydrogen plant does not incorporate a flare gas recovery system for reasons presented in Section 

3 of this FMP; therefore, the process unit will not be affected by hypothetical flare gas recovery 

operations. 

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7.0 Root Cause Analysis and Corrective Action 

March 2013 

This section provides a discussion on RCA and Corrective Action Analysis that are required by 

NSPS Ja. These analyses are not specifically required to be a part of the FMP; however, the 

monitoring systems that provide the data for the RCA threshold determinations are detailed in the FMP 

and the conclusions obtained from the RCA and Corrective Action analyses will potentially require 

changes to be made to the FMP. Therefore, the RCA and Corrective Action Analysis requirements 

have been included in the FMP. 

7.1 Root Cause Analysis 

As defined in NSPS Ja, an RCA is 

"an assessment conducted through a process of investigation to determine the primary cause, 

and any other contributing cause(s), of a discharge of gases in excess of specified thresholds." 

The Rule specifies two thresholds for flares which are the triggers for an RCA. An RCA must be 

completed as soon as possible, but no later than 45 days after a discharge that exceeds one or both of 

the specified thresholds. 

The rule delineates three special circumstances that affect the number of RCAs that the refinery must 

perform following an RCA threshold exceedance: 

• If a single discharge event lasts for two or more consecutive 24-hour periods, only one 

RCA must be performed; 

• If a single discharge event triggers an RCA based on both of the specified thresholds, 

only one RCA must be performed; 

• If multiple flares in a cascaded flare system each trigger an RCA in the same 24-hour 

period, only one RCA must be performed. 

Furthermore, if a discharge that triggers an RCA is the result of a planned startup or shutdown during 

which the Planned Startup & Shutdown procedures referenced in Section 5 of this FMP were followed, 

an RCA is not required. 

The two thresholds which trigger an RCA are the following: 

• Anytime the S02 emissions exceed 500 lb in any 24-hour period, or 

• Any discharge to one or more flares in excess of 500,000 scf above an established 

baseline in a 24-hour period. 

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#2 Hydrogen Plant Flare 

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As discussed earlier, sulfur monitoring is not required for the #2 Hydrogen Plant Flare because the 

process gases are inherently low in sulfur. Therefore, only the flow rate threshold is discussed below. 

7.1.1 RCA- Flow Exceedance 

The specified flow threshold which triggers an RCA is greater than 500,000 scf above an established 

baseline flow in a 24-hour period to the flare. 

When performing an RCA for a flow exceedance, there are several key parameters that should be 

documented as part of the investigation: 

• the connections that were contributing to the header, 

• the duration of the flaring event, 

• what was occurring in the process that lead to the flaring event, and, if possible, 

• the sequence of events that lead to the flaring event. 

Once these items have been investigated and documented, a determination of potential actions that 

could have prevented the flaring event or reduced the volume or duration of the flaring event should be 

evaluated and documented. 

Once the investigation has been completed, the key information and data gathered during the process 

should be assembled into an RCA Report to be stored in internal records. Because the rule specifies 

that certain items must be recorded for each RCA, each internal report should, at minimum, include the 

following: 

• A description of the discharge. 

• Date and time of when the discharge was first identified and the duration of the 

discharge. 

• The measured quantity of gas discharged over the discharge duration. If the discharge 

duration exceeds 24 hours, record the quantity for each 24-hour period. 

• The steps taken to limit the emissions during the discharge. 

• Statement as to whether the discharge resulted from the same root cause(s) identified in 

previous RCAs. 

• Description of the recommended corrective action(s) or an explanation of why corrective 

action is not necessary. 

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• If the discharge was a result of a planned startup or shutdown of a refinery process unit 

or ancillary equipment connected to the affected flare, a statement that an RCA is not 

necessary because the facility followed the FMP. For further information on the 

procedures to minimize flaring during planned startup and shutdown, see Section 3 of 

this FMP. 

7.2 Corrective Action Analysis 

As defined in the rule, a Corrective Action is 

"the design, operation and maintenance changes that one takes consistent with good 

engineering practice to reduce or eliminate the likelihood of the recurrence of the primary cause 

and any other contributing cause(s) of an event identified by a root cause analysis as having 

resulted in a discharge of gases to an affected flare in excess of specified thresholds." 

An identification of corrective action(s) must be performed as the final step of an RCA. The purpose of 

documenting the corrective action(s) in the internal RCA Report is to systematically identify changes 

that could be made to reduce or, if possible, eliminate the possibility of the recurrence of the causes of 

the flaring event that caused an exceedance of one or both of the RCA thresholds. The identification of 

corrective actions should not incorporate rationale regarding economic or technical feasibility or other 

potential limiting factors. The purpose of identifying corrective actions is to determine, based upon 

good engineering practices, potential changes that could rectify the cause(s) of the flaring event(s) that 

was(were) identified by the RCA. 

According to the rule, a corrective action analysis is 

"a description of all reasonable interim and long-term measures, if any, that are available, and 

an explanation of why the selected corrective action(s) is/are the best alternative(s), including, 

but not limited to, considerations of cost effectiveness, technical feasibility, safety and 

secondary impacts." 

The Corrective Action Analysis is the process to determine which of the identified corrective actions 

presents the most plausible argument for implementation. It is during this analysis that rationale 

regarding economic and technical feasibility, along with other potential limiting factors, are taken into 

consideration. If the facility concludes that corrective action should not be conducted, the facility must 

document the decision and include the basis for the conclusion. 

All corrective actions must be implemented within 45 days of the discharge for which the RCA and 

corrective action analyses were required or as soon as practicable. If it is determined that a corrective 

action should not be implemented, the explanation of the basis of that decision must be recorded no 

later than 45 days following the discharge. Because the Corrective Action Analysis is a consequence 

of the RCA, it is imperative to commence the RCA as soon after the discharge as possible in order to 

allow for the maximum amount of time to be allotted to the determination and implementation of the 

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most beneficial corrective action. However, if a corrective action cannot be fully implemented within 

45 days, the facility must develop an implementation schedule to complete the corrective action as 

soon as practicable. 

Once the 45-day period following the discharge has passed, the rule specifies that certain items must 

be included in the internal RCA Report for each Correct Action Analysis. At minimum, each internal 

report must include the following items: 

• If it is determined that a corrective action should not be implemented, an explanation of 

the basis of that decision. 

• A description of the corrective action(s) completed within the first 45 days following the 

discharge. 

• For corrective actions not completed within 45 days, a schedule for implementation, 

including proposed commencement and completion dates. 

• If the discharge was a result of a planned startup or shutdown of a refinery process unit 

or ancillary equipment connected to the affected flare, a statement that a Corrective 

Action Analysis is not necessary because the facility followed the FMP. 

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APPENDIX A- Simplified Process Flow Diagram of Flare System 

21 
Flare Ignitor 

Control System 

46-LCP-6 

Unintenuptible f:TI 

(no Natural S, H2S, Gas or flcri __________ L___________ . I . rote monitoring) ------·----·- - ·--- ·---- _ ___ ...L _ 

Three Natural 

Gas Pnots 

#2 Hydrogen 

Plant 

Prac"''" Unit 

#2 Hydrogen Produ'"'t 

Compo 

(46-

#2 Hydrogen 

Plant 

Sampling 

Vents 

:::::::........ 

Velocity Seal 

H2 Plant Flare 

46-2802 

--+--- K.O. Drum 

(within flare stack) 

29" i.d. x 1 o' 1 .6" 

1..,___ 

H2 PLANT FLARE SYSTEM- SIMPLIFIED PFD 

BP Cherry Point Refinery 

Blaine, Washington 
#2 Hydrogen Plant Flare 

Flare Management Plan 

BP Cherry Point Refinery March 2013 

APPENDIX B- Document Revision Log 

This Flare Management Plan (FMP) fulfills the requirements for NSPS Ja for the #2 Hydrogen Plant 

Flare. Any changes to the original plan should be documented in the table below. 

Requires 

Revision Revision Revision Submission to 

No. Date Author (name, Reason for Revision the USEPA? 

company) (See Section 1.3 

of the FMPl 

0 [month, year] [name, company} Original Yes 

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APPENDIX C - NSPS Ja Regulatory Cross-Reference Table 

Citation Regulatory Description FMPManua/ 

Section 

60.103a(a) Items to be included in the Flare Management Plan See Below 

60.103a(a(1)) List of process units 2.2 

60.103a(a(1)) List of ancillary equipment 2.2 

60.103a(a(1)) List of fuel gas systems 2.2 

60.103a(a)(2) Minimization assessment 3.0 

General description 

60.103a(a)(3)(i) Flare type 2.1 

60.103a(a)(3)(i) Assist system 2.1 

60.103a(a)(3)(i) Flare header system 2.1 

60.103a(a)(3)(i) Flare gas recovery system 2.1 

Description and simple PFD 

60.103a(a)(3)(ii) Flare tip 2.3 

60.103a(a)(3)(ii) KOdrum 2.3 

60.103a(a)(3)(ii) Flare header and subheader 2.3 

60.103a(a)(3)(ii) Assist system 2.3 

60.103a(a)(3)(ii) Ignition system 2.3 

Design parameters 

60.103a(a)(3)(iii) Maximum vent gas flow rate 2.4 

60.103a(a)(3)(iii) Minimum sweep gas flow rate 2.4 

60.103a(a)(3)(iii) Minimum purge gas flow rate 2.4 

60.103a(a)(3)(iii) Maximum supplemental gas flow rate 2.4 

60.103a(a)(3)(iii) Maximum pilot gas flow rate 2.4 

60.103a(a)(3)(iii) Minimum total steam flow rate 2.4 

Description and simple PFD of flow meter and sulfur content 

analyzers 

60.103a(a)(3)(iv) Flare header 2.3 

60.103a(a)(3)(iv) Purge gas 2.3 

60.103a(a)(3)(iv) Sweep gas 2.3 

60.103a(a)(3)(iv) Supplement gas 2.3 

60.103a(a)(3)(iv) Pilot gas 2.3 

60. 103a(a)(3)(v) Manufacturer's specifications for each monitor/analyzer 2.5 

indentified in 60.103a(a)(3)(iv) 

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APPENDIX C - NSPS Ja Regulatory Cross-Reference Table 

Citation Regulatory Description FMPManual 

Section 

For emergency flares, secondary flares, and flares with FGRUs 

that are designed to capture all normal flows 

60.103a(a)(3)(vi) Description of water seal NA 

60.103a(a)(3)(vl) Designation of monitoring option NA 

60.103a(a)(4) Baseline flow evaluation 4.0 

60.103a(a)(5) Procedures to minimize or eliminate discharges during planned 5.0 

shutdown and startup 

60.103a(a)(6) Procedures to reduce flaring in cases of fuel gas imbalance 6.0 

60.103a(a)(7) Procedures to minimize frequency and duration during FGRU 6.0 

outages and to minimize flaring during FGRU outages 

60.103a(b)(1) Submission timeline for initial FMP 1.0 

60.103a(b)(2) Events which trigger a re-submittal of the FMP 1.1 

60.103a(c)(1) Conditions which Trigger a Root Cause Analysis for a Flaring 7.1 

Event 

60.103a(d) Timeline to conduct Root Cause Analysis and Corrective Action 7.2 

Analysis 

60.103a(e) Records to be maintained for Corrective Action Implementation 7. 1.1 

60.103a(f) Timeframe for initial compliance for Root Cause Analysis and 7.2 

Corrective Action Implementation Programs 

60.103a(g) Specific requirements for flares located in the BAAQMD and N/A 

SCAQMD 

60.103a(h) Applicability of flares to < 162 ppmv H2S concentration limit in 2.5.2 

flare gas 

60.107a(a)(2) Requirements for monitoring flare gas H2S concentration 2.5.2 

60.107a(a)(3) Exemptions for flares gas H2S concentration monitoring 2.5.2 

60.107a(b) Procedures to exempt steams for flare gas H2S concentration 2.5.2 

monitoring 

60.107a(e) Monitoring of sulfur content for RCA 2.5.2 

60.107a(f) Monitoring of flow rates for RCA 7.1 

60.107a(a)-(c) Required notifications and records 7.0 

24