# bp

March 14, 2013 U.S EPA, Region 10 BP Cherry Point Refinery 4519 Grandview Road Blaine, Washington 98230 Telephone 360 371-1500

Office ofAir, Waste andToxics 1200 6thAvenue, Suite 900, AWT-107 Seattle, WA 98101
Subject: NSPS SubpartJa FlareManagementPlan- New#2 HydrogenFlare Dear Sir: BP West Coast Products LLC ("BP") is submitting this letter to provide updated information for Cherry Point Refinery'snew#2 hydrogen flare. This year we willbe startingup the newhydrogen flare which is subjectto NSPS Ja after start-up. Enclosed for your files is our Flare Management Plan (FMP) which includes all ofthe elements described in 40 CFR §60.103a(a). Anelectronic copyofthis FMP was also e-mailedto refmerynsps@spa.gov. Onlythe #2 hydrogen flare will become subjectto New Source Performance Standard (NSPS) SubpartJaupon startup. BP has two other modified flares (HP & LP) which will be subject to NSPS Ja requirement in November of 2015. Please contactme ifyou have anyquestions or concerns regarding the FMP at (360) 317-1530

.

ScottInloes Sr. EnvironmentalEngineer BP CherryPointRefinery

cc: JeffChalfant. BP AgataMcintyre, P.E. Northwest CleanAirAgency 1600 South2nd Street MountVernon, WA98273
U.S. EnvironmentalProtectionAgency Office ofAir QualityPlanning and Standards SectorPolicies & Programs Division U.S. EPAMailroom (E143-01) Attention: Refinery SectorLead 109 T.W. AlexanderDrive ResearchParkTriangle, NC 27711

# #2 Hydrogen Plant Flare Management Plan New Source Performance Standard Subpart Ja

Preparedby: 

## BP Cherry Point Refinery

4519 Grandview Road Blaine, Washington 98230

March 2013#2 Hydrogen PlantFlare Flare ManagementPlan BP CherryPointRefinery


## 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 ofSubpart 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 §60.103a(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 §60.103a(a)(3)(iii))

... .............................................5 2.5 Flare Monitoring System Specifications (40 CFR §60.103a(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 offlare 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

ii#2 Hydrogen Plant Flare Flare Management Plan BP Cherry PointRef inery March2013 

### 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

iii#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery 

## Glossary ofTerms The following terms are used throughout this plan: March 2013

AncillaryEquipment (per SubpartJa): 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 SubpartJa): 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 primarybaseline flow rate that willbe usedas the defaultbaseline forallconditions except those specificallydelineatedin the flare managementplan;
• A description ofeach specialconditions for which an alternative baseline is established, including the rationale for each alternative baseline, the dailyflow for each alternative baseline and the expected duration ofthe special conditions for each alternative baseline; and
• Procedures to minimize discharges to the affected flare for each alternative baseline, unless procedures are alreadydeveloped for these cases forplannedstartup and shutdown ofrefinerprocess units, fuel gas imbalance, andflare gas recoverysystems. • Baseline flow includes sweep gas on flares withouta waterseal.
Cascaded Flare System (per SubpartJa): A series offlares 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). Ifthe discharge pressure exceeds a set point atwhich 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 (orfourth) flare ifthe pressure in the flare gas headersystem exceeds a threshold where the flow to the first two (or three) flares would exceed their capacities. EmergencyFlare (per SubpartJa): A flare that combusts gas exclusively released as a result of malfunctions (and not startup, shutdown, routine operations or any other cause) on four orfewer occasions in a rolling 365-day period. For purposes ofthis 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 SubpartJa): A combustion device that uses an uncontrolled volume ofairto burn gases. The flare includes the foundation, flare tip, structural support, burner, igniter, flare controls, including air injection orsteam injection systems, flame arrestors and the flare gas header system. In the case ofan interconnected flare gas header system, the flare includes
iv#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery each individual flare serviced by the interconnected flare gas header system and the interconnected flare gas header system. March 2013

Flare Gas HeaderSystem (perSubpartJa): All piping and knockout pots, including those in a subheader system, used to collect and transport gas to a flare eitherfrom a process unit or a pressure reliefvalve from the fuel gas system, regardless ofwhether 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 ifthe purpose ofthe piping is to transport gas to a flare or knockout pot that is part ofthe flare. Flare Gas RecoverySystem (per SubpartJa): A system ofone or more compressors, piping and the associated water seal, rupture disk orsimilar device used to divert gas from the flare and directthe gas to the fuel gas system orto a fuel gas combustion device. Fuel Gas (per SubpartJa): 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 ata 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 orflare installed to control emissions from wastewater treatment units otherthan those processing sour water, marine tank vessel loading operations orasphalt processing units (i.e., asphalt blowing stills)

. Fuel Gas Combustion Device (per SubpartJa): Any equipment, such as process heaters and boilers, used to combust fuel gas. Forthe purposes ofthis subpart, fuel gas combustion device does not include flares orfacilities in which gases are combuste.d to produce sulfur or sulfuric acid. Fuel Gas System (perSubpartJa): A system ofcompressors, 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 priorto 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 ofstandard cubic feet perday. MMSCFD: Millions ofstandard cubic feet per day. Non-EmergencyFlare (per SubpartJa): Anyflare that is not an emergency flare as defined in this subpart. Petroleum Refinery (per SubpartJa): Any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum orthrough redistillation, cracking or reforming of unfinished petroleum derivatives. A facility that produces only oil shale ortar sands-derived crude oil forfurther processing at a petroleum refinery using only solvent extraction and/ordistillation to recover diluent is not a petroleum refinery.
v#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery
PrimaryFlare (perSubpartJa): The first flare in a cascaded flare system. March 2013

Process Upset Gas (per SubpartJa): Any gas generated by a petroleum refinery process unit or by ancillary equipment as a result ofstartup, shutdown, upset or malfunction. Purge Gas (per SubpartJa): 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 SubpartJa): Hydrogen sulfide (H2S), carbonyl sulfide, and carbon disulfide. RefineryProcess Unit (per SubpartJa): Any segment ofthe petroleum refinery in which a specific processing operation is conducted. Root Cause Analysis (per SubpartJa): An assessment conducted through a process of investigation to determine the primary cause, and any other contributing cause(s), ofa discharge ofgases in excess ofspecified thresholds. SecondaryFlare (per SubpartJa): A flare in a cascaded flare system that provides additional flare capacity and pressure reliefto a flare gas system when the flare gas flow exceeds the capacity ofthe primary flare. For purposes ofthis subpart, a secondaryflare is characterized by infrequent use and must maintain a water seal. Sweep Gas (perSubpartJa): The gas introduced in a flare gas header system to maintain a constant flow ofgas to prevent oxygen buildup in the flare header. Forflares 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 ofa flare associated with the #2 hydrogen plant, which will become subject to New Source Performance Standard (NSPS) Subpart Ja upon startup. Underthis regulation, a Flare Management Plant (FMP) is required to minimize flaring to the extent practicable. The FMP must include all ofthe elements described in 40 CFR §60.1 03a(a). This document constitutes the FMP forthe BP Cherry Point Refinery. The following flare is subject to the provisions ofthis 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 ManagementPlan A copy ofthe 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 ofthe 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 ofthe FMP require re-submitting the revised FMP to the Northwest Clean Air Agency (NWCAA), EPA Region 10, and the EPA Office ofAir Quality Planning and Standards (OAQPS). The rule requires the FMP to be re-submitted for one ofthe 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.

1#2 Hydrogen Plant Flare Flare Management Plan BP Cherry PointRefinery 

### 1.2 Flare ManagementPlan 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 ofthe rule. The following information is specifically required to be included in or referenced by this Plan:
• Listing ofall process units, ancillary equipment, and fuel gas systems that are connected to the flare header system;

• Descriptions ofall 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 ofthe fuel gas system, and during outages ofthe 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 ofthis supplemental information enables this Plan to fully document the management practices and flaring minimization measures and strategies that are in place atthe refinery. The following supplemental information is provided in or referenced by this Plan:
• Description oftriggering events and compliance timeframesfor Root Cause Analyses (RCAs) and Corrective Action Analyses and Implementation;
• Details ofthe required records, reports, and notifications

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

2#2 Hydrogen Plant'Flare Flare ManagementPlan BP Cherry Point Refinery March 2013


## 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 GeneralDescription ofSubpartJa Flare (40 CFR §60.103a(a)(3)(i))
A general description ofthe affected flare covered by this plan is provided below. A simplified process flow diagram ofthe flare/flare system described in this plan is provided in Appendix A.

Table 2: General Description of Subpart Ja Flare
Flare Description #2 Hydrogen PlantFlare Flare Type Elevated Flare Height 120ft. Assist System Non-Assisted Flare Tip Type Simple
Flare System Type Not Cascaded NotApplicable 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

3#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery March 2013 

## 2.2 RefineryProcess Units,AncillaryEquipmentandFuel GasSystems ConnectedtoSubpart]aFlare (40 CFR §60.103a(a)(1))
The primary function ofthe #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 outletfor 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 safetyfeature ofthe refinery. The flare gas header relieves the pressure ofthe gas, rendering the gas safe to both equipment and surrounding personnel. Table 3 below presents a list ofall 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 ofthe offlare header, and (2) at PSA flare line. Appendix A provides a simplified process flow diagram ofthe #2 Hydrogen Plant Flare and flare header system The VOC content ofthe vents to the flare were evaluated for VOC (1 0%) and HAP (5%)
4#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March2013 content. Based on an analysis ofall 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 or40 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 SimplifiedFlareSystemDiagramandComponentDesign Information (40 CFR §60.103a(a)(3)(ii) & 

## (iv))
A simplified process flow diagram ofthe 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 PLANTFLARE 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 DesignParameters(40 CFR §60.103a(a)(3)(iii))

Table 5: Summary of Flare Design Parameters
Flare Description #2 HYDROGEN PLANTFLARE 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).
5#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery
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 ofthe two sweep gas injection points has a maximum flow rate of 16.4 MSCFD. c - The knockout drum forthe #2 hydrogen plantflare is incorporated into the base ofthe flare stack. BP considers the operating level range ofthe level transmitters on the base ofthe flare to be the knockout area. This knockout drum design removes a potential mechanism forfailure because there are no moving pieces associated with the design compared to using a separate knockout drum prior to the flare stack.


## 2.5 FlareMonitoringSystemSpecifications(40 CFR §60.103a(a)(3)(v))

2.5.1 VentGas FlowRate NSPS Ja requires the refinery to operate a flow meterthat 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 ifflaring 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 ofthe total gas flow rate,
• Must have a flow sensitivity of no more than 5% ofthe 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 ofa flow meter and associated pressure and temperature sensors for the flare gas header. A GE DigitalFlow 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

6#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March 2013 meter is installed in a representative location offlare gas flow rate, thereby complying with the selection and installation ofthe flow meter. The following table summarizes the specifications ofthe flow meter.



### FLOWMETER IDENTIFICATIONINFORMATION 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 ofthe 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 SulfurContent Each flare subject to NSPS Ja requires the refinery to operate a monitorto measure the sulfur content ofthe gases combusted in the flare. However, 40 CFR 60.107a(a)(3) exempts inherently low sulfurfuel 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 60.107a(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 monitoror H2S monitor is required to be installed on the #2 Hydrogen Plant Flare header.

7#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery March2013


## 3.0 Flare Minimization Assessment (40 CFR §60.103a(a)(2))

The #2 Hydrogen Plantflare system is designed to handle start-up venting and excess gases in the event ofa 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 ofthe flare would be for the combustion ofcarbon 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. Forthe 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 ofthe 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 ofthe two sweep gas contributions to the #2 Hydrogen Plant Flare headerwith a restriction orifice at the flow rate recommended in the design documentation. Each design sweep gas flow rate is a necessary component ofthe 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 sentto the flare. The sample lines associated with each sample point consist ofone-inch ortwo-inch piping ortubing. Additionally, the sample points are located in close proximity to the process vessel to be sampled. Therefore, the volume ofgas required to be purged prior to sampling has been minimized by design to the extent possible.

8#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March2013 4. Loss ofthe PSA beds. This can occurfor 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 everyfew minutes. The malfunction ofa PSA automatic valve can cause a set of PSA beds to be taken out ofservice. This, in turn, increases the PSA offgas flow. Depending on the dynamics ofthe increase of PSA offgas 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 forthe additional PSA off gas flow. But in the meantime, flaring can occur during this disturbance. The estimated flaring from the loss ofall 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. Ifthere is a malfunction in one ofthe PSA beds, the pair of PSA beds is removed from service and the remaining 8 beds keep functioning without the need forflaring 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 ofthe 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 ofthe process gas and flaring ofthe excess process gas would be required until a reduction in plantfeed 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 oftime. 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 compressorwill 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 operatorfor 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 compressorwill be anticipated and coordinated ahead oftime. In this way, hydrogen production can be reduced prior to the loss ofcompression to reduce flaring. It is only under circumstances that are "unplanned" and "beyond reasonable control" that 9#2 Hydrogen PlantFlare Flare Management Plan BP Cherry Point Refinery March 2013 the shutting down ofthe compressorwill lead to significant flaring of hydrogen product until the plant feed rate can be cut orthe compressor can be restarted. 7. Purging to prepare equipmentfor maintenance. Some equipment requires that it be purged to achieve a safe atmosphere In order to safely do maintenance. Planned turnaround maintenance forthe #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. Ifthe piece ofequipment can be taken down with the remainder ofthe plant running, gas upstream ofthe equipment is notflared. An example ofdesign 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 ofthe 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 ofthe 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 inertwork environment priorto 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 closerto 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 equipmentfailure, etc.) does not result in catastrophic failure ofthe equipment and release of untreated process gases to the atmosphere

. The 

### 10#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery March 2013 PSVs allow equipment to release gas into the hydrogen plantflare 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 ofthe process conditions. BP trains its operators to do everything possible to get relieffrom 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 ofthe hydrogen plant design, BP reviewed each PSV service and established a mitigation plan that includes a range ofoptions 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 ofthese 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 ofthe 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 forfeed into the hydrogen plant, BP was able to design the plant with only product compression. Fewer compressors mean less opportunity for a compressorfailure and fewer compressors to conduct maintenance on. In addition, the hydrogen plant is designed so that ifthe product compressor is offline, the hydrogen is route to the low pressure hydrogen header (upstream ofthe 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 heaterfor fuel, which reduces natural gas consumption at the plant. Alternatives would be to flare the PSA offgas or install a compressorto recover the gas into the refinery fuel gas system. However, as discussed in the next section, recovery ofthe 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.

11#2 Hydrogen PlantFlare Flare Management Plan BP Cherry PointRefinery 

## 3.1 Evaluation of flaregasrecovery March 2013

As shown bythe information below on the composition and characteristics typical of PSA inlet gas during startup, the heating value ofthis gas is extremely low and there is a high percentage of inert gas. The ability to use this gasforfuel is very low based on the heating value
- most burners are notdesigned for gas ofthis composition. The fact that flare gas is flammable creates safety concerns if large volumes are to be stored. Combustion offlammable gases as they are produced, either in process equipment or in a flare system, is intrinsically saferthan storage, as it minimizes the onsite inventory of combustible material. The minimization of onsite storage ofcombustible gases also addresses Homeland Security concerns and the potential for damage from an earthquake. The design basis forthe hydrogen plant startup (flaring offspec gas) is 

### 8,049 scfm, which represents 50% ofthe typical PSAfeed 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 GasasRefineryFuel The composition ofthe 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 ofthe entire fuel gas system would be decreased ifthe PSA gas was recovered. Therefore, BP does not believe flare gas recovery is logical for the hydrogen plant flare header.



### 12#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery


## 4.0 Baseline Flow Evaluation (40 CFR §60.103a(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 underwhich the refinery conducts a Root Cause Analysis (RCA). A RCA is required ifvent gas flow exceeds the baseline conditions by 500 MSCFD during a 24-hour period. The refinery is also required to conduct a RCA, regardless offlow, ifthe 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 sulfurfuel gas streams from the sulfur monitoring requirement. All ofthe 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 DefaultBaselineFlowRates(40 CFR §60.103a(a)(4)(i))
Because the Hydrogen Plant Flare is under construction atthe time this FMP is being prepared, operational data are not yet available to develop a baseline flow rate for this flare. With implementation ofthe minimization measures discussed in this Plan, the default baseline flow rate is anticipated to be solely the flare sweep gas. NSPS SubpartJa 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 leastone year of normal operational data has been collected. 

### Baseline flow of33,600 scf/24 hour- flow ofover 533,600 scf/24 hours would triggera 

### RCA.


## 4.2 AlternateBaselineFlowRates(40 CFR §60.103a(a)(4)(ii))
Alternate Baseline Flow Rates forthe #2 Hydrogen Plant Flare are proposed forthe conditions listed below. The methodology used to develop projected flow rates for these scenarios is also provided below.
13#2 Hydrogen PlantFlare Flare Management Plan BP CherryPointRefinery March 2013 

### Table 6: Summary ofAlternate 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 orderto 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. HydrocrackerTrip) horus rate based on 2 hours at 100 percent product rate and 8 hours at 50 percent rate.



### 4.3 Procedures to MinimizeFlaring While Operating UnderanAlternate BaselineFlowRate (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.



### 14#2 Hydrogen Plant Flare Flare Management Plan BP CherryPointRefinery March2013


## 5.0 Procedures to Minimize Flaring During Planned Start-up and Shutdown (40 CFR §60.103a(a)(5))
5.1 Shutdown/Startupplanning & 

## ShutdownProcedures Procedures for planned startup and shutdown ofthe #2 Hydrogen Plant are currently in development and will be fully implemented by the time the unit will begin operation. The operational philosophy atthe refinery encourages the minimization offlaring 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 forflaring to occur in orderto maintain an appropriate level ofsafety 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.



### 15#2 Hydrogen Plant Flare Flare ManagementPlan BP CherryPoint Refinery March2013


## 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 orflaring conditions. The hydrogen plant does not incorporate a flare gas recovery system for reasons presented in Section 3 ofthis FMP; therefore, the process unitwill not be affected by hypothetical flare gas recovery operations.



### 16#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery 

## 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 ofthe 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 RootCauseAnalysis 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), ofa discharge ofgases in excess ofspecified 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:

• Ifa single discharge event lasts fortwo or more consecutive 24-hour periods, only one RCA must be performed;

• Ifa single discharge event triggers an RCA based on both ofthe 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 ofa planned startup or shutdown during which the Planned Startup & Shutdown procedures referenced in Section 5 ofthis 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 of500,000 scfabove an established baseline in a 24-hour period.



### 17#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March 2013 As discussed earlier, sulfur monitoring is not required forthe #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- FlowExceedance The specified flow threshold which triggers an RCA is greaterthan 500,000 scfabove 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 ofthe investigation:

• the connections that were contributing to the header,
• the duration ofthe flaring event,
• what was occurring in the process that lead to the flaring event, and, if possible,
• the sequence ofevents 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 orduration ofthe 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 ofthe discharge.
• Date and time ofwhen the discharge was first identified and the duration ofthe discharge.

• The measured quantity ofgas discharged overthe discharge duration. Ifthe discharge duration exceeds 24 hours, record the quantityfor each 24-hour period.
• The steps taken to limitthe emissions during the discharge

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

• Description ofthe recommended corrective action(s) or an explanation ofwhy corrective action is not necessary.



### 18#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March 2013
• Ifthe discharge was a result ofa planned startup or shutdown ofa 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. Forfurther information on the procedures to minimize flaring during planned startup and shutdown, see Section 3 of this FMP. 

## 7.2 CorrectiveActionAnalysis 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 ofthe recurrence ofthe primary cause and any other contributing cause(s) ofan event identified by a root cause analysis as having resulted in a discharge ofgases to an affected flare in excess of specified thresholds." An identification ofcorrective action(s) must be performed as the final step ofan 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, ifpossible, eliminate the possibility ofthe recurrence ofthe causes of the flaring event that caused an exceedance ofone or both ofthe RCA thresholds. The identification of corrective actions should not incorporate rationale regarding economic ortechnical feasibility orother 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) ofthe 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, ifany, that are available, and an explanation ofwhy the selected corrective action(s) is/are the best alternative(s), including, but not limited to, considerations ofcost effectiveness, technical feasibility, safety and secondary impacts." The Corrective Action Analysis is the process to determine which ofthe 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. Ifthe 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 ofthe discharge for which the RCA and corrective action analyses were required oras soon as practicable. If it is determined that a corrective action should not be implemented, the explanation ofthe basis ofthat decision must be recorded no laterthan 45 days following the discharge. Because the Corrective Action Analysis is a consequence ofthe RCA, it is imperative to commence the RCA as soon afterthe discharge as possible in orderto allow forthe maximum amount oftime to be allotted to the determination and implementation ofthe 

### 19#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March2013 most beneficial corrective action. However, ifa 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 ofthat decision.

• A description ofthe 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.

• Ifthe discharge was a result ofa planned startup or shutdown ofa refinery process unit orancillary equipment connected to the affected flare, a statement that a Corrective Action Analysis is not necessary because the facility followed the FMP.

20#2 Hydrogen Plant Flare Flare Management Plan BP CherryPoint Refinery March2013



## APPENDIXA- Simplified Process Flow Diagram of Flare System

21\...FlareIgnitorControlSystem46-LCP-6Unintenuptiblef:TI(noS,H2S,orflcri__________L___________.I.NaturalGasrotemonitoring)------·----·--·---·----____...L_ThreeNaturalGasPnots#2HydrogenPlantPrac"''"Unit#2HydrogenProdu'"'tCompo(46-#2HydrogenPlantSamplingVents:::::::........VelocitySealH2PlantFlare46-2802--+---K.O.Drum(withinflarestack)29"i.d.x1o'1.6"1..,___H2PLANTFLARESYSTEM-SIMPLIFIEDPFDBPCherryPointRefineryBlaine,Washington#2 Hydrogen PlantFlare Flare ManagementPlan 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 forRevision the USEPA? company) (See Section 1.3 ofthe FMPl 0 [month, year] [name, company} Original Yes



### 22#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March 2013 

## APPENDIX C - NSPS Ja Regulatory Cross-Reference Table

Citation RegulatoryDescription FMPManua/ Section 60.103a(a) Items to be includedin the Flare Management Plan See Below 60.103a(a(1)) Listofprocess units 2.2 60.103a(a(1)) Listofancillaryequipment 2.2 60.103a(a(1)) Listoffuelgas systems 2.2 60.103a(a)(2) Minimization assessment 3.0 Generaldescription 60.103a(a)(3)(i) Flare type 2.1 60.103a(a)(3)(i) Assistsystem 2.1 60.103a(a)(3)(i) Flare headersystem 2.1 60.103a(a)(3)(i) Flare gas recoverysystem 2.1 Description andsimple PFD 60.103a(a)(3)(ii) Flare tip 2.3 60.103a(a)(3)(ii) KOdrum 2.3 60.103a(a)(3)(ii) Flare headerandsubheader 2.3 60.103a(a)(3)(ii) Assistsystem 2.3 60

. 103a(a)(3)(ii) Ignition system 2.3 Design parameters 60.103a(a)(3)(iii) Maximum ventgas flowrate 2.4 60.103a(a)(3)(iii) Minimum sweep gas flowrate 2.4 60.103a(a)(3)(iii) Minimumpurge gas flowrate 2.4 60.103a(a)(3)(iii) Maximum supplementalgas flowrate 2.4 60.103a(a)(3)(iii) Maximumpilotgas flowrate 2.4 60

. 103a(a)(3)(iii) Minimum total steam flow rate 2

.4 Description andsimple PFD offlowmeterandsulfurcontent 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) Supplementgas 2.3 60.103a(a)(3)(iv) Pilotgas 2.3 60. 103a(a)(3)(v) Manufacturer' s specifications foreach monitor/analyzer 2.5 indentifiedin 60.103a(a)(3)(iv)



### 23#2 Hydrogen Plant Flare Flare Management Plan BP Cherry Point Refinery March2013 

## APPENDIX C- NSPS Ja Regulatory Cross-ReferenceTable Citation Regulatory Description FMPManual Section Foremergencyflares, secondary flares, andflares with FGRUs thatare designedto capture allnormalflows 60

. 103a(a)(3)(vi) Description ofwaterseal NA 60.103a( a)(3)( vl) Designation ofmonitoring option NA 60.103a(a)(4) Baseline flowevaluation 4.0 60.103a(a)(5) Procedures to minimize oreliminate discharges duringplanned 5.0 shutdown andstartup 60.103a(a)(6) Procedures to reduce flaring in cases offuelgas imbalance 6.0 60.103a(a)(7) Procedures to minimize frequencyandduration during FGRU 6.0 outages andto minimize flaring during FGRU outages 60.103a(b)(1) Submission timeline forinitial FMP 1.0 60.103a(b)(2) Events which triggera re-submittal ofthe FMP 1.1 60.103a(c)(1) Conditions which Triggera Root Cause Analysis fora 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 maintainedfor Corrective Action Implementation 7. 1.1 60.103a(f) Timeframe forinitialcompliance for Root Cause Analysis and 7.2 Corrective Action Implementation Programs 60.103a(g) Specific requirements forflares locatedin the BAAQMD and N/A SCAQMD 60.103a(h) Applicabilityofflares to < 162 ppmvH2S concentration limitin 2.5.2 flare gas 60.107a(a)(2) Requirements formonitoring flare gas H2S concentration 2.5.2 60.107a(a)(3) Exemptions forflares gas H2S concentration monitoring 2

.5.2 60.107a(b) Procedures to exemptsteams for flare gas H2S concentration 2.5.2 monitoring 60.107a(e) Monitoring ofsulfurcontentforRCA 2.5.2 60.107a(f) Monitoring offlowrates for RCA 7

. 1 60.107a(a)-(c) Requirednotifications andrecords 7.0

24