November 13, 2012 

Attention: Mr. Joel Sutton 

Alabama Department of Environmental Management 

Air Division 

P.O. Box 301463 

Montgomery, AL 36130-1463 

RE: Hunt Refining Company, Tuscaloosa, Alabama 

Facility No.: 413-0007 

NSPS Subpart Ja Flare Management Plan 

Dear Mr. Sutton: 

Enclosed is the NSPS Subpart Ja Flare Management Plan for the Hydrocracker Area Flare, Coker Area 

Flare, and Hydrobon Area Flare. 

If you have any questions please contact Casey Frederick at (205) 391-3376. 

"Based on information and belief formed after reasonable inquiry, the statements and information in 

this document are true, accurate and complete." 

Sr. Vice President Operations 

cc: U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

U.S. EPA Mailroom (E143-01) 

Attention: Refinery Sector Lead 

109 T.W. Alexander Drive 

Research Triangle Park, NC 27711 

David Carroll - coversheet only 

Casey Frederick 

Stefanie Thompson 

HUNT REFINING COMPANY 

2200 Jack Warner Parkway, Suite 400 · Tuscaloosa, Alabama 35401 

P.O. Box 038995 · Tuscaloosa, Alabama 35403-8995 
REFINING COMPANY 

Hunt Refining Company 

Tuscaloosa, Alabama 

NSPS Subpart Ja Flare Management Plan 

Hydrocracker Area Flare, Coker Area Flare, 

and Hydrobon Area Flare 

1855 Fairlawn Road 

Tuscaloosa, Alabama 

Tuscaloosa County 

November 2012 

Prepared by: 

SAGE 

ENVIRON MENIAL CONSULTING 
TABLE OF CONTENTS 

Section 1 Introduction ......................................................................................................... 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 of Flare Systems .............................................................................. 2-1 

2.1 Flare Type ........................................................................................................... 2-1 

2.2 Flare Tip .............................................................................................................. 2-2 

2.3 Flare Header System ........................................................................................... 2-2 

2.4 Knockout Drum .................................................................................................. 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 Sulfur Content.. ..................................................................................... 2-20 

Section 3 Flare Minimization .............................................................................................. 3-1 

3.1 Description of Contributions to Flare Header .................................................... 3-1 

3.2 Minimization Assessment.. ................................................................................. 3-1 

3.3 Baseline Flow Evaluation ................................................................................... 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 Cause Analysis and Corrective Action ..................................................... 4-1 

4.1 Root Cause Analysis ........................................................................................... 4-1 

4.1.1 RCA -Flow Exceedance ........................................................................ 4-2 

4.1.2 RCA- S02 Exceedance .......................................................................... 4-2 

4.2 Corrective Action Analyses ................................................................................ 4-3 

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November 2012 

i Hunt Refining Company 

Flare Management Plan 
LIST OF APPENDICES 

Required Notifications 

Process Flow Diagrams 

Flare Tip Drawings 

Document Revision Log 

Appendix A 

AppendixB 

AppendixC 

AppendixD 

Appendix E NSPS Ja Cross-Reference Table 

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ii Hunt Refining Company 

Flare Management Plan 
1.1 Facility Description 

SECTION 1 

INTRODUCTION 

The Hunt Refining Company (Hunt) owns and operates a petroleum refinery in Tuscaloosa, 

Alabama (Tuscaloosa refinery). Refinery products include, but are not limited to, gasoline, 

diesel, kerosene, naphtha, jet fuel, coke and asphalt. 

1.2 NSPS Ja Applicability 

The most recent promulgation of the petroleum refinery New Source Performance Standard 

(NSPS) is contained within 40 CFR 60 Subpart Ja. NSPS Ja applies to fluid catalytic 

cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas combustion 

devices, flares, and sulfur recovery plants. 

According to NSPS Ja, the definition of a flare is as follows: 

"Flare means a combustion device that uses an uncontrolled volume of air to burn gases. 

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

controls (including air injection or steam injection systems), flame arrestors, and the 

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

flare includes each individual flare serviced by the interconnected flare gas header 

system." 

An affected flare under NSPS Ja is one for which construction, modification or 

reconstruction commenced after June 24, 2008. A modification to a flare occurs when a 

project that includes any of the 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 of the flare. 

However, the following activities do not, by themselves, implicate a modification: 

• Connections made to install monitoring systems to the flare; 

• Connections to install or enhance a flare gas recovery system; 

• Connections made to replace or upgrade existing pressure relief or safety valves; 

• Connections made for flare gas sulfur removal; 

• Connections made to install redundant equipment associated with the flare, provided 

they do not increase the capacity of the flare; 

• Replacement or relocation of pipe "in kind"; or 

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• Connections that interconnect two or more flares. 

The Hydrocracker Area Flare (BN-3250) was constructed in June 2009. Under the Ja Rule, 

the Hydrocracker Area Flare is subject to the requirements and compliance timeframes of a 

new flare since it was constructed after June 24, 2008. A list of all required notifications for 

the flares is included in Appendix A. 

At the Tuscaloosa Refinery, the Hydrocracker Area Flare is a new source and is 

interconnected to the Coker Area Flare (M-2201), and the Hydrobon Area Flare (D10.3301) 

An interconnected flare header system must be treated as a single affected unit under NSPS 

Ja. As such, for each category of standards that is promulgated in NSPS Ja, the strictest 

standard that is required for any one of the three interconnected flares must be applied to all 

three flares. A process flow diagram that depicts the configuration of these three flares as an 

interconnected flare header system in provided in Appendix B. 

NSPS Ja contains work practice provisions that are applicable to refinery flares'. These work 

practice standards, as well as the applicability triggers for flares, were proposed to be 

changed in the Federal Register dated 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 of this Flare Management Plant (FMP). As the 

interconnected flare system is considered as an affected source that is subject to the rule, the 

Tuscaloosa Refinery must develop and implement a single FMP for the interconnected flares 

by no later than 60 days after the rule was published in the Federal Register, or November 

13,2012. The Tuscaloosa Refinery is required to maintain a copy of the 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 internally reviewed and updated 

periodically to account for changes in the operation of the interconnected flare system. 

These changes include, but are not limited to, adding new connections to the flare header 

system or the expansion of the flare gas recovery system. The Tuscaloosa Refinery is 

required to maintain a copy of the current Plan. It is important to note that not all events 

which trigger the need for an internal revision of the FMP require are-submission of the 

revised FMP to the United States Environmental Protection Agency (USEPA) Administrator 

and to the Alabama Department of Environmental Management (ADEM) Administrator. 

The rule requires the FMP to be re-submitted to both regulatory agencies for one of the 

following four reasons: 

• Addition of an alternative baseline flow rate, 

• Revision of an existing baseline, 

• Installation of a flare gas recovery system, or 

• Change of flare designations and monitoring methods. 

1 40 CFR 60.103a 2 73 FR78522, dated December 22, 2008 

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1-2 Hunt Refining Company 

Flare Management Plan 
A 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 ofNSPS Ja regarding the development of a written FMP 

and has been prepared pursuant to the requirements and provisions of the rule. Appendix E 

includes a table that cross-references the requirements ofNSPS Ja and their location within 

this FMP. The following information is specifically required to be included in or referenced 

by this Plan: 

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

connected to the flare header system; 

• Flare minimization assessment; 

• Descriptions of all 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 

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

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

included in the FMP under NSPS Ja. The inclusion of this supplemental information enables 

this Plan to fully document the management practices and flaring minimization measures and 

strategies that are in place at the Tuscaloosa refinery. The following supplemental 

information is provided in or referenced by this Plan: 

• Description of triggering events and compliance timefl-ames for Root Cause Analyses 

(RCAs) and Corrective Action Analyses and Implementation; 

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

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2.1 Flare Type 

SECTION 2 

DESCRIPTION OF FLARE SYSTEMS 

All three flares of this interconnected flare header system are elevated flares. An elevated 

flare consists of a tip that is mounted on a flare stack, which is raised high above grade, and 

supports combustion at the upper end of a vertical riser. The combustion zone is elevated in 

order to separate the heat generated by combustion from people, equipment, or structures at 

grade level and to aid in air dispersion. 

Per the definitions contained in the rule, each of these 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 

cannot operate as full capacity backup flares for each other. 

The Hydrocracker Area flare is a self-supporting elevated flare that stands 220 feet above the 

ground, with a 144" diameter base. The diameter of the flare tip is 54". The flare has a 

maximum design capacity of808,775 pounds per hour (lb/hr) of hydrocarbon flow and has a 

smokeless capacity of I 0% of total hydrocarbon flow. 

The Coker Area flare is a self-supported elevated flare that winds 200 feet above ground, 

with a 72" diameter base. The diameter of the flare tip is 30". The flare has a maximum case 

study capacity of 372,503 lblhr of hydrocarbon flow and has an assumed smokeless capacity 

of 10% of total hydrocarbon flow. 

The Hydro bon Area flare is a self-supported elevated flare that stands 120 feet above the 

ground, with a 45" diameter base. The diameter of the flare tip is 26". The flare has a 

maximum case study capacity of 88,187 lb/hr of hydrocarbon flow and has an assumed 

smokeless capacity of 10% of total hydrocarbon flow. 

Each flare includes a molecular seal within the flare stack to limit the possibility of air 

infiltration through the stack and into the header. Each molecular seal is equipped with a 

drain to allow any condensable materials to be removed from the base of the seal device to 

ensure proper continuous operation. Additionally, each molecular seal drain is designed with 

a water trap to ensure that air cannot enter the flare system through the drain. The Hydrobon 

water trap is fitted with a level gauge to allow operators to check the water level in the water 

trap. The water traps are free-draining to the Coker Area knockout drum (V-2201), to the 

Hydro bon Area water seal (08.3301), and to the oily water sewer connection, for the drains 

from the Coker Area flare, Hydrobon Area flare, and Hydrocracker Area flare, respectively. 

Based on available information, the Hydrocracker Area flare utilizes a specific molecular 

seal that is a proprietary density seal device (BTZ-DS-54) designed by Callidus 

Technologies, Inc. 

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2.2 Flare Tip 

The function of the 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 relief gas flow rates at the system-allowable pressure drop. Although 

the Tuscaloosa Refinery normally has a low base load of flare 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 of the flare tip 

is an integral part of the flare system because it enables the refinery to handle large variances 

in the volume, pressure drop, concentration, and temperature of the 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 of the tip is approximately 54". It consists of a 

single burner equipped with steam assist. Steam assist can be supplied radially using an 

upper external steam ring, as well as, in the center of the flare stack, just above the density 

seal. A drawing of the 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 of the 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 of the 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 of the 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 of the flare stack. A drawing of the 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 Subpart Ja, 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 relief valve from 

the fuel gas system, regardless of whether or not a flare gas recovery system draws 

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

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

gas to a flare or knockout pot that is part of the flare." 

The primary function of the 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 of the gas, rendering the gas safe to both 

equipment and surrounding personnel. 

At the Tuscaloosa Refinery, each of the three flares is part of an 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 of the three separate water 

seals during normal operations. Each flare has its own water seal at the base of the flare 

which provides the header system with the ability to maximize the volume of gases that are 

routed to the recovery compressors. This maximized utilization is possible not only during 

normal operations, but also during periods of turnaround, 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 of the 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/CCR Platfonner 

o Hydrocracker 

o No. 2 Hydrogen Plant 

o DMS Plant 

• Coker Area Flare 

o Coker 

o Diesel Hydrotreater 

o No. I Hydrogen Plant 

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F1are Management P !an 
o No. 2 Amine 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 

If the 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 of contributions. Two of the categories of streams 

are connected to the flare header downstream of a water seal while the other category is 

connected to the flare header upstream of a water seal. Those streams injected upstream of a 

water seal have the opportunity to be recovered by the flare gas recovery system for use as 

refinery fuel gas while those connected downstream of a water 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 of the 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 of a water seal 

o Process gas (continuous) 

• Downstream of a water seal 

o Process gas with high concentrations of hydrogen (continuous, to 

Hydrocracker Area Flare) 

o Acid gas and associated lift gas (non-continuous, to Coker Area Flare) 

o Gas from the over-pressuring of FGRU mix gas vessel (non-continuous, to 

Coker Area Flare) 

o No. 1 Hydrogen Plant depressure (non-continuous, to Coker Area Flare) 

o Excess fuel gas discharged through the lift gas valve (non-continuous, to 

Coker Area Flare) 

o ISOM depressure (non-continuous, to Coker Area Flare) 

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o ISOM dryer regeneration (non-continuous, to Coker Area Flare) 

The interconnected flare header system has a common flare gas recovery system, which is 

comprised of two 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 of the 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 vent gases that are connected downstream of its water seal. 

In the event of an event or incident causing the pressure in the flare gas header to exceed the 

pressure in one of the water seals, the flare gas is released into the associated flare stack for 

combustion. 

Breakthrough of one of the water seals is due to one of the following activities relating to key 

pieces of equipment: 

I) Outage of Fuel gas recovery system, and 

2) Closing of Flare Isolation Valve (XV-1132). 

The pressure threshold created by each of the water seals, in order of increasing pressure, is 

as follows: 

I) Hydrocracker Area flare- 24" 1-hO, 

2) Coker Area flare- 30" H20, and 

3) Hydrobon Area flare- 42" H20. 

Because of the design of the refinery and the targeted production volumes of specific 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 of all three water seals, if flaring 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 of the flare header system that 

connects the Hydrocracker Area flare sub header and the Coker Area flare subheader. Local 

pressure sensors that are installed on either side of the 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 I 32 control 

valve towards the Coker Area flare header and are recovered by the flare gas recovery 

system. However, when one or more of the following thresholds are exceeded, the DCS 

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logic automatically closes XV -1132, isolating the Hydrocracker complex process units from 

the Coker complex process units: 

• Pressure of 25" H20 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 of 75% of the weir height as measured by LT-9022 at the Hydrocracker 

Area Flare Water Seal (V-3251). 

As the flares are part of an interconnected flare header system, the operations of each unit has 

the ability to affect flaring at the other flares. Based on the type of gases in the header, a 

flaring event at the Coker Area flare could cause flaring at the Hydrocracker Area flare if the 

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 of the two complexes during selected flaring events is controlled by control valve 

XV-1132 and is required to prevent over-pressuring of the 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. 

Once the XV-1132 related flaring event has ceased, the operators remotely re-open XV-1132. 

The Flare Isolation Valve is able to be reset when each of the set points referenced above are 

satisfied. During the period of time when XV -1132 is closed, the recovery compressors 

continue to operate and are able to recover the flare gas that is on the Coker Area 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 of XV -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 of sweet 

gases from processes that are generally rich in H2, is injected into the flare header 

downstream of the Hydrocracker Area flare water seal (V-3251) and is flared continuously at 

the Hydrocracker Area flare. 

The Tuscaloosa refinery purposefully excludes the Hydrocracker Area medium pressure line 

gases from fuel gas recovery. Com busting a higher concentration of H2-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 Area to bypass the 

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interconnected recovery system in order to allow for the proper operation of the recovery 

compressors and the exclusion of certain hydrogen fuel in the combustion devices. 

There are six non-continuous streams that intentionally bypass the flare gas recovery system 

and are connected downstream of a 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 of the Coker area water seal, D1100. 

The acid gas line, which is the collection of acid gases from the Hydrobon Area Unit, is 

injected into the flare header downstream of the 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 of the SRUs and DMS Plant, the 

DCS logic actuates the opening of the control valve, which causes the acid gas to flow to the 

Coker Area flare. Lift gas, which is comprised of refinery 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 

kept during period of HV -1658 opening and discharge. 

Because of the potentially high content of hydrogen sulfide in the acid gas stream from HV1658, the Tuscaloosa Refinery routes this stream, when it is present, to the Coker Area flare. 

If this stream were to be recovered by the flare gas recovery system, it would overwhelm the 

H2S Scrubber system because of the high H2S content and the volume of the stream. If the 

H2S Scrubber system were ove1whelmed and shut down, further recovery by the recovery 

compressors would not be possible, resulting in a larger amount of potentially 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 of its point of introduction, 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 of the 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 of a valve in the line in the recovered gas line to the amine scrubber or stmtup of the 

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 for the flare system. 

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2.4 Knockout Drum 

The hydrocarbon liquid knockout drum removes any potential liquid hydrocarbons from the 

flare gas prior to combustion. Generally, liquid hydrocarbons cannot be safely or completely 

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 of liquid 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 of the vessel and are recycled to 

either the sour water 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 of the vessel and contains the phase separation process prior to the 

outlet of the vessel. (This flare's water seal and KO drum are integrated into a single vessel.) 

The inner diameter of the 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 (MA WP) is 50 psig and the Maximum Allowable Working Temperature 

(MA WT) is 580°F. The flare gas is off-gased directly to the flare stack while the water that 

accumulates in the boot of the vessel is pumped to the sour water processing area by pumps 

P-3252A/B and the oil that accumulates in the boot of the 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 

or water removal pumps are automatically activated when the liquid level in the boot triggers 

their respective low-low, low, high, or high-high alarms. 

The Coker Area flare Knockout Drum, V-2201, is a horizontal vessel that is located upstream 

of the Coker Area water seal. The inner diameter of the vessel is 102 inches and the length, 

from seam to seam, is 8.5 feet in diameter. The MA WP is 50 psig and the MA WT is 450° F. 

The flare gas is sent to the Coker Area flare water seal while the liquid that accumulates in 

the boot of the 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 or water removal 

pumps are automatically activated when the liquid level in the boot triggers their respective 

low-low, low, high, or high-high alarms. 

The Hydrobon Area flare Knockout Drum, D8.3301, is a horizontal vessel that is located 

upstream of the Hydrobon Area flare water seal. The vessel has an inner diameter of 72 

inches and is 20 feet long, from seam to seam. The MA WP is 50 psig and the MA WT is 

650° F. The flare gas is sent to the Hydrobon Area water seal while the liquid that 

accumulates in the boot of the 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 or water removal 

pumps are automatically activated when the liquid level in the boot triggers their respective 

low-low, low, high, or high-high alarms. 

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November 2012 

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Flare Management Plan 
2.5 Flare Gas Recovery System 

According to the definitions promulgated in Subpart Ja, flare gas recovery system is 

"a system of one or more compressors, piping and the associated water seal, rupture 

disk or similar device used to divert gas from the flare and direct the gas to the fue I 

gas system or to a fuel gas combustion device." 

Flare gases at the 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 

AB 1500F GARO compressors (CP-111 011111 ). Each compressor has a maximum design 

capacity of 1,041 scfm. Typical flow rates to the recovery system are approximately 

equivalent to the capacity of one compressor. If only one compressor was 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 of the 

recovery system. The recovery system is capable of recovering all the normal operation 

related flows in the interconnected flare header if the 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 of the 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 of hydrocarbon 

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 over the internal weir when the height of the 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 of the recovered flare gas to the 

sour gas header. 

The following conditions of the 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 of the 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 of the compressors from the DCS 

screen in the control room. Outages of one or both of the recovery compressors due to their 

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Flare Management Plan 
own failure or need for maintenance occur infrequently. Outages for routine or preventative 

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. 

Table 2-1: Recovery Compressor Shutdown Criteria 

Sensor Set Point Action 

PIT-85001 2" H20 Shutdown after 20 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 of the recovery 

compressors. The Tuscaloosa refinery has created procedures for the Coker Area flare 

operators to instruct them regarding the operation of the 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 greater than the pressure of the 

liquid seal and "breakthrough" the water. The maximum height of liquid in the seal must be 

determined by the maximum exit back pressure allowable in the flare gas header. 

The seal serves multiple purposes to maintain the integrity of the flare system. However, the 

pressure created in the flare gas header by the water seal must not exceed the pressure rating 

of the 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. If atmospheric oxygen entered the flare gas header, the oxygen 

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would 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 greater recovery. 

• The seal prevents flashback originating from the flare burner propagating back 

through the flare system. The flare is an ignition source and must be isolated 

from the header and 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 of the 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 of the knockout section of the vessel to the weir and ensure that the liquid level 

in the water seal is maintained even when the utility makeup water valve is not opened. The 

water level is monitored by L T -9022, which provides a read-out in the DCS of the percent of 

weir height. If the level of the water seals drops below 75% of the weir height, the Low Low 

Alarm of the 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% of the weir height. The Tuscaloosa refinery 

created a document titled Hydrocracker Area Flare Knock Out Drum Complex Control 

Philosophy Description that provides the Hydrocracker operators with a reference manual for 

the Water Seal portion of the Knock Out drum vessel. 

The Coker Area flare uses a water seal with a breakthrough pressure of 30 inches H20, which 

coincides with the pressure setpoint of the 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 MA WP is 50 psi and the MA WT 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 Hydro bon Area flare uses a water seal with a breakthrough pressure of 42 inches H20. 

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 of 6 feet, 4 inches and a 

height, from seam to seam, of 15 feet, 5 inches. The MA WP is 50 psig and the MA WT 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 of water 

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Flare Management Plan 
within 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-330 I A/S. The liquid 

level is monitored by Ll 3320, which provides a read-out in the DCS of the percent of the 

range of the 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 of the combined gases is not 

diluted by excess use of assist 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 of the flare stack circumference. The center steam 

injection includes a single internal steam injection nozzle using a 2" supply pipe centered 

inside the stack just above the density seal. Each of the two steam supply lines provide steam 

at 230 psig and can be controlled independently. Steam is delivered to the flare tip by means 

of an 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 or tiered. 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 of steam per I ,000 lbs of vent gas for an 

effective steam-to-vent gas (SNG) ratio of 0.25 for the tip steam. A restriction 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 stack just above the density seal by means of a 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 of steam per I ,000 lbs of vent gas for an effective 

SNG ratio of 0.003 for the center steam. There is also a manually operated globe valve that 

bypasses the FV -9023 to ensure that a nominal flow of I ,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 of the flare stack 

circumference. Steam is delivered to the flare tip by means of a 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 of H!C-3314, which is viewed in the Coker complex control room. The steam 

is remotely controlled by the operators based upon a visual observation of the flare via a 

closed-circuit television (CCTV) in the control room. If smoke is observed during a flaring 

event via the video monitoring, the operators will increase steam flow rate to the tip to 

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facilitate smokeless flaring. The minimum steam requirement for continuous cooling and 

protection of the 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 of the flare stack circumference. The lower steam injection, 

also called jet steam, includes five internal steam injection nozzles using a 4" supply pipe 

centered inside the stack and just above the molecular seal. Each of the two steam supply 

lines can be controlled independently and delivers the steam at 230 psig. The minimum 

steam requirement for continuous cooling and protection of the tip is 540 lb/hr. Steam is 

delivered to the flare tip by means of a 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 of the flare via a CCTV in the control room. If smoke 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 of HIC-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 of the flare stack by means of a 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 of center steam flow rate is the percent open of HIC-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 of HIC-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 of the flare. The minimum steam requirement for continuous 

cooling and protection of the tip is 540 lb/hr. 

2.8 Pilot Gas 

Pilot gas is introduced through the pilot tip of a flare in order to provide a flame to reliably 

ignite the flare. If the 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. 

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Flare Management Plan 
The Coker Area flare has three pilot lights, whose presence is detected by a stationary IR 

camera that is mounted in the line of sight 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-33 I2) 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 of sight with the pilots. The pilot lights are spaced at I 20 

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 of the H2S concentration 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 ensure that a flame remains always present. 

The ignition equipment functions to reliably light the pilot. The type of ignition used at the 

Tuscaloosa refinery 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 of the 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 of this ignition system is with its propensity 

for moisture formation in the piping leading to the pilot, which, if corrosive, may 

potentially render the ignition system useless. Therefore, it is necessary to flush 

each ignition line after use 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 

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the 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 of the 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 of pilot 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 Complex Flare Lighting Procedure. 

The Coker Area ignition system consists of three pilots, all of which are continuous. All 

three pilots have a manual electronic spark ignition system. Ignition gas is supplied through 

a 2 inch control valve, PCV-331 0. An operator standing at the ignition panel with proximity 

to the base of the 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 

Lighting Procedure. 

The Hydrobon Area ignition system consists of three pilots, all of which 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 of the 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-- Procedure for Relighting 

of the Flare. 

2.10 Purge Gas 

According to the definitions promulgated in Subpart Ja, 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 if oxygen 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 of flow 

and so that no intrusion of air that 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 of each water seal primarily to 

condition the molecular seal and to assist in the backflow prevention. Sweep gas is injected 

upstream of each water seal into the flare header to reduce the likelihood of stratification of 

gases in the header See Section 2.11 for further information on sweep gas. 

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For 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 of 562 scf/hr. This purge gas is injected directly into the Hydrocracker Area flare 

KO Drum, V -325!, downstream of the 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 of 833 scf/hr. The valve is normally 

open, providing a continuous purge to the density seal and to the flare. Because of its point 

of introduction into the flare header, this purge gas is incorporated into the combined flare 

gas being monitored to comply with the <162 ppmv H2S limit. 

For the Coker Area flare, a mixture of refinery 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-11 00, downstream of the water barrier, via a 2 inch line. the flow is regulated 

with an orifice plate with a I ;gth inch bore. Because of its point of introduction into the flare 

header, this purge gas is incorporated into the combined flare gas being monitored to comply 

with the <162 ppmv H2S 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 of the 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 of its point of introduction 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 of gas to 

prevent oxygen buildup in the flare header. For flares with no water seals, sweep gas 

also performs the function of preventing oxygen infiltration (backflow) into the flare 

tip". 

Because all three flares have water seals, purge gas is distinctly different from sweep gas at 

the Tuscaloosa refinery. Purge gas is injected downstream of each water seal primarily to 

condition the molecular seal and to assist in the backflow prevention. With the FGRU and 

the seal backpressure, sweep gas is injected upstream of each water seal into the flare headers 

and subheaders to provide a constant "flushing" and prevent stagnation of vapors 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), 

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• 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 of all 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 of the sweep gas injection points is maintained at a flow rate of 667 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/hr of natural gas), 

• Flare header above the reactivator reflux pumps (740 scf/hr), 

• North end of the compressor building (740 scf/hr), 

• South end of the compressor building (740 scf/hr), 

• TGTU flare subheader (917 scf/hr of natural gas), 

The sum of all 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 of refinery fuel gas, with the exception of 

the SCOT Unit flare subheader and the TGTU flare subheader that consist of natural gas. 

Because the refinery fuel gas, by definition, is not inherently low in sulfur, sulfur content 

analysis of the sweep gas must be conducted to demonstrate compliance with the <162 ppmv 

H2S limit. The natural gas sweeps meet the definition of inherently low in sulfur and do not 

require monitoring. The rule explicitly allows the analysis of a common source of fuel gas, 

provided that the monitoring location accurately represents the concentration of H2S that is 

being combusted. Therefore, because the sulfur analysis that is conducted for the refinery 

fuel gas is representative of all refinery fuel gas, regardless of its use, a separate analysis of 

the sweep gas is not necessary. 

In total, the three flare subheaders utilize a combined sweep gas of approximately 28,127 

seth or 469 scfm. The total flare gas recovery compressor capacity is a combined 2,082 

scfm. As such, sweeps represent approximately 23% of the FGRU capacity. 

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2.12 Supplemental Gas 

Supplemental gas is gas that is introduced to the flare in order to comply with the net heating 

value requirements of 40 CFR §60. I 8(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 or purge gas, it simultaneously functions as supplemental gas. 

There is no dedicated mechanism to control the flow of supplemental gas to the 

Hydrocracker Area 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 of refinery fuel gas, is 

automatically injected just downstream of the Coker Area Flare Water Seal (D-1 100). The 

lift gas is regulated with a control valve and adds lift gas at a rate of one volume of lift gas 

per every two volumes of acid gas. The maximum flow rate of the lift gas is 900 Mscf/day, 

which is understood to be the maximum flow rate of supplemental 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 (08.330 I), which is downstream 

of the 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 of acid gas. This operating scenario occurs very infrequently, as the acid gas is now 

primarily directed towards the Coker Area flare. 

Because of its point of introduction, 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 Vent Gas Flow 

NSPS Ja requires the Tuscaloosa refinery to operate a flow meter that provides a 

representative measurement of the total flow rate discharged to each flare. The flow rate data 

that is collected will be used to determine if flaring events occur that exceed the Root Cause 

Analysis (RCA) threshold of 500,000 scf in a 24-hour period above the established baseline. 

The following standards for the flow meter are required pursuant to the rule: 

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

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• 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 of the 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 of the flow meters. The following table 

summarizes the specifications of the 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% of reading at 1 fps 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 of the water seal and downstream of all 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 of the Coker Area flare KO Drum, V -220 I, which is downstream of the Coker 

Area flare water seal, D-11 00. The meter configuration is a single-channel bias-90 setup with 

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temperature and pressure corrected readings. The pressure sensor that 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 correct the 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 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 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 of the Hydro bon 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 

of the gases com busted in each flare. The rule allows the Tuscaloosa refinery to select one of 

two options that involve direct analysis of the gas that is directed to the flare in order to 

comply with the sulfur monitoring requirements: 

• Total Reduced Sulfur (TRS) monitoring, or 

• H2S Monitoring. 

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 of total reduced sulfur to substitute for the measurement of 

H2S. Therefore, by substitution, the TRS concentration in flare gas at each of the 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 

of 500 lb S02 emissions in a 24-hour period. 

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 of the GC Model 500. 

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Table 2-3. TRS Monitor Specifications 

Item Monitor Specification 

Make Rosemount Analytical 

Model 500 

Type Gas Chromatograph 

Hydrocracker 

COS: 0-0.5% 

CS2: 0-0.5% 

H2S: 0-5% 

Hydro bon 

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 of the 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 of their respective water seals; therefore, the 

monitors are able to sample all the gases sent to the flare. 

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SECTION 3 

FLARE MINIMIZATION 

3.1 Description of Contributions 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 Hydrocracker Area, 

• The Coker Area, and 

• The Hydrobon Area. 

The contributions to each of these subheaders include sweep gas that is injected upstream of 

the water seal and purge gas that is injected downstream of the 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 of process gas discharge to the flare through process operating changes or 

gas recovery at the source; 

• Reduction of the volume of process gas to the flare through process operating 

changes; 

• Installation of a flare gas recovery system*; and, 

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• Minimization of sweep and purge gas flow rates, if applicable. 

* If a 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 of the items above, the minimization assessment must provide rationale in terms of 

the following considerations: 

• Costs, including capital and annual operating; 

• Natural gas offset credits, if applicable; 

• 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 

sweet process 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 of the recovety 

compressors and the exclusion of hydrogen fuel in the combustion devices. This also is 

integral in the safety of operability 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 of the 

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 gas header. When this gas is 

present, its volume is much greater than the capacity of the Sulfur Plants Recovery of this 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 of potentially recoverable gases to be flared. 

Therefore, routing this gas to the recovery compressors would only result in the failure of the 

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 

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downstream 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 of a valve in the line in the recovered gas line to the 

amine scrubber or startup of the 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 of this 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 of the 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 of all 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 of separate baseline flow 

rates: 

• Identification of a primary baseline that will be used as the default baseline; 

• Description of each 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 Hydrocracker Area flare data was analyzed and was determined to consist primarily of a 

constant low level of flaring with infrequent short durations of high flow. As the 

Hydrocracker Area flare receives the gas streams that have a high concentration of hydrogen 

that bypass the water seal, the Hydrocracker Area flare is anticipated to receive regular flows. 

The data indicates that the spikes of high flow are representative of the closure of Flare 

Isolation Valve XV-1132. 

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Because routine flaring of process gas does not occur at the Coker Area flare and the 

Hydrobon Area flare, the baseline flow at each of these flares is equivalent to the flow of the 

purge gas at each flare. 

For flares that do 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 event were 

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 of a flare includes "In the case of an 

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 of 500,000 scf/day above the baseline. Therefore, when determining 

when a RCA needs to be performed, the flow rates fi·om each of the interconnected system 

need to be combined. Similarly, when determining a baseline for the flare, the baseline 

analysis for each of the interconnected flares needs to be combined. 

Based on the analysis performed, the baseline for individual flares was determined to be as 

follows: 

• The Coker Area 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 of an 

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 clear rationale in 

terms of costs (capital and annual operating), natural gas offset credits (if applicable), 

technical feasibility, secondary environmental impacts and safety considerations for the 

selected minimization alternative(s) or a statement, with justifications, that flow reduction 

could not be achieved." 

As discussed in this minimization assessment, the acid gas from the Hydrobon Area cannot 

be minimized. Further, the high hydrogen content streams cannot currently be directed to the 

refinery fuel gas system for utilization. 

Hunt has total compressor recovery capacity of approximately 2082 scfm (maximum of both 

FGRU compressors operating concurrently). At present, typical recovery rates are 

approximately 1,200 scfm, representing 58% of available routine capacity. Hunt believes 

that additional compressor capacity is not warranted at this time. 

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3.4 Startup and Shutdown 

It is Hunt Refining's operating philosophy 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 of the 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 striving to limit flaring during stattup and shutdown, the operators 

must always consider the safe operation of the unit, so the potential exists for additional 

flaring events during startup and shutdown. 

3.5 Fuel Gas Imbalance 

The procedure for the operation of the 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 of fuel gas to the process areas of the refinery. The fuel gas makeup is a 

combination of gas 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-l 001. The fuel gas system pressure is regulated with a pressure 

control system that includes controllers that regulate 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 are two outside suppliers of natural gas and each 

can be operated on flow and/or pressure control. A secondary overpressure controller vents 

excess fuel gas directly to the Coker Area Flare in the event of a refinery imbalance in 

production/consumption. This same controller operates the lift gas and is metered going to 

the Coker Area 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 other supplier's flow is controlled by FIC-852 and 

is regulated on flow control. The Crude Unit DCS Operator can 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 Coker Area 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 of high pressure fuel gas can be 

operated on pressure control with the controller from either supplier in automatic remote with 

a setpoint of the desired pressure. The pressure setpoint is selected by the Crude Unit DCS 

Operator. If the 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 higher than the setpoint on 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 

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to 3 psig higher than PIC-2003C. This allows PIC-20038 to open when the pressure rises 

too quickly for PIC-2003C to stabilize the fuel mix drum pressure. With the implementation 

of the 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. For this 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 3 to 6 psig higher than PIC-2003A. If 

the range between the set points is too high, the pressure changes are likely to cause unstable 

heater operations throughout the refinery. If the set points are too low, gas may be wasted 

into the flares. It is 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 relief valve on the Fuel Gas header to the Coker Area 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 

Hunt operates two fuel gas recovery compressors for the interconnected flare system. 

Currently, the loads experienced by the compressors are slightly higher than the capacity of a 

single compressor. In the event that one of the compressors were to shut down, a greater 

fraction of the capacity of the second compressor could be utilized than is typically utilized 

during normal operations in order to continue to capture the majority of the available gases; 

thereby, minimizing flaring during an outage of one of the compressors. 

To minimize flaring that would occur if both recovery compressors would experience a 

shutdown due to maintenance, Hunt schedules maintenance events of the compressors to 

coincide with major unit outages. Therefore, the amount of gases being produced that would 

be available for recovery but are now required to be flared, is minimized. 

Hunt has total compressor recovery capacity of approximately 2082 scfm (maximum of both 

compressors operating concurrently). At present, typical recovery rates are approximately 

l ,200 scfm representing 58% of available routine capacity. Hunt believes that additional 

compressor capacity is not warranted at this time. 

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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 Cause Analysis 

As defined in NSPS Ja, an RCA is 

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

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

thresholds." 

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

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

both of the specified thresholds. 

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

Tuscaloosa refinery must perform following an RCA threshold exceedance: 

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

RCA must be performed; 

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

only one RCA must be performed; 

• If a discharge that triggers an RCA is the result of a planned startup or shutdown during 

which the Planned Startup & Shutdown procedures referenced in Section 3.4 were 

followed, an RCA is not required; and 

• If multiple 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 of whether an RCA threshold has 

been exceed must consider a data analysis from all three flares. 

The two thresholds which trigger an RCA are the following: 

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

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

baseline in a 24-hour period. 

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A 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 of the CD meet the requirements ofNSPS Ja. 

4.1.1 RCA- Flow Exceedance 

The specified flow threshold which triggers an RCA is the discharge to a flare of greater than 

500,000 scf above 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 of the investigation: 

• the connections that were contributing to the header, 

• the duration of the flaring event, 

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

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

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

that could have prevented the flaring event or reduced the volume or duration of the flaring event 

should be evaluated and documented. 

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

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

rule specifies that certain items must be recorded for each RCA, each internal report should, at 

minimum, include the following: 

• A description of the discharge. 

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

discharge. 

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

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

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

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

previous RCAs. 

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

action is not necessary. 

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

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

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

procedures to minimize flaring during planned startup and shutdown, see Section 3.4. 

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 of S02 in any 24-hour period. In contrast to the RCA flow threshold, there is 

no reference baseline upon which to compare S02 emissions. The S02 emissions are 

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determined by monitoring the TRS or H2S concentrations in the gases sent to the flare for 

combustion. Pilot gas is specifically exempted from sulfur monitoring. 

When performing an RCA for an S02 exceedance at Tuscaloosa, there are several key 

parameters that should be documented as part of the investigation: 

• the connections that were contributing to the header, 

• the duration of the flaring event, 

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

• the sequence of events lead to the flaring event. 

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

that could have prevented the flaring event or reduced the volume or duration of the flaring event 

should be evaluated and documented. 

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

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

rule specifies that certain items must be recorded for each RCA, each internal report should, at 

minimum, include the following: 

• A description of the discharge. 

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

discharge. 

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

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

• The measured total sulfur concentrations in the fuel gas at a representative location in the 

flare inlet. 

• The cumulative quantity of H2S and S02 released into the atmosphere. Assume a 99 % 

conversion ofTRS to 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 of the recommended corrective action(s) or an explanation of why corrective 

action is not necessary. 

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

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

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

procedures to minimize flaring during planned startup and shutdown, see Section 3.4. 

4.2 Corrective Action Analyses 

As defined in the rule, a Corrective Action is 

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

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

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

as having resulted in a discharge of gases to an affected flare in excess of specified 

thresholds" 

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

purpose of documenting the corrective action( s) in the internal RCA Report is to systematically 

identifY changes that could be made to reduce or, if possible, eliminate the possibility of the 

recurrence of the causes of the flaring event that caused an exceedance of one or both of the 

RCA thresholds. The identification of corrective actions should not incorporate rationale 

regarding economic or technical feasibility or other potential limiting factors. The purpose of 

identifYing corrective actions is to determine, based upon good engineering practices, potential 

changes that could rectifY the cause(s) of the flaring event that was/were identified by the RCA. 

According to the rule, a Corrective action analysis is 

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

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

including, but not limited to, considerations of cost effectiveness, technical feasibility, 

safety and secondary impacts." 

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

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

rationale regarding economic and technical feasibility, along with other potential limiting factors, 

are taken into consideration. If the facility concludes that corrective action should not be 

conducted, the facility must document the decision and include the basis for the conclusion. 

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

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

corrective action should not be implemented, the explanation of the basis of that decision must 

be recorded no later than 45 days following the discharge. Because the Corrective Action 

Analysis is a consequence of the RCA, it is imperative to commence the RCA as soon after the 

discharge as possible in order to allow for the maximum amount of time to be allotted to the 

determination and implementation of the most beneficial corrective action. However, if a 

corrective action cannot be fully implemented within 45 days, the facility must develop an 

implementation schedule to complete the corrective action as soon as practicable. 

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

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

each internal report must include the following items: 

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

the basis of that decision 

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

discharge. 

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

including proposed commencement and completion dates. 

Sage Environmental Consulting, L.P. 

November 2012 

4-4 Hunt Refining Company 

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

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

Analysis is not necessary because the facility followed the FMP. For fmther information 

on the procedures to minimize flaring during planned startup and shutdown, see Section 

3.4. 

Sage Environmental Consulting, L.P. 

November 2012 

4-5 Hunt Refining Company 

Flare Management Plan 
Sage Environmental Consulting, L.P. 

November 2012 

APPENDIX A 

REQUIRED NOTIFICATIONS 

Hunt Refining Company 

Flare Management Plan 
Summary of Key NSPS Subpart A and Subpart Ja Deadlines 

Any flare built or reconstructed after June 24,2008 is new 

Flare Applicability Dates 

Any flare modified after June 24, 2008 is modified 

NSPS Subpart Ja Rule Promulgation Date September 12, 2012 

NSPS Subpart Ja Rule Effective Date November 13, 2012 

Deadlines Citation Constructed after June 24, 2008 and before rule Date Submitted 

promulgation (September 12, 2012) 

Construction notification 60.7(8)(1) Actual date wrthon 30 days after constructoon commenced 

Startup notification 60.7(a)3 Actual date of initial startup with on 15 days of startup 

Agency notification for monitors 60.108a(b) Submotted woth startup notificatoon 

Monitor Perfonnance test 60. 7(a)(5, 6) 30 days pnor to monotor performance testong not ification 

Performance test 

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

60.8(d) than 180 days after onitoal startup 

Performance test report 60.13c(2) 60 days after completion of monotoring venficatoon 

Flare Management Plan 60.1038 (b)(1) November 13, 2012 

Root Cause Analysis program 60.108a (c)(6)(x) November 13, 2012 

Flow and TRS/H2S Monitoring 60.107a(e) November 13, 2012 

60.107a(f) 

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

(relief valve 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 

Hunt Refining Company 

Flare Management Plan 
llydrobon Area Hare 

L< <nd 

llydrobon 1\Ie~ Un.~s 

CokcrArco Un1tS 

NewComplc-.: 

SwcctG_,s 

Ac1d Gas ~leader 

Coker 1\rc:t Flare 

NonnaHy Open 

Hunt Refining · Tusuloo~.Al 

Hum Refining 

DATE· November 2012 

PROJECT NUMBER: 4)5-1-15 
\ 

Flare Drawing Color Legend 

Vent Gas 

Air 

Pilot Fuel Gas line (3x) 

FIGURE 8·2. 

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

D10.3301 

AL 

DATE: November 2012 

PROJECT NUMBER: 435·1-15 
Flare Drawing Color Legend 

Pilot Fuel Gas Line (3x) 

Ignition Gas 

(3x)IHEI) 

FIGURE B-3. Hydrocracker Area Flare . 

Hunt Refining · Tuscaloosa, AL 

Hunt 

SAGE DATE: November 2012 

E:NVIOON M . /'ITJ\1. CO ~lll.TIIl () 

PROJECT NUMBER: 435-1·15 
l:xccs:~!U..:I g~s 15 \\."nted lhrough tho.: hR ~S COM« liOn to lhc h¢eck'f 

"lb.: ISOM cotU"k:ttton.snrl! lhc dcpn."JSU~ lll'k: and the dryer n.-scn ILnc; lhcj(: slrealns shar.:a cotlni.'Chon to th.: hcad.:r 
Sage Environmental Consulting, L.P. 

November 2012 

APPENDIX C 

FLARE TIP DRAWINGS 

Hunt Refining Company 

Flare Management Plan 
1' 1SOI Rf.J !Cum~ GAS CONN. 

.El,EVAT:Of':L.Y.l.E..~ 

(POOII~S ROIAI[Q fOR Cl.I.~IIY) 

JlO SS 

2S3.1' 

I 

I 

PLAN ViEW (TR\JE ORIENTAnllll) 

1J.1' 

' \ 

\ 

' . ~I 00 

' I 

13ll" 
lo--"L_.!,:~~-1'-!/L,.-~~~~~r:. W<K 

·~~ 'gJt tf.w. 
ll~~i~~.t:]~'-!1 '•n:.jl.[ . I.E .I ~,\lrr,!!o we nmn 

WWsm,Mi'U'iJW,._~.•;,t..:-u 

m':M'W'~>~-i 

Wl~_slti!/~~I!S 

.''·OJ/t' I_ 

I_ 

&@ 

----- /,,'/';f'" "'~ 

1Jtli1::ct~· /;.i'$;J"''>: 

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

November 2012 

APPENDIX D 

DOCUMENT REVISION LOG 

Hunt Refining Company 

Flare Management Plan 
Revision Log 

Hunt Refining Company 

Tuscaloosa, Alabama 

NSPS Subpart Ja 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 USEP A? 

No. Date (See Section 1.3 of company) the FMP) 

November I 3, Sage 

0 2012 Environmental Original Yes 

Consulting 
Sage Environmental Consulting, L.P. 

November 2012 

APPENDIX E 

NSPS JA CROSS-REFERENCE TABLE 

Hunt Refining Company 

Flare Management Plan 
60 103a!a' 

60.103a(a)(l) 

( 

60 103a(a)(3)(il 

I 60. 

I 60. llliiil 

60. 

NSPS Ja ( 

1 CUalion 

ltell\S!o be included in the t • 1 Plan 

I j<t of s units 

lUst of fuel gas systems 

IGeueral i 

ifihletvoe 

Assist svstem 

Flaretio 

flare 

IFJ'" s Reeoverv Sv<tem 

De :ripticn and simple PFD 

lflafetip 

lkbdmm 

Flam :&. 

Assist system 

lenition system 

o vent cas flow rate 

n sweep eaSflow rate 

1 oume eas flow 

tl eas nate 

t 1pilotea~ 

1 total ""m 

Table 

1 and simole PFD 1 meters and sulfur cot 

/Flare rruriCi!as 

I Sween 

t1 gas 

~ 

60. 103a(a)(3)(v) :,. ·;~;:;;;;;;,, for each I 1u~::nnucu in 

60.103a(a)(3)(vi) lri;;;;~;dto .• , '~; • nonnal ~o~res, and flaces with FGRUs that are 

1:;;-;;;;::;-;:::l(;;;~~· ; 'i~~1 of ·, e ootion 

60.103a(a)(3)(vii) svstem'"l~~,~~-~GRU, FGRU i parameters, and compressor 

60.103a(a)(5) 

60 

Baseline 

to minimize or eliminate discharges during planned shutdown 

o reduce flarine in s of fuel gas i 

3. 

u 

2.2 

~.3 

'~n~tX ...... 

7 4 irB 

2. ir B 

-i. ir B 

~ 2. 

2.12 

2.8 

'J:}:'ii ·,s 

2.10 

.I 1. i ( B 

2.12 

?.R 'B 

2.13 

~ 2.13 

2.5 

3.3 

3.4 

3.5 

60.103a(a)(7) 

Ia( 

l;~uceuures ~~arm~ during FGRJ'~:e~ration during FURU outages and 2.5 

1--' 6'j ::i, Ill ---'6t )3a(, 

60.103a(D 

60=-

60.107a(b) 

6(. 

6if l7a!O 

oO. • (c) 

i timcline for initial FMP 

IEve<1ts h trigger a fthe FMP 

i ' i ' Trigger a Root Cause Analysis forR: : Event 

~Root CauseAnalvsis and· , Analvsis 

~~for initial. J for e tor R~o~~~ u~e Analysis and~""""'" 

<neoific · 'for flares j in the BAAOMD ar 

ililv 'flaresto < !62 oom~S · ., in flare cas 

. ~s '. · Tor flare eas H2S i 

to exempt streams from flare gas H2S concentration 

r content for 

rates fofRCA 

i ! s and re;corrls 

1.3 

4.1 

4.! 

42 

1.132 

!3.2 

132 

2.132 

4 1.2 

4.!.! 

.2 ·,A