### November 13, 2012

Attention: Mr. 

### Joel Sutton AlabamaDepartmentofEnvironmentalManagement AirDivision P.O. Box 301463 Montgomery, AL 36130-1463 RE: HuntRefining Company, Tuscaloosa, Alabama FacilityNo.: 413-0007 NSPS SubpartJaFlareManagementPlan DearMr. 

### Sutton: Enclosed istheNSPS SubpartJaFla re ManagementPlan for theHydrocrackerAreaFlare, CokerArea Flare, and Hydrobon AreaFlare. Ifyou have any questionsplease contactCaseyFrederickat(205) 391-3376.

"Based oninformation and beliefformed after reasonable inquiry, the statements and information in this document aretrue, accurate and complete."

Sr. Vice President Operations

cc: U.S

.EnvironmentalProtection Agency OfficeofAirQualityPlanning and Standards SectorPolicies and ProgramsDivision U.S. EPAMailroom (E143-01) Attention: Refinery SectorLead 109 T.W. AlexanderDrive ResearchTrianglePark, NC 27711 David Carroll

- coversheetonly CaseyFrederick Stefanie Thompson

HUNT REFINI NG COMPANY 2200 Jack Warner Parkway, Suite 400 ·Tuscaloosa, Alabama 35401 P

.O. Box 038995 · Tuscaloosa, Alabama 35403
-8995

## REFINING COMPANY



# HuntRefining Company Tuscaloosa, Alabama

NSPS SubpartJaFlareManagementPlan HydrocrackerAreaFlare, CokerAreaFlare, and HydrobonAreaFlare 

## 1855 FairlawnRoad Tuscaloosa, Alabama

Tuscaloosa County

November 2012

Preparedby:


## SAGE
ENVIRONMENIAL CONSULTING

## TABLE OFCONTENTS

Section 1Introduction ......................................................................................................... 1-1 1.1 Facility Description ............................................................................................ 1-l 1.2 NSPS Ja Applicability ........................................................................................ 1-l 1.3 Revisions to the Flare Management Plan
........................................................... 1-2 1.4 Flare Management Plan Contents
....................................................................... l-3 Section 2 Description ofFlare Systems..............................................................................2-1 2.1 Flare Type...........................................................................................................2-1 2.2 Flare Tip..............................................................................................................2-2 2.3 Flare Header System...........................................................................................2-2 2.4 KnockoutDrum ..................................................................................................2-8 2.5 Flare Gas Recovery System................................................................................2-9 2.6 Water Seal.........................................................................................................2-10 2.7 Assist System....................................................................................................2-12 2.8 Pilot Gas............................................................................................................2-13 2.9 Ignition System.................................................................................................2-14 2.10 PurgeGas..........................................................................................................2-15 2.11 SweepGas ........................................................................................................2-16 2.12 Supplemental Gas .............................................................................................2-18 2.13 Monitoring Instrumentation..............................................................................2-18 2.13.1 Vent Gas Flow......................................................................................2-18 2.13.2 SulfurContent.......................................................................................2-20 Section 3 FlareMinimization..............................................................................................3-1 3.1 Description ofContributions to Flare Header
.................................................... 3-1 3.2 Minimization Assessment...................................................................................3-1 3.3 Baseline FlowEvaluation ...................................................................................3-3 3.4 Stmtup and Shutdown......................................................................................... 3-5 3.5 Fuel Gas Imbalance ............................................................................................ 3-5 3.6 Fuel Gas Recovery Outage .................................................................................3-6 Section 4 Root CauseAnalysis and CorrectiveAction
.....................................................4-1 4.1 Root Cause Analysis...........................................................................................4-1 4.1.1 RCA -FlowExceedance
........................................................................4-2 4.1.2 RCA- S02

### Exceedance..........................................................................4-2 4.2 Corrective Action Analyses................................................................................4-3
Sage Environmental Consulting, L.P. November2012 i HuntRefining Company Flare ManagementPlanLIST OF APPENDICES Required Notifications Process Flow Diagrams Flare Tip Drawings DocumentRevision Log Appendix A AppendixB AppendixC AppendixD Appendix E NSPS JaCross-ReferenceTable

Sage EnvironmentalConsulting, L.P. November20/2 ii HuntRefiningCompany Flare ManagementPlan

### 1.1 Facility Description 

## SECTION 1 INTRODUCTION

The Hunt Refining Company (Hunt) owns and operates a petroleum refinery in Tuscaloosa, Alabama (Tuscaloosarefinery). Refinery products include, butare not limited to, gasoline, diesel, kerosene, naphtha,jetfuel, coke and asphalt. 

### 1.2 NSPS Ja Applicability The mostrecent promulgation ofthe petroleum refineryNew Source Performance Standard (NSPS) is contained within 40 CFR60 SubpartJa. NSPS Ja applies to fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas combustion devices, flares, and sulfurrecovery plants. Accordingto NSPS Ja, the definition ofa flare is as follows: "Flaremeans 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 or steam injection systems), flame arrestors, and the flare gas header system. In the case ofan interconnected flare gas header system, the flare includes each individual flare serviced by the interconnected flare gas header system." An affected flare underNSPS Ja is onefor which construction, modification or reconstruction commenced after June 24, 2008. A modification to a flare occurs when a project that includes any ofthe following activities commences:
• Any new piping from a refinery process unit, ancillary equipment, or a fuel gas system is physically connected to the flare; or
• A flare is physically altered to increase the flow capacity ofthe flare. However, the following activities do not, by themselves, implicate amodification:
• Connections made to install monitoring systems to the flare;
• Connectionsto install orenhance a flare gas recovery system;
• Connections madeto replace orupgrade existing pressurereliefor safety valves;
• Connections made for flare gas sulfurremoval;
• Connectionsmadeto install redundantequipment associated with the flare, provided they do not increasethe capacity ofthe flare;
• Replacement orrelocation ofpipe "inkind"; or

SageEnvironmental Consulting, L.P. November2012 1-1 Hunt RefiningCompany Flare Management Plan• Connections that interconnect two ormore flares. The HydrocrackerAreaFlare (BN-3250) was constructed in June 2009. Underthe Ja Rule, the HydrocrackerAreaFlare is subjectto the requirements and compliance timeframes ofa new flare since it was constructed after June 24, 2008. A list ofall required notifications for the flares is included in AppendixA. At the Tuscaloosa Refinery, the HydrocrackerArea Flare is a new source and is interconnected to the CokerArea Flare (M-2201), and the Hydrobon Area Flare (D10.3301) An interconnected flare header system must be treated as a single affected unit underNSPS Ja. As such, for each category ofstandards that is promulgated in NSPS Ja, the strictest standard that is required for any one ofthe three interconnected flares mustbe applied to all three flares. A process flow diagram thatdepicts the configuration ofthesethree flares as an interconnected flare header system in provided in Appendix B. NSPS Ja contains workpracticeprovisions that are applicable to refinery flares'. Thesework practice standards, as well asthe applicability triggers for flares, were proposed to be changed in the Federal Registerdated December 22, 20082• On September 12,2012,the revised NSPS Ja standards were published in the Federal Register. The work practice standards require the preparation ofthis Flare Management Plant(FMP). As the interconnected flare system is considered as an affected sourcethat is subject to the rule, the Tuscaloosa Refinery mustdevelop and implement a singleFMPfor the interconnected flares by no laterthan 60 days afterthe rule was published in the Federal Register, orNovember 13,2012. The Tuscaloosa Refinery is required to maintain a copy ofthe initial FMP until it is revised. See Section 1.3 for operational changes which trigger a revision to the FMP. 

### 1.3 Revisions to the Flare Management Plan The FMP and all documents referenced herein should be internallyreviewed and updated periodically to account for changes in the operation ofthe interconnected flare system. These changes include, but are not limited to, adding new connectionsto the flare header system orthe expansion ofthe flare gas recovery system. The Tuscaloosa Refinery is required to maintain a copy ofthe currentPlan. Itis importantto note that notall events which triggerthe need for an internal revision ofthe FMPrequire are-submission ofthe revised FMP to the United States Environmental Protection Agency (USEPA) Administrator and to the Alabama Department ofEnvironmental Management (ADEM) Administrator. The rule requires the FMPto be re-submitted to both regulatory agencies for one ofthe following four reasons:
• Addition ofan alternative baseline flow rate, • Revision ofan existingbaseline, • Installation ofa flare gas recovery system, or • Change offlare designations and monitoring methods.

1 40 CFR 60.103a 2 73 FR78522, dated December22, 2008

Sage EnvironmentalConsulting, L.P. November2012 

### 1-2 HuntRefiningCompany Flare ManagementPlanA Plan Revision History log is included in Appendix D. 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 Administrator. 

### 1.4 Flare Management Plan Contents This FMP fulfills the requirements ofNSPSJaregarding the development ofa written FMP and has been prepared pursuantto the requirements and provisions ofthe rule. Appendix E includes atable thatcross-references the requirements ofNSPSJa and their location within this FMP. The following information is specifically required to be included in orreferenced by this Plan:
• Listing ofall process units, ancillary equipment, and fuel gas systems thatare connected to the flare header system; • Flare minimization assessment; • Descriptions ofall flare components and design parameters; • Specifications for all required monitoring instrumentation;
• 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 orreferences information which is not explicitly required to be included in the FMP underNSPS Ja. The inclusion ofthis supplemental information enables this Plan to fully document the managementpractices and flaring minimization measures and strategiesthat are in place atthe Tuscaloosarefinery. The following supplemental information is provided in orreferenced by this Plan:
• Description oftriggering events and compliance timefl-ames for Root Cause Analyses (RCAs) and CorrectiveAction Analyses and Implementation;
• Details ofthe required records, reports, and notifications.

Sage EnvironmentalConsulting, L.P. November2012 

### 1-3 HuntRefiningCompany Flare ManagementPlan

### 2.1 Flare Type 

## SECTION 2 DESCRIPTION OF FLARE SYSTEMS

All three flares ofthis interconnected flare header system are elevated flares. An elevated flare consists ofa tip that is mounted on a flare stack, which is raised high above grade, and supports combustion atthe upper end ofa vertical riser. The combustion zone is elevated in orderto separate the heat generated by combustion from people, equipment, or structures at grade level and to aid in airdispersion. Perthe definitions contained in the rule, each ofthese flares are non-emergency flares meaning they can potentially receive continuous flows. In addition, the system contains a flare gas recovery compressor system that significantly reduces the potential for continuous flow to these flares. The flares are not a permanent cascaded flare system and the flares cannotoperate as full capacity backup flares for each other. The HydrocrackerAreaflare is a self-supporting elevated flare that stands 220 feet above the ground, with a 144"diameterbase. The diameterofthe flare tip is 54". The flare has a maximum design capacity of808,775 pounds per hour (lb/hr) ofhydrocarbon flow and has a smokeless capacity ofI0% oftotal hydrocarbon flow. TheCoker Area flare is a self-supported elevated flare that winds 200 feet above ground, with a 72"diameter base. Thediameterofthe flare tip is 30". The flare has a maximum case study capacity of372,503 lblhrofhydrocarbon flow and has an assumed smokeless capacity of10% oftotal hydrocarbon flow. The Hydrobon Area flare is a self-supported elevated flare that stands 120 feet above the ground, with a45"diameter base. The diameterofthe flare tip is 26". The flare has a maximum case study capacity of88,187 lb/hrofhydrocarbon flow and has an assumed smokeless capacity of 10% oftotal hydrocarbon flow. Each flare includes a molecularseal within the flare stack to limitthe possibility ofair infiltration through the stackand into the header. Each molecular seal is equipped with a drain to allow any condensable materials to be removed from the base ofthe seal device to ensure propercontinuous operation. Additionally, each molecular seal drain is designed with a watertrap to ensure that aircannotenterthe flare system through the drain. The Hydrobon watertrap is fitted with a level gauge to allow operators to checkthe water level in the water trap. The watertraps are free-draining to the CokerAreaknockoutdrum (V-2201), to the Hydrobon Area water seal (08.3301),and to the oily water sewerconnection, for the drains from the CokerArea flare, Hydrobon Areaflare, and Hydrocracker Area flare, respectively. Based on available information, the HydrocrackerArea flare utilizes a specific molecular sealthat is aproprietary density seal device (BTZ-DS-54) designed by Callidus Technologies, Inc.

Sage EnvironmentalConsulting, L.P. November 2012 2-1 Hunt RefiningCompany Flare Management Plan2.2 Flare Tip The function ofthe flare tip is to mix the flare gas and assist gas at velocities, turbulence, and concentration required to establish and maintain proper ignition and stable combustion for the maximum specified reliefgas flow rates atthe system-allowable pressure drop. Although the Tuscaloosa Refinery normally has a low base load offlare gas in the interconnected flare header system during normal operations, the largest concern with respect to the flare system is its ability to handle the rare yet large emergency flaring events. The design ofthe flare tip is an integral part ofthe flare system because it enables the refinery to handle large variances in the volume, pressure drop, concentration, and temperature ofthe flare gas streams. The Hydrocracker Area flare tip, which was installed in June 2009, is a 54" diameter tip designed by Callidus Technologies Inc., model number BTZ-US-54C. Based on a review of the flare tip drawings, the flare tip appears to be unobstructed by the steam ring and pilot assemblies; therefore, the effective diameter ofthe tip is approximately 54". Itconsists ofa single burner equipped with steam assist. Steam assist can be supplied radially using an upper external steam ring, as well as, in the center ofthe flare stack,just above the density seal. A drawing ofthe tip is included in Appendix C. Fmther information on the steam assist system can be found in Section 2.7. The current Coker Area flare tip, which was installed on April 3, 2007, is a 30" diameter tip designed by Zeeco, Inc., model number QFS-30. This tip replaced an earlier installed flare tip. Based on a review ofthe flare tip drawings, the flare tip appears to be unobstructed by the steam ring and pilot assemblies; therefore, the effective diameter of the tip is approximately 30". It consists of a single burner equipped with steam assist delivered through a 4" steam supply pipe. Steam is supplied radially using an upper external steam ring. A drawing ofthe tip is included in Appendix C. Fmther information on the steam assist system can be found in Section 2.7. The Hydrobon Area flare tip, which was installed on April 3, 2007, is a 26" diameter tip designed by Zeeco, Inc., model number HCS-20. This tip replaced an earlier installed flare tip. Based on a review ofthe flare tip drawings, the flare tip appears to be unobstructed by the steam ring and pilot assemblies; therefore, the effective diameter of the tip is approximately 26". It consists of a single burner equipped with steam assist delivered through a 4" steam supply pipe. Steam is supplied radially using an upper external steam ring as well as in the center ofthe flare stack. A drawing ofthe tip is included in Appendix C. Further information on the steam assist system can be found in Section 2.7. 2.3 Flare Header System According to the definitions promulgated in SubpartJa, flare gas header system is defined as "all piping and knockout pots, including those in a subheader system, used to collect and transport gas to a flare either from 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

Sage EnvironmentalConsulting, L.P. November2012 2-2 HuntRefining Company Flare ManagementPlaninside the battery limits ofa process unit ifthe purpose ofthe piping is to transport gas to a flare or knockoutpotthat is part ofthe flare." The primary function ofthe flare gas header is to safely accumulate and transfer gases to the flare for combustion. In addition to normal operating conditions, 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 process units with a controlled low-pressure outlet for any excess vapor flow that originates with high-pressure operations within the refinery. Nearly all vapors are flammable, making the flare gas header an essential safety feature of the refinery. The flare gas header relieves the pressure ofthe gas, rendering the gas safe to both equipment and surrounding personnel. At the Tuscaloosa Refinery, each ofthe three flares is part ofan interconnected network of flare headers that preferentially routes gases in the flare header to a common flare gas recovery system that is designed to recover the gases upstream ofthe three separate water seals during normal operations. Each flare has its own water seal at the base ofthe flare which provides the header system with the ability to maximize the volume ofgases that are routed to the recovery compressors. This maximized utilization is possible not only during normal operations, but also during periods ofturnaround, startup, shutdown, malfunction, and emergency. Although all three flares share the same flare header network, there are distinct and separate subheaders to which each process unit is connected. During normal operations, all process units contribute flare gases to their associated subheader. These separate subheaders are then connected by common piping. During normal operations, all gases that are discharged to the separate subheaders upstream of the water seals migrate towards the Coker Area Flare Header, where the flare gas recovery compressors are physically located. Therefore, the gases from all three ofthe interconnected units can be recovered by one integrated FGRU. However, it is possible during certain operating scenarios to isolate each subheader and direct all gases in the individual subheaders to only their associated flare. The following list details the refinery process units and their**assoc~ated** flare:
• Hydrocracker Area Flare
o Naphtha Splitter/CCRPlatfonner
o Hydrocracker
o No. 2Hydrogen Plant
o DMS Plant
• Coker Area Flare
o Coker
o Diesel Hydrotreater
o No. I Hydrogen Plant

Sage EnvironmentalConsulting, L.P. November2012 2-3 HuntRefiningCompany F1are Management P !ano No. 2Amine Unit
o OMS Plant
• Hydrobon Area Flare
o Isomerization Unit
o Naphtha Hydrobon
o No. I and No. 2 Sulfur Recovery Units
o TGTU
o SCOT Unit
o No. I Amine Unit
o Sour Water Stripper
o GOHB and Vacuum Splitter Ifthe interconnected flare header system is analyzed as one low-pressure collection point for all process gases independent of the associated flare, the process gas streams can be organized according to three categories ofcontributions. Two ofthe categories ofstreams are connected to the flare header downstream of a water seal while the other category is connected to the flare header upstream ofa water seal. Those streams injected upstream ofa water seal have the opportunity to be recovered by the flare gas recovery system for use as refinery fuel gas while those connected downstream ofawater seal are routed directly to the flare tip. The downstream sources have been reviewed and assessed as being unsuitable for potential recovery as refinery fuel gas, hence they are directed to the flares after the water seals and beyond the capture ofthe FGRU. The following list describes the streams that are connected upstream and downstream of water seals with the frequency of contributions provided in parentheses:
• Upstream ofa water seal
o Process gas (continuous)
• Downstream ofa water seal
o Process gas with high concentrations of hydrogen (continuous, to HydrocrackerAreaFlare)
o Acid gas and associated liftgas (non-continuous, to Coker Area Flare)
o Gas from the over-pressuring ofFGRU mix gas vessel (non-continuous, to CokerArea Flare)
o No. 1Hydrogen Plant depressure (non-continuous, to CokerAreaFlare)
o Excess fuel gas discharged through the lift gas valve (non-continuous, to Coker AreaFlare)
o ISOM depressure (non-continuous, to CokerArea Flare)

Sage Environmental Consulting, L.P. November 2012 2-4 HuntRefiningCompany Flare ManagementPlano ISOM dryer regeneration (non-continuous, to Coker Area Flare)

The interconnected flare header system has a common flare gas recovery system, which is comprised oftwo liquid ring compressors. Because the recovery system directs all routine vent gases to the fuel gas mix drum (DRM-22933) of the refinery fuel gas distribution system, only minimal flaring is expected to occur during routine operation ofthe process units referenced above. A sophisticated pressure control scheme allows each flare to remain in standby mode for greater-than-normal vent gas flow rates. During normal operations the flares experience virtually no flaring due to pressure breakthroughs at each water seal. Each experiences minor flows due to ventgases that are connected downstream ofits water seal. In the event ofan event or incident causing the pressure in the flare gas header to exceed the pressure in one ofthe water seals, the flare gas is released into the associated flare stack for combustion. Breakthrough ofone ofthe water seals is due to one ofthe following activities relating to key pieces ofequipment: I) Outage ofFuel gas recovery system, and 2) Closing ofFlare Isolation Valve (XV-1132). The pressure threshold created by each ofthe water seals, in order ofincreasing pressure, is as follows: I) Hydrocracker Area flare- 24" 1-hO, 2) Coker Area flare- 30" H2 0, and 3) Hydrobon Area flare- 42" H20. Because ofthe design ofthe refinery and the targeted production volumes ofspecific refinery products, the Hydrobon complex's typical contributions are not sufficient to cause a flaring event at any of the flares and are suitable for recovery by the flare gas compressors. Furthermore, because the Hydrobon Area flare water seal provides the greatest pressure threshold ofall three water seals, ifflaring occurs at the Hydrobon Area flare, it is typically due to increased vent gas flow during refinery-wide maintenance events, shutdowns, startups, and malfunctions. The Flare Isolation Valve, XV-I 132, is installed on the piping ofthe flare header system that connects the Hydrocracker Area flare subheader and the Coker Area flare subheader. Local pressure sensors that are installed on either side ofthe control valve close to the process unit contributions are used to calculate the pressure differential in the Distributed Control System (DCS). During normal operations, the pressure in the Hydrocracker Area Flare header is maintained slightly higher than the pressure in the Coker Area Flare header, yielding a minimal positive differential pressure and ensuring that the process gases that are discharged to the flare header from the Hydrocracker complex flow through the open XV-I I32 control valve towards the Coker Area flare header and are recovered by the flare gas recovery system. However, when one or more ofthe following thresholds are exceeded, the DCS

Sage EnvironmentalConsulting, L.P. November 2012 2-5 Hunt RefiningCompany Flare ManagementPlanlogic automatically closes XV-1132, isolating the Hydrocracker complex process units from the Cokercomplex process units:
• Pressure of25" H 2

### 0 within the Hydrocracker Area Flare header as measured by PT1130;
• Temperature of 180° F within the Hydrocracker Area Flare header as measured by TT-1131; and,
• Liquid level of75% ofthe weir height as measured by LT-9022 at the Hydrocracker Area Flare Water Seal (V-3251). As the flares are part ofan interconnected flare header system, the operations ofeach unit has the ability to affect flaring at the other flares. Based on the type ofgases in the header, a flaring event at the Coker Area flare could cause flaring at the Hydrocracker Area flare ifthe pressure exceeded the water seal breakthrough pressure. However, flaring at the Hydrocracker Area flare does not automatically cause flaring at the Coker Area flare. The isolation ofthe two complexes during selected flaring events is controlled by control valve XV-1132 and is required to prevent over-pressuring ofthe flare systems and to prevent gases being sent to the FGRU that exceed the pressure and temperature design parameters. Hence, the system is fully interconnected for purposes of flare gas recovery optimization during normal operations, and partially cascaded to accommodate small malfunctions or maintenance events, but above 25" H20 in the header, the systems become isolated from the Hydrocracker Area flare while the Coker Area flare and Hydrobon Area flare remain cascaded. Oncethe XV-1132 related flaring eventhas ceased, the operators remotely re-open XV-1132. The Flare Isolation Valve is able to be resetwhen each ofthe set points referenced above are satisfied. During the period oftime when XV-1132 is closed, the recovery compressors continueto operate and are able to recoverthe flare gas that is on the CokerArea flare side of XV-1132, up to the design capacity of the compressors (approximately 1,041 scfm/compressor). However, until XV-1132 is re-opened, there is no recovery potential for the flare gas on the Hydrocracker Area flare header side ofXV-1132 and flaring occurs when the local pressure exceeds the pressure threshold created by the Hydrocracker Area flare water seal. The continuous day-to-day flow to the flare stack, other than purge gases that are injected directly into the flare stacks to condition the molecular seals, is the medium pressure blowdown line to the Hydrocracker Area flare. This stream, which is the collection ofsweet gases from processes that are generally rich in H2, is injected into the flare header downstream ofthe HydrocrackerAreaflare water seal (V-3251) and is flared continuously at the HydrocrackerArea flare. The Tuscaloosa refinery purposefully excludes the Hydrocracker Area medium pressure line gases from fuel gas recovery. Combusting a higher concentration ofH2-rich fuel in the fuel gas combustion devices (such as the process heaters) would require a significant technical effort to retro-fit the existing burners to accommodate the hydrogen-rich fuel. Therefore, the refinery designed this medium pressure line within the new Hydrocracker Areato bypass the

Sage Environmental Consulting, L.P. November2012 2-6 HuntRefiningCompany Flare ManagementPlaninterconnected recovery system in order to allow for the proper operation ofthe recovery compressors and the exclusion ofcertain hydrogen fuel in the combustion devices. There are six non-continuous streams that intentionally bypass the flare gas recovery system and are connected downstream ofa water seal: ISOM depressure, ISOM dryer regeneration, No. I Hydrogen Plant depressure, excess fuel gas through the lift gas valve, an acid gas line with associated lift gas and the FGRU mix gas vessel (DRM-22933) over-pressure line. The discharges are directed to the Coker Area flare downstream ofthe Coker area water seal, D1100. The acid gas line, which is the collection ofacid gases from the Hydrobon Area Unit, is injected into the flare header downstream ofthe Coker Area flare water seal. There is a pressure control valve (HV-1658) on the acid gas line to the Coker Area flare, which is closed during normal operations. However, when the acid gas header experiences elevated pressures or the acid gas production exceeds the capacity ofthe SRUs and DMS Plant, the DCS logic actuates the opening ofthe control valve, which causes the acid gas to flow to the Coker Area flare. Lift gas, which is comprised ofrefinery fuel gas, is mixed with the acid gas line prior to combustion to promote proper combustion. More information on the lift gas is provided in Section 2.12, Supplemental Gas. Once the pressure sensor indicates that the pressure in the acid gas header has been reduced to an acceptable level, the control valve is automatically closed and the acid gas flaring event ceases. Detailed operational records are keptduring period ofHV-1658 opening and discharge. Because ofthe potentially high content ofhydrogen sulfide in the acid gas stream from HV1658, the Tuscaloosa Refinery routes this stream, when it is present, to the Coker Area flare. Ifthis stream were to be recovered by the flare gas recovery system, it would overwhelm the H2S Scrubber system because ofthe high H2S content and the volume ofthe stream. Ifthe H2S Scrubber system were ove1whelmed and shut down, further recovery by the recovery compressors would not be possible, resulting in a larger amount ofpotentially recoverable gases to be flared. Therefore, it was necessary for the refinery to direct the acid gas line to the flare stack without a possibility for recovery. The flow in the acid gas line is monitored by a dedicated flow meter (FIC-901). Because ofits point ofintroduction, this acid gas is incorporated into the combined flare gas being monitored to comply with the <162 ppmv 

### H2S limit. The FGRU mix gas vessel (on the discharge side ofthe compressors) is equipped with a PRV that will release material to the Coker Area flare when the pressure in the vessel exceeds 150 psig. The primary cause for a discharge from the PRV is from a blockage or inadve1tent closure ofa valve in the line in the recovered gas line to the amine scrubber or stmtup ofthe FGRU with a valve blocked in the discharge. It is not possible to connect the PRV back to the flare subheader for potential re-recovery. Installing a connection of this type would create a closed loop and "dead head" the compressor, which creates an unsafe operation. The PRV functions as a safety release device and releasing this flow back into a process would cause an overpressure situation for the FGRU and potential forthe flare system.

Sage EnvironmentalConsulting, L.P. November 2012 2-7 Hunt RefiningCompany Flare ManagementPlan2.4 Knockout Drum The hydrocarbon liquid knockout drum removes any potential liquid hydrocarbons from the flare gas priorto combustion. Generally, liquid hydrocarbons cannot be safely orcompletely burned in most flare systems. Because the gas recovery compressors are used as an alternative to flaring, the liquid hydrocarbons may cause mechanical damage to most types of compressors. Knockout drums contain a specified amount ofliquid that is monitored and maintained to ensure proper operation. All three flares each employ a knockout drum to remove liquid from the flare gas prior to flaring. In each case, when the pressure within the header increases to the point that flaring will occur, the flare gas is sent to either the water seal or the flare stack, depending on the configuration, while the liquids accumulate in the bottom ofthe vessel and are recycled to eitherthe sourwater header or slop oil tanks via pumps. The Hydrocracker Area flare Knockout Drum, V-3251, is a horizontal vessel that houses the water seal in the inlet ofthe vessel and contains the phase separation process prior to the outlet ofthe vessel. (This flare's water seal and KO drum are integrated into a single vessel.) The inner diameter ofthe vessel is 13 feet and the length, from tangent to tangent, which includes the space that contains the water seal, is 56 feet. The boot in which the liquids accumulate has a 3-foot outer diameter and is 4.5 feet tall. The Maximum Allowable Working Pressure (MAWP) is 50 psig and the Maximum Allowable Working Temperature (MAWT) is 580°F. The flare gas is off-gased directly to the flare stack while the water that accumulates in the boot ofthe vessel is pumped to the sour water processing area by pumps P-3252A/B and the oil that accumulates in the boot ofthe vessel is pump to the slop oil system by pumps P-3253A/B. The level in the boot is measured by LI-9002. Water addition orwater removal pumps are automatically activated when the liquid level in the boot triggers theirrespective low-low, low, high, orhigh-high alarms. The CokerArea flare Knockout Drum, V-2201, is a horizontal vessel that is located upstream ofthe Coker Area water seal. The inner diameter ofthe vessel is 102 inches and the length, from seam to seam, is 8.5 feet in diameter. The MAWP is 50 psig and the MAWT is 450° F. The flare gas is sent to the Coker Area flare water seal while the liquid that accumulates in the boot ofthe vessel is pumped to the Sour Water Surge Drum (MS-501) by pumps P2206A/B/C. The level in the boot is measured by LI-224. Water addition orwater removal pumps are automatically activated when the liquid level in the boot triggers their respective low-low, low, high, orhigh-high alarms. The Hydrobon Area flare Knockout Drum, D8.3301, is a horizontal vessel that is located upstream ofthe Hydrobon Area flare water seal. The vessel has an inner diameter of72 inches and is 20 feet long, from seam to seam. The MAWP is 50 psig and the MAWT is 650° F. The flare gas is sent to the Hydrobon Area water seal while the liquid that accumulates in the boot ofthe vessel is pumped to the sour water processing area by pumps P-3301A/S. The level in the boot is measured by Ll-3301. Water addition orwaterremoval pumps are automatically activated when the liquid level in the boot triggers their respective low-low, low, high, orhigh-high alarms.

Sage EnvironmentalConsulting, L.P. November2012 2-8 HuntRefiningCompany Flare ManagementPlan

### 2.5 FlareGasRecovery System Accordingto the definitions promulgated in SubpartJa, flare gas recovery system is "a system ofone 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 fueI gas system orto a fuel gas combustion device." Flare gases atthe Tuscaloosa refinery are collected in the interconnected flare gas header and recovered using a flare gas recovery system consisting of two dual stage liquid ring AB1500F GARO compressors (CP-111011111). Each compressor has a maximum design capacity of 1,041 scfm. Typical flow rates to the recovery system are approximately equivalentto the capacity ofone compressor. Ifonly one compressorwas typically operating during normal operations, flaring would occur during compressor staging when flow rates to the flare gas recovery system exceeded the capacity of one compressor. Therefore, to eliminate flaring due to compressor staging, the Tuscaloosa refinery typically operates both compressors simultaneously each at approximately 50% capacity. This ensures that no flaring occurs due to compressor staging when flow rates are below the capacity ofthe recovery system. The recovery system is capable of recovering all the normal operation related flows in the interconnected flare header ifthe control valve XV-1132 is open and if pressure within the header remains below 28" H20, up to approximately 3.0 MMscfd. Typical recovery rates during normal operations are approximately I,200 scfm. Gases within the flare header are directed to a manifold for either ofthe two compressors. The typical discharge pressure from the compressors is 110

- 120 psig. Because the compressors are designed to process an inlet vapor stream with a wide range ofhydrocarbon composition, there are, at times, hydrocarbon liquids that are condensed during the compression process. These compressed hydrocarbons are discharged to the horizontal Gas Separator Drum (DRM-22933; also referred to as V-5000) from the compressors along with the condensed flare gas and the operating liquid. The operating liquid is water, which is recirculated from utility make-up water, and forms the liquid seal, or ring, for compression. In the Gas Separator Drum, the condensed hydrocarbons accumulate on top of the working fluid, and spill overthe internal weir when the height ofthe liquid reaches approximately 2". The oily liquid is discharged to recovered liquid blowdown via the Hydrocarbon Slowdown Liquid Control Valve, LV-85042. A check valve in the blowdown prevents backflow into the Gas Separator Drum. The condensed flare gas is discharged to the Amine Unit for sulfur removal prior to introduction into the refinery fuel gas network. The Flare Gas Outlet Flow Transmitter, FIT-85023, measures and records the flow rate ofthe recovered flare gas to the sour gas header. The following conditions ofthe gas in the flare header presented in the table below represent the thresholds at which the DCS logic automatically activates the shutdown logic for the recovery compressors. Only one ofthe thresholds must be exceeded for the shutdown logic to be initiated. After the compressors have been shut down and once the operators have confirmed that the conditions within the flare header have been re-established to acceptable levels, the operators can remotely re-start one or both ofthe compressors from the DCS screen in the control room. Outages ofone or both ofthe recovery compressors due to their

Sage Environmental Consulting, L.P. November2012 2-9 HuntRefining Company Flare ManagementPlanown failure or need for maintenance occur infrequently. Outages for routine orpreventative maintenance are scheduled to occur during major process turnarounds. Additional set points for key parameters within the flare header that could potentially affect the performance and reliability of the compressors have been programmed to automatically shut down the compressors. These parameters are documented in the Coker Flare Gas Recovery Routine Operation procedure. Table2-1: Recovery Compressor Shutdown Criteria Sensor SetPoint Action PIT-85001 2" H20 Shutdown after20 second delay TIT-85031 175° F Immediate shutdown PIT-85001 28" H20 High pressure shutdown

Because the flare gas recovery compressor skids are located in close proximity to the Coker Area flare, the Coker Area flare operators are responsible for the operation ofthe recovery compressors. The Tuscaloosa refinery has created procedures for the Coker Area flare operators to instruct them regarding the operation ofthe fuel gas recovery system. The procedures are reviewed and updated, as necessary, annually. Procedures include the following:
• HP-V.B. Flare Gas Recovery Routine Operation
• CK_V.A. FGRU Routine Startup
• CK_V.C. FGRU Routine Shutdown
• CK_V.E FGRU Startup After Shutdown 2.6 Water Seal In a water seal, liquid is maintained at a certain level in the seal drum to create a barrier which seals the flare gas header from the flare burner. In order for the flare gas to reach the flare burner, the gas must create a pressure in the flare header greaterthan the pressure ofthe liquid seal and "breakthrough"the water. The maximum height ofliquid in the seal must be determined by the maximum exit backpressure allowable in the flare gas header. The seal serves multiple purposes to maintain the integrity ofthe flare system. However, the pressure created in the flare gas header by the water seal must not exceed the pressure rating ofthe flare gas header.
• The seal helps to maintain a slight positive pressure in the flare system to ensure that there is no air leakage into the flare system. This is especially true during sudden temperature changes, such as occurs following a major release of flare gas. Ifatmospheric oxygen entered the flare gas header, the oxygen

Sage EnvironmentalConsulting, L.P. November2012 2-10 HuntRefiningCompany Flare ManagementPlanwould combine with the hydrocarbon gas and potentially cause combustion or detonation within the flare header.
• With flare gas recovery in place, the liquid seal sets a pressure threshold that must be overcome in order for flaring to occur and essentially holds back the gases from the flare to allow for greaterrecovery.
• The seal prevents flashback originating from the flare burnerpropagatingback through the flare system. The flare is an ignition source and must be isolated from the headerand process units. The Hydrocracker Area flare uses a water seal with a breakthrough pressure of 24 inches H20. The water seal is maintained within the Hydrocracker Area flare KO Drum, V-3251, which is a horizontal vessel that houses the water seal at the inlet ofthe vessel. Utility makeup water valve, KC-9003, is opened on a frequent basis to flush the water in the vessel. This flushing ensures that the water seal liquids do not accumulate excess liquid hydrocarbons. The overflow is directed over an internal weir and is pumped to the sour water header by pumps P-3252A/B. Additionally, pumps P-3252A/B can circulate water from the boot ofthe knockout section ofthe vessel to the weir and ensure thatthe liquid level in the water seal is maintained even when the utility makeup watervalve is not opened. The water level is monitored by L T-9022, which provides aread-out in the DCS ofthe percent of weirheight. Ifthe level ofthe water seals drops below75% ofthe weir height, the LowLow Alarm ofthe water seal will be triggered, causing the Flare Isolation Valve XV-1132 to automatically close. Simultaneously, the utility makeup water valve, KC-9003, will automatically open until the seal level is at 96% ofthe weir height. The Tuscaloosa refinery created a document titled 

### Hydrocracker Area Flare Knock Out Drum Complex Control PhilosophyDescription thatprovides the Hydrocrackeroperators with areference manual for the Water Seal portion ofthe Knock Outdrum vessel. The CokerArea flare uses a water seal with abreakthrough pressure of30 inches H 2 0,which coincides with the pressure setpoint ofthe Fuel Gas Recovery System (CK-85001). The vessel, D-1100 (also referred to as DRM22934), is a vertical vessel with an outer diameter of 9 feet and a height, from seam to seam, of 15 feet. The MAWP is 50 psi and the MAWT is 450°F. Seal water is provided from the utility makeup water through control valve XV85047 at 20 gpm at 90 psig. XV-85047 is used to quickly replenish the water seal level after a release event. XV-85049 is the small skim flow system to cause accumulated hydrocarbons on top of the seal water to overflow to the KO drum, where the liquid is returned to the process. Additionally, the seal water is flushed on a frequent basis to flush the water in the seal water. The overflow drains back to the Coker Area Flare KO Drum, V220!. The liquid level can be observed via sight glass LG-85044. The Hydrobon Area flare uses a water seal with a breakthrough pressure of42 inches H2 0. The vessel, V-100, which is located between the Hydrobon Area flare KO Drum (V-2201) and the flare stack, is a vertical vessel that has an outer diameter of6 feet, 4 inches and a height, from seam to seam, of 15 feet, 5 inches. The MAWP is 50 psig and the MAWT is 550°F. Stripped sour water or utility makeup water flows through XV-3316 and is used to maintain the seal. On a frequent basis, XV-3316 opens to purge the entire volume ofwater

Sage EnvironmentalConsulting, L.P. November2012 2-11 HuntRefiningCompany Flare ManagementPlanwithin the water seal. The overflow flows over an internal weir and is pumped to the sour water treatment area by the Hydrobon Area flare KO Drum pumps P-330IA/S. The liquid level is monitored by Ll 3320, which provides a read-out in the DCS ofthe percent ofthe range ofthe level indicator. The pumps are automatically activated when the liquid level triggers low-low, low, high, and high-high alarms. 2.7 Assist System Assist gas is added to the flare tip to encourage additional flame zone turbulence, improved air entrainment, and thus, improved combustion efficiency and the reduction of smoke formation. Care is taken to ensure the combustible mixture ofthe combined gases is not diluted by excess use ofassist gas. The Hydrocracker Area flare is a steam assisted flare. Ring steam is supplied through a single 6" steam supply pipe, radially using an upper, 54" diameter external steam ring with 32 star-shaped steam diffusers outside ofthe flare stack circumference. The center steam injection includes a single internal steam injection nozzle using a 2" supply pipe centered inside the stackjustabove the density seal. Each ofthetwo steam supply lines provide steam at 230 psig and can be controlled independently. Steam is delivered to the flare tip by means ofan 8 inch control valve (FV-9024). The tip steam flow is monitored by a flow transmitter (FT-9024) and viewed in the Hydrocracker complex control room. Steam supply to the tip is automatically adjusted by a control valve (FIC-9024). The steam is not staged ortiered. The maximum tip steam flow rate is 82,500 lb/hr. Steam adjustments to the tip are made based upon a programmed DCS logic, which adds 250 lbs ofsteam per I,000 lbs ofvent gas for an effective steam-to-vent gas (SNG)ratio of0.25 for the tip steam. Arestriction orifice with a 3/8" bore provides a nominal steam flow rate of 1,000 lb/hr to the tip. Center steam is delivered to the flare stackjust above the density seal by means ofa 1.5 inch control valve (FV-9023), which is delivered via 2 inch piping. The center steam flow is monitored by a flow transmitter (FT-9023) and viewed in the Hydrocracker complex control room. The center steam supply is automatically adjusted by a control valve (FIC-9023). The maximum center steam flow rate is 3,000 lb/hr. The center steam adjustments are made based upon a programmed DCS logic, which adds 3 lbs ofsteam per I,000 lbs ofvent gas for an effective SNGratio of0.003 for the center steam. There is also a manually operated globe valve that bypasses the FV-9023 to ensurethat a nominal flow ofI,500 lb/hr is delivered to the stack as center steam. Per design, the minimum continuous steam flow rate is 825 lb/hr. The Coker Area flare is a steam assisted flare. Steam is supplied radially using an upper, 30" diameter external steam ring with 18 star-shaped steam diffusers outside ofthe flare stack circumference. Steam is delivered to the flare tip by means ofa control valve (HIC-3314), which is delivered at the tip via 4 inch piping. The steam is not staged or tiered. The maximum steam flow rate is 34,850 lb/hr. The only indication of steam flow rate is the percent open ofH!C-3314, which is viewed in the Coker complex control room. The steam is remotely controlled by the operators based upon a visual observation ofthe flare via a closed-circuit television (CCTV) in the control room. Ifsmoke is observed during a flaring event via the video monitoring, the operators will increase steam flow rate to the tip to

Sage Environmental Consulting, L.P. November2012 2-12 Hunt Refining Company Flare ManagementPlanfacilitate smokeless flaring. The minimum steam requirement for continuous cooling and protection ofthe tip is 550 lb/hr. The Hydrobon Area flare tip is a steam assisted flare. Ring steam is supplied through a single 4" steam supply pipe, radially using an upper, 26" external steam ring with 27 starshaped steam diffusers outside ofthe flare stack circumference. The lower steam injection, also calledjet steam, includes five internal steam injection nozzles using a 4" supply pipe centered inside the stack andjust above the molecular seal. Each ofthe two steam supply lines can be controlled independently and delivers the steam at 230 psig. The minimum steam requirement for continuous cooling and protection ofthe tip is 540 lb/hr. Steam is delivered to the flare tip by means ofa 3 inch control valve (HIC-3305). The steam is not staged or tiered. The maximum tip steam flow rate is 25,560 lb/hr. The only indication of tip steam flow rate is the percent open of HIC-3305, which is viewed in the Hydrobon complex control room. The steam is remotely controlled by the operators based upon 

### a visual observation ofthe flare via a CCTV in the control room. Ifsmoke is observed during a flaring event via the video monitoring, the operators will increase steam flow rate to the tip to facilitate smokeless flaring. There is a 2 inch manual bypass valve to the control valve, which is used during maintenance ofHIC-3305. There is also a % inch restriction orifice (R0-3303) that bypasses HIC-3305 to ensure that a nominal flow of I,135 lb/hr is delivered to the flare tip. Steam is delivered to the center ofthe flare stack by means ofa control valve (HIC-3304). The steam is not staged or tiered. The maximum lower steam flow rate is 13,500 lb/hr. The only indication ofcenter steam flow rate is the percent open ofHIC-3304, which is viewed in the Hydrobon complex control room. The steam is remotely controlled by operators based upon the flame characteristics. There is a 2 inch manual bypass valve to the control valve, which is used during maintenance ofHIC-3304. There is also a % inch restriction orifice (R0-3302) that bypasses HIC-3304 to ensure that a nominal flow of I,210 lb/hr is delivered to the center ofthe flare. The minimum steam requirement for continuous cooling and protection ofthe tip is 540 lb/hr. 

### 2.8 Pilot Gas Pilot gas is introduced through the pilot tip ofa flare in order to provide a flame to reliably ignite the flare. Ifthe pilot is unreliable, the potential for unburned hydrocarbons and/or toxic gases releasing to the atmosphere increases drastically and may result in an undesirable health affects, vapor-cloud explosion, and/or odor problems. Since the flare must be removed from service to maintain or replace the pilot, pilot systems are designed to operate for extended periods without requiring maintenance. The Hydrocracker Area flare has three natural gas fueled pilot lights, paired with redundant thermocouples (TE-9034A/B- 9036A/B). The pilot lights are spaced at 120 degree intervals around the flare tip. The pilot gas flow rate is adjusted by a 2-inch Pilot Gas self-contained regulator (PCV-9021) up to a maximum flow rate of250 scf/hr. The minimum requirement for each pilot is 85,000 Btu/hi', which is equivalent to approximately 250 scf/hr for all three pilots combined. There is also a 2 inch bypass valve to PCV-9021 that provides the nominal flow to the pilot during regulator maintenance. The pilot gas flow rate is maintained at all times and spread evenly to all three pilots.

Sage Environmental Consulting, L.P. November 2012 2-13 HuntRefining Company Flare ManagementPlanThe Coker Area flare has three pilot lights, whose presence is detected by a stationary IR camera that is mounted in the line ofsight with the pilots. The pilot lights are spaced at 120 degree intervals around the flare tip. The pilot gas flow rate can be adjusted by a l-inch control valve (PCV-33I2) up to a maximum flow rate of 356 scf/hr. The minimum requirement for each pilot is 356 scf/hr, which is equivalent to I ,068 scf/hr for all three pilots combined. The pilot gas flow rate is maintained by the regulator pressure setting and pilot orifice bore size (7/64"). The flow rate is spread evenly to all three pilots. The Hydrobon Area flare has three pilot lights, whose presence is detected by a stationary IR camera that is mounted in the line ofsight with the pilots. The pilot lights are spaced at I20 degree intervals around the flare tip. The pilot gas flow rate can be adjusted by a I-inch regulator (PCV-3309) up to a maximum flow rate of 135 scf/hr. The minimum requirement for each pilot is 135 scf/hr, which is equivalent to 405 scf/hr for all three pilots combined. The pilot gas flow rate is maintained by the regulator pressure setting and the pilot orifice bore size (7/64"). The flow rate is spread evenly to all three pilots. The pilot lights at all three flares are fueled by purchased natural gas. The rule explicitly allows all pilot gas lines to be exempted from sulfur content monitoring that is required for all other gas lines to demonstrate compliance with the <162 ppmv H2S limit. Therefore, an analysis ofthe H2 Sconcentration in the pilot gas is not required. 

### 2.9 Ignition System Pilot ignition is a critical concern because without a flame, there will be no flare gas combustion and a pilot light is required to ensurethat a flame remains always present. The ignition equipment functions to reliably light the pilot. The type ofignition used at the Tuscaloosarefinery is the following:
• The compressed-air flame-front generator ignition system is the most widely-used flare ignition system. Compressed air and fuel are introduced into a mixing chamber at grade through orifices. Piping connects a sparking device located downstream ofthe mixing chamber with the pilot tip. A flame front that ignites the pilot is sent through the piping when the flare gas stream is ignited by the sparking device. The primary advantage of the compressed-air flame-front generator is that both the sparking device and flow controls are located at ground level and can be maintained and repaired without removing the flare from service. However, the primary disadvantage ofthis ignition system is with its propensity for moisture formation in the piping leading to the pilot, which, ifcorrosive, may potentially render the ignition system useless. Therefore, it is necessary to flush each ignition line afteruse to reduce the moisture problem.
The Hydrocracker Area ignition system consists of three pilot lights, all of which are continuous. All three pilots have an automated high energy ignition (HE!) system with a manual flame front generator (FFG) system as backup. Ignition gas is supplied through the Pilot Gas Pressure Control Valve (PCV-9021) when the HE! system is used. However, when

Sage EnvironmentalConsulting, L.P. November2012 2-14 HuntRefiningCompany Flare Management Planthe FFG system is used, ignition gas is supplied through a l-inch control valve, PCV-9017. When the HE! system is activated, it operates on a five-minute cycle and automatically stops the ignition sequence when the pilot flame is detected. When the FFG system is used, an operator standing at the ignition panel within proximity to the base ofthe flare manually closes the gas valve once the pilot flame has been detected. During ignition, 150,000 Btu/hr per pilot, or approximately 150 scf/hr ofpilot fuel gas per pilot is required to ensure that ignition occurs. Once the pilots are lit, the pilot fuel gas is reduced to the nominal flow rate of 85 scf/hr per pilot. The Tuscaloosa refinery created a procedure for flare pilot ignition titled South ComplexFlare LightingProcedure. The Coker Area ignition system consists ofthree pilots, all ofwhich are continuous. All three pilots have a manual electronic spark ignition system. Ignition gas is supplied through a 2 inch control valve, PCV-3310. An operator standing at the ignition panel with proximity to the base ofthe flare manually closes the gas valve once the pilot flame has been detected. The Tuscaloosa refinery created a procedure for flare pilot ignition titled Coker Flare LightingProcedure. The Hydrobon Area ignition system consists ofthree pilots, all ofwhich are continuous. All three pilots have a manual electronic spark ignition system. Ignition gas is supplied through a %-inch control valve (PCV-3307) and/or a l-inch control valve (PCV-3308). An operator standing at the ignition panel with proximity to the base ofthe flare manually closes the gas valve once the pilot flame has been detected. The Tuscaloosa refinery created a procedure for flare pilot ignition titled Hydrobon Utilities Flare Operations-- Procedurefor Relighting of the Flare. 2.10 Purge Gas According to the definitions promulgated in SubpartJa, purge gas is "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)". All flare systems have the propensity for flashback, in-line detonation, and potential explosion in the flare stack ifoxygen enters through the flare burner and travels down the flare stack. A continuous purge is therefore necessary to prevent atmospheric oxygen from entering down through the flare burners. The purge is an injected gas designed to provide a minimum continuous momentum flux upward thru the flare tip ensuring no reversal offlow and so that no intrusion ofairthat could create an ignitable mixture. Because all three flares have water seals, purge gas is distinctly different from sweep gas at the Tuscaloosa refinery. Purge gas is injected downstream ofeach water seal primarily to condition the molecular seal and to assist in the backflow prevention. Sweep gas is injected upstream ofeach water seal into the flare header to reduce the likelihood ofstratification of gases in the header See Section 2.11 for further information on sweep gas.

Sage Environmental Consulting, L.P. November2012 2-15 Hunt Refining Company Flare ManagementPlanFor the Hydrocracker Area flare, refinery fuel gas is used for the purge gas to condition the Callidus density seal, model BTZ-DS-54. Callidus recommends a minimum continual purge flow rate of562 scf/hr. This purge gas is injected directly into the Hydrocracker Area flare KO Drum, V-325!, downstream ofthe water seal, via a 2 inch line. Recall that this is 

### a combination vessel incorporating both the water seal and the KO requirements. The purge gas flow rate is regulated by an RO with a design flow of833 scf/hr. The valve is normally open, providing a continuous purge to the density seal and to the flare. Because ofits point ofintroduction into the flare header, this purge gas is incorporated into the combined flare gas being monitored to comply with the <162 ppmv H2S limit. Forthe Coker Area flare, a mixture ofrefinery fuel gas and/or natural gas can be used for the purge gas to condition the molecular seal. The recommended minimum continual purge flow rate for the molecular seal is 917 scf/hr. This purge gas is injected directly into the water seal vessel, D-1100, downstream ofthe water barrier, via a 2 inch line. the flow is regulated with an orifice plate with a I

### ;gth inch bore. Because ofits point ofintroduction into the flare header, this purge gas is incorporated into the combined flare gas being monitored to comply with the <162 ppmv H 2S limit. For the Hydrobon Area flare, refinery fuel gas is used for the purge gas to condition the molecular seal. The recommended minimum continual purge flow rate for the molecular seal is 900 scf/hr. This purge gas is injected downstream ofthe water seal, V-!00, via a %-inch line. This flow is regulated by R0-3315, providing a continuous purge to the velocity seal and to the flare. There is also a bypass valve to R0-3315, which is normally closed. Because ofits point ofintroduction into the flare header, this purge gas is incorporated into the combined flare gas being monitored to comply with the <162 ppmv H2S limit. 2.11 Sweep Gas Sweep gas is defined as "Gas introduced in a flare gas header system to maintain a constant flow ofgas to prevent oxygen buildup in the flare header. For flares with no water seals, sweep gas also performs the function ofpreventing oxygen infiltration (backflow) into the flare tip". Because all three flares have water seals, purge gas is distinctly different from sweep gas at the Tuscaloosarefinery. Purge gas is injected downstream ofeach water seal primarily to condition the molecular seal and to assist in the backflowprevention. With the FGRU and the seal backpressure, sweep gas is injected upstream ofeach water seal into the flare headers and subheaders to provide a constant "flushing" and prevent stagnation ofvapors and localized corrosion. See Section 2.10 for further information on purge gas. There are ten sweep gas injection points in the Hydrocracker Area flare subheader. The following list identifies each injection point Tag ID and its associated minimum flow rate in parentheses:
• HP2-F0-67 (2,917 scf/hr),
• HP2-F0-53 (667 scf/hr),

Sage Environmental Consulting, L.P. November2012 2-16 HuntRefining Company Flare ManagementPlan• HP2-F0-209 (2,417 scf/hr),
• HC-FUEL-3 (833 scf/hr),

· • HC-2031 (833 scf/hr),

• CR-F0-406 (1,875 scf/hr),
• CR-F0-262 (917 scf/hr),
• CR-F0-168 (3,875 scf/hr),
• HC-FUEL-4 (I,667 scf/hr), and
• DMS-R0-482 (740 scf/hr). The sum ofall the individual sweep gas flow rates is 16,740 scf/hr, which is, operationally, the minimum sweep gas flow rate. There are eleven potential sweep gas injection points in the Coker Area flare subheader. Each ofthe sweep gas injection points is maintained at a flow rate of667 scf/hr for a total flow rate of7,333 scf/hr, which is, operationally, the minimum sweep gas flow rate. There are five sweep gas injection points in the Hydrobon Area flare subheader. The following list identifies each injection point and its associated minimum flow rate in parentheses:
• SCOT Unit flare subheader(917 scf/hrofnatural gas),
• Flare headerabovethe reactivator reflux pumps (740 scf/hr),
• North end ofthe compressor building (740 scf/hr),
• South end ofthe compressorbuilding (740 scf/hr),
• TGTU flare subheader (917 scf/hrofnatural gas), The sum ofall the individual sweep gas flow rates is 4,054 scf/hr, which is, operationally, the minimum sweep gas flow rate. All sweep gas in all three flare subheaders consists ofrefinery fuel gas, with the exception of the SCOT Unit flare subheader and the TGTU flare subheader that consist ofnatural gas. Because the refinery fuel gas, by definition, is not inherently low in sulfur, sulfur content analysis ofthe sweep gas must be conducted to demonstrate compliance with the <162 ppmv H2S limit. The natural gas sweeps meet the definition ofinherently low in sulfur and do not require monitoring. The rule explicitly allows the analysis ofa common source offuel gas, provided that the monitoring location accurately represents the concentration ofH2S that is being combusted. Therefore, because the sulfur analysis that is conducted for the refinery fuel gas is representative ofall refinery fuel gas, regardless ofits use, a separate analysis of the sweep gas is not necessary. In total, the three flare subheaders utilize a combined sweep gas ofapproximately 28,127 seth or 469 scfm. The total flare gas recovery compressor capacity is a combined 2,082 scfm. As such, sweepsrepresentapproximately 23%ofthe FGRU capacity.

Sage EnvironmentalConsulting, L.P. November2012 2-17 HuntRefiningCompany Flare ManagementPian2.12 Supplemental Gas Supplemental gas is gas that is introduced to the flare in orderto comply with the net heating value requirements of40 CFR §60. I8(b) and/or 40 CFR 63.ll(b). Supplemental gas is used as a calorific boost to the vented gas to ensure adequate combustion. When combustible gases are used for sweep gas orpurge gas, it simultaneously functions as supplemental gas. There is no dedicated mechanism to control the flow of supplemental gas to the HydrocrackerArea flare to explicitly increase the net heating value (NHV) in the combustion zone at the flare tip. However, since natural gas and refinery fuel gas are utilized for the purge gas, they simultaneously function as supplemental gas. The only time that supplemental gas, referred to as "lift gas" at the Tuscaloosa refinery, is added to the Coker Area flare subheader is when the non-continuous acid gas line from the Hydrobon Area Units flows to the flare. The lift gas, which consists ofrefinery fuel gas, is automatically injectedjust downstream ofthe Coker Area Flare Water Seal (D-1 100). The lift gas is regulated with a control valve and adds lift gas at a rate ofone volume oflift gas perevery two volumes ofacid gas. The maximum flow rate ofthe lift gas is 900 Mscf/day, which is understood to be the maximum flow rate ofsupplemental gas. As a backup case, lift gas can also be added to the Hydrobon Area flare should pre-planned maintenance needs arise. However, the valve is car-sealed closed (CSC) and must be manually opened. The lift gas is injected into the KO drum (08.330I), which is downstream ofthe Hydrobon Area Flare Water Seal (V-100). The valve is only opened when the acid gas that is usually discharged to the Coker Area flare is either re-routed or overflows to the Hydrobon Area flare. The lift gas is added at a ratio of one volume of lift gas per two volumes ofacid gas. This operating scenario occurs very infrequently, as the acid gas is now primarily directed towards the CokerAreaflare. Because ofits point ofintroduction, this supplemental gas is incorporated into the combined flare gas being monitored to comply with the <162 ppmv H2S limit. 2.13 Monitoring Instrumentation NSPS Ja identifies a monitoring scheme to demonstrate compliance with the rule. NSPS Ja also provides an alternative monitoring scheme for certain flares equipped with water seals; however, the Tuscaloosa flares do not meet the criteria required to utilize the alternative monitoring. 2.13.1 VentGas Flow NSPS Ja requires the Tuscaloosa refinery to operate a flow meter that provides a representative measurement ofthe total flow rate discharged to each flare. The flow rate data that is collected will be used to determine ifflaring events occurthat exceed the Root Cause Analysis (RCA) threshold of500,000 scfin a 24-hour period above the established baseline. The following standards for the flow meter are required pursuantto the rule:
• Must be located in a position that is representative ofthe total gas flow rate,

Sage Environmental Consulting, L.P. November 2012 2-18 HuntRefining Company Flare ManagementPlan• 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, Each ofthe three flares uses an ultra GE Panametrics GF868 Flare Gas Flow Meter System with single path T5 Ultrasonic Flow Transducers to continuously measure the flow rate to each flare. The GF868 is manufactured according to the specifications in the rule, and the Tuscaloosa refinery has ensured that each flow meter is installed in a representative location, thereby complying with the selection and installation ofthe flow meters. The following table summarizes the specifications ofthe GF868.
Table 2-2. Flow Meter Specifications Item Monitor Specification Make General Electric Model DigitalFlowTM GF868 Type Panametrics Ultrasonic Flare Gas Mass FlowMeter Range 0.1 fps to 275 fps Precision ±1%at 0.5 fps to 100 fps Accuracy ±2%to 5% ofreading at 1fps to 275 fps
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 document maintained by Hunt. For the Hydrocracker Area flare, the flow meter (FT-9006, DCS tag # Fl-9006) is located downstream of flare KO Drum, V-3251, which also contains the water seal. The meter configuration is a single-channel bias-90 setup with temperature and pressure corrected readings. The pressure sensor that is configured with FT-9006 is PT-9005 (DCS tag # Pl9005). The temperature sensor that is configured with FT-9006 is n·-9007 (DCS tag# Tl9007). The pressure and temperature readings are used to automatically correct the raw flow meter reading to standard condition flow rates and are reported to the DCS. Because this meter is downstream ofthe water seal and downstream ofall flow injections which bypass the water seal, the flow that is measured is the total actual flow to the flare. The total flow includes continuous flows, such as the purge gas from the medium pressure line, and noncontinuous flows that occur when the pressure in the header exceeds the pressure threshold created by the water seal. Baseline flow evaluation is discussed in Section 3.3. For the Coker Area flare, the flow meter (FT-85100A, DCS tag# FI-85IOOA) is located downstream ofthe Coker Area flare KO Drum, V-220I, which is downstream ofthe Coker Area flare water seal, D-1100. The meterconfiguration is a single-channel bias-90 setup with

Sage EnvironmentalConsulting, L.P. November2012 2-19 HuntRefiningCompany Flare ManagementPlantemperature and pressure corrected readings. The pressure sensorthat is configured with FT85100A is PT-85101 (DCS tag# PI-85101). The temperature sensor that is configured with FT-85100A is TT-85101 (DCS tag# TI-85101). The pressure and temperature readings are used to automatically correctthe raw flow meter reading to standard condition flow rates and are reported to the DCS. Because this meter is downstream of the water seal and downstream ofall flow injections which bypass the water seal, the flow that is measured is the total actual flow to the flare, which includes continuous flows, such as the purge gas and non-continuous flows that occur when the pressure in the header exceeds the pressure threshold created by the water seal and when the acid gas line is directed to the flare. Baseline flow evaluation is discussed in Section 3.3. For the Hydrobon Area flare, the flow meter (FT-3311, DCS tag # FI-3311) is located downstream ofthe Hydrobon Area water seal, V-110. The meter configuration is a singlechannel bias-90 setup with temperature and pressure corrected readings. The pressure sensor that is configured with FT-3311 is PT-3312 (DCS tag# PI-3312). The temperature sensor that is configured with FT-3311 is TT-3313 (DCS tag # TI-3313). The pressure and temperature readings are automatically incorporated into the raw flow meter reading to instantaneously provide the actual flow meter reading to the DCS. Because this meter is downstream of the water seal and there are no downstream of all flow injections which bypass the water seal, the flow that is measured is the total actual flow to the flare, which includes continuous flows, such as the purge gas and non-continuous flows that occur when the pressure in the header exceeds the pressure threshold created by the water seal. Baseline flow evaluation is discussed in Section 3.3. 

### 2.13.2 Sulfur Content NSPS Ja requires the Tuscaloosa refinery to operate a monitor to measure the sulfur content ofthe gases combusted in each flare. The rule allows the Tuscaloosa refinery to select one of two options that involve direct analysis ofthe gas that is directed to the flare in order to comply with the sulfurmonitoring requirements:
• Total Reduced Sulfur (TRS) monitoring, or • H2SMonitoring. The Tuscaloosa refinery has selected compliance with TRS monitoring in accordance with 60.107a(a)(2) and 60.107a(e)(l). When the TRS analysis method is selected, the rule allows the TRS analyzer measurement oftotal reduced sulfur to substitute for the measurement of H2S. Therefore, by substitution, the TRS concentration in flare gas at each ofthe flares is limited to 162 ppmv on a 3-hour rolling period. The data that is collected will be used to document compliance with the <162 ppmv TRS concentration for any flared gases and to determine when flaring events occur that exceed the Root Cause Analysis (RCA) threshold of500 lb S02emissions in a 24-hourperiod. All three flares use an identical Rosemount Analytical Model 500 Gas Chromatograph, manufactured by Emerson Process Management, to measure TRS in the flare gas. The following table summarizes the specifications ofthe GC Model 500.

Sage Environmental Consulting, LP. November2012 2-20 HuntRefiningCompany Flare ManagementPlanTable2-3. TRS Monitor Specifications Item Monitor Specification Make RosemountAnalytical Model 500 Type Gas Chromatograph 

### Hydrocracker COS: 0-0.5% CS2: 0-0.5%

H2S: 0-5% 

### Hydrobon Range COS: 0-2% CS2: 0-2% H2S: 0-100% 

### Coker COS: 0-0.5% CS2: 0-0.5% H2S: 0-50% Details regarding the specifications ofthe GC, including the precision, accuracy, calibration, maintenance procedures, and quality assurance procedures are contained in the GC QA document maintained by Hunt. The sulfur monitors are located downstream oftheir respective water seals; therefore, the monitors are ableto sample all the gases sent to the flare.

Sage EnvironmentalConsulting, L.P. November2012 2-21 Hunt RefiningCompany Flare ManagementPian

## SECTION 3 FLARE MINIMIZATION

3.1 Description ofContributions to Flare Header As detailed in Section 2.3, the flare header system consists of three distinct and separate subheaders that are connected by common piping to form a single conjoined flare header network. Each subheader receives contributions from a complex of process units and is equipped with its own flare capable of controlling the gases produced by its associated complex. There is also a common flare gas recovery system that is installed on the interconnected flare header system. Each flare is equipped with its own water seal so that gases that are discharged to any of the three subheaders upstream of the water seal are preferentially routed to the flare gas recovery system to be utilized as fuel gas throughout the refinery. The three subheaders with their associated process units and flares are as follows:
• The HydrocrackerArea,
• The CokerArea, and
• The Hydrobon Area. The contributions to each ofthese subheaders include sweep gas that is injected upstream of the water seal and purge gas that is injected downstream ofthe water seal. See Sections 2.10 and 2.11 for further information on purge gas and sweep gas, respectively. An in-depth discussion on these contributions is provided in Section 2.3.

Three process streams are not suitable for recovery by the FGRU. These contributions are continuous sweet process gas that is high in hydrogen, non-continuous acid gas fi·om the Hydrobon Area, and emergency releases from the FGRU mix gas fuel drum. These flows are addressed in Section 3.2. 3.2 Minimization Assessment According to the rule, the Tuscaloosa refinery must conduct an assessment of whether discharges to the flares from process units, from associated equipment, and from the fuel gas system can be minimized. The assessment must include the following items:
• Elimination ofprocess gas discharge to the flare through process operating changes or gas recovery atthe source;
• Reduction ofthe volume ofprocess gas to the flare through process operating changes;
• Installation ofa flare gas recovery system*; and,

Sage Environmental Consulting, L.P. November2012 3-1 HuntRefiningCompany Flare Management Plan• Minimization ofsweep and purge gas flow rates, ifapplicable. 

## *Ifa facility is fuel rich, a flare gas recovery system and a co-generation unit or combined heat and power unit would also need to be considered. This situation is not reflected at Tuscaloosa. For each ofthe items above, the minimization assessment must provide rationale in terms of the following considerations:
• Costs, including capital and annual operating;
• Natural gas offset credits, ifapplicable;
• Technical feasibility;
• Secondary environmental impacts , and,
• Safety considerations. If a reduction in flow cannot be achieved, a statement must be made justifying why the minimization could not occur. Three process streams are not suitable for recovery by the FGRU. These contributions are sweetprocess gas that is high in hydrogen, acid gas from the Hydrobon Area, and emergency releases from the FGRU mix gas fuel drum. Sweet Process Gas that is High in Hydrogen: This stream is injected into the flare header downstream of the Hydrocracker Area flare water seal (V-3251) and is flared at the Hydrocracker Area flare. The Tuscaloosa refinery purposefully excludes these gases from fuel gas recovery. Combusting a higher concentration of H2-rich fuel in the combustion devices would require a significant technical effmt to retro-fit the burners and heaters to accommodate the hydrogen-rich fuel. Therefore, the refinery designed this medium pressure line to bypass the recovery system in order to allow for the proper operation ofthe recovety compressors and the exclusion of hydrogen fuel in the combustion devices. This also is integral in the safety ofoperability in the No. 2 Hydrogen Plant Compression Section, where hydrogen is compressed from 230 lbs to 2,300 lbs. This is pressure controlled to the Hydrocracker Area Flare medium pressure line. Therefore, the sweet process gas that is normally and routinely high in hydrogen cannot be directly minimized by utilization ofthe existing flare gas recovery system. Acid gas from the Hydrobon Area: Acid gas from the Hydrobon Area units is generated infrequently and caused by a high pressure condition in the acid gasheader. When this gas is present, its volume is much greaterthan the capacity ofthe SulfurPlants Recovery ofthis gas would cause a closed loop and overwhelm the amine system. If the amine system was overwhelmed and shutdown, further recovery by the recovety compressors would not be possible, which would result in a larger amount ofpotentially recoverable gases to be flared. Therefore, routing this gas to the recovery compressors would only result in the failure ofthe amine unit, which would effectively remove the fuel gas recovery system from operation until the amine unit was restarted. Therefore, this gas stream is connected to the flare header

Sage Environmental Consulting, L.P. November2012 3-2 HuntRefining Company Flare ManagementPlandownstream of the Coker Area water seal to bypass the recovery system compressors. Therefore, the acid gas from the Hydrobon Area cannot be minimized. Emergency Releases from the FGRU Mixed Gas Fuel Drum: The FGRU mixed gas vessel is equipped with a PRY that will release material to the Coker Area flare when the pressure in the vessel exceeds 150 psig. The primary cause for a discharge from the PRY is from a blockage or inadvertent closure ofa valve in the line in the recovered gas line to the amine scrubber or startup ofthe FGRU with a valve blocked in the discharge. It is not possible to connect the PRY back to the flare header for potential re-recovery. Installing a connection ofthis type would create a closed loop and "dead head" the compressor, which creates an unsafe operation. The PRY functions as a safety release device and releasing this flow back into a process would cause an overpressure situation for the FGRU and potential for the flare system. To date, this PRY has no known releases. Therefore, emergency releases from the FGRU mixed gas fuel drum cannot be minimized. 3.3 Baseline Flow Evaluation The rule specifies that a baseline flow evaluation must be conducted after the minimization assessment has been completed. Upon the completion of a minimization assessment, a baseline flow to the flare can be established based upon the results of the minimization assessment. The determination ofthe baseline flow does not include pilot gas or purge gas, provided that these flow rates remain relatively constant. See Sections 2.8 and 2.10 for further information on pilot gas and purge gas, respectively. The numeric value of the baseline flow is the sum ofall flows that the minimization assessment determined could not be further minimized. See Section 3.2 for futther information on the Minimization Assessment. Alternative baseline flow rates can be established for different operating conditions provided that the following information is included with the development ofseparate baseline flow rates:
• Identification ofa primary baseline thatwill be used as the default baseline;
• Description ofeach operating condition for which a separate baseline is established; and
• Procedures to minimize discharges to the flare during each operating condition for which a separate baseline is established.

The HydrocrackerArea flare data was analyzed and was determined to consistprimarily ofa constant low level offlaring with infrequent short durations ofhigh flow. As the HydrocrackerArea flare receives the gas streams that have a high concentration ofhydrogen thatbypass the water seal, the HydrocrackerArea flare is anticipated to receive regular flows. The data indicates thatthe spikes ofhigh flow are representative ofthe closure ofFlare Isolation Valve XV-1132.

Sage EnvironmentalConsulting, L.P. November 2012 3-3 HuntRefiningCompany Flare ManagementPlcmBecause routine flaring ofprocess gas does not occurat the CokerArea flare and the Hydrobon Area flare, the baseline flow at each ofthese flares is equivalent to the flow ofthe purge gas at each flare. Forflares thatdo not have fuel gas recovery, the sweep gas would be subtracted from the total baseline flow. However, as the Hunt interconnected flare system is equipped with a FGRU, the sweep gas would not be included in the flow data, unless a flaring eventwere occurring. Therefore, when determining the baseline for the interconnected flare system, the sweep gas will not be subtracted. As discussed in Section 1.2, the definition ofa flare includes "In the case ofan interconnected flare gas header system, the flare includes each individual flare serviced by the interconnected flare gas header system." When determining the threshold for performing an RCA as identified in 60.103a(c)(l), for a flare an RCA must be performed for any discharge in excess of500,000 scf/day above the baseline. Therefore, when determining when a RCA needs to be performed, the flow rates fi·om each ofthe interconnected system need to be combined. Similarly, when determining a baseline forthe flare, the baseline analysis for each ofthe interconnected flares needs to be combined. Based on the analysis performed, the baseline for individual flares was determined to be as follows:
• The CokerArea flare- 22,000 scf/day
• The Hydrobon Area flare- 22,000 scf/day
• The Hydrocracker Area flare- 2,000,000 scf/day Therefore, the baseline for the interconnected flare system was determined to total 2.04 mmscf/day. Please note that this baseline includes the presence and on-going operation ofan existing FGRU operating with two compressors at an optimal 3 million scf/day recovery rate. As required 

### by 60.103a(a)(2)- "The minimization assessment must provide clearrationale in terms ofcosts (capital and annual operating), natural gas offset credits (ifapplicable), technical feasibility, secondary environmental impacts and safety considerations for the selected minimization alternative(s) or a statement, withjustifications,that flow reduction could notbe achieved." As discussed in this minimization assessment, the acid gas from the Hydrobon Area cannot be minimized. Further, the high hydrogen content streams cannotcurrently be directed to the refinery fuel gas system for utilization. Hunt has total compressorrecovery capacity ofapproximately 2082 scfm (maximum ofboth FGRU compressors operatingconcurrently). At present, typical recovery rates are approximately 1,200 scfm, representing 58% ofavailable routine capacity. Huntbelieves that additional compressorcapacity is not warranted atthis time.

Sage EnvironmentalConsulting, L.P. November2012 3-4 Hunt RefiningCompany Flare ManagementPian3.4 Startup and Shutdown Itis Hunt Refining's operatingphilosophy to operate the processes to minimize flaring. Flaring represents lost raw materials and lost profits, which correlates to lost revenue. Therefore, Hunt has imbedded this philosophy in the operating procedures ofthe units. Startup and shutdown procedures will present operators with alternatives that have differing flaring repercussions and will indicate which alternative has the largest potential to cause flaring. However, while strivingto limit flaring during stattup and shutdown, the operators must always considerthe safe operation ofthe unit, so the potential exists for additional flaring events during startup and shutdown. 3.5 Fuel Gas Imbalance The procedure for the operation ofthe fuel mix system was reviewed to determine the steps taken to prevent flaring due to fuel gas imbalances. The fuel mix system provides a controlled supply offuel gas to the process areas ofthe refinery. The fuel gas makeup is a combination ofgas produced in refinery operations and purchased natural gas, makeup from two outside suppliers. These sources flow into a vertical mix drum, HRC-057, and a horizontal mix drum, D-l001. The fuel gas system pressure is regulated with a pressure control system that includes controllers thatregulate the purchased makeup gas as well as controllers that vents excess gas to the Crude Unit and Coker Area Flares. Overall, the refinery must purchase additional make-up natural gas. Low Pressure Fuel Gas System: There aretwo outside suppliers ofnatural gas and each can be operated on flow and/or pressure control. A secondary overpressure controller vents excess fuel gas directly to the CokerArea Flare in the event ofa refinery imbalance in production/consumption. This same controller operates the liftgas and is metered going to the CokerArea Flare. Flows from the process streams can be routed to either drum and the gas can be routed to the refinery from either dmm. One supplier's flow is controlled by FlC851 and is regulated on flow control. The othersupplier's flow is controlled by FIC-852 and is regulated on flow control. The Crude UnitDCS Operatorcan also regulate the Fuel Mix Drum pressure via PlC-2003A. FIC-852 and FIC-851 cannot both be on pressure control. One must be selected for flow control. The flow to prevent overpressure from the Fuel Mix System to the Crude Unit flare is controlled by PIC-2003B. The flow to the CokerArea flare is controlled by PIC-2003C. High Pressure Fuel Gas System: The natural gas flow from the primary supplier into the High Pressure Fuel Gas System is measured on FIC-850B. The natural gas flow from the secondary supplier is measured on FIC-10!. The makeup ofhigh pressure fuel gas can be operated on pressure control with the controllerfrom either supplier in automaticremote with a setpoint ofthe desired pressure. The pressure setpoint is selected by the CrudeUnitDCS Operator. Ifthe system pressure exceeds the set point, FV-2003C opens and the excess gas is vented to the Coker Area Flare. Normally, the set point on PIC-2003C is selected approximately 3 psig higherthan the setpointon PIC-2003A. Excess gas is also vented to the Crude Unit flare and is controlled by PIC-2003C. Normally PIC-2003B setpoint is set I

Sage EnvironmentalConsulting, L.P. November2012 3-5 Hunt RefiningCompany Flare ManagementPlanto 3psig higherthan PIC-2003C. This allows PIC-20038 to open when the pressure rises too quickly for PIC-2003C to stabilizethe fuel mix drum pressure. With the implementation ofthe Crude Unit FGRU, this gas will be recovered back into the fuel system unless the seal is lost on the Crude Unit FGRU which will allow the gas to be flared. Forthis reason, it is the last resort for pressure control. Typically, the fuel mix drum pressure is maintained at 60-65 psig by PIC-2003A, 8, and C. Typically, the set points on PIC-20038 and C are set 3to 6 psig higherthan PIC-2003A. If the range between the set points is too high, the pressure changes are likely to cause unstable heateroperations throughoutthe refinery. Ifthe setpoints are too low, gas may be wasted into the flares. Itis essential to keep the Fuel Gas System pressure within a constant and narrow pressure range to avoid problems with the processes. The fuel gas system is protected by a reliefvalve on the Fuel Gas header to the CokerArea flare header set to relieve at 80 psig. These procedures illustrate how Hunt Tuscaloosa works constantly to keep the fuel gas system in balance to avoid flaring. 

### 3.6 Fuel Gas Recovery Outage Huntoperates two fuel gas recovery compressors for the interconnected flare system. Currently, the loads experienced by the compressors are slightly higherthan the capacity ofa single compressor. In the event that one ofthe compressors were to shut down, a greater fraction ofthe capacity ofthe second compressorcould be utilized than is typically utilized during normal operations in orderto continue to capture the majority ofthe available gases; thereby, minimizing flaring during an outage ofone ofthe compressors. To minimize flaring that would occurifboth recovery compressors would experience a shutdown due to maintenance, Hunt schedules maintenance events ofthe compressors to coincide with major unit outages. Therefore, the amount ofgases beingproduced that would be available for recovery but are nowrequired to beflared, is minimized. Hunt has total compressorrecovery capacity ofapproximately 2082 scfm (maximum ofboth compressors operating concurrently). Atpresent, typical recovery rates are approximately l,200 scfm representing 58% ofavailableroutine capacity. Huntbelieves thatadditional compressorcapacity is notwarranted atthis time.

Sage EnvironmentalConsulting, L.P. November 2012 3-6 HuntRefiningCompany Flare ManagementPlan

## SECTION 4 ROOT 

## CAUSE ANALYSIS AND CORRECTIVE ACTION
This section provides a discussion on Root Cause Analysis (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. 4.1 Root CauseAnalysis 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 ofthe specified thresholds. The rule delineates three special circumstances that affect the number of RCAs that the Tuscaloosarefinery must perform following an RCA threshold exceedance:
• Ifa single discharge event lasts for two 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;
• Ifa discharge that triggers an RCA is the result ofa planned startup or shutdown during which the Planned Startup & Shutdown procedures referenced in Section 3.4 were followed, an RCA is not required; and
• Ifmultiple flares in a cascaded flare system each trigger an RCA in the same 24-hour period, only one RCA must be performed. Because each of these three flares is part of an interconnected flare header system, the rule specifies that the thresholds that trigger an RCA are not thresholds for the individual flares, but for all three flares combined. Therefore, the determination ofwhether an RCA threshold has been exceed must consider adata analysis from all three flares. The two thresholds which triggeran RCA are the following:
• Anytime the S02 emissions exceed 500 lb in any 24-hourperiod, or
• Any discharge to one or more flares in excess of 500,000 scf above an established baseline in a 24-hourperiod.

Sage Environmental Consulting, L.P. November20!2 4-1 HuntRefiningCompany Flare ManagementPlanA detailed discussion regarding each threshold is provided below. Hunt is currently required to perform RCAs for sulfur exceedances as required by their Consent Decree (CD). The RCA requirements ofthe CD meet the requirements ofNSPSJa. 

### 4.1.1 RCA- Flow Exceedance The specified flow threshold which triggers an RCA is the discharge to a flare ofgreater than 500,000 scfabove the established baseline flow in a 24-hour period to the flare. When performing a, RCA for a flow exceedance at Tuscaloosa, there are several key parameters that should be documented as part ofthe investigation:
• the connections that were contributingto the header,
• the duration ofthe flaring event,
• whatwas occurring in the process that lead to the flaring event, and, ifpossible,
• the sequence ofevents that lead to the flaring event. Once these items have been investigated and documented, a determination ofpotential actions that could have prevented the flaring event orreduced the volume or duration 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:
• Adescription ofthe discharge.
• Date and time of when the discharge was first identified and the duration of the discharge.
• The measured quantity ofgas discharged over the discharge duration. Ifthe 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 ofthe recommended corrective action(s) or an explanation ofwhy corrective action is not necessary.
• 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. For further information on the procedures to minimize flaring during planned startup and shutdown, see Section 3.4. 

### 4.1.2 RCA- 802

### Exceedance The specified sulfur content threshold which triggers an RCA is the emission from the flare of more than 500 lbs ofS02 in any 24-hourperiod. In contrast to the RCA flow threshold, there is no reference baseline upon which to compare S02 emissions. The S02 emissions are

Sage Environmental Consulting, L.P. November2012 4-2 Hunt RefiningCompany Flare ManagementP fandetermined by monitoring the TRS or H2S concentrations in the gases sent to the flare for combustion. Pilot gas is specifically exempted from sulfurmonitoring. When performing an RCA for an S02 exceedance at Tuscaloosa, there are several key parameters that should be documented as partofthe investigation:
• the connections that were contributingto the header,
• the duration ofthe flaring event,
• what was occurring in the process that lead to the flaring event, and, ifpossible,
• the sequence ofevents lead to the flaring event. Once these items have been investigated and documented, a determination ofpotential 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 of when the discharge was first identified and the duration of the discharge.
• The measured quantity ofgas discharged over the discharge duration. Ifthe discharge duration exceeds 24 hours, record the quantity for each 24-hourperiod.
• The measured total sulfur concentrations in the fuel gas at a representative location in the flare inlet.
• The cumulative quantity ofH2S and S02 released into the atmosphere. Assume a 99 % conversion ofTRSto S02.
• 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 ofthe recommended corrective action(s) or an explanation ofwhy corrective action is notnecessary. • 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. For further information on the procedures to minimize flaring during planned startup and shutdown, see Section 3.4. 

### 4.2 CorrectiveAction Analyses As defined in the rule, a Corrective Action is

Sage EnvironmentalConsulting, L.P. November 2012 4-3 Hunt RefiningCompany Flare ManagementP /an"the design, operation and maintenance changes that one takes consistent with good engineering practice to reduce oreliminate 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 of gases 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 ofdocumenting 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 ofthe recurrence ofthe causes ofthe flaring event that caused an exceedance of one or both ofthe 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 thatcould rectifY the cause(s) ofthe flaring event that was/were identified by the RCA. According to the rule, a Corrective action analysis is "adescription ofall 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 of cost 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. 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 ofthe discharge for which the RCA and corrective action analyses were required or as soon as practicable. Ifit is determined that a corrective action should not be implemented, the explanation ofthe basis ofthat decision must be recorded no later than 45 days following the discharge. Because the Corrective Action Analysis is a consequence ofthe RCA, it is imperative to commence the RCA as soon after the discharge as possible in order to allow for the maximum amount oftime to be allotted to the determination and implementation of the 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:
• Ifit 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 commencementand completion dates.

Sage EnvironmentalConsulting, L.P. November2012 4-4 HuntRefiningCompany Flare ManagementPlan• Ifthe discharge was a result ofa planned startup or shutdown ofarefinery 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. For fmther information on the procedures to minimize flaring during planned startup and shutdown, see Section 3.4.

Sage EnvironmentalConsulting, L.P. November2012 4-5 Hunt RefiningCompany Flare ManagementPlanSage Environmental Consulting, L.P. November 2012 

## APPENDIX A REQUIRED NOTIFICATIONS

HuntRefining Company Flare Management PlanSummary ofKey NSPSSubpartA and SubpartJa Deadlines
Anyflare builtorreconstructedafterJune 24,2008is new Flare Applicability Dates Anyflare modifiedafterJune 24, 2008is modified NSPS SubpartJa Rule Promulgation Date September 12, 2012

NSPS SubpartJa Rule Effective Date November 13 , 2012

Deadlines Citation Constructed afterJune 24, 2008 and before rule Date Submitted promulgation (September 12, 2012) Construction notification 60

.7(8)(1) Actual datewrthon 30daysafterconstructoon commenced

Startup notification 60.7(a)3 Actual dateof initial startupwithon 15 daysofstartup Agency notificationfor monitors 60

.108a(b) Submotted woth startup notificato on Monit or Perfonnancetest 60.7(a)(5, 6) 30days pnorto monotor performancetestong

notifica tion Performancetest 60.8(a) INithon 60 days after maxomum production rate but not later 60

.8(d) than 180days afteronitoal startup Performance test report 60.13c(2) 60daysaftercompletion ofmonotoring venficatoon Flare ManagementPlan 60.1038 (b)(1) November 13, 2012 RootCause Analysis program 60.108a (c)(6)(x) November 13,2012
Flowand TRS/H2S Monitoring 60.107a(e) November 13,2012 60

.107a(f) 162 ppmv H2S limit in flare gas 60.103a(f)

(reliefvalve leakage and 60. 103a(h) November 13,2012 emergencies are exempt) 60.107a(2)(vi)(A)Sage Environmental Consulting, L.P. November 2012 

## APPENDIX B PROCESS FLOW DIAGRAMS

HuntRefining Company Flare ManagementPlanllydrobonArea Hare L< <nd llydrobon**1\Ie ~** **Un.~s** CokcrArcoUn1tS NewComplc-.: SwcctG_,s

Ac1dGas**~leader** Cok er 1\rc:tFlare

NonnaH yOpen

Hunt Refining ·**Tusuloo~.A l**  HumRefining DAT E· November 2012 PROJECT NUMBER:4)5-1-15\ Flare DrawingColor Legend VentGas

Air Pilot Fuel Gasline(3x)

FIGURE 8·2.

SAGE E'NYin:OtU.t!ONT"hL.COtiCOULTtUC D10.3301 AL

DA

TE

: November 2012 PROJECT NUMBER:435·1
-15Flare DrawingColor Legend Pilot Fuel Gas Line (3x)

Ignition Gas (3x)IHEI)

FIGURE B-3. HydrocrackerArea Flare

. Hunt Refining · Tuscaloosa, AL Hunt SAGE DATE: November 2012
E:NVIOON M
. /'ITJ\1
.**CO ~lll.T** **IIl ()**  PR OJECT NUMBER: 435
-1 ·15**l:xccs:~!U..:I g~s**  1 5\\."ntedlhrough tho.:hR**~S**COM«liOnto lhc h¢eck'f "lb.:ISOMcotU"k:ttton.snrl! lhc**dcpn."JSU~** lll'k:and thedryern.-scnILnc; lhcj(:slrealnsshar.:acotlni.'Chon toth.: hcad.:rSage Environmental Consulting, L.P. November 2012 

## APPENDIX C FLARE TIP DRAWINGS

HuntRefining Company Flare Management Plan1' 1SOI

### Rf.J**!Cum~** GAS CONN.**.El,EVAT:Of':L.Y.l.E..~ (POOII~S**  ROIAI[Q fOR**Cl.I.~IIY)** JlO SS

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**_c~?:?~~'f"""**Sage Environmental Consulting, L.P. November2012 

## APPENDIX D DOCUMENT REVISION LOG

HuntRefining Company Flare Management Plan

### Revision Log

Hunt Refining Company

Tuscaloosa, Alabama NSPS SubpartJa Flare Management Plan
This Flare Management Plan (FMP) fulfills the requirements for NSPS Subpart Ja for the Interconnected Flare Header System at the Hunt Tuscaloosa refinery. Any changes to the original plan should be documented in the table below.
Revision Requires Submission Revision Revision Author (name, Reason for Revision to the USEPA? No. Date (See Section 1.3 of company) the FMP) November I3, Sage 0 2012 Environmental Original Yes ConsultingSage Environmental Consulting, L.P. November2012 

## APPENDIX E NSPS JA CROSS-REFERENCE TABLE

Hunt Refining Company Flare Management Plan60 103a!a' 60.103a(a)(l)
( 60 103a(a)(3)(il

I 60.

I 60. llliiil

60. NSPS Ja ( 1CUalion ltell\S!obe included in the t • 1Plan Ij<tof sunits lUstoffuel gas systems IGeueral i ifihletvoe Assist svstem Flaretio flare IFJ'" sReeoverv Sv<tem De :ripticnand simple PFD lflafetip lkbdmm Flam :&. Assist system lenition system

ovent cas flow rate nsweep eaSflowrate 1 oume eas flow tl eas nate t

**1pilotea~** 1total ""m Table

1and simole PFD 1meters and sulfur cot /Flare 

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60.103a(a)(5) 60 Baseline to minimize or eliminate discharges during planned shutdown

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