Phillips 66 

San Francisco Refinery 

Rodeo, California 

BAAQMD Plant 16 

Flare 

Minimization 

 

Plan (FMP) 

 

Non-Confidential version 

Bay Area Air Quality Management District (BAAQMD) 

Regulation 12, Rule 12 

October 2013, Revision 9 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

1-1

Contents 

1.0 Flare Minimization Plan ........................................................................................................................... 1-3

1.1 Safety Statement ............................................................................................................................. 1-3

1.2 Executive Summary ......................................................................................................................... 1-3

1.3 Certification ...................................................................................................................................... 1-5

2.0 Flare System Information ........................................................................................................................ 2-1

2.1 Background Information for Flare Systems .................................................................................... 2-1

2.2 Technical Data – Description of Flaring Systems (401.1) .............................................................. 2-3

2.2.1 Phillips 66, San Francisco Refinery Flare & Fuel Gas Recovery System Overview ....... 2-3

2.2.2 Detailed process flow diagram, PFD (401.1.1) ................................................................. 2-3

2.2.3 Description of Monitoring and Control Equipment (401.1.2) ............................................ 2-4

3.0 Reductions & Planned Reductions ........................................................................................................ 3-1

3.1 Reductions Previously Realized (401.2) ......................................................................................... 3-1

3.2 Planned Reductions (401.3) .......................................................................................................... 3-15

4.0 Prevention Measures (401.4) .................................................................................................................. 4-1

4.1 “Major” Maintenance Activities (401.4.1) ........................................................................................ 4-1

4.1.1 Refinery Maintenance and Turnaround Activities ............................................................. 4-1

4.1.2 Measures to Minimize Flaring During Preplanned Maintenance ..................................... 4-8

4.1.3 Turnaround and Maintenance Flare Minimization Planning Tool .................................. 4-15

4.1.4 Measures to Minimize Flaring During Unplanned Maintenance .................................... 4-15

4.2 Gas Quality/Quantity Issues for Each Flare (401.4.2) .................................................................. 4-16

4.2.1 When Flaring is Likely to Occur ...................................................................................... 4-16

4.2.2 Vent Gas Recovery Systems .......................................................................................... 4-20

4.3 Recurrent failure (401.4.3) ............................................................................................................ 4-26

4.3.1 Reportable Flaring Events Attributable to the Same Process or Equipment Item ........ 4-26

4.3.2 Means to Prevent Recurrent Failure ............................................................................... 4-26

5.0 Other Information Requested by APCO to Assure Compliance (401.5) ........................................... 5-1

5.1 New Equipment Installations (404.2) .............................................................................................. 5-1
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Attachments 

Attachment A San Francisco Refinery Simplified Flare System Overview 

Attachment B San Francisco Refinery Detailed Flare Gas System Description 

Attachment C San Francisco Refinery Flare System Process Flow Diagram 

Attachment D Historical Startup / Shutdown Event Data (2000 – 2006) BUSINESS CONFIDENTIAL

Attachment E San Francisco Refinery Unit List 

Attachment F Flare Minimization Process Flowchart 

Attachment G Typical Flare Gas Recovery System 

Attachment H Flaring Event Overview, Recurring Failure Review, and Categorization 

Attachment I Storage, Treatment, & Recovery Schematic 

Attachment J DELETED – previous Attachment J now included in Attachment H

Attachment K Flare Construction BUSINESS CONFIDENTIAL portion

Attachment L Compressor Capacity & Monitoring Description BUSINESS CONFIDENTIAL portion 

Attachment M Fuel Gas System Description BUSINESS CONFIDENTIAL portion

Attachment N Cost Effectiveness Calculation Background Material 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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1.0 Flare Minimization Plan 

Regulation 12, Rule 12, was adopted by the BAAQMD in July, 2005, with the objective of reducing emissions 

from flares at petroleum refineries. This flare minimization plan for the Phillips 66, San Francisco Refinery 

(SFR) located in Rodeo, CA is consistent with progress toward that goal. It defines a series of measures that 

will lead to minimization of flaring without compromising refinery operations and practices with regard to safety. 

The key tools utilized are careful planning to minimize flaring, measuring and monitoring of flare events when 

they occur, coupled with evaluation of the cause of flaring events that do occur. Using this approach, an 

understanding of the events leading to the flaring event can then be incorporated into future planning and flare 

minimization efforts. The plan also examines the costs and benefits of potential equipment modifications to 

further increase flare gas recovery. 

1.1 Safety Statement 

This Flare Minimization plan outlines the approach that Phillips 66, San Francisco Refinery has developed to 

manage and minimize flaring events, without compromising the critical safety function of the flare system. 

Flares are first and foremost devices to ensure the safety of refinery operations and personnel. Nothing in the 

BAAQMD 12-12 rule or in this Flare Minimization Plan (FMP) should be construed to compromise refinery 

operations and practices with regards to safety. 

1.2 Executive Summary 

Shown below are graphical representations of historical flare flow and emissions from the period of 2004 to 

June 30, 2013: 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

1-4

The Rodeo Refinery installed and has utilized a Flare Gas Recovery Compressor since the mid-70’s. Historic 

practices emphasized flare minimization. Some of the recent flaring reductions have occurred due to improved 

monitoring and tracking of flare volumes as well as attributing causes to all flaring as required by BAAQMD 12-

11 and 12-12 and internal policies for incident investigation. Other efforts to minimize flare emissions have 

occurred through communication and improved awareness. Flare Key Performance Indicators (KPIs) are 

shared throughout the organization. 

High flare volumes in 2004 and 2009 were due to significant turnaround activities taking place. Key pressure 

vessels in the flare gas recovery system were removed from service for required 10 year vessel metallurgical 

inspections in 2009. In 2012 there was a large turnaround which contributed to higher than usual year to date 

flows. Following the turnaround, a relief valve leaking to the flare was discovered. An engineered solution 

was developed in order to isolate and provide an alternative relief path. In 2012 there were also a number of 

periods of fuel gas imbalance in which scrubbed fuel gas was sent to the flare. 

In the second half of 2010 the facility experienced a number of flaring events due to the unplanned shutdowns 

of the 3rd party Hydrogen supplier. Phillips 66 worked closely with the 3rd party Hydrogen supplier to improve 

reliability at their facility. Work began in 2010 and continued up until mid-2011 when the supplier made 

significant equipment reliability upgrades during a planned shutdown. 

In August 2009 three new, redundant liquid ring Flare Gas Recovery Compressors were installed and put in 

service. The purpose of the new compressors is to provide additional capacity on a consistent basis and to 

provide for backup compressor capacity. The new compressors are of a different design than the existing 

compressor and are designed to handle a wider range of composition and of flare gas. They are also less 

susceptible to liquid carryover impacts. 

Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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2.0 Flare System Information 

2.1 Background Information for Flare Systems 

Refineries process crude oil by separating it into a range of components, or fractions, and then rearranging 

those components to better match the yield of each fraction with market demand. Petroleum fractions include 

heavy oils and residual materials used to make asphalt or petroleum coke, mid range materials such as diesel 

(heating oil), jet fuel and gasoline, and lighter products such as butane, propane, and fuel gases. 

The San Francisco Refinery is organized into groups of process units, with the general goal of maximizing the 

production of transportation fuels. Each unit takes in a set of feed streams and produces a set of product 

streams with the composition changed (or upgraded) as one step toward production of an optimal mix of 

refined products. Many of these processes operate at elevated temperatures and pressures, and a critical 

element of safe design is having the capability of releasing excess pressure via relieving devices to the flare 

header to manage excess materials in a controlled manner. These separation and rearrangement processes 

also produce and/or consume materials that are gases at atmospheric pressure. As a final step in processing, 

many units provide treatment to conform to environmental specifications such as reduced sulfur levels. 

The refinery is designed and operated so that there will be a balance between the rates of gas production and 

consumption. Under normal operating conditions, essentially all gases that are produced are routed to the 

refinery fuel gas system, allowing them to be used for combustion in refinery heaters and boilers. Typical 

refinery fuel gas systems are configured so that the fuel gas header pressure is maintained by making up 

natural gas to meet the net fuel requirement. This provides a simple way to keep the system in balance so 

long as gas needs exceed the volume of gaseous products produced. Additional operational flexibility is 

typically maintained by having the ability to add butane and having the capability to adjust the rate of fuel gas 

consumption to a limited extent at the various refinery users (e.g. heaters, boilers, cogeneration units). 

A header for collection of vapor streams is included as an essential element of nearly every refinery process 

unit. These are referred to as “flare headers”, as the ultimate destination for any net excess of gas is a refinery 

flare. One of the primary functions of the flare header is safety. It provides the process unit with a controlled 

outlet for any excess vapor flow, making it an essential safety feature of every refinery. The flare header also 

has connections for equipment depressurization and purging related to maintenance turnaround, startup, and 

shutdown, as well as pressure relief devices to handle upsets, malfunctions, and emergency releases. 

Knockout drums are in place for separation of entrained liquid. This minimizes the possibility of liquid being 

carried forward to the flare or flare gas compressor. The vapor stream from the unit knockout drum is then 

routed to the refinery flare gas recovery system. 

The refinery flare system consists of a series of branch lines from various unit collection systems which join a 

main flare header. The main flare header is in turn connected to both a flare gas recovery system and to the 

flares. Normally all vapor flow to the flare header is recovered by the flare gas recovery compressor, which 

increases the pressure of the flare gas allowing it to be routed to a gas treater for removal of contaminants 

such as sulfur and then to the refinery fuel gas system. Gases that cannot be recovered or used by the flare 

gas recovery compressor, the treater(s), and/or the fuel gas system end users flows to a refinery flare so it can 

be safely disposed of by combustion. 
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Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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A flare seal drum is located at the base of each flare to serve several functions. A level of water is maintained 

in the seal drum to create a barrier which the gas must cross in order to get to the flare stack. The depth of 

liquid maintained in the seal determines the pressure that the gas must reach in the flare header before it can 

enter the flare. This creates a positive barrier between the header and the flare, ensuring that so long as the 

flare gas recovery system can keep pace with net gas production, no gas from the flare header will flow to the 

flare. It also guarantees a positive pressure at all points along the flare header, eliminating the possibility of air 

leakage into the system. Finally it provides a positive seal to isolate the flare, which is an ignition source, from 

the flare gas header and the process units. The flare systems combine two flares with different water seal 

depths, effectively “staging” operation of the flares. 

Gases exit the flare via a flare tip which is designed to promote proper combustion over a range of gas 

flowrates. Steam is used to improve mixing between air and hydrocarbon vapors at the flare tip, so as to 

improve the efficiency of combustion and reduce smoking. A continuous flow of gas to each flare is required 

for two reasons. Natural gas pilot flames are kept burning at all times at the flare tip to ignite any gas flowing 

to the flare. Additionally, a small purge gas flow is required to prevent air from flowing back into the flare stack. 

The sources of normal or base level flow to the refinery flare gas collection system are varied, but in general 

result from many small sources such as leaking relief valves, instrument purges, and pressure control for 

refinery equipment items (e.g. overhead systems for distillation columns). Added to this base load are small 

spikes in flow from routine maintenance operations, such as clearing hydrocarbon from a pump or filter by 

displacing volatiles to the flare header with nitrogen or steam. Additional flare load results from routine 

process functions, such as drum depressurization at the delayed coking unit. 

Flaring often occurs during unit startups and shutdowns or when pieces of equipment associated with units are 

taken out of service. Equipment maintenance results in the need for removal of hydrocarbon from process 

equipment and associated piping before opening, for both safety and environmental reasons including 

compliance with BAAQMD Regulation 8 Rule 10. Typical decommissioning procedures include multiple steps 

of depressurization, and purging with nitrogen or steam to the flare header. During these steps, the quality of 

the fuel gas is degraded and at times cannot be recovered. During startups, low quality gases may also be 

produced which are not desirable to be recovered. Additionally, when multiple units are shutdown, flaring can 

occur when gases are being produced at one unit and an interrelated unit which normally utilizes the gases, 

such as hydrogen, have not yet been started up. 

Although maintenance-related flows can be large, the design and sizing of refinery flare systems is without 

exception driven by the need for safe disposal of much larger quantities of gases during upsets and 

emergencies. A major emergency event, such as a total power failure, will require the safe disposal of a very 

large quantity of gas and hydrocarbon materials during a very short period of time in order to prevent a 

catastrophic increase in system pressure. The flow that the flare system could be called upon to handle during 

an event of this type is several orders of magnitude greater than the normal or baseline flowrate. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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2.2 Technical Data – Description of Flaring Systems (401.1) 

This section contains the information required under 401.1 in regards to required Technical Data. 

2.2.1 Phillips 66, San Francisco Refinery Flare & Fuel Gas Recovery System Overview 

2.2.1.1 General Flare Gas System Overview 

The Phillips 66 Rodeo Refinery has a flare gas recovery system in which liquids and gases are recovered 

the majority of the time, cleaned, and utilized as fuel gas in facility heaters and the co-generation plant. 

When gases cannot be recovered due to quality or quantity issues gases would be routed to the flare. 

There are two flares on site which function in a semi-cascading manner. The C-1 Main Flare (S-296) is 

the primary flare that is utilized. The MP-30 Flare (S-398) is used during significant events (i.e. major 

utilities failure) and during times in which the Main Flare is shut down for maintenance. The Refinery flare 

system consists of the following key components: 

 Flare gas compressor recovery system; 

 Liquid recovery system; 

 Video monitoring system; 

 Flare gas flow measurement system; 

 Automated flare gas sampling system, and 

 Smokeless flare installation. 

See Attachment A for simplified diagram of the flare gas recovery system. Attachment B contains a 

detailed description of the refinery flare gas system. Attachments K and L contain information on the 

flares and compressors, respectively. 

2.2.2 Detailed process flow diagram, PFD (401.1.1) 

See Attachment C for PFD of SFR Flare System components. The PFD contains the information required 

under 401.1.1. The PFD contains the pipelines, process unit blowdown origins, flare gas recovery system 

equipment, water seals, surge drums, knock-out pots, and other equipment associated with the flare system. 

The drawing contains the dimensions and capacities of the flare gas recovery system, compressor, water 

seals, surge drums, and knockout pots. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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2.2.3 Description of Monitoring and Control Equipment (401.1.2) 

Locations of flowmeters, temperature and pressure indicators are shown on the PFDs referenced in the section above. Locations of sample points 

and monitoring equipment are also shown on the PFDs. Listed below are the monitors and controls associated with the flare gas recovery system as 

required by 401.1.2. 

2.2.3.1 C-1 Main Flare (S-296) 

Flare System Flowmeters 

Main Flare (S-296) – Flare System Flowmeters

Tag Number Description Location Type

(e.g. sonic)

Range

(X – Y scfd)

Flare Gas Flow:

RFLRE:19FI0520 Main Flare 42" Line 42" Line - Upstream of Flare Stack Water Seal (C-1) Ultrasonic Flowmeter 0 - 60,000

RFLRE:19FI0520l. 42" Line - low range 0 - 2,000

RFLRE:19FI0520h. 42" Line - high range 0 - 60,000

RFLRE:19FI0513A. Main Flare 42" Line 42" Line - Upstream of Flare Stack Water Seal (C-1) Anemometer 10 - 110,000

RFLRE:19FI0586 Main Flare 10" Line 10" Line - From U200 & U267 Ultrasonic Flowmeter 0 - 20,000

RFLRE:19FI0586l. 10" Line - low range 0 - 2,000
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Main Flare (S-296) – Flare System Flowmeters

Tag Number Description Location Type

(e.g. sonic)

Range

(X – Y scfd)

RFLRE:19FI0586h. 10" Line - high range 0 - 20,000

RFLRE:19FI0513. Main Flare 10" Line 10" Line - From U200 & U267 Anemometer 10 - 6000

Purge Gas Flow:

RFLRE:19FIC0510. Natural Gas Purge Purge into Flare Stack (C-1) Orifice Plate 0 - 930 MSCFD

RFLRE:19FI0521. Natural Gas Purge Purge into Flare Stack (C-1) Orifice Plate 0 - 25 MSCFD

1

 Does not meet 12-11 accuracy requirements for all ranges. Utilized as a backup meter, when necessary. 

Continuous Recording Instruments 

Main Flare (S-296) – Continuous Recording Instruments

Tag Number Description Location Instrument Type

Pressure

RFLRE:19PIC0530. 200:19F-1 PRESSURE 

Refinery Relief Blowdown Drum (F-1) 

Pressure Pressure Indicator

RFLRE:19PI0520.

42" Line - Upstream of Flare Stack Water Seal (C-1) 

(integrated with ultrasonic flowmeter)

42" Line - Upstream of Flare Stack Water 

Seal (C-1) Pressure Indicator
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Main Flare (S-296) – Continuous Recording Instruments

Tag Number Description Location Instrument Type

RFLRE:19PI0586. Main Flare 10" Line (integrated with ultrasonic flowmeter) 10" Line - From U200 & U267 Pressure Indicator

Level

RFLRE:19LIC0512. 200:19F-3 Water Seal Level 19F-3 Water Seal

Water Seal Level 

Indicator

RFLRE:19LI0508. 200:19C-1 Flare Stack Water Seal Level 19C-1 Flare Stack

Water Seal Level 

Indicator

Temperature

RFLRE:19TI0520. 200:Flare Blowdown Line Temperature

42" Line - Upstream of Flare Stack Water 

Seal (C-1) Temperature

RFLRE:19TI0586. 200:10” Line Flare Blowdown Line Temperature 10" Line - From U200 & U267 Temperature

RFLRE:19TI0528A. 200:19C-1 Flame Sensor Flare Tip Thermocouple

RFLRE:19TI0528B. 200:19C-1 Flame Sensor Flare Tip Thermocouple
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Main Flare (S-296) – Continuous Recording Instruments

Tag Number Description Location Instrument Type

RFLRE:19TI0528C. 200:19C-1 Flame Sensor Flare Tip Thermocouple

RFLRE:19TI0528D. 200:19C-1 Flame Sensor Flare Tip Thermocouple

Analyzers

RFLRE:19AI0520. 42" Line - Molecular Weight 

42" Line - Upstream of Flare Stack Water 

Seal (C-1) MW Indicator

RFLRE:19AI0586. 10” Line – Molecular Weight 10" Line - From U200 & U267 MW Indicator

RFLRE:19AI0501. 42" Line - Oxygen

42" Line - Upstream of Flare Stack Water 

Seal (C-1)

Oxygen Content 

Indicator
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

2-8

2.2.3.2 MP-30 Flare (S-398) 

Flare System Flowmeters 

MP-30 Flare (S-398) – Flare System Flowmeters

Tag Number Description Location Type

(e.g. sonic)

Range

(X – Y scfd)

Flare Gas Flow:

RFLRE:19FI0584. MP30 48" Line

48" Line - Downstream of Water Seal (F604) Ultrasonic Flowmeter

RFLRE:19FI0584L. 48" Line - low range 0 - 2,000

RFLRE:19FI0584H. 48" Line - high range 0 - 35,070

RFLRE:19FI0585. 36" Line

36" Line - from Refinery Blowdown Line (F2) Ultrasonic Flowmeter 0 - 120,000

RFLRE:19FI0585L. 36" Line – low range

RFLRE:19FI0585H. 36" Line – high range

Purge Gas Flow

RFLRE:19FIC0511. Natural Gas Purge Orifice Plate 0 - 930 MSCFD

1

 Does not meet 12-11 accuracy requirements for all ranges. Utilized as a backup meter, when necessary. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

2-9

Continuous Recording Instruments 

MP-30 Flare (S-398) – Continuous Recording Instruments

Tag Number Description Location Instrument Type

Pressure

R230:PI6014. 230F-600 Blowdown Drum 

Upstream of MP30 Relief Blowdown Drum (F600)Pressure Indicator

RFLRE:19PI0584. MP30 48" Line 48" Line - Downstream of Water Seal (F-604) Pressure Indicator

Level

R230:LIC654A.

230:F-604 MP30 Flare System Water Seal Make Up H2O 

Level F-604 Vessel

R230:LIC654B.

230F-604 MP30 Flare System Water Seal H2O Drain 

Level F-604 Vessel

RFLRE:19LI0509. 200:(C-602) Flare Stack Water Seal MP30 Flare Stack (C-602) Water Seal

Water Seal Level 

Indicator

Temperature:

RFLRE:19TI0584. 200:MP30 Flare Vapor Temperature 48" Line - Downstream of Water Seal (F-604) Temperature
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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MP-30 Flare (S-398) – Continuous Recording Instruments

Tag Number Description Location Instrument Type

RFLRE:19TI0529A. 200:(C-602) NW Flare Pilot Flare Tip Thermocouple

RFLRE:19TI0529B. 200:(C-602) NE Flare Pilot Flare Tip Thermocouple

RFLRE:19TI0529C. 200:(C-602) SE Flare Pilot Flare Tip Thermocouple

RFLRE:19TI0529D. 200:(C-602) SW Flare Pilot Flare Tip Thermocouple

Analyzers

RFLRE:19AI0584. 200:MP30 Flare Vapor Molecular Weight 48" Line - Downstream of Water Seal (F-604)

Molecular Weight 

Indicator

RFLRE:19AI0502. 200:MP30 Flare Oxygen 48" Line - Downstream of Water Seal (F-604)

Oxygen Content 

Indicator
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Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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2.2.3.3 Unit 200 Flare Gas Recovery Compressor (G-503) 

See Attachment C and L for diagrams showing locations of meters and analyzers. 

Flowmeters 

Flare Gas Recovery Compressor (G-503) Flowmeters

Tag Number Description Location Type

(e.g. sonic)

Range

(X – Y MMSCFD)

Gas Flow:

R200:FI_506B. Flare Gas Recovery Compressor (G-503) Downstream of Salt Water Exchanger E-510 Orifice Plate 0 – 4.64

Monitors and Instruments 

 Note: All setpoints and alarms are subject to change. These values may change as operational or safety optimization opportunities are identified. 

This list contains the values at the time of publication. 

Flare Gas Recovery Compressor (G-503) Monitors and Instruments

Flare Gas Recovery Compressor (G-503) Monitors & Instruments

Tag Number Description Location Att Setpoint or Alarms

Pressure

R200:PI0509. 200:F-509 Separator Overhead F-509 Separator Overhead C 0.5 psig Alarm 

0.0 psig – Action automatic unloading of 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Flare Gas Recovery Compressor (G-503) Monitors & Instruments

Tag Number Description Location Att Setpoint or Alarms

compressor cylinders

R200:PI0513. 200:G-503 1st Stage Downstream of 1st Stage C None

R200:PI0515. 200:G-503 2nd Stage Downstream of 2nd Stage C None

R200:PI0514. 200:G-503 Frame Oil Downstream of Frame Oil Filters L None

R200 – PAL 575 200: G-503 Frame Oil (Local Indication) Downstream of Frame Oil Filters L Shutdown Compressor - < 16 psig

Temperature

R200:TI0509. 200:F-509 Separator Overhead F-509 Separator Overhead C Alarm – 150 o

F

R200:TI0511. 200:G-503 Flare Gas Recovery Compressor 

1st Stage 

Downstream of 1st Stage C None

R200:TI0513. 200:G-503 Flare Gas Recovery Compressor 

2nd Stage 

Downstream of 2nd Stage C Alarm – 300 o

F

Shutdown - 350 oF 

R200:TI0510. 200:G-503 Tempered Water Upstream of Exchanger E-512 L None

R200:TI0512. 200:G-503 Frame Oil Downstream of Frame Oil Pump L None

Analyzer

R200:AI0504. 200:G-503 Discharge Specific Gravity (SG) Compressor Discharge L Alarm Low SG – 0.60
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Flare Gas Recovery Compressor (G-503) Monitors & Instruments

Tag Number Description Location Att Setpoint or Alarms

Alarm High SG – 1.12

R200 - AE503. 200:G-503 Compressor Discharge Oxygen 

Analyzer 

Compressor Discharge L Alarm – 1.5% O2

Level Indicator

R200:L 509 200:F-509 Level Indicator (Local Indicator) F-509 Low Pressure Separator L Level is monitored by Operator. 

R200 – LAH 510 200:F-509 Level Shutdown (Local Indicator) F-509 Low Pressure Separator L Shutdown Compressor – 30% Level

R200 – LAH 537 200:F-503A Level Shutdown (Local 

Indicator)

F-503A G-503 First Stage Suction 

Pulsation Dampener L Shutdown Compressor – 75% Level

R200 – LAH 538 200:F-503C Level Shutdown (Local 

Indicator)

F-503C: G-503 Second Station 

Suction Pulsation Dampener L Shutdown Compressor – 75% Level

R200 – LAH 541 200:F-503E Level Shutdown (Local 

Indicator)

F-503E: G-503 Second Stage Suction 

Knock Out Pot L Shutdown Compressor – 90% Level
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Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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2.2.3.4 Unit 200 Liquid Ring Flare Gas Recovery Compressors (G-540A/B/C) 

Note: All data in this section is preliminary and subject to change. These values and meter numbers may change as operational or safety 

optimization opportunities are identified. The Compressor is undergoing a Process Hazard Analysis (PHA) at the time of the FMP update, which 

may result in additional changes. At this time all ranges and setpoints are being developed and thus are shown as pending. 

See Attachment C and L for diagrams showing locations of meters and analyzers. 

Flowmeters 

Liquid Ring Flare Gas Recovery Compressor (G-540 A/B/C) Flowmeters

Tag Number Description Location Type

(e.g. sonic)

Range

(X – Y MMSCFD)

Gas Flow:

FI-1573 Liquid Ring Flare Gas Recovery Compressor 

(G-540A, B, & C) Flow Downstream of F-540 Gas Separator Drum Orifice 0 – 6,000 MSCFD

Service Liquid Flow:

FI-1544 (A)

FI-1545 (B)

FI-1546 (C)

Compressor Service Liquid Flow Indication, 

Alarm, & Shutdown To Compressor Orifice

0-200 gpm

Alarms:

Low Low 100 (SD)

Low 110 gpm

High 150 gpm

Monitors and Instruments 
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Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

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Note: All data in this section is preliminary and subject to change. These values may change as operational or safety optimization opportunities are 

identified. The Compressor is undergoing a Process Hazard Analysis (PHA) at the time of the FMP update, which may result in additional changes. 

Liquid Ring Flare Gas Recovery Compressor (G-540 A/B/C) Monitors and Instruments

Liquid Ring Flare Gas Recovery Compressor (G-540 A/B/C) Monitors & Instruments

Tag Number Description Location Att Setpoint or Alarms

Pressure

PI-1541 High Pressure Alarm and Shutdown Flare Gas to Compressor C Alarm High 115.3 psig

Alarm High High 125.3 psig (SD)

PI-1543 Low & High Suction Pressure Alarm Flare Gas to Compressor C Alarm High 18.5 psia

Alarm Low 14.7 psia

PI-1881 (A)

PI-1882 (B)

PI-1883 (C)

Compressor Dual Seal Low Pressure Alarm Compressor Seal C Alarm Low 50 psig

Temperature

TI-1540 Suction Temperature Alarm and Shutdown Compressor Suction C Alarm High 150 o

F

Alarm High High 170 oF (SD)

TI – 1547 (A) Compressor Temperature Discharge Gas 

Temperature Indication, Alarm, & Shutdown

Discharge of Compressor C Alarm High 150 o

F
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

2-16

Liquid Ring Flare Gas Recovery Compressor (G-540 A/B/C) Monitors & Instruments

Tag Number Description Location Att Setpoint or Alarms

TI-1548 (B)

TI-1549 (C)

Alarm High High 170 oF (SD)

TAH-1545 Service Water Temperature Alarm Service Water to Compressor C Alarm High 150 o

F

Analyzer

VI-1541 (A)

VI-1542 (B)

VI-1543 (C)

Compressor Vibration Alarms Connected to compressor C High Alarm 0.4 in/second

High High Alarm 0.6 in/second (SD)

Level Indicator

LI-1881 (A)

LI-1882 (B)

LI-1883 (C)

Compressor Dual Seal Low Level Alarm Compressor Seal C Alarm Low 35%

LAHH-1543 Compressor Suction Liquid Level Alarm and 

Shutdown

Compressor Suction C Alarm Low 32%

LAHH-1540 Gas Separator Drum Liquid Level Alarm & F-540 Gas Separator Drum C Alarm High 85% 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

2-17

Liquid Ring Flare Gas Recovery Compressor (G-540 A/B/C) Monitors & Instruments

Tag Number Description Location Att Setpoint or Alarms

Shutdown Alarm High High 99% (SD)

Alarm Low 15.2%

Alarm Low Low 4.3% (SD)

LAH-1542 Gas Separator High Level Alarm F-540 Gas Separator Drum Blowdown 

Side C Alarm Low 10%
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-1

3.0 Reductions & Planned Reductions 

3.1 Reductions Previously Realized (401.2) 

Changes or Equipment in Place prior to 2003 which Prevent or Minimize Flaring

Due to economics and community concern, the refinery has a long history of flare minimization practices. The Flare Gas Recovery Compressor (G-503) 

was installed in the early 70’s. Up until 2000 the facility utilized a ground flare that was located near I-80. When the flare was utilized the flame was very 

visible from the highway. Prior to 2000 the Refinery Management had expectations for Operations to increase facility reliability to prevent upsets and to 

develop a means to conduct Startups & Shutdowns with minimal flaring. Those practices remain in place today. 

Another item of note is the existing Sulfur Recovery Unit system. The facility has three Sulfur Recovery Units (U235, 236, & 238) which can provide for 

significant redundancy. This has allowed the facility to experience only one instance of acid gas flaring in the past five years from a complete refinery 

shutdown. 

In 1999, the Unit 200 Wet Gas Compressor (G-501) seal was upgraded to a dry seal system. Previously, the seal would fail every 12 – 24 months which 

required a seal replacement. The seal replacement would take approximately 5 – 6 days and flaring would occur throughout this period. After the dry 

seals were installed, the on-line performance of the Compressor significantly improved. The compressor has not experienced a seal failure since the seal 

upgrade. The upgrade has resulted in a reduction of approximately 4 - 6 MMSCFD of gas flared for approximately 5 days every 12 – 24 months. 

Starting in 2003 weekly updates and quarterly Key Performance Indicators (KPIs) are reported & distributed with Flaring History to all Refinery employees. 

The content and distribution of the KPIs is described in Environmental Services Department (ESD) Policy and Procedure 1.1 “Environmental KPIs”. The 

KPIs issued show trends and causes for flaring events and other reportable environmental events. The KPIs helps reduce flaring by showing all 

employees this is important in that it is tracked and communicated. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-2

Changes Made to Reduce Flare Emissions 

May 30, 2003 to June 30, 2010 

In accordance with 401.2, listed below are reductions that have been made to reduce flaring over the past 5 years. Many of the items listed are 

Management System improvements. Although some of these improvements are difficult to quantify, they have had a significant impact on minimizing 

flaring. 

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

Procedures: 

3

rd Qtr 2005

1

st Qtr 2013

(updated)

Refinery Policy & Procedure (P&P) 6.05-05 “Flare Monitoring & Reporting” -

 Procedure created to communicate flare sampling, monitoring, & root cause analysis requirements. The contents of the procedure include Responsibilities for personnel at the refinery in respect to flare compliance activities.

 Sets standards for accountability in regards to monitoring, reporting, and preventing recurrence.

 Criteria for agency release reporting (i.e. CA OES, CCC HSD, BAAQMD, NRC, etc.) for flare events.

 Summary of BAAQMD 12-11 flare monitoring requirements (e.g. video, flare flow, sampling),

 Summary of various regulatory reporting requirements.

 Criteria for incident investigation in respect to BAAQMD regulations and the Phillips 66 EPA Consent Decree.

 Means to track flare events with P66 Corporate incident tracking system.

This procedure reduces flaring by demonstrating to employees that those who have defined roles must follow the steps outlined in 

the procedure and that these activities are important. It also mandates expectation for consistent evaluation of flaring events & 

development of corrective actions to prevent recurrence. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-3

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

2

nd Qtr 2005

3

rd Qtr 2013

(updated)

4

th Qtr 2009 & 

on-going 

(training)

Refinery Policy & Procedure (P&P) 10.00-01 “Incident Investigation” & Incident Investigation Training - P&P 10.00-01

establishes responsibilities, event triggers, and typical means for conducting incident investigations. The contents of the procedure 

include:

 Definition of the types of incidents that can occur (i.e. minor, serious, major).

 Responsibilities for employees that discover an incident and who must complete tasks in respect to incident investigations.

 Establishes accountability. 

 Description of whom and when personnel should be notified of incidents. 

 Defines who should participate in an incident investigation.

 Description of the investigation process.

 How the findings of an incident investigation are reviewed. 

 How findings of an incident investigation should be communicated to employees and Phillips 66 sister refineries.

 How corrective actions should be addressed. 

The existing procedure was updated to denote environmental related events requiring incident investigation. Flaring events are 

identified in the procedure. P&P 6-7 cross references P&P 5-1. This procedure reduces flaring by demonstrating to employees that 

those who have defined roles must follow the steps outlined in the procedure and that these activities are important. Without this 

procedure incidents which occur would not necessarily be investigated and addressed in a consistent fashion. The main value in 

flaring reduction is that this procedure requires that corrective actions be developed and addressed for incidents. 

To ensure good quality investigations are conducted the facility identified key personnel to receive incident investigation training. 

Training ensured that first reporting (basic who, what, when, where) captures critical initial information. The training also ensures 

that investigations receive the necessary level of investigation and get to defined root causes. Additional work is on-going to 

improve and maintain the quality of the investigations conducted. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-4

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

Procedures: 

2

nd Qtr 2003 

(approx.)

2

nd Qtr 2013

(updated)

Emergency Operating Procedure EOP-1 “Guidelines for Standard Public Address System Announcements” - Enhanced 

Communication within the Facility when Flare Gas Recovery System Load Increases – For example, the facility Public 

Announcement system is currently used if an increase in the compressor load occurs. This requires process units to review their 

operations in order to find the cause of the increase and take actions to mitigate. This prevents some flaring events from occurring 

in that discretionary gases, such as nitrogen purges and hydrogen, sent to the flare gas recovery system can be scheduled around 

peak loading periods to maximize gases recovered. Coordination of these activities is done through Operators at various units and 

Shift Supervisors working together to coordinate their activities in respect to use of the flare gas blowdown system. This minimizes 

flaring by consciously identify periods in which the blowdown system can be utilized without overloading the flare gas recovery 

compressor. This results in less periods of flaring due to brief peak loading of the compressor. In addition to this process, the 

Public Announcement system is utilized during planned and emergency events as specified in some of the Unit 200 procedures 

(ESOP & NSOP-various-200) to improve equipment use and switching. For example, if the Flare Gas Recovery Compressor (G503) is put into Wet Gas or Odor Abatement service the public announcement system will be utilized to notify plant personnel of the 

change in operation. Listed below is a partial list of some of the key procedures where the public announcement system use is 

referenced: 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-5

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

Normal Operating Procedures

 NSOP-001-200 Relief “U200 Table of Safe Operating Limits”

 NSOP-306-200 “Light Ends Shutdown, Unit Running”

 NSOP-704-200 “G-501 Compressor Shutdown & Clean-up”

 NSOP-707-200 “G-503 Flare Compressor Planned Shutdown”

 NSOP-709-200 G-503 Flare Compressor Start-up

 NSOP-710-200 “Switching G-503 to Wet Gas Service”

 NSOP-711-200 “Switching G-503 from Wet Gas to Flare Service”

 NSOP-716-200 “Switching G-503 to Odor Abatement Service”

 NSOP 717-200 “G-503 Flare Compressor Circulation”

Emergency Operating Procedures

 ESOP-700-200 “Loss of G-501 Compressor”

 ESOP-701-200 “G-503 Compressor Failure”

1

st Qtr 2006 Normal Safe Operating Procedure (NSOP) NSOP-900-200-1 “Drum Switching” Operational Improvement 

Flaring can occur during Unit 200 Coker drum cooling due to brief peak loading to the flare gas recovery compressor. Changes 

have been made which reduced the instances of this flaring. The procedure associated with drum cooling has been revised. The 

process of Drum Switching involves numerous steps. The procedure was revised to clearly indicate the sequencing of steps 

involving cooling of the drum and the details surrounding each step. This ensures consistency and repeatability of this activity. In 

the past the steps were not as clearly defined. This resulted in periods of flaring with some Shifts and no flaring while other Shifts 

were conducting the same activity. By establishing specific steps this eliminates variability and prevents flaring. Additionally, 

communication around flare gas compressor loading has been enhanced. This has minimized the amount of instances that flaring 

occurs during drum cooling. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-6

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

4

th Qtr 2006 & 

On-Going

Turnaround Planning Flare Minimization - as part of the FMP, a formal process is utilized for turnarounds. This process had 

been performed in a consistent manner and lessons learned captured and includes the following: 

 Establishing Personnel Responsibilities for Various Planning Steps

 Conducting Review of Potential Flare Minimization Techniques Prior to Turnaround

 Documenting Flare Minimization Turnaround Planning Review

 Conducting a Post Turnaround Review of Comparison of expected and actual flaring. Discussion of lessons learned and 

opportunities for improvement

 Documenting lessons learned and opportunities for improvement.

 Incorporating elements regarding flare minimization and communication of flaring in operating procedures.

Identifying corrective actions and taking action to minimize flaring in future turnarounds. 

3

rd Qtr 

2003(approx.)

Maintenance Startup / Shutdown Coordination – Coordinated the shutdown and startup of units and major pieces of equipment 

during periods of high flare gas compressor loading in order to minimize total period of flaring. This coordination includes examining 

the periods when flaring is expected to occur and targets accomplishing shutdown and startup work in similar fashion while 

minimizing flaring. Some examples include emphasis on communication with Unit 200 operators when going to blowdown to work 

around drum switching, conducting G-503 Flare Gas Recovery Compressor maintenance when major gas producers are shutdown, 

staging of nitrogen purging of vessels to minimize the total volume of nitrogen going to blowdown. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-7

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

3

rd Qtr 2013 Loss of Emergency Gas Flow to Air Liquide (REOP-25-OPS) - A new Refinery Emergency Operating Procedure (REOP) was 

developed in response to the June 10, 2013 flaring event after loss of RFG-A to Air Liquide. This procedure will help to reduce the 

flaring of sour flare gas by improved management of the RFG-A gas at Unit 240 Plant 3 and it should also reduce the overall flaring 

time for this type of event with improved management of the Flare Gas recovery compressors.

Equipment 

3

rd Qtr 2003

4

th Qtr 2010

Flow Meter Installation on Main & MP30 Flares – Flow meter installation per BAAQMD Regulation 12-11-501. The installation of 

the flow meters provides for enhanced recognition of flaring events. The flow meters help reduce flaring by providing an accurate 

means to measure and provide indication as to when flaring is occurring. The flow meters are especially useful for small flaring 

events which may not be detectable from visual flare stack monitoring only. The meters help to track and record all instances of 

flaring as well as giving Unit Operators immediate indication that flaring is occurring so that they can take action to reduce flaring. 

Added an additional ultrasonic meter to a line that was previously only put in service every 5 -10 years. This meter (RFLRE:FI0585) 

went into service December 2010. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-8

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

2

nd Qtr 2005 Unit 250 Diesel Hydrotreater Design – This unit was designed with a Zero Power Failure Relief Load. This unit operates under 

pressure. Typically, hydrotreaters would automatically relieve to a refinery flare blowdown system in the event of a power failure to 

protect equipment from overpressuring. This unit was designed in a manner that prevents the need for the unit to vent to the flare 

during a power failure or other loss of utilities. Listed below are the primary means this design was accomplished. . 

 High design pressure of reaction system equipment to contain settle out pressure in event of a power failure.

 No automatic reaction system depressuring.

 Designed with a manually activated depressuring system.

 Product stripper was designed as a steam stripper, eliminating a fired heater and reducing power failure relief load.

 Hot Separator was designed with the capacity to contain all oil from the reactors, minimizing impact on the Product Stripper 

in a power failure.

Dec. 2006 

Completed

Addition of Unit 110 Atmospheric Vent for Hydrogen - Benefit is to vent hydrogen during startup, shutdown, and/or during 

hydrogen supply imbalances to the atmosphere rather than sending it to the flare. When hydrogen is sent to the flare this results in 

the shutdown of the flare compressor & flaring of all materials that have been sent to the blowdown system. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-9

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

Milestones 

(approximate)

 October 

2008 –

Construction 

Start

 August 

2009 

Startup 

(actual)

Installation of Additional Flare Gas Recovery Compressors G-540A/B/C -– The Clean Fuels Expansion Project (CFEP) 

determined a new Odor Abatement (OA) Compressor would be required to maintain reliability of the OA system during peak loading 

periods. Initially, the new compressor was to be designed in order to serve in both OA and Flare Gas Recovery Compressor 

service in order to leverage the use of the new OA compressor. After detailed engineering evaluation and analysis it was 

determined to install separate compressors in each service. The main benefits will be to allow for additional Flare Gas Recovery 

Compressor capacity on a consistent basis and to provide for backup compressor capacity. The new Flare Gas Recovery 

Compressor was also designed to handle the varying composition of flare gas. The Liquid Ring compressor installed is actually a 

set of 3 compressors that can be used in conjunction with each other or separately. Some of the identified benefits of the Liquid 

Ring compressor are reliability and it can handle gas quality variations and liquid carryover much more readily than other types of 

compressors. The total capacity of the three liquid ring compressors is 4.8 MMSCF/D. The new compressors will eliminate the 

majority of flaring associated with brief peak loading and eliminate flaring that occurs when the G-503 Flare Gas Recovery 

Compressor is taken out of service for routine maintenance. The compressor and associated fuel gas system will still be limited by 

gas quality and heating value requirements of the downstream fuel gas combustion sources. 

The G-503 compressor and one of the Liquid Ring Compressors will be operated at all times with the exception of planned 

maintenance periods. This will allow for increased capacity in the flare gas recovery compressor system and will be able to pick up 

swings that occur during brief peak loading on the existing compressor. The 3 new Liquid Ring Flare Gas Compressors will be 

operated simultaneously when the G-503 compressor is shutdown for planned maintenance. The operational philosophy of this 

system of compressors will incorporate measures to minimize periods of no flare gas recovery. That will be done by optimizing up 

time of flare gas recovery by developing operating and maintenance procedures which focus on compressor up time. The system 

operation may change as operating procedures are developed and actual operation experience is gained. 

As stated above, a separate Odor Abatement Compressor was installed. The new odor abatement compressor will add an 

additional compressor to the three currently available. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-10

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

2

nd Qtr 2015 

target

Propane Recovery Project – permit application No. 25199 has been submitted to BAAQMD and is undergoing review. The 

purpose of the project is to recovery propane and butane from the refinery fuel gas (RFG). Another aspect of the project is to 

remove a portion of the sulfur compounds from the remaining Refinery Fuel Gas (RFG). From a flaring standpoint, this project is 

beneficial in reducing overall volume of Refinery Fuel Gas. The propane and butane will be replaced by natural gas provided by 

PG&E. Because it is relatively easy to reduce the amount of natural gas being imported, the likelihood of flaring due to fuel gas 

imbalance will be reduced. In addition, by reducing the concentration of sulfur in fuel gas this removes some of the restrictions on 

where fuel gas can be routed which further helps to minimize and reduce periods of potential fuel gas imbalance.

Processes: 

3

rd Qtr 2003 Monthly Flare Event Reporting - BAAQMD Regulation 12-11-401 requires reporting of all flaring. The requirement to report all 

events has required enhanced recognition for all flaring events and establishes the history of all flaring events. Reporting of flaring 

events requires the refinery to recognize all flaring events and track them. These records are used to monitor trends of flaring 

events as described in the reference to monthly Key Performance Indicator (KPI) tracking: ESD Policy & Procedure 1.1 “Monthly 

Environmental KPIs” The data is also used for root cause analysis and to identify ways to take action to prevent recurrent flaring. 

4

th Qtr 2003 Flare Root Cause Analysis Reporting for Land Use Permit – Under the facility Land Use Permit (LP02-2095) an agreement was 

made and a condition (S7) was imposed that required the facility to conduct a root cause analysis of any flaring event at the refinery 

that exceeded 500,000 SCF. The analysis was required to be provided to a Non-Governmental Organization (NGO) and a copy 

submitted to the BAAQMD. This reporting reduces flaring by requiring the facility to identify causes of flaring which brings focus to 

potential failures, repetitive activities, and potential trends. This requirement was in place for Rodeo prior to the 12-12 root cause 

requirement. This condition has now expired. This reporting required the refinery to focus on the cause of events 1-1/2 years prior 

to the adoption of 12-12. It also caused the facility to start examining causes of flaring events in order to take action to prevent 

recurrence. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-11

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

3

rd Qtr 2005

3

rd Qtr 2007 

(Land Use 

Permit addition)

Flare Root Cause Analysis Reporting BAAQMD – Reporting of root cause of flaring events which exceeded a volume of 500,000 

SCF/D or 500 lbs SO2 (4/06) as required by BAAQMD Regulation 12-12-406. Reporting of root cause required the facility to take a 

closer look at flaring events and ensure that corrective actions had been appropriately identified to prevent recurrence. This 

reporting reduces flaring by requiring the facility to identify causes of flaring which brings focus to potential failures, repetitive 

activities, and potential trends. Prevention measures identified to prevent recurrent flaring must also be identified and reported to 

the BAAQMD. As part of the root cause analysis, actions are defined and taken to prevent recurrence. 

Under the Clean Fuels Expansion Project (CFEP) Land Use Permit 05-2048 Community Working Group (CWG) agreement the 

flare Root Cause Analysis reports are required to be provided to the CWG. The RCAs are provided to the CWG when the report is 

transmitted to BAAQMD. 

1

st Qtr 2004 Operational Improvement – Monitoring: 

Flare System Diagnostic Tools – Developed tools for better flare flow & monitoring capability.

 PI Process Book Flare System Overviews – tool was developed to provide Supervision & Operations Engineers an overview of 

the flare system operation. This is useful when load to the flare increases or following a flaring event to better understand 

triggers for flaring.

 Flare Flow Spreadsheet – spreadsheet was developed to be used by Shift Superintendent to monitor flow to the flare in relation 

to Federal and BAAQMD reporting requirements. The spreadsheet is referenced in Refinery P&P 6-7 “Flare Monitoring & 

Reporting”

The use of this tool helps reduce flaring by letting parties who are responsible for flare reporting and incident investigation 

management know the magnitude and characteristics of a particular flaring event. It also provides a good snapshot as to when

there is a change in the baseline load to the compressor which, if continuing to rise can result in flaring. In some cases, where the 

cause is not immediately known this can help give insight to the cause which can result in quicker flare minimization. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-12

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

3

rd Qtr 2005

3

rd Qtr 2009 

(update)

Operational Improvement – Drum Cooling

Flaring can occur during Unit 200 Coker drum cooling due to brief peak loading to the flare gas recovery compressor. Changes 

have been made which reduced the instances of this flaring. 

Communication Enhancements – Increased inter and intra departmental communication during regular periods of high flare gas 

recovery compressor loading association with Unit 200 Coker drum cooling. This reduces flaring in cases where activities in which 

discretionary gasses (i.e. small volumes of nitrogen, hydrogen, etc.) are being sent to blowdown can be coordinated. For example, 

if one unit needs to purge equipment with small amounts of nitrogen which can be absorbed by flare gas recovery this activity could 

potentially be delayed during Coker drum cooling. Rather then two activities which add increased volume to the flare gas recovery 

compressor occurring at one time they can be staggered to prevent exceeding the capacity of the flare gas recovery compressor. 

Since the Coker drum cooling process has a routine schedule, this communication occurs when the unit that needs to send 

discretionary gasses to blowdown contacts the Operators at Unit 200 in order to coordinate their activities. This communication is 

important since Operators from various units are currently housed in separate control rooms. As referenced in the Central Control 

Room item listed under Planned Reductions, this communication will more easily occur when Operators are housed in a central 

location. 

Equipment installation – the addition of the new, redundant flare gas recovery compressor G-540 A/B/C increases the capacity of 

the flare gas recovery system during most operating periods. This has further prevented and minimized the number and volume of

small flaring events that occur during drum cools.

1

sr 2007

2

nd Qtr 2009 

(update)

Improved Incident Investigation – Smaller Flare Activity (<500,000 SCFD and/or <500 lbs SO2)

Personnel from the Environmental Department and Operations meet on a periodic basis to review all flaring activity to determine 

potential cause of all flaring events. These regular meetings reinforce that identifying and minimizing all flaring events is important. 

For example, the PI Process Book Flare System Overview tool that was listed in this section under Operational Improvement -

Monitoring has been improved over time in order to more quickly identify the source of smaller flaring events in different flare 

headers systems. See Attachment H for analysis of smaller flare events. A detailed analysis was initially performed as part of the 

2008 FMP update. The results showed small events account for on average 5-10% total annual flow. The new Flare Gas 

Recovery Compressor G-540 A/B/C has mitigated some of the smaller events.
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-13

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

3

rd Qtr 2010 Unicracker Plant 4 Hydrogen Plant Shutdown Procedure – a new procedure for shutting down the Plant 4 Hydrogen Plant was 

implemented in order to reduce flaring. The revised procedure was successful and no flaring occurred during a recent shutdown. 

Based on past experience it was estimated this reduced 4-6 hours of flaring of gasses. This procedure was successfully 

implemented in 2011 as well. This Hydrogen Plant is now shutdown. 

3

rd Qtr 2010 Installation of Backup Lube Mist System for the G-540 Flare Gas Compressors – a backup lube oil mist system was installed 

for the new Flare Gas Recovery Compressors. The purpose of this system is to ensure that continuous lubrication is available to 

each of the compressors. If an oil mist system alarm sounds or failure occurs the backup compressor can be utilized without 

compressor operation loss. 

3

rd Qtr 2010 Operational Improvement – Monitoring: 

Fuel System Diagnostic Tools – Developed tools for better fuel flow monitoring & optimization capability.

 PI Process Book Fuel Flow System Overviews – tool was developed to provide Supervision & Operations Engineers an 

overview of the fuel system operation with key parameters displayed. The key parameters shown include fuel gas produced, 

natural gas imported, sulfur levels in fuel, fuel consumer demand. 

 PI Process Book Fuel Imbalance Optimization Tool – an online tool was developed which provide recommended steps for 

mitigating fuel gas imbalance. The tool lists the steps and limitations for each step which need to be optimized. ”

The use of this tool helps to reduce flaring caused due to fuel gas imbalance by providing tools & a multi unit overview of key 

parameters. Users of the tool can plot trends of key parameters. 

1

st Qtr 2011 & 

On-Going

Unit 110 Hydrogen Plant Startups and Shutdowns – changes have been made in how Unit 110 startups and shutdowns, when 

conditions warrant, to minimize flaring. For example, a shutdown takes place and human entry is not required, the unit may be 

purged with plant Nitrogen rather than hot, pumped Nitrogen. This allows for the Nitrogen to slowly be swept into the blowdown 

system, allowing for the Fuel Gas Recovery Compressor to remain operating. For some shutdowns the amount of flaring has been 

eliminated vs. a previous average period of of 5-1/2 hours. Unit startups have also been reduced from a period of approximately 2-

1/2 hours in comparison to the previous duration of 5 hours. Throughout 2011 and 2012 efforts to minimize Unit 110 related flaring 

has continued by examining steps related to startup and shutdown activities.
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

3-14

Changes Made to Reduce Flare Emissions

(May 30, 2003 – June 30, 2010)

Year Installed 

or 

Implemented

Equipment Item Added, Process Changed or Procedure Implemented

4

th Quarter 2012 Flare System Rundown List (R-065) – A checklist was developed for looking for possible sources (lines and monitoring tags) at 

operating units which may be contributing high base load to the flare compressors and/or directly to the flare. This checklist is to be 

used by Shift Superintendents, Head Operators, and Unit Supervisors to pinpoint and locate higher than normal flows. 
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3.2 Planned Reductions (401.3) 

The table below summarizes the actions currently planned to effect further reductions in refinery flaring. 

Planned Actions for Reducing Flaring 

Planned Actions for Reducing Flaring

Planned Date of 

Installation/ 

Implementation

Equipment Item to be Added, Process to be Changed or Procedure to be Implemented

Procedure: 

Equipment

Phased 2006 – 2013

 2006 – MP30 (complete)

 2009 – Sulfur Plant

(complete)

 2009 – UK (complete)

 2011 – U200/ U267/U250

(complete)

 2014 - U110 & SPP

 2015 – U100 & Bulk

(completion dates listed)

Construction & Operation of Central Control Room (CCR) The CCR has been built and is currently contains the 

controls for the MP30 Complex, the Sulfur Plant, the Unicracker Complex, Unit 200 and Units 215/233/250/267. The CCR 

now houses all of the process unit Boardmen. The Boardmen for the utility and bulk movement units will be moved into 

the CCR by 2015. The Boardmen are the Operators that oversee the unit operation and provide direction to Outside 

Operators. The Boardmen were housed in Control Rooms at their individual units The CCR brings all the Boardmen 

together in one large control room. There is an inherent value in having the Boardmen housed in one Control Room that 

will minimize flaring. Improved communication will occur and better awareness of each unit’s impact upon another unit’s 

operation will occur. In addition, optimization by Operations Supervision will be simplified when the unit controls are 

housed in one Control Room. An example of this benefit is that if one unit is nitrogen purging a vessel which will add 

loading to the U200 G-503 Flare Gas Recovery Compressor the Boardman can immediately talk to the Unit 200 

Boardman about whether or not additional loading can be handled. As the purging is taking place the two Boardmen can 

work closely together to monitor the impact of purging and provide immediate feedback as to the impact of the activity on 

the Compressor. Adjustments can be made much more quickly to manage the activity. This enhanced coordination will 

reduce in flaring. 
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BAAQMD Plant 16 

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Planned Actions for Reducing Flaring

Planned Date of 

Installation/ 

Implementation

Equipment Item to be Added, Process to be Changed or Procedure to be Implemented

Phased 2006 – 2013

 2006 – MP30 (Complete)

 2009 – Sulfur Plant

(complete)

 2009 – UK (complete)

 2011 – U200/ U267/U250

(complete)

 2014 – U110 & SPP

 2015 – U100 & Bulk

(completion dates listed)

Controls Modernization – a series of controls modernization projects are underway and scheduled to be completed in 

phases. One major phase, MP-30 Controls Modernization, is complete. Listed below are the benefits of the 

modernization projects in respect to flare minimization. 

 Provides for enhanced diagnostic tools (i.e. graphics of unit operation are much more visible and easy to follow) in 

units where Distributed Control Systems (DCS) are not currently in place (MP30 & Sulfur Recovery Units).

 Reduction of control system instrumentation failures due to upgrade from old, pneumatic technology. This will result 

in much better reliability of the controls. 

 Increases unit stability and minimizes unit upsets. 

 Improves operator performance by incorporating Abnormal Situation Management practices such as alarm 

management and graphic guidelines. Alarm management is a philosophy which prioritizes alarms and minimizes the 

amount of alarms an operator must respond to in an abnormal situation. This prevents an operator from being 

overloaded with alarms and helps the operator focus on the immediate issues which must be remedied. 

 Use of human factors in information processing in order to communicate information in a proven, consistent, 

simplified, meaningful way.

Early event detection to reduce abnormal situations which might cause an upset. 

Installation of state of the art Safety Instrumented Systems (SIS) that will minimize spurious trips. Overall, the Controls 

Modernization will reduce flaring by minimizing upsets that can occur with the current controls in place. Improving the way 

that operators interface with controls allows them to prioritize their response to abnormal situations. This can result in 

more rapidly mitigating an unusual situation and minimizing overall impacts. One example would be by upgrading field 

tags (which are monitoring devices for operating parameters such as pressure or temperature, currently only visible in the 

field) to a tag which can be monitored in the control room. For example, if an equipment shutdown occurs and the 

parameter which shut the equipment down is a field tag, the modernized control system will more rapidly pinpoint the 

cause of the shutdown. The upgraded field tag would now be able to be seen rapidly by the Board Operator which will 

assist in restarting the piece of equipment more rapidly. This will reduce flaring. 

Processes:
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BAAQMD Plant 16 

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Planned Actions for Reducing Flaring

Planned Date of 

Installation/ 

Implementation

Equipment Item to be Added, Process to be Changed or Procedure to be Implemented

On-going Improved Incident Analysis Investigation – Continue to complete required 12-12 Root Cause analysis and analysis 

triggered by internal incident investigation drivers. Investigations and corrective actions identified will continue to address 

issues that may result in flaring if not otherwise addressed. The root cause analysis requires that the facility find the actual 

cause of flaring, down to a single part that may have failed in some instances. The 12-12 analysis also requires the facility 

to identify changes that can be made to prevent flaring and list those in the root cause analysis submittal to BAAQMD. 

This results in the facility taking action to prevent recurrence of flaring events. For example, some of the recent root cause 

analysis have identified equipment upgrades that should be made, additional training to be conducted, equipment repairs, 

etc.

Permit Application 

Submitted 12/2011

Target Completion 4th Qtr 

2013

Fuel Gas Combustion Sulfur Dioxide Emissions –A permit application was submitted to BAAQMD to obtain new Sulfur 

Dioxide (SO2) limits for the Steam Power Plant (SPP) via permit modification. This would allow greater percentage of 

refinery fuel gas to natural gas to be fired in the turbines. By revising the SPP emission limits it is possible that a large

portion of flaring during periods of fuel gas imbalance could be minimized while reducing overall combustion emissions. 

Historically fuel gas imbalance occurred during major Unicracker turnarounds when 30% of fired duty sources are 

shutdown. Discussions were previously held with BAAQMD permit engineers in 2007 to review the benefits and potential 

permitting mechanisms for repermitting SPP. Numerous discussions and responses have been provided to BAAQMD in 

respect to the permit application and permit revisions BAAQMD has been provided the necessary supporting information 

and must approve and finalize the permit in order for the facility to implement this item. . 

Target 4th Qtr 2012 Flare Activity Review – Soon after a reportable flaring event occurs an overview of the event is communicated between 

site management. 

Maintenance:
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BAAQMD Plant 16 

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Planned Actions for Reducing Flaring

Planned Date of 

Installation/ 

Implementation

Equipment Item to be Added, Process to be Changed or Procedure to be Implemented

On-going G-503/G-540 Flare Gas Recovery Compressors - this practice began more than 5 years ago and continues to date. 

Approximately every 18 months, in association with a major unit turnaround, the G-503 Flare Gas Recovery Compressor 

is taken out of service for a major overhaul. The purpose is to maintain critical equipment associated with the compressor 

in order to prevent unplanned failures. This practice minimizes overall downtime for the compressor. The work is 

scheduled with a major turnaround since gasses produced at the facility are at reduced rates and many fuel gas 

consumers are out of service. Without this maintenance it is more likely that the compressor would experience unplanned 

failures during periods when high gas volumes are being produced. The unplanned failure repair is of longer duration 

because the personnel and equipment must be assembled without advanced planning. In many cases, diagnosis must be 

performed to determine the failure and this can take considerable time. Whereas, planned maintenance prevents many of 

these types of failures from occurring. As with regular maintenance on a vehicle, this maintenance performs a similar 

purpose. 

Now that the new Liquid Ring Flare Gas Recovery Compressor has been installed all flare gas recovery compressors will 

be maintained on a routine basis yet it will be done when the spare compressor(s) are in operation which will further 

reduce overall flare emissions.
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4.0 Prevention Measures (401.4) 

4.1 “Major” Maintenance Activities (401.4.1) 

This section discusses refinery maintenance and turnaround activities, outlines measures to minimize 

flaring during both preplanned and unplanned maintenance activities. A description of flaring that 

occurs during major maintenance activities is included in this section and in the section titled “When 

Flaring is Likely to Occur” in accordance to 401.4.1. As required by 401.4.1 a review of flaring 

associated with major maintenance has been conducted and is referenced below. The measures 

taken to prevent flaring during portions of major maintenance activities are included in the section 

titled “Measures to Minimize Flaring During Preplanned Maintenance”. 

4.1.1 Refinery Maintenance and Turnaround Activities 

Maintenance activities often result in a higher than normal flow of material to the flare gas recovery 

system. In order to maintain process equipment, the first step is to clear the process equipment and 

associated piping of hydrocarbons, before the system is opened to the atmosphere, for both safety 

and environmental reasons, including compliance with BAAQMD Regulation 8 Rule 10, (Process 

Vessel Depressurization). How this is accomplished depends on the physical properties of the 

hydrocarbons to be removed (vapor pressure, viscosity) and on the process details of the equipment 

that is to be maintained. 

The first step is to recover as much of the hydrocarbon as is possible by transferring it to a process 

unit that is not in the part of the refinery that is being prepared for maintenance. For example, liquid 

hydrocarbons can be pumped to tankage or another process system; gases under pressure may be 

depressurized to another process unit. Heavy hydrocarbons that are viscous at ambient temperatures 

are often displaced from the equipment to be maintained using lighter hydrocarbons, e.g. diesel type 

material. This material can then be pumped from the equipment. 

Although depressurization and pump-out can be used to remove the bulk of the hydrocarbon from the 

equipment, they leave some residual material. Following pump-out or depressurization to other 

process equipment, the next step in decommissioning typically requires a low-pressure location that 

has the ability to accept a wide range of hydrocarbon materials in order to avoid putting these 

materials to the atmosphere. The flare gas header is the only location within the refinery that meets 

these criteria. Equipment items containing materials that are gases at ambient temperature and 

pressure are often vented to the flare gas recovery system so that the hydrocarbon can be recovered 

as fuel gas. To free the equipment of hydrocarbons following depressurization, they can be purged 

using an inert gas such as nitrogen. Alternatively nitrogen can be added to the equipment increasing 

the internal pressure. The resulting mixture of nitrogen and hydrocarbon can then be released to the 

flare header, reducing the pressure in the equipment. Steam can be substituted for nitrogen in some 

cases, but not for processes that need to be kept dry in order to avoid corrosion or catalyst damage, or 

for some other reason. 

For equipment containing liquids, often steam or nitrogen are used to “blow” the liquid to the flare 

header. The liquid hydrocarbon and condensed steam are separated from the vapor phase and 

returned to the refinery’s recovered oil system and to wastewater treatment either at the unit knockout 

drum or at the flare knockout drum. Nitrogen with hydrocarbon vapor continues on to flare gas 

recovery. Once the bulk of the liquid hydrocarbon has been displaced, the flow of steam or nitrogen is 

continued to remove any residual hydrocarbon by vaporization. Steam can be more effective for 

heavier materials as it increases their volatility by increasing temperature. Proprietary solvents such 
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as “Zyme-flow” are sometimes used in aqueous solution for removal of residual hydrocarbons. When 

aqueous solvents are used, they are typically circulated in the equipment and then treated. 

Although these procedures eliminate hydrocarbon emissions related to equipment opening, they 

require a high volumetric, high velocity, steam or nitrogen flowrate in order to be effective. This high 

flowrate of inert gas can create several sets of circumstances where flare gas recovery is not feasible. 

These problems relate either to the change in fuel gas composition (increased molecular weight or 

temperature) or to the increase in volumetric flowrate. 

In addition to an increase in flare gas average molecular weight from higher than normal nitrogen 

flowrate, there is also the potential for much lower than average molecular weight gas from increased 

flow of hydrogen. There are many process and reactor systems within a refinery that contain gases 

with a high hydrogen content. When this equipment is decommissioned by depressurization to the 

flare gas header, there can be a sharp decrease in the flare gas average molecular weight. 

Effect of Flare Gas on Downstream Equipment 

Gas composition affects the equipment in the flare gas recovery system. Specifically: 

 High nitrogen content can impact heaters, boilers and the flare gas compressor. 

 Hydrogen and other low molecular weight gases impact flare gas compressor performance. 

 Steam impacts knock out drums and compressors. 

High flows of nitrogen from equipment purging leads to a much higher than normal inert content in the 

recovered flare gas, greatly reducing its fuel value (measured as Btu/scf) and increasing its molecular 

weight. Reciprocating compressor (G-503) increase the pressure of a constant inlet volumetric 

flowrate of gas. For a given volume of gas, an increase in molecular weight creates an increase in its 

mass. This increases the work that the compressor has to do to compress the gas, overloading and 

potentially damaging the machine. 

For a reciprocating compressor, the compression ratio (ratio of outlet pressure to inlet pressure) is 

high enough that more than one stage of compression is needed. The temperature of the gas 

increases as it is compressed. The gas is cooled between stages in order to control the temperature 

increase. Operation of a reciprocating compressor with a feed stream that has a molecular weight 

outside of the range for which it was designed (e.g. high hydrogen content) can lead to a temperature 

increase exceeding the design limitations of the machine. Flare Gas Compressor (G-503) is 

shutdown in order to protect it from failure that could be caused by a decrease in molecular weight. 

The Liquid Ring compressors are expected to have a wider range of operating conditions. The 

compressors and associated control system will have enhanced monitoring in comparison with the 

existing Reciprocating Compressor. There will still be limitations on the type of gases that should be 

recovered and utilized in the fuel gas system (i.e. high volumes of hydrogen potentially impacting Btu 

values). 

Additionally, if low Btu flare gas is transferred to the fuel gas header, the lower fuel value can have the 

effect of reducing combustion efficiency, as the combustion device burners are designed to operate 

with fuels that have higher heat content per cubic foot. In extreme cases, the heating value of the gas 

can be reduced by dilution with nitrogen to the point of extinguishing the burner flame. This creates 

the potential for unburned fuel to accumulate in the heater or boiler, potentially leading to an explosion 

when it is re-ignited. NFPA 85 – Boiler and Combustion Systems Hazards Code and NFPA 86 

Standards for Ovens and Furnaces warn against this possibility. 

A major advantage of using steam to clear hydrocarbons from equipment is its elevated temperature; 

however this can be a disadvantage with respect to flare gas recovery. When the distance the gas 

must travel to reach the flare gas compressor is large, (the flare header is long), the gas will cool, and 
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much of the steam will condense and be removed as water at the knock-out drum. However; with a 

shorter flare line or a long-duration steam out event, the temperature of the flare gas at the flare gas 

compressor can be elevated significantly. If the temperature of the flare gas stream at the inlet to the 

flare gas compressor exceeds machine limits, the gas must be diverted away from the compressor 

inlet in order to avoid mechanical damage. 

Summary 

Each of the situations described above potentially leads to the need to divert gas produced during 

refinery maintenance away from the flare gas recovery compressor and to a flare. This is a necessary 

result of maintenance procedures which have been adopted to minimize the release of hydrocarbons 

to the atmosphere during equipment opening. The need to divert gas is driven by the quantity and 

composition of the gases produced during equipment shutdown and startup. 

Major maintenance activities can result in flaring, as discussed above. A review of maintenancerelated flaring from 2000 to 2006 at the Phillips 66 San Francisco refinery in Rodeo has been 

completed. See Attachment D for list of flaring due to planned and unplanned unit shutdowns or 

startups during that time frame. Attachment D has been marked Business Confidential. Due to the 

requirement to install flowmeters and report flare emissions to BAAQMD the data from September 

2003 to date is the most accurate for this review. Subsequent flaring taking place during equipment 

startups and shutdowns are being examined as part of the Turnaround Planning Flare Minimization 

Process and causal analysis being conducted. 

Based on the review there were means of further reducing and/or eliminating flaring that were 

identified. Included below is a summary of the measures identified and rationale for the acceptance or 

rejection of the concept:
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Major Maintenance 

Prevention Measure Evaluation 

This is a list of prevention measures that were identified based on the 5-year look back of Major Maintenance activities. Attachment D 

(Confidential) contains a list of the Major Maintenance events. Attachment H is a summary of all flaring events and is grouped by category. 

Based on the 5-year look back the following types of flaring were identified for elimination: 

 Flaring associated with Hydrogen Unit Startups/Shutdowns (H2 SU/SD) 

 Flaring due to G-503 Flare Gas Recovery Compressor Planned Maintenance (G-503 PM) 

 General Flaring Associated with Major Maintenance (.e.g. nitrogen purging, steaming, etc.) (General) 

Major Maintenance – Prevention Measure Evaluation

Measure 

Description

Schedule for 

Implementation

Rationale to Support Schedule Type of Flaring 

that would be 

Reduced or 

Eliminated

Rationale for 

Rejecting Measure

Section 

Reference 

(for more 

details)

Addition of Unit 110 

Hydrogen Vent

 Dec. 2006



Installation of a vent which will allow a small 

stream of purified hydrogen to be vented. 

H2 SU/SD n/a 3.2

Odor Abatement/Flare 

Gas Recovery System 

Optimization 

 October 2008 –

Construction Start

 August 2009 

(completed)

A set of 3 Liquid Ring Compressors were installed 

in order to provide redundant and extra capacity

for the Flare Gas Recovery compressor. This will 

eliminate some flaring events that have historically 

occurred by having additional flare gas recovery 

service. A separate odor abatement compressor 

was installed which will provide further reliability 

for the odor abatement system.

G-503 SU/SD

G-503 Brief Peak 

Loading 

Completed 3.2

Turnaround (T/A) 

Planning Procedure

4

th Qtr 2006 Being coordinated with submittal of Flare 

Minimization Plan.

H2 SU/SD

G-503 PM

General

n/a 4.1.3

Shutdown & Startup 

Activity Extension

4

th Qtr 2006 This will be included as part of the T/A Planning 

Procedure. In some cases flaring may be 

General To be included as part of 

T/A Planning Procedure

4.1.3
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4-5

Major Maintenance – Prevention Measure Evaluation

Measure 

Description

Schedule for 

Implementation

Rationale to Support Schedule Type of Flaring 

that would be 

Reduced or 

Eliminated

Rationale for 

Rejecting Measure

Section 

Reference 

(for more 

details)

eliminated or minimized by extending the period 

that a unit is going through shutdown or startup. 

An example would be to nitrogen (N2) purge 

equipment at a lower rate so the G-503 Flare Gas 

Recovery Compressor can handle the excess N2. 

More importantly, the safest operating conditions 

for a unit are when it is out of service or when it is

running at normal conditions. The transition 

period, which occurs during startup and shutdown,

requires special attention and procedures. 

Equipment placed under these conditions 

experience temperature and pressure changes 

which can result in hydrocarbon leaks. Due to 

these factors it is necessary to minimize the 

duration of transition periods. 

process. 

This will not be utilized in 

each case due to 

transitional activity 

concerns. 

Rate Reduction / Unit 

Shutdowns

4

th Qtr 2006 This will be included as part of the T/A Planning 

Procedure process. In some cases flaring may be 

eliminated or minimized through reducing rates or 

shutting down units. The implications of shutting 

down a unit must be examined for each case. For 

example, shutting down additional units may result 

in more fuel gas imbalance (i.e. production of 

more gas then can be consumed). The refinery 

units are interrelated so shutting down one or two 

units will result in impacts to other units. In some 

cases a number of units must be shutdown in 

association with a particular unit. In order to 

properly shutdown units they must be 

General To be included as part of 

T/A Planning Procedure 

process. 

It is not beneficial to use 

this for all situations as 

described in the previous 

column. 

4.1.3
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Major Maintenance – Prevention Measure Evaluation

Measure 

Description

Schedule for 

Implementation

Rationale to Support Schedule Type of Flaring 

that would be 

Reduced or 

Eliminated

Rationale for 

Rejecting Measure

Section 

Reference 

(for more 

details)

depressured and purged. This typically results in 

flaring. So, the shutdown of associated units 

doesn’t reduce flaring in all cases and must be 

evaluated for the overall benefit on a case by case 

basis. 

Rate reduction is typically only of potential value if 

refinery is out of fuel gas balance. See Section 

4.1.2 for the steps taken to mitigate fuel gas 

imbalances, including rate reduction. Some units 

may be an overall fuel consumer so reducing rate 

may not be helpful. The benefits need to be 

examined on a case by case basis.

Implementation of 

Prevention Measures 

Identified during 

Causal Analysis 

Reporting

3

rd Qtr 2005 Prevention Measures are identified during the 

required BAAQMD flare event Causal Analysis 

reporting. These measures are then implemented 

to reduce flaring. 

Note: General programmatic prevention 

measures identified will be listed in this section 

during Annual updates. Equipment specific 

prevention measures have been added to 

Attachment H. 

Various n/a 3.1

Identification of Cause 

of Small (<500,000 

SCFD or <500 lb 

SO2) Flaring Activity

1

st Qtr 2007 Conduct regular meetings with Operation 

personnel who are responsible for the flare 

operation to identify causes of all flare activities. 

Various n/a 3.1
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Major Maintenance – Prevention Measure Evaluation

Measure 

Description

Schedule for 

Implementation

Rationale to Support Schedule Type of Flaring 

that would be 

Reduced or 

Eliminated

Rationale for 

Rejecting Measure

Section 

Reference 

(for more 

details)

Storage, Treatment, 

Recovery Scenario 1 

– Addition of New 1.5 

MMSCF/D 

Compressor

n/a n/a G-503 PM 

(portion)

General

Determined not to be cost 

effective.

4.2.2.1

Storage, Treatment, 

Recovery Scenario 2 

– Addition of New 6.0 

MMSCF/D 

Compressor

n/a n/a G-503 PM

General

Determined not to be cost 

effective. However, a set 

of three new Flare Gas 

Recovery Compressors

are being installed in 

conjunction with the 

Clean Fuels Expansion 

Project. 

4.2.2.1

Storage, Treatment, 

Recovery Scenario 3 

& 4 – Addition of New 

High Pressure 

Storage Sphere, 

Compressor, & Amine 

Treater

n/a n/a H2 SU/SD

G-503 PM

General

Determined not to be cost 

effective. Technological, 

operability, and safety 

feasibility not yet 

determined. It is likely 

that upon further study 

cost effectiveness will be 

further diminished. 

Operability and feasibility 

of safe operation of such 

a system may also pose a 

challenge.

4.2.2.1
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Section 4.1.2 contains a list of measures that are currently in practice for reducing flaring. 

From this review it is clear that one of the greatest potentials for achieving further cost-effective 

reductions in flaring lie in maintenance planning with flare minimization as a goal coupled with the 

existing goals of safety and minimizing production impacts due to extended downtimes. The essential 

component of any plan that satisfies maintenance needs while minimizing flaring is that it must 

mitigate or eliminate the conditions described in the sections above that make recovery of flare gas 

impossible. In practical terms this means taking a series of actions specific to the unit being 

decommissioned to limit the rate at which flare gas is generated and maintain its temperature and 

composition within a range acceptable for transfer via a flare gas compressor and for use in the fuel 

gas system. Concepts for accomplishing this are discussed in the section following. 

4.1.2 Measures to Minimize Flaring During Preplanned Maintenance 

In accordance with 401.4.1 in regards to feasible prevention measures that can be used to minimize 

future flaring: (including that related to scheduled process unit turnarounds and immediate near-term 

shutdowns) are listed below. Numerous prevention measures are utilized to prevent flaring from 

occurring during portions of major maintenance events. The information is organized by process unit 

and by topic. There are also some general measures listed that are used at most units, when 

applicable. Refer to Attachment E for list of unit names and numbers. It is noted that although 

prevention measures are routinely employed, as explained in the previous section, all flaring cannot 

be eliminated due to gas quality and quantity issues associated with major maintenance activities. 

Hydroprocessing (U228, U229, U230, U231, U240-2, U244, U248, U250) 

Hydroprocessing units are depressurized to hydrogen recovery, or other lower pressure 

locations , and only after this are they depressurized to flare gas recovery, reducing the load on 

the flare gas recovery system. This prevents flaring by minimizing load on the flare gas recovery 

system and decreases the period of time in which flaring occurs during venting activities. 

Following depressurization, the remaining hydrocarbon is removed by increasing the pressure in 

the equipment with nitrogen and then depressurizing it to flare gas recovery multiple times. Doing 

this quickly helps with mixing, which improves removal of hydrocarbon from the vessel so that 

fewer cycles are needed. This minimizes the volume of low quality gasses that are sent to the 

flare. 

Depressurization of the unit to the flare gas recovery system is staged in order to minimize 

exceeding the capacity or quality parameters of the system in order to maximize the time in which 

the flare gas recovery compressor is on-line. The longer the flare gas recovery compressor is online the less flaring that occurs. 

Gases are recirculated using the hydrogen recycle compressors as the reactors cool. When the 

equipment is cooled and at low pressure, nitrogen pressurization and release steps are used to 

clear hydrocarbons. Hydrogen-containing streams are directed to the hydrogen plant. Use of 

hydrogen recycle for cooling and cleaning minimizes the need for nitrogen which, when utilized, 

typically results in flaring. 

U250 - A high pressure hydrotreater design is used to avoid flow to the flare by containing the 

process during loss of utilities. Without this design, additional volume of materials would be sent 

to the flare during loss of utilities. See Section 3.1 for more details on elements of this design. 
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Reformer (U231, U244) 

The timing of the steps involved in the regeneration cycle are controlled and the venting / 

depressuring rate limited to be within the capacity of the compressors. This minimizes the total 

vent stream that must be sent to the flare. 

Delayed Coker (U200) 

The delayed coker drum cooling cycle time is coordinated with other activities to prevent 

exceeding the Flare Gas Recovery Compressor capacity. 

Fractionation Units (Various units, throughout refinery) 

Vents from depressurization of fractionation units are recovered using the flare gas compressor 

system rather than being routed to the flare, when capacity is available or gas quality allows. This 

minimizes flaring by reducing the volume of gasses that must be sent to the flare. 

Compressor (U200 Flare & Blowdown System) 

Compressor Maintenance 

In some instances, the flare gas recovery compressor (G-503) is placed in wet gas recovery 

compressor service (G-501) if the wet gas compressor is expected to be offline. This minimizes 

the total amount of gas flared. A greater volume of gas can be recovered by placing G-503 

directly in Wet Gas service rather than directing the Wet Gas into the blowdown system. 

Recovering higher rates of gas reduces the volume recovered. 

Flare gas compressors are maintained during planned unit shutdowns, to improve reliability 

during periods of normal operation. A planned shutdown provides an opportunity to do 

maintenance while flare system load is lower. 

In the future, when the redundant new Liquid Ring Flare Gas Recovery Compressors are 

operational planned maintenance scheduling will be optimized and staggered to minimize 

and/or prevent flare gas recovery outages for compressor maintenance. 

Regular preventative maintenance of flare gas compressors, as described further in Section 

3.2, is used to improve their reliability. 

Maintenance is also conducted on compressors based on critical monitoring (i.e. vibration, 

temperature, load) results. 

Flare System Monitoring 

Flare Gas Recovery Compressor load is monitored to identify & mitigate higher than normal 

baseline load. High loads are mitigated by identifying the source and making reductions. For 

example, if a PRV is venting to blowdown then the responsible unit will be identified and 

directed to make adjustments to prevent the PRV from venting. 

The flare gas recovery compressor is monitored when maintenance is being conducted at other 

units that will cause the compressor to be taken off-line. The purpose is to minimize the 

amount of compressor downtime in order to protect the compressor and minimize the total time 

the compressor is shutdown and reduce overall flaring. 
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Plant personnel who oversee flare gas recovery systems have been instilled with an improved 

understanding. The operators monitor flare gas compressor load to check for high load or load 

changes, record instances of flaring and potential causes, take action to minimize flaring, and 

notify Shift Superintendents when flaring occurs. This results in conscious management of the 

flare system to minimize flaring. 

Flow and/or temperature measurement as a means of indicating flow in each flare header is 

used to identify and eliminate sources of flow to the flare gas header. Indication of flow during 

periods when flow is not expected is a direct indication of flaring. As described above, 

operators respond to flaring events by attempting to track the source and working with the Shift 

Superintendent to take action to make reductions or eliminate flaring. 

The monitoring parameters available for the Liquid Ring Compressors will be more robust and 

provide more on-line indication of changes in flare gas quality. This enhanced monitoring will 

likely assist in the optimization of compressor on-line performance. 

On-line diagnostic tools are utilized to monitor flows to the flare in order to minimize flaring 

duration. See Section 3.1 “Operational Improvement – Monitoring” for more details on how 

these tools reduce flaring. 

When higher than normal flare gas recovery compressor loads are detected announcements 

are made throughout the refinery in order to proactively identify and address the source of 

gases. See Section 3.1 Emergency Operating Procedure EOP-1 “Guidelines for Standard 

Public Address System Announcements” for more details. 

Fuel Gas Scrubbing 

Gases collected by the flare gas compressor are scrubbed whenever possible. This includes 

periods of fuel gas imbalance and periods when the compressor capacity is exceeded but the 

compressor is still operational. This results in reduced sulfur dioxide emissions from the flare. 

Sulfur Recovery Units (U235, 236, & 238) 

The refinery has three sulfur recovery units operating in parallel. During periods of maintenance 

the load is shifted from one unit to the others. Thus, no flaring is necessary during unit startups or 

shutdowns. Additionally, sulfur load can readily be reduced by decreasing sour water stripping. 

The Refinery has not historically experienced acid gas flaring during sulfur plant startups & 

shutdowns or upsets. 

General Measures (used at various units, as applicable) 

Liquid Vessel Cleanup 

Chemical cleaning is used to so that cleanup is faster, minimizing the time needed for steam 

out. Chemical cleaning works similar to using dish soap on greasy dishes in that cleaning 

time and rinse water is minimized. Thus, in practice overall time in which steaming must 

occur is minimized, thus minimizing flaring. Chemical cleaning is primarily used in units where 

there is a high volume of residual oil and solids in equipment and piping. Chemical cleaning 

must be balanced with wastewater treatment plant capabilities. 

Depressurization 

Separate flare gas headers are in place at the Unicracker Complex for the Reactor section 

and Hydrogen Plant so that some gases produced during maintenance, startup, and 
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shutdown can be directly routed to the flare. This minimizes the volume of gases sent to the 

flare during maintenance activities since it provides a separate system from the refinery 

blowdown system. This allows a portion of the refinery gasses to be recovered while only 

those from the Unicracker are sent to the flare. 

Pressure Relief 

Routine maintenance of PRDs, consistent with API 510, is used to minimize “routine” flow to 

the flare gas header. The purpose of the maintenance is to ensure the PRDs are operating 

properly at the appropriate set points and not relieving prior to the intended set point. Proper 

operation of PRDs provides a safe operation, reduces the base load and allows the system to

better able to handle flow peaks during maintenance or other periods where there is additional 

flow in the blowdown system. 

Source Reduction 

If there are indications of increased base load to the flare gas compressor efforts are taken to 

identify and mitigate or minimize the source of gasses. This is done by identifying the flare 

header affected by use of monitoring parameters, as available, such as flare header flow 

meters, pressure and temperature indicators. 

Shutdown/Startup Planning & Scheduling 

A specific plan will be developed to minimize flaring during each turnaround, as each is unique. 

Specific actions depend on which parts of the unit are being brought down and which other units 

are down at the same time. Note: Historically this has taken place for major turnarounds, this will 

be expanded to minor turnarounds as well. 

Specific “flare planning” has been conducted in respect to major turnarounds. 

Plans have been prepared to insure there will be a viable fuel balance during each time period 

during the shutdown. 

The length of the shutdown has been extended in some cases to allow equipment to be purged at 

lower rates that can be handled by the flare gas recovery system. Extension of shutdown length 

will be considered as part of the turnaround planning procedure referenced in Section 2. There 

are limitations to this activity. The safest operating condition for a unit is either when it is out of 

service or when it is running at normal conditions. The transition period, which occurs during 

startup and shutdown, requires special attention and procedures. Equipment placed under these 

conditions experience temperature and pressure changes during the transition period which can 

result in hydrocarbon loss. Due to these factors it is necessary to minimize the duration of 

transition periods. 

Rate Reductions and Unit Shutdowns at interrelated units occur to balance inventory. This will be 

included as part of the T/A Planning Procedure process referenced in Section 2. The implications 

of shutting down a unit must be examined for each case. For example, shutting down additional 

units may result in more fuel gas imbalance (i.e. production of more gas then can be consumed). 

The refinery units are interrelated so shutting down one or two units will result in impacts to other 

units. In some cases a number of units must be shutdown in association with a particular unit. In 

order to properly shutdown units they must be depressured and purged. This typically results in 

flaring. So, the shutdown of associated units doesn’t reduce flaring in all cases and must be 

evaluated for the overall benefit on a case by case basis. 
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Rate reduction is typically only of potential value if refinery is out of fuel gas balance. Again, the 

big picture needs to be examined. Some units may be an overall fuel consumer so reducing rate 

may not be helpful. The benefits need to be examined on a case by case basis. 

Load shed planning is used to keep the fuel gas system in balance as units come up/down. 

Following the turnaround, any flaring that did occur is reviewed and a list of lessons learned is 

developed in order to minimize flaring during future turnaround events. Note: This is a 

minimization effort that is being instituted in a more rigorous manner as part of this FMP. This 

consistently applied review will help establish successful flare minimization practices that can be 

utilized in the future. 

Shutdown activities are staged to keep the rate to the flare gas compressor low. This will be 

considered on a case by case basis as part of the turnaround planning procedure referenced in 

Section 2 which addresses flare minimization. 

Turnarounds are scheduled so as to bring some units down every year, so that not all units are 

down at any one time. 

Turnarounds are scheduled to minimize downtime associated with the unit and to provide a 

window for conducting preventative maintenance in order to promote equipment reliability. 

Conducting turnarounds on a regular basis prevents unplanned shutdowns that can lead to long 

periods of flaring if the necessary equipment is not available to quickly remedy a failure. 

The duration between turnarounds is being extended over time as technology improves in order to 

minimize production impacts. This also results in minimizing flaring over long periods of time (i.e. 

5 – 10 year windows). The reason this reduces flaring is that the number of turnarounds in a 10 

year period is reduced if the duration between turnarounds is extended. Eliminating one or two 

turnarounds in a 10 year period will eliminate the flaring associated with the startup and shutdown 

activities. The duration between turnarounds is being extended due to improvements such as 

longer catalyst life, better unit monitoring, better metallurgy, enhanced inspection technology and 

procedures. 

Shutdown and Startup Execution 

Equipment is purged slowly to avoid overloading flare gas recovery system capacity. The 

minimum purge rate that can be achieved is limited by the need to prepare the equipment for 

maintenance. This will be evaluated as part of the turnaround planning procedure referenced in 

Section 2. 

Cleanup activities are cascaded so that large amounts of nitrogen are not routed to the flare at 

any one time. If all equipment was purged with nitrogen simultaneously this would likely 

overwhelm the flare gas recovery compressor. By cascading the purging, this allows the flare gas 

recovery compressor to recovery gasses to blowdown during a longer period of time, thus 

minimizing overall flaring since the compressor has been kept on-line for a longer period of time. 

Steam is used instead of nitrogen for equipment clearing, as much of the steam condenses 

reducing the load on the flare recovery system. Steam is typically used in cases where there are 

not equipment vacuum limitations (e.g. piping, small equipment). Vessels typically have vacuum 

limitations. During steamout the peak flow to the flare gas recovery system is minimized by 

monitoring the steam rate and cutting back if the rate is too high. This does not eliminate all 

flaring associated with steamout procedures but minimizes the total amount of flaring. 

The molecular weight of the flare gas is monitored, so that it is diverted away from the flare gas 

compressor when approaching outside of parameters that it can handle or that is suitable for 
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combustion in unit heaters and boilers. This minimizes flaring by optimizing the period in which 

the compressor is on-line while also protecting the compressor from an equipment failure. Feed 

and product compressors are used to recycle material during startup until product specifications 

are met, allowing flaring to be avoided. The alternative would be to send gasses that have run 

once-through the reactors directly to blowdown. This minimizes the load to the flare gas recovery 

system and eliminates the potential for flaring. 

Communication Measures 

There is coordination from operator to operator and coordination within the shift organization so 

that the flare gas compressor load is not exceeded. The operators call to check on compressor 

operation before initiating actions that increase vent load. 

Fuel Gas Balance 

The fuel balance is adjusted to avoid flaring. This is done by examining the fuel gas balance which 

contains fuel producers and consumers. Depending on the environmental, safety and process 

constraints, operational changes are made dependent on which units have the most impact to the 

balance and the most flexibility. Reductions in fuel consumption or increases in consumption are 

attempted at numerous locations in order to get the facility back into fuel gas balance. 

Steps taken to prevent fuel gas imbalances include and are generally included in the order of 

potential impact are: 

 Minimize or cease butane vaporization to fuel gas. 

 Increasing fuel consumption at operating heaters. 

 Increasing production (i.e. fuel consumption) at Co-Generation plant. 

 Operating steam turbines rather than electric drivers for pumps and compressors. 

 Adjust the fuel supply at the Co-Generation plant to back out purchased natural gas and use 

more refinery fuel gas. 

 Adjusting the severity of unit operations to affect the rate of gas production. 

 Reducing process unit rates to decrease fuel gas generation. 

The Refinery is also reviewing an application of a permit modification to address the short term 

SO2 limit at the Co-Generation plant that restricts fuels gas consumption. Removing that 

restrictive limit will significantly reduce flaring from a fuel gas imbalance. 

If a fuel gas imbalance does occur gasses are typically scrubbed for hydrogen sulfide removal. 

Excess clean gasses are then flared while additional measures are taken to mitigate the 

imbalance. 
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Reliability 

The reliabilities of ancillary systems which can lead to flaring if they trip have been improved, 

reducing flaring. See the “Maintenance Excellence Philosophy” portion of Section 4.3.2.1 for 

more details of the facilities reliability practices. 

Incident investigations, as further described in Section 3.1 and 3.2, are utilized to determine root 

cause of failures and determine appropriate corrective actions to prevent recurrence. 

Maintenance is conducted on compressors based on critical monitoring (i.e. vibration, 

temperature, load) results. 

Preventative maintenance is conducted on critical pieces of equipment (pumps, compressors, etc) 

throughout the refinery to prevent failures. The benefits described for Flare Gas Recovery 

Compressors in Section 3.2, preventative maintenance conducted on critical equipment serves a 

similar purpose. Planned maintenance prevents failures. Equipment failures can often lead to 

flaring if a unit experiences an upset or must be shutdown. By conducting preventative 

maintenance, failures can be prevented which reduces flaring. 
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4.1.3 Turnaround and Maintenance Flare Minimization Planning Tool 

A planning tool has been developed and will be used to minimize flaring associated with planned 

turnaround and maintenance events, incorporating the minimization concepts outlined above. The 

means in which it will be utilized is presented in Attachment F. Listed below is an overview of the 

elements contained in the procedure: 

 Establishing a timeline for conducting the initial evaluation of when flaring may occur prior to the 

turnaround; 

 Scoping of the flaring that is expected to occur; 

 Checklist which has a list of elements which should be considered in respect to flare minimization 

techniques; 

 Post turnaround review of flaring which occurred. 

 Documentation of lessons learned during the turnaround & successful minimization techniques 

utilized. 

 Incorporation of lessons learned into appropriate shutdown, operating procedures, facility 

documents. 

This process will minimize flaring by requiring more planning to address flaring that may occur during 

a unit shutdown and turnaround. It will also cause personnel associated with turnaround activities to 

develop means to alter their work in order to take action to minimize flaring. Lessons learned will be 

captured and used for future turnarounds in order to continue efforts to minimize and/or eliminate 

flaring. See Section 3 Turnaround Planning Flare Minimization Procedure discussion for more 

detail. 

4.1.4 Measures to Minimize Flaring During Unplanned Maintenance 

There are occasions, primarily as a result of equipment malfunction, where a relatively immediate 

decision is made to shut down a block of the refinery, typically within a period of hours, allowing very 

little time for specific planning. In these cases, although the maintenance planning tool can still be 

used, it is often not possible to make the adjustments necessary to minimize flaring to the same extent 

as is possible when the shutdown is planned in advance. Despite this, there are many actions that 

can be taken to minimize flaring even when there is very little advance notice. For these cases, the 

refinery utilizes general procedures that have been developed to minimize flaring during all 

maintenance events, as shown in the attached flowchart. Although there is less of an opportunity for 

scheduling turnaround activities so as to insure that there will be a home for all of the gas generated at 

each step of the process, many of the same general principles apply when the decision to bring the 

unit down is immediate. 
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4.2 Gas Quality/Quantity Issues for Each Flare (401.4.2) 

This section discusses when flaring is likely to occur due to gas quality/quantity issues, systems for 

recovery of vent gas, and options for recovery, treatment and use of flare gas in accordance with 

401.4.2 

4.2.1 When Flaring is Likely to Occur 

Releases of vent gas to the flare result from an imbalance between the quantity of vent gas produced 

by the refinery and the rate at which it can be compressed, treated to remove contaminants (sulfur 

compounds) and utilized as fuel gas. Situations that can lead to flaring can be grouped together 

based on similarity of cause. These general categories, including specific examples of events which 

fit into each category, are outlined and discussed below as required by 401.4.2 in respect to flaring 

that may reasonably be expected to occur due to issues of gas quantity and quality: 

4.2.1.1 Maintenance, Turnaround, Startup, and Shutdown 

Generally, in order to maintain either an individual equipment item or a block of refinery equipment, it 

is necessary to remove it from operation and clear it of process fluids. Examples include: 

 Unit shutdown 

 Working on equipment 

 Catalyst change 

 Plant leak repairs 

 Compressor system repairs (planned and unplanned) 

 Unit Startup 

Fuel and Hydrogen Gas Balance 

All of these activities of necessity impact refinery operations in a variety of ways. In order to minimize 

the risk of flaring, there must, at all times, be a balance between producers and consumers of fuel gas. 

When either a block of equipment or an individual equipment item is removed from service, if it either 

produces or consumes gases, then the balance of the fuel gas system is changed and adjustments 

are necessary to bring the system back into balance. If the net change in gas production/consumption 

is large and adjustments in the rate at which gas is produced/consumed by other units cannot be 

made quickly enough, then flaring results. 

Flaring also occurs during Hydrogen Plant startups, shutdowns, or when a downstream hydrogen user 

experiences a sudden outage. As previously described, flare gas recovery compressors cannot 

handle high volumes of hydrogen in the system. When a hydrogen plant has been shutdown it 

typically is shutdown with a hydrogen consumer. In order to properly startup the consumer unit the 

hydrogen must first be available. Therefore, hydrogen plants are started up initially and may not have 

an outlet for all the hydrogen being produced. If a vent is not available, the hydrogen is sent to the 

flare gas recovery system if the system can handle minor volumes, otherwise it is sent to the flare. 

Hydrogen is also utilized for downstream equipment sweeping, thus the hydrogen plant is typically 

shutdown after the downstream unit. Thus, for similar reasons to startup there can be hydrogen 

containing streams sent to the flare system. If a hydrogen consumer suddenly shuts down, in order to 

minimize overall facility impacts, the hydrogen plant is typically kept running, rates may be reduced, 

but excess hydrogen flared until the downstream unit is restarted. Specific examples of this effect and 

fuel gas balance issues are listed below: 

 Fewer locations that can accept the gas due to equipment/units out of service 

 Hydrogen plant startup/shutdown 

o Including Excess Hydrogen production following startup or unit shutdown 

o Temporary flaring of off-spec hydrogen during startup 
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o Planned & Unplanned shutdowns can result in flaring 

o Planned & Unplanned shutdowns of the third party plant can result in flaring. 

 Unicracker Complex turnaround (i.e. numerous combustion devices shutdown) 

Equipment Preparation for Maintenance 

Additionally, in order to clear hydrocarbons from equipment in a safe and orderly fashion so as to 

allow it to be maintained, a variety of procedures must be used. Many of these necessary procedures 

result in changes in the quantity and quality of fuel gas produced. For example: 

 Depressurization of equipment 

 Pressurization of equipment with nitrogen to remove hydrocarbon resulting in low fuel value 

(high nitrogen content) gas which cannot be used with burners designed for “normal” fuel 

gas, as there can be NOx production and flameout concerns with low Btu gas. 

 Steaming provides an efficient means for removing hydrocarbon clingage from equipment 

but the effects of steam (high temperature, condensation production) can result in the need 

to shutdown flare gas recovery compressors. 

See the “Refinery Maintenance and Turnaround Activities” section for more details in regards to the 

reasons for flaring during equipment preparation for maintenance. 

Preventative Maintenance, On-Line Planned Maintenance, Equipment Upgrades, Changes 

In order to prevent unplanned failures preventative maintenance (PM) is conducted at varying 

schedules. Typically, PM is conducted to minimize production and/or environmental impacts by 

grouping PM activities together. Additionally, equipment upgrades occur periodically or changes may 

be made to improve existing systems. During equipment upgrades/changes pieces of equipment may 

be required to be taken out of service for brief periods of time to ensure worker safety and/or allow for 

equipment access. 

Flare Gas Recovery Compressor Maintenance – 

Major Maintenance - typically conducted in conjunction with the Unicracker Complex 

turnaround in order to minimize environmental impact (i.e. less gas being produced while the 

Unicracker Complex is shutdown). The purpose of the PM is to maintain the compressor in 

order to minimize unplanned failures. This results in better on-line efficiency. Unplanned 

failures typically require more downtime due to time needed to diagnose the failure and then 

acquiring the necessary parts to make repairs. 

Minor Maintenance – Based on on-going monitoring conducted on the compressor, see 

Recurring Failure section for more details, minor maintenance is conducted to replace parts or 

equipment which may fail or is not operating per the design. Purpose of the maintenance is to 

minimize and control downtime by preventing an unplanned, uncontrolled failure which may 

result in increased downtime. Additionally, the maintenance also can restore the compressor 

capacity and prevent flaring if the compressor is not functioning up to the equipment design.

Refinery Relief and Blowdown System Maintenance – Periodic maintenance is required on 

sections of the relief and blowdown systems (e.g. process vessels, drums, flare water seals, 

flare tips, etc.). This maintenance can include periodic, required metallurgical equipment 

inspections as well as preventative maintenance cleaning and replacement of components. 
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These activities are required to prevent unplanned shutdowns which might incur long repair 

periods of not performed proactively.

Miscellaneous PM, Equipment Upgrades, Changes 

Flare Gas Recovery System Maintenance - Construction tie-ins to the flare system, 

instrument changes, electrical upgrades, new equipment installations could require equipment 

to be taken out of service. This might result in flaring in order to isolate equipment and then 

also during equipment startup. 

Equipment Upgrades / Changes - are made periodically to improve existing systems. This 

may require various pieces of equipment to be temporarily taken out of service. Portions of 

operating units or individual pieces of equipment may be taken off line for preventative 

maintenance or repairs. This can result in flaring during the clearing of equipment and flaring 

when equipment is put back in service. 

On-Line Maintenance - Water washing of U244 D-506 and U231 D-105 Reformate Stabilizer 

is conducted periodically. The procedure is managed in order to minimize loading to the flare 

gas recovery system but there are periods when flaring may occur during this procedure. 

4.2.1.2 High Base/Continuous Load 

Although flaring is often the result of a sudden, short-term imbalance in the flare/fuel gas system, it is 

made more likely when the gap between the capacity of the flare gas recovery system and long term 

average flow to the flare header is reduced. Examples of base load to the flare header include:

 Leakage of relief valves 

 Low pressure equipment vented to flare header, e.g. tower overhead systems 

 Delayed coker depressurization 

 Low pressure tankage or odor sources vented to flare header via blower or compressor 

 Hydrocrackers and reformers at end of run with elevated gas production rates 

 Accumulation of small actions each of which results in production of flare gas 

 Seasonal issues with cooling water temperature resulting in increased rates to flare header

 Temporary re-rerouting of gases from other systems such as odor abatement to fuel gas 

recovery in order to prevent system overpressure. 

 Feed quality issue resulting in temporary increased base load. 

In cases of this type of flaring when the flare gas compressor is still operating the gasses recovered by 

the compressor will continue to be scrubbed for hydrogen sulfide removal at Unit 233. 

4.2.1.3 Reduced Consumption of Fuel Gas 

Treated flare gas may be flared during supply/demand imbalance. If flaring is to be minimized, it is 

necessary to balance fuel gas producers and consumers in the refinery. Refinery modifications that 

can change the fuel gas balance so as to make flaring more likely include: 

 Energy efficiency projects that reduce fuel gas consumption 

 Fuel gas imbalances can occur when fuel consumers (e.g. heaters, turbines) are shutdown and 

more gas is being produced then can be consumed. 

 Fuel gas imbalances can occur when the third party Hydrogen Plant conducts planned or 

unplanned maintenance on feed filters and knock out drums. 
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4.2.1.4 Upset/Malfunction 

An imbalance in the flare gas system can also result from any of a series of upsets or equipment 

malfunctions that either increase the volume of flare gas produced or decrease the ability of the fuel 

gas handling system to accommodate it. Examples include: 

 Leaking relief valves, PRV malfunction 

 Relieving relief valves 

 Equipment plugging 

 Loss of a major compressor (e.g. Wet gas compressor) 

 Loss of flare gas compressors, including but not limited to: 

o Reciprocating compressor seats overheating from high nitrogen or hydrogen content 

o Fuel gas with low specific gravity (due to Hydrogen), or high heat of compression resulting 

in overheating 

o High inlet temperature to flare gas compressor 

o Monitored safety/protective parameter (e.g. vibration) triggered shutdown. 

o General mechanical problems inherent in the operation of rotating equipment. 

o High liquid level. 

o Equipment failure resulting in loss of compressor efficiency. 

 Loss of other compressors (e.g. odor abatement, recycle hydrogen) 

 Loss of a utility (steam, air, cooling water, power) 

 Loss of air fins or condensers 

 Failure of instrumentation, valve, pump, compressor, etc. to function as designed. 

 Fuel quality upsets 

 Hydrogen plant Pressure Swing Adsorption (PSA) operational changes (e.g. switching from 10 bed 

to 8 bed operation). 

 Hydrogen plant PSA valve leaks resulting in a unit upset. 

 Hydrogen may be sent to the flare system when there is a supply/demand imbalance. 

 Unplanned/sudden shutdown of 3rd party Hydrogen Plant. 

 Equipment failure which results in an immediate or controlled unit shutdown (e.g. charge pump 

failure) 

 Feed quality issue resulting in unit upset. (e.g. wet feed, lighter than typical feed) 

 Control system failures resulting in either unit shutdowns or unit not operating as efficiently in manual 

operating mode. 

 The unit Hazard and Operability (HAZOP) studies contain more specific listings of potential causes 

of equipment malfunctions and upsets which may lead to flaring. 

4.2.1.5 Emergencies 

Equipment failures and operational issues that result in equipment overpressure, typically leading to 

relief valves opening to the flare system, are classed as emergencies. Emergency flaring events are 

severe instances of upsets or malfunction. Emergencies are further defined in BAAQMD 12-12. 

 Line leak, fires due to leaking flanges, etc. can result in emergency unit shutdowns in which 

material from units is quickly sent to the flare. 

 Unit Hazards and Operability Studies (HAZOPs) and Process Hazards Analysis (PHA) also 

reference emergency conditions which may lead to flaring. These studies are a systematic 

evaluation of the hazards involved in the process. PHAs are required for initiation of a process, 

for major equipment/operating changes, and at least once every five years after that. One of the 

values of PHA’s is to identify potential hazardous and develop means for mitigating hazards 

before they occur. For example, one of the ways to conduct this evaluation is to take unit piping 

and instrument diagram (P&ID). The consequences of failure of pieces of equipment (e.g. on a 
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pump if flow is lost, flow is increased, flow is decreased) are discussed and the mitigation in 

place is reviewed. Where improvements should be made they are identified and tracked to 

completion. See Section 4.3.2.1 for more details about PHAs. 

4.2.1.6 Miscellaneous 

 Undetermined Cause - in some cases the cause of flaring cannot be determined. Typically, this 

is during minor flaring events (<500,000 scfd). Systems have been setup to try and pinpoint the 

cause of all flaring events, most events are traced back to a source but there are instances 

when a direct cause cannot be determined. 

 Natural Gas Purge – flaring can occur if there is a spike in the natural gas purge flow. One of 

the ways this may occur is if the natural gas purge valve is opened too quickly or at a rate 

greater then typical flow. This results in the brief flaring of excess purge gas. 

 False Flow Meter Reading – as previously described to BAAQMD, many parameters (e.g. water 

seal level, flare line pressure, flare tip cameras) are utilized to determine whether or not flaring 

has actually occurred. In some cases flow may be detected by the meter, for example due to 

thermal expansion, but not all other parameters indicate that flaring has occurred. This is a 

common issue due to the sensitivity of the ultrasonic flow meters. 

4.2.1.7 Other Causes 

There are many potential causes of flaring, some of which are exceedingly difficult to totally 

eliminate, despite careful planning and system design. 

4.2.2 Vent Gas Recovery Systems 

As required by 401.4.2 the following sections contain an audit of the vent gas recovery, storage, and 

treatment capacity. In addition, an evaluation for installing additional recovery, storage, or treatment 

equipment to recover portions of gases periodically sent to the flare. 

Refinery unit operations both produce and consume light hydrocarbons. Most of these hydrocarbons 

are routed directly from one refinery process unit to another. Refineries are constructed with a 

network of flare headers running throughout each of the process units in order to allow collection and 

safe handling of any hydrocarbon vapors that cannot be routed directly to another process unit. The 

hydrocarbon vapors are collected at low pressures in these flare headers. These gases are recovered 

for reuse by increasing their pressure using a flare gas compressor system. The compressed gases 

are typically returned to the refinery fuel gas system for use in fired equipment within the refinery. Any 

gas not compressed and sent to the fuel gas system is routed to a flare so it can be disposed of safely 

by combustion under controlled conditions. A typical flare gas system is shown in: 

See Attachment G. In order to recover flare gas for use in the fuel gas system, three criteria must be 

met. First, there must be sufficient flare gas compressor capacity. Second, there must be sufficient 

gas treating capacity. Finally there must either be available storage volume or a user (e.g. fired 

heater) with a need for the gas. If any of these conditions are not met, then the gas cannot be 

recovered into the fuel gas header. 

Existing Systems for Vent Gas Recovery 

Within the Phillips 66 San Francisco Refinery at Rodeo, CA, the systems that currently exist for recovery of 

vent gas are described by the table below. 
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Flare System Vent Gas 

Recovery

Capacity

(MM scfd)

Storage 

Capacity

(MM scf)

Scrubbing 

Capacity for Vent 

Gas

(MM scfd)

Total Gas 

Scrubbing 

Capacity

(MM scfd)

Main Flare & MP30 

Flare

4.75 None None 35 1

1 The facility does not have a scrubber for gases sent directly to the flare. The flare gas recovery system typically sends 

gases to U233 for H2S removal and then sends these gases to fired sources. The capacity listed above includes the total 

capacity of the scrubbing system. 

The Phillips 66, San Francisco Refinery vent gas recovery system does not include any dedicated capacity for 

storage of fuel gas or vent gas. However, on a continuous basis the refinery optimizes the refinery fuel gas 

system of producers and consumers to maximize the capacity available for treatment and reuse of recovered 

gases by employing the following strategies: 

 adjusting the sources of fuel that are made up to the fuel gas system including imported natural gas, 

and butane; 

 adjusting the operations of units that produce fuel gas range materials including at times reducing 

severity of operations to reduce fuel gas production if it would put the refinery in a flaring situation; 

 adjusting the refinery profile for consumption of fuel gas by ensuring the cogeneration unit is at its 

maximum capacity (within constraints on exporting power), shifting rotating equipment to turbine drivers 

(which operate with steam generated in the fuel gas fired boilers), and at times reducing the throughput of 

processing units to minimize gas production. There are limitations to this activity. For example, the 

cogeneration unit has a sulfur dioxide (lb/hr) limit. The cogeneration unit utilizes a fuel mixture of refinery 

fuel gas (sulfur containing) and natural gas (nearly nil sulfur). As the ratio of refinery fuel gas is increased 

the units start approaching their sulfur dioxide limits. The amount of fuel gas burned in facility heaters is 

limited by permit conditions and energy efficiency constraints. 

 When possible, the usage of fuel gas can be increased for brief periods of time to mitigate or prevent 

flaring. 
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The total gas scrubbing capacity that is indicated is an integral part of the refinery fuel gas management 

system. This capacity is closely matched with the fuel gas consumers’ (heaters, boilers, etc.) usage 

requirements. The capacity indicated as being available for recovered vent gas scrubbing will vary depending 

on the balance between fuel gas production and consumption; it will vary both on a seasonal basis and during 

the course of the day. With this system for flare gas recovery in place, the Phillips 66 San Francisco refinery at 

Rodeo, CA has recovered the following daily and annual average flow volumes: 

Year Daily Average 

Flare Gas 

Recovered

(MMSCF/d)

Daily Average 

Flare Gas 

Flared 

(MMSCF/d)

% of Material 

Recovered

Annual Volume 

Flare Gas 

Recovered 

(MMSCF/Yr)

Annual Volume 

Flare Gas 

Flared 

(MMSCF/Yr)

2006 to date prorated 2.35 0.06 99% 858 22

2005 1.97 0.16 92% 722 58

2004 2.30 0.64 78% 850 234

Note: The amount of material flared and % of material recovered can be very dependent on the turnaround schedule. 

Major turnarounds are typically conducted less frequently than once per year. For example, a major turnaround of the flare 

system occurred in 2004. 

4.2.2.1 Options for Recovery, Treatment and Use 

To address the requirements of Regulation 12 Rule 12 (401.4), the Phillips 66, San Francisco refinery at 

Rodeo, CA has considered the feasibility of further reducing flaring through additional recovery, treatment, 

and/or storage of flare header gases, or to use the recovered gases through other means. This evaluation 

considers the impact these additional systems would have on the volume of flared gases remaining in excess 

of what has already been recovered (as noted in the previous section), and the associated mass flow of 

hydrocarbons emitted after combustion in the flare control device. 

A typical flare header is connected to both a flare gas recovery system and to one or more flares. Normally all 

vapor flow to the flare header is recovered by a flare gas recovery compressor, which increases the pressure 

of the flare gas allowing it to be routed to a gas treater for removal of contaminants such as sulfur and then to 

the refinery fuel gas system. Gas in excess of what can be handled by the flare gas recovery compressor(s), 

the treater(s), and/or the fuel gas system end users flows to a refinery flare so it can be safely disposed of by 

combustion. Therefore, in order to reduce the volume of gas flared, three essential infrastructure elements are 

required: sufficient compressor capacity to increase the pressure of the gas to the point where it can be used 

in the refinery fuel system, sufficient storage volume to dampen out the variation in volumetric flowrate to the 

flare gas header, and sufficient capacity in treating systems to condition the gas (primarily by removal of sulfur) 

for use in the fuel gas system. 

Options for storage of flare gas are analogous to those for storage of other process gases. Gases can be 

stored at low pressure in expandable gas-holders with either liquid (water) or dry (fabric diaphragm) seals. 

The volumes of these systems expand and contract as gas is added or removed from the container. Very 

large vessels, containing up to 10,000,000 cubic feet of gas can be constructed by using multiple “lifts”, or 

stages. Gases can also be stored at higher pressures, and correspondingly lower volumes, in steel bullets or 

spheres. The optimal pressure vessel configuration depends on system design pressure and total required 

storage volume. 

For any type of gas storage facility, selection of an acceptable site and obtaining the permits necessary for 

construction both present difficulties. Despite the refinery’s demonstrated commitment and strong track record 

with respect to safe handling of hazardous materials, the surrounding community can be expected to have 
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concerns about any plan to store large volumes of flammable gas containing hydrogen sulfide and other sulfur 

compounds. Safety concerns are expected to impact site selection as well, with a relatively remote location 

preferred. Modifications to the recovery, storage and treating of refinery flare gases are subject to the 

provisions and approval of federal and local regulations including Process Safety Management (PSM), Contra 

Costa County Industrial Safety Ordinance (ISO), and California Accidental Release Prevention Program 

(CalARP). Although the objective of the project would be a reduction in flaring, there are expected to be 

multiple hurdles along the path to a construction/land use permit. 

Flare gas treating is used to condition flare gas for use as fuel in the refinery fuel gas system. Treatment is 

focused on removal of sulfur compounds, with some systems improving fuel value by removing carbon dioxide 

as well. A range of technology options exist, most of which are based on absorption of acid gases into a “lean” 

amine solution (MEA, DEA, MDEA, DGA) with regeneration of the resulting “rich” solution by stripping at lower 

pressure. In order to recover additional fuel gas it is necessary to have sufficient capacity to match the 

capacity of gas treating systems to the peak flowrate of the flare gas requiring treatment. 

In order to assess the potential effect of additional flare gas recovery, a hypothetical design for an upgraded 

system was developed. The impact that this system would be expected to have on hydrocarbon emissions, 

based on the refinery’s recent flaring history, was then evaluated. Results of this evaluation are provided for 

three system capacities corresponding to the rate of flow of additional flared gases that could be recovered, 

the modifications required to achieve that recovery, and the estimated total installed cost for the additional 

equipment needed for the increase in recovery. The budgetary level (order of magnitude) cost information 

provided in this section has been developed based on total installed cost data from similar installations where 

available, otherwise vendor quotes in combination with standard industry cost estimation procedures have 

been used to estimate system cost. 

An evaluation was conducted for the Phillips 66, San Francisco Refinery in Rodeo, CA. In order to conduct the 

analysis a summary of historical flaring was prepared. Flaring events were categorized in order to determine 

feasible means for reducing flaring through storage, recovery, and treatment. See Attachment H for summary 

of categorized, historical flaring. The period of 2004 – 2006 was utilized to determine general trends. The 

data for 2005 was utilized to quantify potential costs and benefits of additional storage, recovery, and/or 

treatment. 

Based on the data review it was determined that four cases should be examined. The cases include the 

following scenarios: 

 Case 1 – Installation of Small Compressor (1.5 MMSCF/day) to enhance existing compressor 

recovery during peak loading. 

 Case 2 – Installation of Large Compressor (6.0 MMSCF/day) to eliminate minor compressor loading 

events and some flaring events which occur during brief Flare Gas Recovery Compressor (G-503) 

preventative maintenance periods. 

 Case 3 – Installation of high pressure storage sphere, installation of large compressor, and addition of 

amine treater. Value of this case would be to eliminate all events listed in Case 2 as well as some 

events which are quality driven (e.g. high Nitrogen & Hydrogen) due to equipment purging. 

 Case 4 – Similar to Case 3 with a higher percentage of the volume generated during the quality driven 

flaring events would be eliminated. 

See Attachment I for example schematic of the equipment installations that would be involved in Case 3 and 4. 

Listed below is a summary of the overview of the analysis performed and the results of the analysis. 
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Storage, Treatment, & Recovery Scenario - Emission Reduction & Cost Effective Analysis

Estimated Potential Reductions (tons/yr) Cost 

Effective 

Basis 

(tons)

Cost of 

Control 

($MM)

Annualized 

Cost of 

Abatement 

System 

($MM)

Cost 

Effectiveness 

Basis ($/ton)

Case VOC SO2 Nox CO PM

1 -0.15 -0.62 -0.02 -0.19 negligible -0.98 $ 3.25 $ 1.06 $ (1,084,092)

2 -1.12 -4.51 -0.13 -1.38 -0.01 -7.16 $ 7.50 $ 2.51 $ (350,420)

3 -1.57 -6.35 -0.19 -1.94 -0.02 -10.07 $ 23.40 $ 6.19 $ (615,476)

4 -2.02 -8.18 -0.24 -2.51 -0.02 -12.97 $ 23.40 $ 6.19 $ (477,509)

1

 Basis is BAAQMD Guidelines for calculation of cost-effectiveness for BACT using the “levilized cash flow method”. Costs 

for equipment were based on cost curves developed by a third-party. 

It should be noted that the cost basis did not include the consideration of infrastructure adequacy and did not 

include all potential equipment and instrumentation necessary. It is expected that once a more rigorous 

evaluation is performed the costs will significantly be impacted. For example, the cost of infrastructure needs 

for equipment utilizing electricity and air is expected to be significant. Attachment N contains data utilized to 

calculate the cost effectiveness of the four cases described above. The storage sphere costs were based on 

quotes provided by Chicago Bridge and Iron and are contained in the Attachment. A cost curve was prepared 

by a third-party for the compressor costs. The costs were based on data points of actual costs provided by 

WSPA membership. 

For Case 3 and 4, the evaluation is based on the need for installation of new major systems in order to 

increase recovery of flare gases from current levels: 

 Additional flare gas recovery compressor capacity - the estimated cost to provide additional 

compressor capacity to recover vent gas flowing in the flare header in excess of current compressor 

capacity, for transfer to storage and / or treatment. Costs provided are for one unspared compressor 

system to be added to one existing flare header. The estimate is for a reciprocating compressor with 

all necessary appurtenances for operation, including knock out pots, coolers, and instrumentation for 

a fully functional system. 

 Addition of surge volume storage capacity – the estimated cost to provide temporary surge storage for 

a portion of the gases routed to the flare header in excess of the volumes currently being recovered, 

treated, and consumed. The addition of temporary surge storage volume is necessary for any further 

increase in flare gas recovery to allow flare gas flow (which is highly variable) to be matched to the 

demand for fuel gas. The cost used is based on a storage volume equal to the total volume of gas 

accumulated over one day, and is based on recovery in a high pressure sphere system with discharge 

at a controlled rate back to the flare gas header. Other lower pressure approaches were considered 

(low pressure gas holder, medium pressure sphere), but for the sizes analyzed a high pressure 

sphere was identified as the preferred approach based on operational, safety and economic 

considerations. 
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 Additional recovered gas treatment capacity – the cost of additional amine-based treating capacity to 

process recovered gases for sulfur removal so that they can be burned by existing fuel gas consumers 

without exceeding environmental or equipment operational limits. The assumption is that for small 

increases in treating capacity the existing treater(s) will be modified / upgraded to allow for the 

increase. No additional cost has been included for expansion of sulfur recovery system capacity. 

Based on this review the Phillips 66, San Francisco Refinery has concluded that further expansion of systems 

for the recovery, treatment and use of flared gases is not the most effective approach to reducing these 

emissions. The refinery has concluded that the major source of flared gases on a volume basis can be 

attributed to large flow rate, low quality flaring events, especially those of extended duration such as may occur 

during emergency events or prolonged shutdowns where systems within the refinery are out of fuel gas (and / 

or hydrogen) balance. Additionally, a synergy was identified that the Refinery will leverage to install additional 

capacity of 3.3 MMSCFD. 

The refinery has allocated significant resources to the development of procedures to plan for, manage, and 

minimize large flow and duration flaring events. Further resources have also been allocated effectively to 

ongoing preventive maintenance programs, and even to adjust refinery operations on a severity and 

throughput basis. These approaches have been identified to be more effective than providing additional flare 

gas recovery system capacity. Additionally, it is expected that the practices discussed in this plan, specifically 

the development of a formal turnaround flare management procedure, continuation of incident investigations, 

and management system programs will result in further reductions of flaring events. These will likely prove to 

be most cost effective and meaningful. 

4.2.2.2 Preventing Production of Low-Quality Flare Gas 

Measures to help prevent production of low-quality flare gas, e.g. sour gas, low Btu gas, high nitrogen content 

are further investigated in this section. The discussion is integrated with the discussion of turnaround and 

maintenance events as gas quantity (insufficient demand) and gas quality (unscrubbed during 

upset/malfunction and nitrogen/steam during turnaround) are the primary drivers for flaring during these 

events. It is for this reason that the measures used to minimize production of low quality fuel gas are closely 

related to those that can be applied to reduce flaring during maintenance and turnaround events. 

Preventing production of sour flare gas is accomplished by making sure that recovered flare gas is routed to 

the fuel gas system via a gas treating system. It is preventing the production of sour fuel gas that drives the 

need to match the capacity of treating systems to accept flare gas to flare gas recovery capacity. 

High fuel gas nitrogen levels are primarily caused by the nitrogen used to purge hydrocarbons from equipment 

in preparation for equipment opening. High nitrogen fuel gas content is controlled by limiting the rate at which 

nitrogen is introduced to equipment and ultimately the flare gas system during nitrogen purging operations. 

There can be a trade-off between nitrogen flowrate and the effectiveness with which the nitrogen mixes within 

the contents of the vessel from which hydrocarbons are being removed. These must be balanced on a caseby-case basis to determine the purge rate that represents the best compromise among competing process 

needs. Scheduling decommissioning activities to minimize overlapping nitrogen purge events is one of the 

best ways to control the nitrogen content of flare gas. 
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4.3 Recurrent failure (401.4.3)

 of Pollution Control Equipment 

 Process Equipment, or 

 A process to operate in a normal or usual manner: 

4.3.1 Reportable Flaring Events Attributable to the Same Process or Equipment Item 

For the Period from June 30, 2006 to June 30, 2013

A discussion and analysis of each event, including actions taken to avoid future flaring as a result of the same 

cause and the adequacy of maintenance schedules and protocols. Flaring as the result of malfunctions and 

upsets is included in the analysis. 

Reportable Flaring Events Attributable to the Same Process or Equipment Item

Date Process or Equipment Item Flaring Event Description

There have been no recurrent failures that occurred at the refinery in which the root cause was associated with 

a refinery equipment failure. There have been third-party supplier outages that have resulted in flaring 

reportable events. Attachment H contains a listing of the reportable events and the associated corrective 

actions. 

4.3.2 Means to Prevent Recurrent Failure 

There are many programs in place in order to prevent recurrent failures. The programs fall into two major 

categories; proactive and reactive. The purpose of the proactive programs is to have systems in place based 

on potential failures that could occur in order to prevent failures from occurring. The reactive programs 

examine failures that have occurred in order to learn from the failure and develop stronger proactive programs 

to prevent recurrence. The facility employs many levels of proactive and reactive programs. 

4.3.2.1 Proactive Programs 

BAAQMD Regulation references “the adequacy of existing maintenance schedules and protocols” for air 

pollution control and process equipment in respect to recurrent failures. There are major programs in place 

which support the prevention of failures. Additionally, these programs facilitate continuous improvement to 

prevent failures. Key programs in place are described below. 

Phillips 66 HSE Management System

Phillips 66 Corporation requires each refinery to implement a standard Health, Safety, and Environmental 

(HSE) Management System. This is achieved through providing organization structure, programs, 

procedures, processes, and resources to manage business activities safely and with respect and care for the 

environment. The HSE Management System seeks to: 

 Demonstrate management commitment to health, safety, & environmental stewardship. 

 Ensure that all reasonably practicable steps are taken to identify the hazards and risks arising from 

business activities. 

 Establish adequate control over business activities with the aim of achieving safe, incident, and injury 

free working conditions. 
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 Maximize the operational integrity, reliability, and efficiency. 

 Ensure regulatory compliance. 

 Promote high standards and the continuous improvement of HSE performance. 

Process Safety Management (PSM) 

The refinery must comply with EPA’s PSM. Major elements of PSM are also incorporated in California’s 

Accidental Release Prevention Program (CalARP), the Contra Costa County (CCC) Industrial Safety 

Ordinance (ISO) and EPA’s Risk Management Program. There are fourteen elements of PSM, each of these 

elements is included in some fashion with the programs listed above. In addition, the CCC ISO and CAL ARP 

program have some additional elements. Although all the elements directly or indirectly prevent failures or 

minimize the impact of a failure if it occurs, listed below are some of the programs that most directly support 

failure prevention. 

Employee Participation – Employees at all levels must be involved with the elements of PSM. This 

encourages ownership, participation and buy-in of incident investigation results and means for 

improvement, and promotes a better safety and operating culture. 

Process Safety Information (PSI) – the refinery is required to maintain accurate Process Safety 

Information. PSI includes chemical inventory, accurate drawings, operating procedures, etc. 

Process Hazards Analysis (PHA) - A PHA is a systematic evaluation of the hazards involved in the 

process. PHAs are required for initiation of a process and at least once every five years after that. The 

PHA team should be multi-disciplinary, including maintenance, operations, and engineering. The 

facilitator of the PHA must be trained in the methodology being used. For proper conduct of a PHA, 

the PSI must be as complete as possible. One of the values of PHA’s is to identify potential 

hazardous and develop means for mitigating hazardous before they occur. 

Operating Procedures - Operating procedures include not only the steps for normal operations, but for 

upset conditions, temporary operations, start-up, and shutdown. Very important safety information 

must also be included in operating procedures. Contained in the procedures are basic hazards of 

exceeding operational limits, appropriate response to upset conditions, safety and health information, 

and emergency operations. The procedures are required to be up to date and reliable. They are also a 

critical element in training of personnel. 

Training - Training is required for all employees new to a process before they become involved in that 

process. The training must include the hazards of the chemicals and process and what is necessary 

to protect themselves, their fellow employees, and their surrounding communities. Training should be 

both written/classroom and hands-on. Employers must evaluate the effectiveness of training and 

make adjustments to content and frequency of training based on those evaluations. 

Pre-Startup Safety Review (PSSR) - The Pre-Startup Safety Review is done before startup of a new 

operation or startup following a change in the process (see Management of Change, below). It is a 

means for ensuring that all essential action items and recommendations from the PHA have been 

completed prior to beginning operations. It is also the point at which the design parameters and 

standards used for construction are verified. If training or modifications to Process Safety Information 

(PSI) are necessary, completion of these items is also verified during the PSSR. Startup should not be 

allowed to occur until all safety-critical PSSR items have been completed. 

Mechanical Integrity - Employers are required to have a program to ensure the integrity of processes 

and equipment. Aspects include listing applicable equipment, training of maintenance personnel, 

inspection and testing, and maintenance of such systems as controls, vessels, piping, safety systems, 
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and emergency systems. Development and modifications to the mechanical integrity program should 

be made based on operational experience, relevant codes, and industry standards. 

Management of Change (MOC) - “Change” includes anything that would require a change in Process 

Safety Information. This includes changes to equipment, processes, and instrumentation. A proper 

MOC system requires that any change be evaluated prior to its implementation. The level of 

evaluation can depend on the degree of change and its criticality to the safety of the operation. In 

addition to the evaluation and approval of a change, MOC requires that suitable training be conducted 

(if necessary) and the relevant PSI be updated. 

Compliance Audits - Per OSHA, compliance audits must be conducted at least once every three 

years. The purpose of the audits is to determine whether the practices and procedures developed 

under the provisions of the PSM standard are being followed and are effective. The auditor(s) must be 

knowledgeable in PSM and should be impartial to the facility being audited. An audit report must be 

developed and the employer must promptly respond to each of the findings. Once deficiencies are 

corrected, the corrective action must also be documented. 

Maintenance Excellence Philosophy

Predictive Maintenance - The Rodeo Refinery utilizes predictive maintenance tools for both rotating 

equipment (pumps, blowers, fans, motors) and fixed equipment (pressure vessels, piping, storage 

tanks). These tools can be used to predict equipment condition and failures so that appropriate 

preventive measures can be taken, or so repairs can be scheduled prior to a failure. The Rotating 

Equipment/Reliability Department is responsible for ensuring that rotating equipment is in good 

condition and the Metallurgical Engineering and Inspection (ME&I) department is responsible for 

inspecting fixed equipment in the facility. 

ROTATING EQUIPMENT 

The following is a list of tools and techniques used for maintaining the rotating equipment: 

 Operator Inspections/Seal Integrity 

 Equipment Deficiencies 

 Vibration Analysis 

 Lube Oil Testing 

 Overhaul Testing 

Operator Inspections / Seal Integrity 

Operators visually inspect the equipment case and seal/packing area for signs of leakage. 

Mechanical seals are the number one failure mode in centrifugal pumps. Operations and 

maintenance personnel include visual monitoring of seals in their shift rounds. In some cases, 

for example where dual seals are installed, instrumentation (level, pressure, etc.) is available to 

alert operations that action is required. Seals subject to LDAR (Leak Detection and Repair) 

regulations are monitored for hydrocarbon emissions on a regular basis. 

Operators listen to and observe the equipment operation to detect any unusual noises and/or 

vibrations that may indicate damage or wear. 

Equipment Deficiencies 

If a potential deficiency is observed, the operator contacts the Operations Supervisor to request 

consultation by the appropriate craft or by the Rotating Equipment Group. If it is determined that 

repair is required, the operator submits a Work Request via the Computerized Maintenance 
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Management System and initiates the steps necessary to make the equipment available for 

repair. The Work Request documents the deficiencies noted during the operator inspection.

Vibration Analysis 

Vibration analysis can be a useful predictive maintenance activity to identify potential 

equipment failures so that proper maintenance can be scheduled before a failure occurs. 

 

Vibration readings are taken using hand-held piezoelectric accelerometers. Readings are 

normally taken on all bearing planes (horizontal, vertical, axial). Local panel readings for 

vibration and temperature, where applicable, are also entered into the data collector. The data 

is then typically uploaded into the vibration analysis computer, which can be compared to 

historical data, industry guidelines, or vendor data to assist in scheduling maintenance or 

indicating the need for additional detailed analysis. Rodeo Refinery personnel participate on a 

Phillips 66 Rotating Equipment Best Practices Network to facilitate learning in this area. 

Lube Oil Testing 

Several pieces of rotating equipment are classified as critical. A sample of lube oil is drawn from 

the appropriate critical equipment, or other machinery of interest, quarterly or as warranted. This 

sample is sent to a certified laboratory for a standard set of analyses. The results are transmitted 

to the Machinery Specialist. The results of each analysis are entered into a computer database 

as a single record. The data included in the record are: 

 Equipment tag number 

 Date of sample 

 Analysis results 

Sample test results are trended and compared to established limits of operation for each specific 

piece of equipment. If a deficiency is noted, the Machinery Specialist initiates an appropriate 

corrective action. These could include continued monitoring, oil replacement, filtration, or a 

repair of the equipment. 

Overhaul Inspections 

Equipment that has been removed to the shop for repair undergoes a detailed internal inspection 

to identify wear or damage that could affect performance or mechanical integrity. Machinists 

perform visual inspections and measure clearances for comparison to manufacturer's 

specifications. If necessary, the Inspection Group can perform more sophisticated tests 

(radiographs, ultrasonic, magnetic particle, liquid penetrant and materials analysis) if requested 

by the Rotating Equipment Group or Maintenance. 

FIXED EQUIPMENT 

The Rodeo Refinery utilizes the following techniques to ensure fixed equipment is in good condition: 

 External Visual Inspection, 

 Internal Visual Inspections, and 

 Thickness Surveys. 

External Visual Inspection
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The primary reasons for performing external visual inspections of pressure vessels, piping 

and storage tanks are to determine the type, rate and causes of any deterioration present 

that may negatively affect their mechanical integrity and/or service performance and to 

determine if any maintenance work is required to maintain the equipment in a safe 

operating condition. 

External visual inspections are performed by qualified Phillips 66 or contract inspectors. 

The external visual inspection results are documented in an external inspection report. The 

report is completed and dated by the inspector(s) performing the external visual inspection. 

It is reviewed by the plant’s Inspection Supervisor or authorized representative. The 

completed report is filed in the equipment inspection history file located in the plant’s 

Inspection Department. 

Internal Visual Inspection 

The primary reasons for performing an internal visual inspection are: 

1. to determine if the essential sections of the vessel are safe to operate until the next 

inspection; 

2. to determine the type, rate and causes of any deterioration present which may 

negatively affect its mechanical integrity; and, 

3. to determine if any maintenance work is required to maintain the pressure vessel in 

a safe operating condition. 

The internal visual inspections are performed by qualified Phillips 66 or contract inspectors. 

 

Pressure vessels are typically visually inspected internally at least once every 10 years, in 

accordance with API standards. Non-fired boilers are inspected every 6 years maximum 

and fired boilers are inspected every 3 years maximum, in accordance with State of 

California requirements. In practice, many vessels and heaters in sulfur plants are visually 

inspected internally during a boiler inspection period, at a 3, 6, or 9 year interval and 

therefore, well within the 10 year maximum interval allowed by API industry standards. 

The inspection results are documented in an internal inspection report. The report is 

completed and dated by the inspector(s) performing the internal visual inspection. It is 

reviewed by the plant’s Phillips 66 Inspection Supervisor or authorized representative. The 

completed report is filed in the equipment inspection history file located in the plant’s 

Inspection Department. 

Thickness Survey 

A representative number of thickness measurements are taken on pressure vessels via 

ultrasonic and/or radiographic thickness techniques for remaining wall thickness at intervals 

pre-established by the industry. Thickness surveys are also performed on most process 

piping runs. The thickness survey is prompted by the plant’s Inspection Department to 

meet all requirements for thickness surveys as outlined in the applicable API standard. 

 

The thickness surveys are performed by qualified Phillips 66 or contract inspectors who 

have the appropriate education, experience and qualifications. 

 

The general area of each thickness monitoring location (TML) is ultrasonically scanned 

and/or radiographed and the lowest reading is recorded. When using ultrasonics, scanning 

the general area rather than monitoring the same exact location increases the chance of 

finding local corrosion and typically yields a larger (more conservative) general corrosion 

rate. 

 
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The thickness survey results are completed and dated by the inspector(s) performing the 

thickness survey. It is reviewed by the Phillips 66 site Inspection Coordinator or authorized 

representative. The completed report is filed in the appropriate equipment file and all data 

is recorded in an electronic database (PCMS System). 

Preventive Maintenance - Preventive maintenance activities ensure that equipment and 

instrumentation function properly through their design life. Examples of these activities are outlined 

below. Deficiencies are corrected at the time of the inspection where possible or work orders are 

written to facilitate cleaning or repair. 

Instrumentation 

Instruments that are critical to unit operations are reviewed and calibrated and cleaned as 

needed. Examples include flow meters, fire eyes, temperature monitoring devices and 

analyzers used for performance monitoring and control. Plant performance testing, through 

pressure surveys, temperature indicators, efficiency calculations or other data collection is used 

to resolve discrepancies in measurement devices. 

Rotating Equipment 

To ensure reliable operation of rotating equipment, spare equipment can be operated, where 

installed, to facilitate repair. Seals and bearings are replaced based on inspections or 

predictive maintenance activities. 

Preventive maintenance tasks include cleaning, adjustment, and lubrication. Operators replace 

lubricating oil and grease on a frequency set by a master schedule for the Refinery. 

Appropriate lubricants are specified in a written plan. Steam turbine drivers’ over-speed trip 

protection devices are tested at an established frequency. Fans and mixers are cleaned, 

lubricated and tested. 

Fixed equipment 

Thickness measurements and corrosion monitoring (probes, coupons, external UT, and critical 

process variables) are used to schedule preventive maintenance on vessels. Refurbishment of 

steel through weld buildup, plate replacement, coatings, or vessel replacement is used to 

ensure the mechanical integrity of pressure vessels. Refractory is replaced based on 

inspections, monitoring skin temperatures and thickness in fired equipment and based on 

internal visual inspections of refractory condition. 

Jacketing/Tracing 

Integrity of steam and electric tracing used in sulfur processing units is verified through regular 

plant walkthroughs/checklists by plant operations and maintenance personnel. 

Catalyst & Chemicals 

Unit catalyst and chemical activity is monitored by unit engineers and operators through 

pressure surveys and temperature indicators. Lab testing is conducted on intermediate and 

products to monitor quality. When quality is compromised, operational parameters or other 

means are employed to ensure continued performance. 

Turnaround Inspection And Repair - Major maintenance turnarounds of the process and utility units 

are planned based on predictive/preventative maintenance activities. Prior to each planned shutdown, 

a work scope is developed for detailed inspection, repair, replacement and testing of equipment, 

catalyst and chemicals to ensure the unit will operate properly until the next planned shutdown. 
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October 2013, Rev. 9 

4-32

The exact activities for each planned shutdown are determined by Operations, ME&I, Engineering, 

Reliability and Maintenance personnel prior to each shutdown. A criticality ranking process is used to 

determine which proposed work activities are included in the turnaround inspections and repairs. 

 Where practical, maintenance is performed on the equipment while the unit is still in operation. 

Typical turnaround activities include cleaning equipment, replacing/rejuvenating catalyst and 

chemicals and inspecting/repairing/replacing equipment as-needed. 

Critical Instruments & Safety Instrumented System 

The facility has a list of critical devices and has a procedure for handling Safety Instrumented Systems. Safety 

Instrumented Systems (SIS) take processes to a safe state when predetermined conditions are exceeded. 

This includes set points such as pressure, temperature, level, etc. These programs maintain the reliability of 

such devices and systems in order to ensure that shutdown systems have been appropriately established and 

are reliable. 

Near Miss/Good Catch Program 

A process is in place that encourages all employees to identify and report potential near misses. Near misses 

are undesired events which, under different circumstances, could have resulted in harm to people, damage to 

property or the environment, or production/business loss. Near misses may also include unsafe practices, 

acts or conditions. The value of this program is that it facilitates: 

 Identifying and addressing safety, procedural, environmental impact, design or equipment issues in a 

proactive, non-threatening manner. 

 Identifies learning or training opportunities. 

 Sharing of “lessons learned” and best practices with other employees and facilities. 

Solomon Refining Comparative Analysis 

The refinery participates in periodic comparative analysis. Flare volumes are one of the parameters included. 

Flare volumes are included in the metric to examine materials that could have been recovered from an 

economic standpoint. The purpose of the analysis is to determine how facilities compare with their peers in 

critical parameters. 

4.3.2.2 Reactive Programs 

When a failure has occurred, depending on the magnitude of a failure, the event will be examined in 

further detail. Listed below is an overview of the major elements of the programs in place to prevent 

recurrence of failures. 

Incident Investigation 

An internal procedure is in place which identifies the type of failures which require incident investigation. This 

process is a key part of our Health, Safety, and Environmental Management System. Failures captured by this 

process typically include accidents, injuries, events with potential off-site impact, some levels of flaring events, 

upsets which result in business loss. The procedure requires that an investigation be conducted and 

corrective actions identified. The regulatory drivers for this program include, but are not limited to; EPA’s 

PSM, EPA Risk Management Program, Contra Costa County (CCC) Industrial Safety Ordinance (ISO), 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

4-33

California’s Accidental Release Prevention Program (CalARP). Additionally, there are strong business case 

drivers for completing incident investigation and preventing recurrence. 

Root Cause Reporting 

In addition to the incident investigations described above, root cause is required to be reported for higher level 

events based on various regulatory drivers. Regulatory drivers include but are not limited to; BAAQMD 

regulations 12-11 & 12-12, EPA SARA/CERCLA reporting requirements, Phillips 66 EPA Consent Decree 

requirements, Contra Costa County ISO. 

Flare Monitoring & Reporting Procedure 

The procedure documents the BAAQMD monitoring and reporting requirements. Additionally, it contains 

levels in which flare incident investigations must be conducted. The levels correspond to those required by 

BAAQMD and in the Phillips 66 Consent Decree. See Attachment E for general overview of the process for 

reviewing flaring events. 

Use of Incident Investigation Documentation Software 

Phillips 66 requires use of a Corporate wide software tool in which certain risk levels of incidents must be 

tracked. An overview of the incident is included in the software as well as the corrective actions. Depending 

on the level of the incident, the overview of the incident is immediately shared with Vice President level staff 

electronically via the software. 

High Learning Value Event (HLVE) 

If an event occurs in which a lesson learned might have value to sister refineries within Phillips 66 a system 

has been established for quickly sharing lessons learned so that other facilities may not experience a similar 

incident. 

Corporate Incident Notification Requirements 

Higher level events, such as off-site impacts, require immediate notification to the Corporation. 

Corporate Health, Safety, and Environmental Reporting Requirements 

Flaring volumes are required to be reported and are tracked refinery by refinery to the Corporation on a regular 

basis. 

Key Performance Indicators (KPIs) - 

KPIs are reported internally throughout the facility on a periodic basis. The KPIs include the number and 

cause of flaring events. The purpose is to inform plant personnel of occurrences of these events and to 

encourage continuous improvement by tracking cause and number. 

Regulatory Notifications 

There are various regulatory drivers which require notification of various levels of flaring events. Drivers 

include; BAAQMD 12-12, EPA’s SARA/CERCLA, CCC Community Warning System requirements, etc.
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

October 2013, Rev. 9 

5-1

5.0 Other Information Requested by APCO to Assure Compliance 

(401.5) 

5.1 New Equipment Installations (404.2) 

A new source review application was submitted to BAAQMD for the installation of new equipment 

associated with the Clean Fuels Expansion Project (CFEP). The BAAQMD application number is 13424, 

the permit to construct was issued on March 13, 2007. Both the BAAQMD permit and Environmental 

Impact Report (EIR) included an evaluation of potential flaring that may occur as part of the project. 

Minimization techniques utilized for comparable equipment will be utilized for the new equipment/units. 

No routine flaring is planned or expected to occur with the new equipment/units. Anticipated flaring 

includes that associated with equipment maintenance, startups, shutdowns, major turnarounds, and 

during potential emergencies. The types of flaring expected for the new installation comparable to those 

that have been categorized for existing refinery operations in the section titled “When Flaring is Likely to 

Occur”. Listed below is an overview of the tie-ins and changes to be made to the flare system: 

 Installation of three (3) new Liquid Ring Flare Gas Recovery Compressors to increase overall 

flare gas recovery compressor capacity and provide redundant capacity during maintenance 

activities. 

 Tie-ins from the units listed below for non-routine flaring activities as described above: 

o Unit 246-8 New Heavy Oil Hydrocracker 

o Unit 235 Sulfur Recovery Plant including new Sour Water Stripper and new Amine 

Regeneration 

o Unit 120 3rd Party Hydrogen Plant – for upstream (i.e. relief valve venting of feed streams) 

 Debottlenecking of steam piping to flare to allow for wider smokeless range for both flares. 

Resulting in an increase from 50,000 lb/hr per flare to 75,000 lbs/hr to each flare with a maximum 

combined flow of 110,000 lb/hr for both flares.. 

The major tie-ins, new units, and new compressors are reflected in Attachments C, E, L, and M. 

The third-party Hydrogen Plant application was currently processed under BAAQMD Number 13679. The 

permit application and EIR contemplated flaring that could occur in association with the Hydrogen Plant. 

The third party plant has a flare on-site. Flaring that could occur at the Rodeo Refinery and is associated 

with the third party Hydrogen Plant can potentially from feed streams upstream of the new Methane 

Steam Reformer. Downstream flaring off the Methane Steam Reformer would take place at the third part 

plant flare. 
Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT A 

SAN FRANCISCO REFINERY 

SIMPLIFIED FLARE SYSTEM OVERVIEW 
 Process Gas From MP-30 

Complex

 Purge (Natural Gas) 

42'' Line Flow Meter

Purge (Natural Gas)

48" Li

Main Flare

C-1

MP-30 Flare

C-602

Process Gas

From Refinery

Blowdown

AI 586

AI 520

AI 

U-233

Treated

Fuel Gas

Unit 

Heaters 

& Cogen

 F-3

Unicracker

Blowdown

U200/267

Blowdown

Attachment A

San Francisco Refinery

Simplified Flare System Ove

Purge (Natural Gas)

Water

Seal 

Fuel Gas 

Center

U 200 Wet Gas (G-501) (H2S Removal) Compressor

Odor Abatement 

Compressors

UK / MP30 Sour Gas

10'' Line Flow Meter

G-540 Liquid Ring Flare Gas

Recovery Compressor (New 2009)

ABC

G-503 Flare Gas

Recovery Compressor

Water

Seal

AI 585

36" Line Flow Meter

J. Ahlskog, 07/2008 
ATTACHMENT B 

San Francisco Refinery, Rodeo, CA 

Flare Gas System Detailed Description 

Listed below is a detailed overview of the facility flare system. Although some parameters are 

contained in this description they are subject to change as operational or safety enhancements are 

identified. 

The Refinery Relief and Blowdown Systems provide a means for recovery or safe disposal of gases 

and liquids, which may be generated by the process units. Typical sources of normal flow include 

coke drum steam-out and switching, sampling, activation of relief valves, distillation tower overhead 

vapors, and purging of equipment for maintenance or startup. During emergencies, major flow may 

occur from heater or unit depressuring and the lifting of pressure relief valves. Gases and liquids 

flow through relief and blowdown lines to blowdown accumulators and knockout drums. Gases and 

vapors pass overhead to be recovered or flared. The liquids are generally reprocessed through 

appropriate operating units. 

There are two flares in the refinery – the Main Flare and MP-30 Flare. There are three relief and 

blowdown systems; the Refinery, the Hot Coker Blowdown, and the MP-30 system. Typically the 

gases sent to the blowdown systems are recovered, treated, and then utilized for fuel in the facility 

heaters and co-generation equipment. During periods when gases are not recovered, the flare 

gases are typically sent to the Main Flare. The Refinery and Hot Coker Blowdown system gases 

are routed to the Main Flare. The units located in the MP30 Complex relieve to the MP-30 

Blowdown system. Typically, the gases sent to the MP-30 Blowdown System are recovered in 

conjunction with the gases from the Refinery and Hot Coker Blowdown system due to 

interconnecting piping. This interconnecting piping also accommodates minor flaring so that gases 

from the MP-30 Blowdown System are typically sent to the Main Flare. During major releases from 

MP-30, the gases would be flared at the MP-30 flare. 

There are periods in which the Main Flare is shutdown in association with the Unicracker Complex 

shutdown. During these periods, the Refinery Blowdown system can be diverted to the MP-30 

Flare. The Hot Coker Blowdown system would also be diverted to the MP-30 Flare while the Main 

Flare is shutdown. 

Refinery Relief and Blowdown System

The Main Relief and Blowdown system handles relief and blowdown from the Coking Unit 200, 

Crude Unit 267, Gasoline Fractionation, Caustic Treating and Deisobutanizer Unit 215, Diesel 

Hydrotreating Unit 250, Steam Power Plant, Hydrogen Plant Unit 110, Fuel Gas Center Unit 233, 

the Unicracker Complex including Reforming Unit 244, Unit 246 Heavy Oil Hydrocracker (mid2009), and Unisar Unit 248, Sulfur Units, Isomerization Unit 228, the Unit 120 3rd Party Hydrogen 

Plant (mid-2009), and minor MP-30 releases. 

During normal conditions, vapor in the flare headers upstream of 19F-3 Water Seal Drum is 

diverted to the Refinery Flare Compressor G-503 at Unit 200. G-503 compresses this vapor to the 

refinery gas system at the Fuel Gas Center Unit 233. Flare Gas Recovery Compressors G-540 

A/B/C can be used as a total spare for the G-503 compressor. If all of the Flare gas compressors 

shutdown or the release is too large for the compressor system, the gasses flow through the 

Refinery Flare Drum 19F-1 and Water Seal 19F-3 - breaking the water seal and are burned in the 

Refinery Flare. 
F-1 Blowdown Drum

Vapor and liquid releases from the units listed above flow through various blowdown headers to 

Refinery Blowdown Drum F-1. The Unicracker complex has its own separate Blowdown Drum F-45 

upstream of F-1 to limit the liquid releases to F-1. Vapor and liquid release from the Unicracker 

Complex discharge into F-45. Liquids are knocked out and the vapor flows from F-45 through a 36-

42′′ header to F-1. Not all relief valves from the Unicracker Complex discharge to F-45. Relief 

valves from D-305 Fractionator discharge directly into the 36-42 ′′ header from F-45. 

The Steam Power Plant and Unit 110 also have separate Blowdown Drums upstream of F-1 – 

Blowdown Drum F-35 and Flare Knock Out Drum V-18, respectively. The sites of the Steam Power 

Plant and Unit 110 have low points in their relief headers. Liquids condensing in the SPP and Unit 

110 flare headers to F-1 flow back down the flare header to their respective blowdown drums. 

Entrained liquids are knocked out in F-1. At a high liquid level in F-1, blowdown pumps G-1A/1B 

automatically start and pump the collected liquid through Cooling Water Exchanger E-1 to the foul 

water tank. The foul water tank has a water phase and hydrocarbon liquid phase. The water phase 

is fed to the Phenolic Water Stripper D-901. The hydrocarbon liquid phase becomes feed to Coking 

Unit 200 or to Naphtha Hydrotreater Unit 230. 

F-3 Water Seal Drum and Flare Vapor Recovery Compressor Water Seal Drum F-3, located 

between drum F-1 and the Main Flare, permits the use of the blowdown system and its drums as 

suction surge for the G-503 Flare Vapor Recovery Compressor during normal releases. F-3 usually 

contains about an eight foot water seal that diverts the gas in Blowdown Drum F-1 down the main 

36′′ Unicracker blowdown header to the F-509 Knock Out Drum for G-503. The G-503 compressor, 

located in the Coker Light Ends area, returns the compressed gases to the refinery fuel gas system. 

The compressor design flowrate is 200,000 scf/hr of 23 MW gas. If more than 4.8 MMSCF/D gas is 

released to the blowdown system, usually during the steamout of a Coke Drum, one of the G-504 

compressors can also take suction on the flare header and can discharge an additional 1.6 

MMSCF/D to the refinery make gas system for a total of 6.4 MMSCF/D vapor recovery. When the 

vapor flowrate is higher than 200,000 scf/hr, vapors released to the refinery blowdown system break 

through the F-3 water seal and flow to the Main Flare. If the vapors released are from the MP-30 

blowdown system, the vapors may also break through the F-604 water seal and flow to the MP-30 

Flare. G-503 may also spare the Unit 200 Coker Wet Gas Compressor G-501 or the Unit 200 Odor 

Abatement Compressors G-60A/B/C. When G-503 is in G-501 or G-60A/B/C service, or G-503 is 

down, all three G-540 compressors can be placed in flare gas recovery service. Total gas recovery 

is then limited to 4.8 MMSCF/D. If no flare gas recovery compressors are available, the F-3 water 

seal is removed, and vapors flow directly to the Main Flare. The F-604 water seal is not removed 

when G-503 is down, so that flaring of the normal releases only occurs at one flare stack. 

Main Flare Header

Flare gas from D-7 Blowdown Drum and Unit 240 reactor depressuring gas release downstream of 

Water Seal Drum F-3. The Unit 240 reactor depressuring line bypasses drum F-1 and Water Seal 

Drum F-3 to accommodate depressuring of the reactors at a 300 psi/min rate. The Hot Coker 

Blowdown bypasses the F-3 Water Seal Drum to minimize back pressure on the Hot Coker 

Blowdown Drum D-7. 

Any gas breaking through the F-3 water seal, vapor from D-7, and/or Unit 240 depressuring gas 

enter the Main Flare Stack C-1 through a water seal at the base of the flare. This seal is one of the 

flashback protections for the Main Flare - prevents the backflow of gas or air into the flare lines, 

which could create explosive mixtures. Additional flashback protections are the molecular seal and 

continuous purge of the flare stack. An on-line oxygen analyzer is located between F-3 and 19C-1 

and sounds an alarm on high oxygen content in the Unit 200 DCS. 
Vacuum Protection for Refinery Blowdown System

After a hot vapor release through F-3, the water seal in F-3 will be automatically re-established on 

level control. To ensure flashback from the flare cannot occur, natural gas is added to F-1 on 

pressure control (PIC-530) at low pressures. The pressure indicator controller PIC-530 indicates 

and alarms in the Unit 200 DCS. 

Main Flare Purge Gas Requirements

Natural gas supplies purge gas to prevent flashback. The purge gas enters the Main Flare above 

the water seal at the base of the flare. The molecular seal prevents both convective and diffusional 

backflow of air into the stack. The proprietary seal design allows some of the rising flare and purge 

gases to be trapped in the seal. This creates a zone, which is higher than atmospheric pressure 

and lower in molecular weight than air (lighter than air). Air cannot backflow through such a zone. 

Main Flare Pilots

The stack tip has four electronic spark ignited pilots, each with its own ignition system. The pilots 

utilize electronic spark ignition for an automatic re-light function. When the thermocouple on the 

pilot senses a pilot outage (low thermocouple reading), the spark igniter immediately reacts to relight the pilot. After a set period of time, the loss of pilot indication will alarm in the DCS in the Unit 

200 control room. Each pilot is equipped with two thermocouples, but only one thermocouple is 

connected to the DCS for control of the electronic spark system. The other thermocouple is a 

spare. 

As a back-up system to this automatic electronic spark ignition system, each pilot has a manual 

flame front generator line. 

Temperature indicators for each pilot also alarm on low temperature in the Unit 200 DCS to alert the 

operators that pilot flame-out has possibly occurred. If the low temperature alarm remains on 

because the automatic spark ignition system has not been successful to re-ignite the pilot, an 

operator is then dispatched to the field to manually operate the flame front generator to re-ignite the 

pilot. 

Smokeless Flaring at Main Flare 

A small continuous flow of steam to the flare is provided to prevent a condensate build-up in the 

steam line and provide cooling to the flare tip. During a flaring event, additional steam is injected at 

the tip to aspirate air into the flame and ensure smokeless burning of the flare gases. Flow 

indicators, located on the two flare headers - 10′′ header from D-1 and 42′′ header from F-1-to the 

Main Flare stack- detect releases to the flare. These flow indicators also alarm in the Unit 200 

DCS, so that the Unit 200 operators are aware that gas is being released to the flare. A monitor of 

the flare is located in the Unit 200 control room; so that the Unit 200 operators can continuously 

view the flare operation. 
MP-30 Relief and Blowdown System

When the Main Flare is in service, normally only the MP-30 Complex major releases flow to the MP30 Flare. However, the MP-30 Relief and Blowdown System can also handle releases from Coking 

Unit 200, Crude Unit 267, Gasoline Fractionation, Caustic Treating and Deisobutanizer Unit 215, 

Diesel Hydrotreating Unit 250, Steam Power Plant, Hydrogen Plant Unit 110, Fuel Gas Center Unit 

233, Sulfur Units, and Isomerization Unit 228, when the Main Flare is down for maintenance. 

During this maintenance period, the blowdown headers for Units 267, 200, 215, 250, 110, 233, 228, 

Steam Power Plant, and Sulfur Plant Complex headers can be diverted to Blowdown Drum F-2. 

Releases to F-2 will flow directly to the MP-30 Flare Stack 

Diverting the blowdown headers to F-2 is only done, when Blowdown Drum F-1 and/or Water Seal 

Drum F-3 must also be inspected or repaired with the Main Flare. If F-1 and F-3 do not have to be 

inspected when Main Flare is down, a 26′′ interconnecting line downstream of F-3 is opened to the 

36′′ header from F-2. This allows the refinery to keep G-503 Flare Compressor in service during the 

maintenance of the Main Flare and minimize flaring. Only major releases will break the F-3 water 

seal and flow through the 26′′ interconnecting line to the MP-30 Flare. 

MP-30 Complex Blowdown Drum F-600

Releases from the Hydrotreating Units 229 and 230 and Reforming Unit 231 flow to Blowdown 

Drum F-600. Any liquid releases or entrained liquid will drop out in F-600. Liquid in F-600 

gravitates to F-603 Drain Pot. On high level in F-603, blowdown pumps G-600/601 automatically 

start. The liquids are pumped by level control through Blowdown Slops Cooler E-600 to the foul 

water tank, the same foul water tank for the Refinery Relief and Blowdown System. When level in 

F-603 has dropped to the preset level, the pumps automatically stop. 

Minor vapor releases up to 200,000 scf/hr are diverted from F-600 to the Refinery Blowdown 

System by a fifteen foot water seal in F-604 Water Seal Drum downstream of F-600. These minor 

releases flow to the Refinery Blowdown System through a 12′′ cross-connecting line to the Sulfur 

Plant/Isomerization Unit common blowdown header. Major vapor releases break the water seal in 

F-604 and flow through a 42′′/48′′ flare header to the MP-30 Flare. 

Vacuum Protection for F-600 and F-604

To prevent a vacuum, PIC-601 on F-600 adds natural gas to the MP-30 Blowdown on low pressure. 

In addition, the pipe entering the F-604 seal leg rises 19 feet above the top of the 15 foot water seal. 

Therefore, if a vacuum or partial vacuum occurs in the MP-30 blowdown system, water in F-604 will 

back flow up the seal pipe, but the seal will not be broken. 

On low pressure in the flare header, separate pressure controller PIC-658 adds natural gas to the 

flare line to prevent flashback. A small continuous flow of natural gas through a restriction orifice 

sweeps the flare line to ensure the line does not contain any H2S, NH3, or other heavier 

hydrocarbons after flaring ceases. 

MP-30 Flare F-2 Blowdown Drum (Partial spare for F-1)

When blowdown headers are lined up to F-2, any entrained liquids in the vapor releases or any 

liquid releases to F-2 are knocked out in F-2. F-2 is also a low point in the system. Any liquid that 

condenses in the 36′′ header will flow back to F-2. At a high level in F-2, blowdown pumps G-2A/B 

automatically start and pump the collected liquid through Cooling Water Exchanger E-2 to the foul 

water tank. The foul water tank is the same foul water tank as listed for the Refinery Relief and 

Blowdown System. When a low level in F-2 is again reached, the blowdown pumps automatically 

stop. 
Even when no Unit blowdown headers are lined up to F-2, F-2 must remain in service when the 

MP-30 Flare is in service. Any high level at the base of the MP-30 flare is gravity drained to F-2. 

The continuous purge required for the MP-30 Flare Stack to prevent flashback also flows through F2. 

 MP-30 Flare Operation

The MP-30 flare operates similarly to the Main Flare. The MP-30 Flare also has four electronic 

spark ignited pilots. Pilot operation is basically the same as the Main Flare. 

The MP-30 Flare also has a molecular seal. The flare tip is 48′′diameter. Natural gas is also used 

as the purge gas for to prevent flashback. The continuous purge gas requirement of 0.01 ft/sec to 

the MP-30 Flare Stack is supplied through pressure regulator PCV-565 and flow restriction orifice 

FO-523 to 19F-2. The purge gas flows from 19F-2 through the 36′′ flare header to the MP-30 Flare. 

(The minimum purge requirement of 445 SCF/hr for this flare stack is set by the manufacturer’s 

molecular seal and flare tip design.) 

In addition to the molecular seal and continuous purge, a water seal exists at the base of the flare 

stack to prevent flashback. The seal is designed to have a continuous water purge of 0.5 gpm. A 

continuous water purge ensures that any condensed hydrocarbon vapor that may accumulate is 

removed from the base of the flare. The continuous water purge and/or any condensed 

hydrocarbon gravitate from to F-2 for removal to the foul water tank. 

An on-line oxygen analyzer is located on the main 48′′ flare header downstream of the 36′′ F-2 flare 

header and 12′′ D-7 header connections. The analyzer sounds an alarm on high oxygen content in 

the Unit 200 DCS to warn operators of potentially explosive mixtures in the MP-30 flare system. 

 Smokeless Flaring at MP-30 Flare

A small continuous flow of steam is provided to the flare tip to prevent a condensate build-up in the 

steam line and provide cooling to the flare tip. When flaring occurs, additional steam is injected at 

the tip to aspirate air into the flame and ensure smokeless burning of the flare gases. Flow 

indicators, located on the 48′′ header from MP-30, the 36′′ header from F-2, and the 12′′ header 

from D-7 detect releases to the flare. These flow indicators alarm on high flowrates in the Unit 200 

DCS. A monitor of the flare is also located in the Unit 200 control room; so that the Unit 200 

boardman can continuously view the MP-30 flare. If there is a flow to the flare or the flare is 

smoking, the steam to the flare tip is manually increased by the boardman from the Unit 200 DCS. 

Hot Coker Blowdown System

The Hot Coker Blowdown system was built with the Unicracker Complex in 1970. Releases to the 

hot Coker Blowdown System flow through a 16′′ blowdown header to Blowdown Accumulator F-6. 

Even though the system is described as the Hot Coker Blowdown system, not all releases are hot 

nor are all releases from Unit 200 Coking Section. Originally, most of the releases to the blowdown 

system were from relief valves on heater outlets, blowdown lines from heater outlets, and the relief 

valves on the Unit 200 Coke Drums (hot releases in excess of 650 °F). However, other factors 

such as type of material released from a relief valve (i.e. crude) will also cause the relief valve to be 

connected to the Hot Coker Blowdown System. Other Unit 200 connections include Unit 200 

Vacuum Tower relief valve, crude feed pump relief valve, various thermal relief valves for heat 

exchangers, and pump clean-out/ blowdown lines at Unit 200. The Unit 267 Desalter, crude pump 

relief valves, and Diesel Filter relief valves discharge to the Hot Coker Blowdown System as well. 

Although Unit 233 can relieve to either F-6 or F-3 the primary route is through F-6. This is manually 

controlled. During periods of fuel gas imbalance the excess clean fuel gas is vented to F-6 through 

the 10” line. 
Liquid releases to the Hot Coker Blowdown system drop out in F-6. A high liquid alarm on F-6 that 

sounds on the DCS alerts the Unit 200 Operators that liquid is flowing to F-6. Operators manually 

start blowdown drum pump G-61 to pump the liquid to the recoverable oil tank. If the liquid is a hot 

release, the Operators will divert cooler gas oil from Unit 200 to the Hot Coker Blowdown header to 

cool the liquid release before pumping to tankage. 

Any vapor that is released from F-6 flows to Blowdown Drum D-7. On high temperature in the D-7 

overhead line (150 °F), a water deluge control valve automatically opens to flood water into D-7. A 

high temperature alarm sounds in the Unit 200 control room on the DCS and a valve positioner 

alarm from this control valve sounds on the Unit 200 alarm panel when the deluge valve opens. 

This alerts operators that a hot release has occurred and additional operator intervention may be 

required for D-7. Water gravitates through the water deluge control valve from Tank 286 to D-7 and 

condenses most of the vapor released to D-7 by contact with the vapor by flowing over the disc and 

donut baffles inside D-7. Any vapor not condensed will flow overhead from D-7 to one of the flares 

for combustion. D-7 overhead is normally lined up to the Main Flare. 

The water and any entrained hydrocarbon liquid will discharge from D-7 through a water seal leg to 

the process sewer. During any release at the flares or to the Hot Coker Blowdown System, the 

pressure in D-7 will not exceed 15 psig. This water seal leg ensures that the water seal is not blown 

during any potential release. 

 Some of the condensed hydrocarbon in D-7 will separate from the water at the base of D-7. The 

operators manually line up D-7 bottom to the Blowdown Drum Pump G-61 to pump the hydrocarbon 

liquids from D-7 to the recoverable oil tank. 

Gasses from the Hot Coker Blowdown system are recovered if the pressure in the blowdown does 

not exceed the pressure necessary to blow the water seal in the C-1 Flare Stack Water Seal Drum. 

Gasses are periodically sent to the flare from the Hot Coker Blowdown system. This 10” line is 

monitored with a separate ultrasonic meter. 

Capacity of the Relief and Blowdown Systems

The Refinery and MP-30 flare systems are sized to handle releases during refinery-wide utility 

failures -refinery-wide power failure, total saltwater cooling system failure, or 150 psig steam failure. 

The maximum design relief case for both these flare systems is currently a refinery-wide power 

failure. The design of an individual unit blowdown header may be based on other failures. For 

example the DIB blowdown header design is based on a refinery-wide salt water failure. The Unit 

267 blowdown header design is based on a 150 psig steam failure. 

The MP-30 blowdown system (consisting of F-600, F-604, and MP-30 blowdown header) is sized to 

handle releases from common utility failures for the MP-30 Complex - Units 229, 230, and 231. The 

two major utility failures, causing the highest relief loads, are power failure and cooling water failure. 

Power failure creates the highest radiation release concern in the flare area, because a refinerywide power failure can cause both the MP-30 Flare and the Main Flare to have large releases. An 

MP-30 cooling water failure creates the highest back pressure in the system for certain MP-30 relief 

valves. 

Interrelated Systems

Wet Gas Stream, process units, and compressor - The light ends section of Unit 200, Crude/Coking 

Unit, processes the bubble tower wet gas and bubble tower raw naphtha stream to produce a 

stabilized naphtha. Wet gas (high C3 – C5 content) from the bubble tower reflux drum is 

compressed by the G-501 Wet Gas Compressor, a multi-stage centrifugal compressor. The 

compressed gas is mixed with the bubble tower raw naphtha. In exchanger E-511, salt water cools 
the combined stream before the stream discharges into the F-502 High-Pressure Separator. Vapor 

from the high-pressure separator flows to the D-503 Absorber. In D-503, the vapor is contacted with 

a stripped lean oil which removes the heavier components from the vapor. The scrubbed off-gas 

from D-503 is then pressure controlled to the light ends sour fuel gas header. The combined sour 

fuel gas stream from the light ends section flows to Unit 233, the Refinery Fuel Gas Center. 

The Flare Gas Recovery Compressor (G-503) can be put into Wet Gas Compressor (G-501) 

service, if needed. This is done on a planned and emergency basis. The value of this is to 

minimize overall flaring. The “Wet Gas” Compressor runs at a rate much higher than the Flare Gas 

Recovery Compressor. The Flare Gas Recovery Compressor typically runs at about 50% of the 

maximum flow on an annual average basis. When the Flare Gas Recovery Compressor is put into 

Wet Gas Compressor service the entire capacity of the Flare Gas Recovery Compressor is utilized. 

Although flaring will likely occur, the total rate of flaring has been minimized by approximately 2.3 

MMSCFD by placing the Flare Gas Recovery Compressor into Wet Gas Compressor service. 

Odor Abatement: stream, process units, and compressor – There is a group of compressors and 

a closed vent system referred to as the “Odor Abatement” (OA) system. The OA System is a 

Refinery wide collection system that includes tank blanketing, vacuum towers non-condensable 

vapor, de-gassing vapors from various processes, butane tanks vents, and the iso-pentane tank 

vents. Seasonal ambient temperature increases will impact various processes causing an 

increase in flow of material to the OA System. The purpose of the system is to collect and control 

vapors from the sources listed above. Natural gas is purged into the system based on certain set 

points. Natural Gas as Blanketing Gas for tanks has been used due to low H2S/Sulfur content, 

nil oxygen content, consistent quality, and low molecular weight. Low molecular weight and low 

H2S/Sulfur are only critical to finished low sulfur products. Nil oxygen content is critical for 

finished product and intermediate products to prevent formation of materials that foul preheat 

exchangers. 

The compressors help maintain pressure in the system and maintain movement of the vapors. The 

vapors are routed, via the odor abatement compressors directly to Unit 233 Fuel Gas Center. The 

vapors are co-mingled with other recovered streams, such as the U200 Wet Gas & Flare Gas 

Recovery vapors, for sulfur removal. 

There are 4 odor abatement compressors. Typically, one or two compressors are operating with a 

third one as backup. A 4th compressor was installed in 2009. Following the installation of the 4th

compressor, 2 to 3 compressors will typically be operated with 1 to 2 spare compressors. The Flare 

Gas Recovery Compressor can be put into Odor Abatement service, if needed. By utilizing the 

Flare Gas Recovery Compressor in Odor Abatement service, emissions directly to the atmosphere 

are mitigated but flaring will likely take place. 

F-502- F-502 which is shown on the PFD shown in Attachment B is related to the Wet Gas 

Compressor system described above. Gasses collected and compressed in the G-501 Wet Gas 

Compressor are then sent to the Unit 200 F-502 High Pressure Separator. If the Flare Gas 

Recovery Compressor (G-503) is utilized in Wet Gas Compressor service then the Flare Gas 

Recovery Compressor would discharge to the F-502 separator. 
Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT C 

SAN FRANCISCO REFINERY 

FLARE SYSTEM PROCESS FLOW DIAGRAM 
MAIN FLARE

GAS SAMPLER

10" LINE ULTRASONIC

FLOWMETER & INDICATORS

42" LINE ULTRASONIC

FLOWMETER & INDICATORS

MP30 FLARE

GAS SAMPLER

MP30 ULTRASONIC

FLOWMETER & INDICATORS

36" LINE ULTRASONIC

FLOWMETER & INDICATORS
Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT D 

SAN FRANCISCO REFINERY 

HISTORICAL STARTUP / SHUTDOWN EVENT DATA (2001 – 2006) 

Note: This was a one time review. This review was performed as required by 12-12 during the initial 

submittal. Following the submittal of the initial FMP Flare RCA’s and turnaround flare planning was 

conducted to address flare minimization for startup / shutdown activities. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT E 

Phillips 66 

San Francisco Refinery, Rodeo, CA 

Unit List 

Unit Number Unit Description 

 40 Raw Materials Receiving Unit 

 76 Gasoline Blending Unit 

 80 Refined Oil Shipping Unit

 100 Process Water Unit 

 110 Hydrogen Plant 

 120 Hydrogen Plant (new in 2009, 3rd party operated by Air Liquide)

 200 Coking Unit 

 200 Relief and Blowdown System 

 215 Gasoline Fractionation and Deisobutanizer, and Caustic Treating Unit 

 228 Isomerization Unit 

 229 Mid-Barrel Unionfining Unit 

 230 Naphtha Unionfining Unit 

 231 Magnaforming Unit 

 233 Fuel Gas Center 

 235 Sulfur Unit (new in 2009) 

 236 Sulfur Unit 

 238 Sulfur Unit 

 240 Unicracking Unit 

 244 Reforming Unit 

 246 Heavy Oil Hydrocracker (new in 2009) 

 248 Unisar Unit 

 250 Diesel Hydrotreating Unit 

 267 Crude Distillation Unit 

 MTC Marine Terminal Complex 

 SPP Steam Power Plant 

--- Relief and Blowdown System 
Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT F 

SAN FRANCISCO REFINERY 

FLARE MINIMIZATION PROCESS FLOWCHART 

Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT G 

TYPICAL FLARE GAS RECOVERY SYSTEM 

Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT H 

SAN FRANCISCO REFINERY 

FLARING EVENT OVERVIEW & CATEGORIZATION 
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Prevention Measures 

Listed in Causal Analysis Submitted to BAAQMD 

& Recurrent Failure Analysis 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

6/13/2006 Loss of Salt Water 

Cooling, G-503 

Shutdown

The G-503 Flare Gas Recovery 

Compressor shutdown due to high gas 

temperatures from lack of adequate 

cooling water due to loss of salt water 

cooling at the refinery.

Hydroblast screen cleaning 

was not done frequently 

enough and/or not 

coordinated with low tide 

cycles.

1. Develop low tide operating plan.

2. Clean intake structure and 

screens to remove biological growth.

3. Clean mud and debris from

pump bays.

4. Schedule Spring/Fall hydroblast 

cleanings before low tide cycles.

1. COMPLETED 7/21/06

2. COMPLETED 6/13/06

3. COMPLETED 4/1/2007

4. COMPLETED 8/06

Duration: 4 hours

Flow: 551 MSCFD

Emissions:

 SO2 – 1,700 lbs 

 (H2S = 1.9%)

 NMHC – 220 lbs

 Methane – 90 lbs

n/a – FMP not yet in effect 341-06

N

Blow back air burst cleaning 

equipment was not working 

properly on several intake 

screens.

Review benefits of higher 

maintenance frequency for multiple 

blow valve failures.

COMPLETED 10/1/06

Routine operations screen 

washing is insufficient to 

manage marine growth on 

intake screens.

Evaluate alternative options for 

operations screen cleaning, including 

anti-foulant coatings.

COMPLETED 10/1/06

7/10/06 Unit 228 Shutdown The G-503 Flare Gas Compressor was 

shutdown when Unit 228 was 

shutdown. Unit 228 was shutdown 

due to the GB-520 Hydrogen 

Compressor shutting down when the 

electrical circuit tripped, causing the 

lube/seal oil pumps on the compressor 

to shutdown.

The coil of fiber optic cable 

springing loose and moving 

the breaker on GB-520.

1. Install switch covers.

2. Discuss with contractor the 

need to secure the fiber optic 

cable.

1. COMPLETED 7/11/06

2. COMPLETED 7/12/2006

Duration: 7.5 hours

Flow: 990 MSCFD

Emissions:

 SO2 – 2,100 lbs 

 (H2S = 1.3%)

 NMHC – 550 lbs

 Methane – 315 lbs

n/a – FMP not yet in effect 348-06

N

7/23-24/06 Unit 228 Startup & 

Shutdown

The G-503 Flare Gas Compressor was 

shutdown when Unit 228 was 

shutdown. Unit 228 was shutdown 

due to the GB-520 Hydrogen 

Compressor shutting down during a 

PG&E voltage sag. The protective 

relay at at GB-520 interpreted the 

voltage sag as a reverse power 

situation and triggered the shutdown. 

In addition, PSV-890 lifted and sent 

PG&E voltage sag Disabled option that shuts down the 

compressor during a reverse power 

situation.

COMPLETED 7/23/06 Duration: 17 hours

Flow: 1,340 MSCFD

Emissions:

 SO2 – 870 lbs 

 (H2S = 0.38%)

 NMHC – 700 lbs

 Methane – 350 lbs

n/a – FMP not yet in effect. 376-06

N

PSV-890 lifted PSV-890 was serviced and the back 

pressure controller tuned.

COMPLETED 7/31/06

10/26-11/1/06, 

11/7/06, 11/17-

18/06, & 

Unicracker 

Shutdown, G-503 

Shutdown, Fuel 

The main cause of flaring was due to 

the planned shutdown of the 

Unicracker Complex. During this 

Fuel Gas Out of Balance 1. Use of IERC’s to allow for 

temporary higher firing during 

“fuel gas out of balance period”. 

1. COMPLETED – approx. Jan 2007. Duration: 223 hours

Flow: 46,145 MSCFD

n/a – FMP not yet in effect. 479-06

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

11/22/06 Gas Out of Balance period there were numerous units 

shutting down, reducing system 

pressure, purging equipment with 

steam and nitrogen. In addition, there 

was a Plant 4 unit upset following 

startup.

Higher firing would result in an 

increase of the NOx Bubble 

level. 

2. Evaluate permitting options for 

increasing SPP Turbine SO2 

limit during fuel gas out of 

balance periods in order to 

minimize or prevent flaring.

2. See Section 3.2 Planned 

Reductions, 

Emissions:

 SO2 – 8,600 lbs 

 (H2S = 0.3%)

 NMHC – 7,500 lbs

 Methane – 8,720 lbs

Plant 4 Repairs Repairs required to be made to 

complete unit startup & prevent 

recurrence.

COMPLETED 11/18/06

12/7/06 G-503 Maintenance The G-503 compressor was shutdown 

for planned maintenance. In the 

course of performing routine 

equipment checks the Reliability group 

identified a potential issue via an 

auditory observation. It was believed 

the issue was with the loader valve 

positioner so a shutdown was 

scheduled.

Loader Valve Failure 1. Repair valve.

2. Upgrade loader valves which 

are impacted most significantly 

by gravitational forces.

1. COMPLETED – 12/7/06.

2. COMPLETED - February/March 

2007 during G-503 overhaul. See 

Section 4.3.1 in the FMP for 

additional details.

Duration: 86 hours

Flow: 10,264 MSCFD

Emissions:

 SO2 – 18,339 lbs 

 (H2S = 1.14%)

 NMHC – 4421 lbs

 Methane – 3115 lbs

4.2.1.1 Flare Gas Recovery Compressor 

Maintenance – Minor Maintenance

025-07

N

Tarry Substance 1. Investigate source of tarry 

material through analytical 

testing. 

1. COMPLETED Approx. 12/15/06 –

no unusual materials discovered. 

Source indeterminate.

Actuator Cylinder Piston 

Failure

1. Replace failed seal.

2. Conduct regularly scheduled 

compressor overhaul. 

Purpose is to perform 

inspection of equipment and 

make repairs, as needed. 

1. COMPLETED 12/12/06

2. COMPLETED - February/March 

2007. See Section 4.3.1 in the 

FMP for additional details.

2/24/07 Unit 200 

Turnaround & G503 Shutdown

The primary cause for flaring is due to 

the planned shutdown of Unit 200 

Coker & scheduled overhaul of G-503 

Flare Gas Recovery Compressor. 

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround pre & post 

planning was conducted to 

review expected flaring & 

minimization techniques to 

be implemented. 

n/a n/a Duration: 257 hours

Flow: 17,024 MSCFD

Emissions:

 SO2 – 34,220 lbs 

 (H2S = 1.08%)

 NMHC – 10,800 lbs

 Methane – 3,000 lbs

FMP 4.2.1 Equipment Preparation for 

Maintenance (Rev 3, p. 4-17)

FMP 4.2.1 Preventative Maintenance – Flare 

Gas Recovery Compressor Maintenance (Rev 

3, p. 4-17)

127-07

N

3/18/2007 Failure in Electrical 

Power Supply

Power Supply Failure at SRUs Ground Fault Relay Failure Replace the faulty relay. COMPLETED Duration: 3.75 hours

Flow: 1,606 MSCFD

Emissions:

 SO2 – 12,000 lbs 

 (H2S = 4.45%)

 NMHC – 1,200 lbs

 Methane – 525 lbs

FMP 4.2.1.4 Equipment Failure which Results in 

an Immediate or Controlled Unit Shutdown (Rev 

3, p. 4-19)

160-07

N

The Refinery MOC/PHA 

policy does not encompass 

1. Evaluate and modify as needed the 

PHA/MOC process to include 

1. COMPLETED 10/3/2007 & on-going. 

As part of the EUPHA process loss of 
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

electrical design basis 

reliability 

electrical power distribution 

adequacy, redundancy, and reliability. 

2. Operations & Engineering to 

conduct joint process reliability 

reviews of the Sulfur Plant Complex 

electrical power distribution system. 

electrical power is considered. MOCs also 

consider electrical changes.

2. COMPLETED 9/30/08 

The Ground Fault Relay did 

not get tested

Identify and provide a plan to test or 

replace protective relays that are not 

normally accessible online or during 

single unit turnarounds. Review 

results of all relay testing and 

respond according to results. 

COMPLETED 6/30/08. List of inaccessible 

protective relays & plan for replacement 

developed.

8/20/2007 Pressure Safety 

Valve (PSV) 7 on 

Raw Hydrogen Line 

Opened 

Prematurely 

Unit 110 Hydrogen Plant PRV Lift and 

Subsequent Flaring

PSV 7 failed and opened 

prematurely.

Replaced with a new valve. 1. COMPLETED – 8/23/07. Duration: 73.62 hours

Flow: 23,166 MSCFD

Emissions:

 SO2 – 21,563 lbs 

 

 NMHC – 10,110 lbs

 Methane – 4,840 lbs

FMP 4.2.1.4 Upset/Malfunction – Leaking Relief 

Valves, PRV Malfunction (Rev. 3, p. 4-20)

FMP 4.2.1.4 Other Causes – i.e. Metallurgical 

Failure (Rev 3, p. 4-21)

FMP 4.2.1.4 Maintenance, Turnaround, Startup, 

Shutdown – Hydrogen Plant Startups (Rev 3, p. 

4-17)

353-07

N

PV 4 Bypass Valve Failed 1. PV 4 bypass was replaced along 

with a similar type valve in similar 

service as a precaution. 

2. PV 4 bypass was sent out for 

metallurgical examination. 

1. COMPLETED 8/23/2007

2. COMPLETED 9/25/07 (report received) 

– No further actions based on report 

findings.

Venting of H2 to Flare during 

U110 Startup

As described in the Flare

Minimization Plan a review will be 

completed as to the potential benefit 

of installing a H2 process vent.

Global Prevention Measure - see 

Prevention Measure section of FMP for 

current status and plan.

2/22/2008 Unit 110 Shutdown Unit 110 was scheduled for a planned 

turnaround. During the shutdown 

Hydrogen is sent to the flare blowdown 

system. The G-503 Flare Gas 

Recovery Compressor is shutdown 

when high volumes of Hydrogen are 

sent to blowdown.

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround pre & post 

planning was conducted to 

review expected flaring & 

minimization techniques to 

be implemented.

n/a n/a Duration: 9.82 hours

Flow: 2,908 MSCFD

Emissions:

 SO2 – 11,600 lbs

 (H2S = 2.40%) 

 NMHC – 231 lbs

 Methane – 1,583 lbs

FMP 4.2 Maintenance, Turnaround, Startup, & 

Shutdown – Hydrogen Plant Startups (Rev 3

131-08

N

8-Mar-08 U231 High Liquid 

Volume

U231 Startup and High Liquid Volume Shutting down G-503 Flare 

Gas Recovery Compressor

New Additional Flare Gas Recovery 

Compressor – as part of the CFEP 

and Flare Minimization Plan (FMP) 

commitments a redundant flare gas 

recovery compressor is being 

installed. The compressor will be 

able to operate under a wider range 

of gas composition then the existing 

COMPLETED – August 2009. Duration: 5.25 hours

Flow: 318 MSCFD

Emissions:

 SO2 – 1,306 lbs 

 (H2S = 2.5%)

FMP 4.2 Maintenance, Turnaround, Startup, & 

Shutdown – Unit Startup (Rev 3, p. 4-17)

FMP 4.2 Upset/Malfunction – Loss of Flare Gas 

Compressor: High Liquid Level (Rev 3, p. 4-20)

227-08

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

the existing G-503 Compressor. NMHC – 324 lbs

 Methane – 114 lbs

3/9/2008 Unit 110 Startup Unit 110 was scheduled for a planned 

turnaround. During the shutdown 

Hydrogen is sent to the flare blowdown 

system. The G-503 Flare Gas 

Recovery Compressor is shutdown 

when high volumes of Hydrogen are 

sent to blowdown.

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround pre & post 

planning was conducted to

review expected flaring & 

minimization techniques to 

be implemented.

n/a n/a Duration: 4.85 hours

Flow: 1,642 MSCFD

Emissions:

 SO2 – 1,960 lbs 

 (H2S = 0.72%)

 NMHC – 1,540 lbs

 Methane – 600 lbs

FMP 4.2 Maintenance, Turnaround, Startup, 

Shutdown – Hydrogen Plant Startups (Rev 3, p. 

4-17)

151-08

N

20-Mar-08 U250 LIC359 

Improperly Ranged

Unplanned Odor Abatement (OA) 

Compressor Shutdown

Switching G-503 Flare Gas 

Compressor into Odor 

Abatement Service

New Additional Flare Gas Recovery 

Compressor – as part of the CFEP 

and Flare Minimization Plan (FMP) 

commitments a redundant flare gas 

recovery compressor is being 

installed.

1. COMPLETED – August 2009. Duration: 6.83 hours

Flow: 850 MSCFD

Emissions:

 SO2 – 3,500 lbs 

 (H2S = 2.66%)

 NMHC – 452 lbs

 Methane – 345 lbs

FMP 4.2.1.4 Upset/Malfunction – Loss of other 

compressors (e.g. odor abatement, etc.) (Rev 3, 

p. 4-20)

225-08

N

Faulty Level Indication on 

LIC359 & LIC360

1. Re-range level indications on 

D-711 vessel so that full scale 

is seen in the DCS. Obtain 

proper records of calibration 

offset.

2. Confirm specific gravity on 

level indications for D-711 

Vessel. Consider re-calibration 

with water to ensure proper 

configuration parameters are 

used. 

3. Confirm and document any 

calibration offset placed in all 

level displacer indications at 

Unit 250. Verify correct specific 

gravity has been used for each 

level indication.

4. Evaluate a software alarm with 

logic verifying if both diesel 

production meters, FIC378 & 

FIC388 are reading zero. 

1. COMPLETED 3/20/08

2. COMPLETED 3/20/08 

3. COMPLETED 3RD Qtr 2009

4. Target 10/1/08 1st Qtr 2010

Not Identified as a Finding –

Prevention Measure

New Odor Abatement Compressor –

as part of the Clean Fuels Expansion 

Project (CFEP) an additional 

compressor is being added to provide 

more capacity.

 COMPLETED 3RD Qtr 2009.

14-Apr-08 G-503 Flare Gas 

Recovery 

Compressor 

Constant Voltage 

G-503 Unplanned Shutdown Constant Voltage 

Transformer (CVT) failure on 

G-503 Flare Compressor.

Replace CVT COMPLETED 4/14/2008 Duration: 7.85 hours

Flow: 618 MSCFD

FMP 4.2.1.4 Upset/Malfunction – Loss of Flare 

Gas Compressor (Rev 3, p. 4-20)

FMP 4.2.1.4 Upset/Malfunction – Equipment 

283-08

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

Transformer (CVT) 

Failure

Emissions:

 SO2 – 2,183 lbs 

 (H2S = 2.13%)

 NMHC – 373 lbs

 Methane – 258 lbs

Failure (Rev 3, p. 4-20)

Unplanned Shutdown of the 

G-503 Flare Gas 

Compressor due to 

equipment failure

New Additional Flare Gas Recovery 

Compressor – as part of the CFEP 

and Flare Minimization Plan (FMP) 

commitments a redundant flare gas 

recovery compressor is being 

installed.

COMPLETED – August 2009

5/16/2008 Unicracker & Unit 

200 Planned 

Shutdown

A planned shutdown was conducted 

on the Unit 200 Coker/Crude Complex 

& the Unicracker Complex. During the 

unit shutdowns there were periods 

where gas quality and/or quantity 

could not be recovered by the G-503 

Flare Gas Recovery compressor. 

Thus, the Compressor was shutdown 

at various times when gas quality 

and/or quantity issues were occurring.

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround pre & post 

planning was conducted to 

review expected flaring & 

minimization techniques to 

be implemented.

n/a n/a Duration: 45.18 hours

Flow: 6,493 MSCFD

Emissions:

 SO2 – 24,900 lbs 

 (H2S = 2.16%)

 NMHC – 2,201 lbs

 Methane – 2,524 lbs

FMP 4.2.1.1 Equipment Preparation for 

Maintenance (Rev 3, p. 4-17)

344-08

N

5/28/2008 & 

6/2/2008

G-503 Unplanned 

Shutdown

The G-503 Flare Gas Recovery 

Compressor (G-503) shutdown 

unexpectedly due to a high liquid level. 

A G-503 shutdown occurred again on 

June 2, 2008 for the same reason. In 

each case the compressor was restarted as soon as possible once 

liquids had been removed from the 

flare gas recovery system. The 

primary cause was excess butane in 

the flare gas recovery system. 

Removed liquids from flare 

gas recovery system.

Made process and equipment 

adjustments to remove liquids from 

flare gas recovery systems.

COMPLETED 6/2/2008 Duration: 8.75 hours

Flow: 719 MSCFD

Emissions:

 SO2 – 3,980 lbs 

 (H2S = 3.0%)

 NMHC – 690 lbs

 Methane – 218 lbs

FMP 4.2.1.4 Loss of Flare Gas Compressor –

High Liquid Level (Rev 3, p. 4-20)

345-08

N

8/19/2008 G-503 Unplanned 

Shutdown

The G-503 Flare Gas Recovery 

Compressor (G-503) shutdown 

unexpectedly due to a high liquid level 

in the instrument air system. Flaring 

occurred while the compressor was 

down. 

High liquid level in the 

instrument air system.

1. Replacement of filters which 

removes moisture in air system.

2. Updated Operator routine rounds 

form (R-049) to include draining air 

system filters every shift.

1. COMPLETED 9/5/08

2. COMPLETED 8/27/08

Duration: 8.88 hours

Flow: 1,515 MSCFD

Emissions:

 SO2 – 4,700 lbs 

 (H2S = 1.3%)

 NMHC – 770 lbs

 Methane – 780 lbs

 Loss of Flare Gas Compressor – Monitored 

Safety/Protective Parameter (p. 4-20 Rev. 3)

 Loss of Flare Gas Compressor – High Liquid 

Level (p. 4-20 Rev. 3)

 Loss of Utility – Air (p. 4-20 Rev. 3)

472-08

N

10/3/2008 G-503 Unplanned 

Shutdown for Poor 

Gas Quality (U110 

Upset)

The G-503 Flare Gas Recovery 

Compressor (G-503) was shutdown 

due to an upset at the U-110 Hydrogen 

Plant (S-437). 

Water in PV-92 Valve 

Positioner 

1. Operators are manually blowing 

down the instrument air header and 

checking for water daily.

2. Calibration was checked for both 

PV-92 and PV-93 and no issues were 

found.

1. COMPLETED 10/08

2. COMPLETED 10/4/08

Duration: 7 hours

Flow: 1,092 MSCFD

Emissions:

 SO2 – 1,570 lbs 

 (H2S = 0.86%)

 NMHC – 340 lbs

 Methane – 440 lbs

Hydrogen Plant PSA operational changes –

Switching from 10 bed to 8 and 5 bed operation

516-08

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

10/22/08 G-503 Unplanned 

Shutdown for Poor 

Gas Quality (U110 

Upset)

The G-503 Flare Gas Recovery 

Compressor (G-503) was shutdown 

due to an upset at the U-110 Hydrogen 

Plant (S-437) pressure swing adsorber 

(PSA). During the upset at U-110, 

gases sent to the flare gas recovery 

system could not be recovered by the 

G-503 compressor. 

PV-93 stuck in closed 

position when the valve overstroked.

1. Maintenance improved the 

engineering design and modified the 

mechanical stops on PV-92 and PV93 to prevent the valves from overstroking.

1. COMPLETED 10/24/08 Duration: 4.33 hours

Flow: 2,120 MSCFD

Emissions:

 SO2 – 320 lbs 

 (H2S = 0.09%)

 NMHC – 400 lbs

 Methane – 650 lbs

Hydrogen Plant PSA operational changes –

Shutdown of PSA

523-08

N

11/1/2008 G-503 Unplanned 

Shutdown

The G-503 Flare Gas Recovery 

Compressor (G-503) was shutdown 

due to plugging of the compressor 

discharge line. During the period when 

the compressor was shutdown, gases 

sent to the flare gas recovery system 

could not be recovered and flaring 

occurred. 

G-503 discharge valve failed 

to open

1. Steam out of discharge piping 

scheduled for every 6 – 8 

months to prevent material 

buildup

2. Addition of new Flare Gas 

Recovery Compressor (item 

noted after RCA submitted & 

once it was determined periodic 

steaming cannot be performed 

on-line)

1. COMPLETED initially 11/2/08. Later 

determined this piping can only be 

steamed out while G-503 is down. 

2. COMPLETED August 2009. 

Duration: 27.5 hours

Flow: 3,744 MSCFD

Emissions:

 SO2 – 18,900 lbs 

 (H2S = 3.05%)

 NMHC – 2,480 lbs

 Methane – 1,380 lbs

Loss of flare gas compressor – monitored 

protective parameter triggered shutdown 

579-08

N

1/14/2009 G-503 Unplanned 

Shutdown for Poor 

Gas Quality (U110 

Upset)

The G-503 Flare Gas Recovery 

Compressor (G-503) was shutdown 

due to the unscheduled shutdown of 

the U110 Hydrogen Plant. Excess 

hydrogen in the flare gas recovery 

system can damage the G-503 

compressor. During the period when 

the compressor was shutdown, gases 

sent to the flare gas recovery system 

could not be recovered and flaring 

occurred. 

Lack of motor bearing 

lubrication

1. Review and Update the Oil 

Condition check procedure for limits 

on oil quantities removed while 

equipment is in service.

2. Update Reliability Activities 

Requiring Work Order Procedure for 

situations where significant oil is to be 

removed from bearings while 

equipment is in service.

3. Provide refresher training on these 

procedures.

1. COMPLETED Aug 2009

2. COMPLETED July 2009

3. COMPLETED Aug 2009

Duration: 9.92 hours

Flow: 1,459 MSCFD

Emissions:

 SO2 – 4,280 lbs 

 (H2S = 1.77%)

 NMHC – 150 lbs

Methane – 1,020 lbs

 Maintenance, Turnaround, Startup, Shutdown 

– Hydrogen Plant Shutdown (Section 4.2.1.1)

 Upset/Malfunction – Equipment failure which 

results in a unit shutdown (Section 4.2.1.4) 

089-09

N

1/17/2009 U110 Startup / G503 Shutdown The Unit 110 Hydrogen Production 

Plant was down for a turnaround. 

During the start up of the Hydrogen 

Reformer Plant hydrogen is vented to 

the blowdown system. Unit 200 began 

recirculating the G-503 Flare Gas 

Recovery Compressor due to the high 

volume of hydrogen being sent to the 

recovery system. This results in flaring 

of all gases typically recovered through 

the G-503 compressor as well as the 

excess raw Hydrogen. 

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround planning was 

conducted to review 

expected flaring & 

minimization techniques to 

be implemented.

n/a n/a Duration: 3.6 hours

Flow: 1,433 MSCFD

Emissions:

 SO2 – 1,550 lbs 

 (H2S = 0.65%)

 NMHC – 180 lbs

Methane – 960 lbs

 Section 4.2 - Maintenance, Turnaround, 

Startup, Shutdown – Hydrogen Plant Startups 

(p. 4-17)

92-09

N

1/26/09 G-503 Shutdown 

(low quality gas)

The G-503 Flare Gas Recovery 

Compressor (G-503) was shutdown 

due to planned nitrogen purging of 

drum, D-403C, at the U240 Hydrogen 

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

n/a n/a Duration: 7.12 hours

Flow: 1,441 MSCFD

 Section 4.2.1.4 Maintenance, Turnaround, 

Startup, Shutdown – Equipment Preparation 

for Maintenance (Section 4.2.1.1)

094-09

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

Plant. 

Turnaround planning was 

conducted to review 

expected flaring & 

minimization techniques to 

be implemented.

Emissions:

 SO2 – 2,220 lbs 

 (H2S = 0.9%)

 NMHC – 370 lbs

Methane – 830 lbs

March 2 – 9, 

2009

Major Unicracker 

Turnaround

A planned shutdown was conducted at 

the Unit 240 Unicracker Complex in 

order to perform scheduled 

maintenance on several units. During 

this shutdown, there were periods 

where flare gas quality and/or quantity 

could not be recovered by the G-503 

Flare Gas Recovery Compressor.

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround planning was 

conducted to review 

expected flaring & 

minimization techniques to 

be implemented.

n/a – turnaround related n/a Duration: 100 hours

Flow: 29,488 MSCFD

Emissions:

 SO2 – 66,500 lbs 

 (H2S = 1.33%)

 NMHC – 13,994 lbs

Methane – 10,645 lbs

 Section 4.2.1.1 Maintenance, Turnaround, 

Startup, Shutdown – Equipment Preparation 

for Maintenance (Section 4.2.1.1)

139-09

N

March 14 – 28, 

2009

Flare System 

Maintenance

A planned shutdown was conducted 

on the Main Flare (S-296) and 

equipment associated with the flare. 

The purpose of the shutdown was to 

conduct preventative maintenance 

work on the Main Flare and to conduct 

a required vessel inspection on the F-3 

Water Seal drum on the Main Flare 

system. 

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround planning was 

conducted to review 

expected flaring & 

minimization techniques to 

be implemented.

n/a – turnaround related n/a Duration: 298.25 hours

Flow: 77,470 MSCFD

Emissions:

 SO2 – 218,512 lbs 

 NMHC – 29,092 lbs

Methane – 36,183 lbs

 Maintenance, Turnaround, Startup, Shutdown 

– Equipment Preparation for Maintenance & 

Working on Equipment (Section 4.2.1.1)

 Reduced Consumption of Fuel Gas – Fuel 

Gas Imbalance (Section 4.2.1.3)

197-09

N

March 27 – 28, 

2009

Odor Abatement 

Compressor Upset

One of three odor abatement 

compressors, G-60C, shut down. Unit 

200 operators and maintenance 

personnel attempted to re-start the 

compressor a number of times during 

the evening shift. The G-60A 

compressor was already down for 

planned maintenance. This left only 

one of the three odor abatement 

compressors, G-60B, in operation. 

The facility Standard Operating 

Procedure (SOP) to switch the G-503 

Flare Gas Recovery Compressor from 

Flare Gas Recovery service to Odor 

Abatement service was implemented. 

Switching G-503 Flare Gas 

Compressor into Odor 

Abatement Service

1. A New redundant Flare Gas 

Recovery compressor is being 

installed as part of the CFEP and Flare 

Minimization Plan (FMP) 

commitments. 

2. Addition of a new 4th Odor 

Abatement Compressor 

1. COMPLETED August 2009

2. COMPLETED August 2009

Duration: 43 hours

Flow: 6,428 MSCFD

Emissions:

 SO2 – 1,359 lbs 

 (H2S = 0.18%)

 NMHC – 3,135 lbs

Methane – 2,629 lbs

 Upset/Malfunction – Loss of other 

compressors (e.g. odor abtement, etc.) 

(Section 4.2.1.1)

 Reduced Consumption of Fuel Gas – Fuel 

Gas Imbalance (Section 4.2.1.3)

196-09

N

E-11A-2 Leak 1. Replace shell of E-111A-2. 

2. Upgrade metallurgy of the E111A-2 exchanger. 

3. Condenser system maintenance 

such as anode replacement for 

each exchanger and downcomer 

piping replacement. 

3 COMPLETED mid-April 2009

3 COMPLETED mid-April 2009

. 

3 COMPLETED mid-April 2009.

3/29/09 Fuel Gas Imbalance A planned shutdown was conducted at 

the Unicracker Complex to perform 

scheduled maintenance on several 

No equipment specific 

prevention measures 

identified since these were 

n/a – turnaround related n/a Duration: 162 hours

Flow: 8,836 MSCFD

 Reduced Comsumption of fuel gas – Fuel 

Gas Imbalance (Section 4.2.1.3)

198-09

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

units. During this turnaround, 

approximately 30% of the refinery fuel 

gas consumers were out of service. 

This resulted in periods of fuel gas 

imbalance. 

planned activities. 

Turnaround planning was 

conducted to review 

expected flaring & 

minimization techniques to 

be implemented.

Emissions:

 SO2 – 147 lbs 

 (H2S = 0.01%)

 NMHC – 6,791 lbs

Methane – 2,375 lbs

4/19/09 Major Unicracker 

Turnaround

A planned shutdown was conducted at 

the Unicracker Complex to perform 

scheduled maintenance on several 

units. On April 19, 2009 from 3:50 PM 

until 9:10 PM there was flaring due to 

high gas quantity during the 

Unicracker unit startup. i the 

turnaround. 

Exceeding G-503 Flare Gas 

Compressor capacity. 

1. New redundant Flare Gas Recovery 

compressor, as part of the CFEP and Flare 

Minimization Plan (FMP) commitments, a 

redundant flare gas recovery compressor is 

being installed. The compressor will provide 

additional capacity during most periods of 

operation.

Duration: 5.42 hours

Flow: 751 MSCFD

Emissions:

 SO2 – 318 lbs 

 (H2S = 0.25%)

 NMHC – 194 lbs

 Methane – 411 lbs

 High base/continuous load (Section 

4.2.1.2)

 Reduced consumption of fuel gas – fuel 

gas imbalance (Section 4.2.1.3)

211-09

N

5/6/09 Unplanned 

Shutdown of Plant 2

The Unicracker Plant 2 experienced an 

unplanned shutdown due to the auto 

initiation of a safety system shutdown. 

The safety shutdown triggered the 

release of pressure from the reaction 

section of Plant 2 to the flare.

Catalyst bed collapse 1. Dump, screen, and reload catalyst. COMPLETED approximately May 20, 2009 Duration: 5 hours

Flow: 1,674 MSCFD

Emissions:

 SO2 – 30 lbs 

 (H2S = 0.01%)

 NMHC – 975 lbs

 Methane – 490 lbs

 Upset/Malfunction – Equipment Failure 

which Results in a Controlled Unit 

Shutdown (Section 4.2.1.4)

270-09

N

5/10/09 Plant 2 Shutdown Flaring occurred in association with 

maintenance being performed at the 

Unicracker Plant 2. The maintenance 

scheduled was to address the failure 

which occurred May 6th. 

Same as 5/6/09 event Duration: 44 hours

Flow: 16,809 MSCFD

Emissions:

 SO2 – 453 lbs 

 (H2S = 0.01%)

 NMHC – 8,658 lbs

 Methane – 3,386 lbs

 Equipment Preparation for Maintenance –

Depressurization of Equipment & 

Pressurization of Equipment with Nitrogen 

(Section 4.2.1.1)

 Reduced Consumption of Fuel Gas 

(Section 4.2.1.3)

278-09

N

5/23/09 Fuel Gas Imbalance On May 23, 2009 there was a period of 

fuel gas imbalance in which treated 

fuel gas was vented to the flare. 

No equipment specific 

prevention measures 

identified since these were 

planned activities. 

Turnaround planning was 

conducted to review 

expected flaring & 

minimization techniques to 

be implemented.

n/a – turnaround related n/a Duration: 6.5 hours

Flow: 1,092 MSCFD

Emissions:

 SO2 – 20 lbs 

 (H2S = 0.01%)

 NMHC – 1,000 lbs

 Methane – 350 lbs

Reduced Comsumption of fuel gas – Fuel Gas 

Imbalance (Section 4.2.1.3)

279-09

N

8/10/09 .Fuel Gas 

Imbalance

On 8/10/09 there was a fuel gas 

system upset that resulted in high 

levels of Hydrogen Sulfide (H2S) in the 

refinery fuel gas. The Federal limit for 

H2S in fuel gas is 162 ppm (3-hr rolling 

average). The recorded levels of H2S 

Implementation of EOP-15 

‘High H2S Content in the 

Refinery Fuel Gas System”. 

High sulfur fuel gas was 

temporarily flared and offset 

with natural gas.

Replace orifice plate on D-803 Amine 

Regenerator.

COMPLETED 8/11/09 Duration: 4.5 hours

Flow: 600 MSCFD

Emissions:

Reduced Consumption of Fuel Gas – Fuel Gas 

Imbalance (Section 4.2.1.3)

359-09

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

during this period ranged from 170-240 

ppm (3-hr rolling average), during 

which time Emergency Operating 

Procedure EOP-15 was implemented. 

Wrong type Orifice plate in 

the new D-803 Amine 

Regenerator Steam Supply 

to the Reboiler.

 SO2 – 160 lbs 

 (H2S = 0.16%)

 NMHC – 290 lbs

 Methane – 140 lbs

9/25/09 Unit 246 G-803 

Make-Up 

Compressor Relief 

Valve Lift

On 9/25/09 at approximately 8:25am, 

the G-503 Flare Gas Recovery 

Compressor began to load up & the 

unit operators noticed that the specific 

gravity of the gas was very low. In 

addition, the molecular weight of the 

flare gas dropped considerably. The 

G-503 Flare Gas Compressor was 

taken off-line to protect the 

compressor.

Unit 246 G-803 Make-Up 

Compressor Relief Valve 

lifted due to incorrect valve 

seat material

Replaced relief valve seating material 

in valve which relieved and those in 

similar service.

COMPLETED 9/29/09 (all relief valves) Duration: 8 hours

Flow: 1,020 MSCFD

Emissions:

 SO2 – 1,600 lbs 

 (H2S = 0.97%)

 NMHC – 230 lbs

 Methane – 180 lbs

Upset/malfunction - PRV malfunction (Section 

4.2.1.4)

Upset/malfunction-Fuel Quality Upset (4.2.1.4)

441-09

N

09/29/09 Unplanned Unit 110 

Shutdown & Startup

The Unit 110 Hydrogen Production 

Plant shutdown unexpectedly on 

9/28/10. The unit was started up the 

same day. When the Hydrogen Plant 

is started up there is a period of time in 

which the raw Hydrogen is sent to the 

blowdown system until the Hydrogen 

meets the necessary purity to be 

routed to the Hydrogen header. The 

fuel gas quality is not sufficient for 

recovery when there is Hydrogen in 

the blowdown system.

The No. 152 relay on the C-1 

Feed Gas Compressor 

failed. The failure of the 

relay resulted in a safety 

shutdown of the unit being 

triggered.

Replacement of the No. 152 relay. COMPLETED 9/28/09 Duration: 4.3 hours

Flow: 1,520 MSCFD

Emissions:

 SO2 – 2,855 lbs 

 (H2S = 1.13%)

 NMHC – 194 lbs

 Methane – 317 lbs

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups 

414-09

N

10/05/09 Unit 246 Relief

Valve Lift

During the early morning of 10/5/09 it 

was discovered that the relief valve on 

top of the Unit 246 Cold High Pressure 

Separator, F-801, was leaking to the 

MP-30 Flare. The leaking relief valve 

is PSV-05A/

PSV 05A Lifting. Remove from service, perform 

maintenance, seat lapped.

COMPLETED 10/6/09 Duration: 3.3 hours

Flow: 300 MSCFD

Emissions:

 SO2 – 115 lbs 

 (H2S = 0.23%)

 NMHC – 16 lbs

 Methane – 3 lbs

Leaking relief valves, PRV malfunction –

Upset/Malfunction (Section 4.2.1.4)

473-09

N

11/16/09 Unplanned Unit 244 

shutdown.

During the morning of 11/16/09 a small 

flange fire occurred at the Unit 244 

Reformer. The unit pressure was 

dumped to the flare for a unit 

shutdown, which resulted in flaring.

E-501B Exchanger Leak. While the unit was down the 

exchanger flange was tightened & a 

chemical sealant was applied.

COMPLETED 11/19/09 Duration: 5.5 hours

Flow: 830 MSCFD

Emissions:

 SO2 – 615 lbs 

 (H2S = 0.4%)

 NMHC – 435 lbs

 Methane – 140 lbs

Equipment failure which results in the unplanned 

shutdown of a unit – Upset/Malfunction (4.2.1.4)

050-10

N

02/23/10 Unit 110 Hydrogen 

Plant Scheduled 

shutdown

On 2/23/10, steps were taken to 

shutdown Unit 110 Hydrogen 

Production Plant for a scheduled 

shutdown. Unit 110 communicated to 

Unit 200, responsible for the flare, that 

n/a - Planned Shutdown No equipment specific prevention 

measures identified since these were 

planned activities. 

n/a – planned turnaround Duration: 4.5 hours

Flow: 1,060 MSCFD

Emissions:

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups.

136-10

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

Hydrogen would be sent to the fuel 

gas recovery system so that the amt of 

time the fuel gas recovery 

compressors were put on circulation 

would be minimized. 

 SO2 – 650 lbs 

 (H2S = 0.4%)

 NMHC – 180 lbs

 Methane – 470 lbs

03/11/10 Unit 240 Plant 2 

Planned Shutdown 

with Upset

On 3/11/10 Unit 240 Plant 2 

Hydrocracker was starting up after a 

brief planned shutdown. During the 

startup, approx 2 hrs after feed had 

been introduced, the recycle 

compressor shutdown. This resulted 

in the unit depressuring to the flare.

2F-201 High Pressure 

Separator level indicator is 

calibrated for normal 

operating feed, not feed used 

during startup.

Turnaround startup procedure updated 

to require visual monitoring of sight 

glass level.

COMPLETED 3/15/10 Duration: 0.3 hours

Flow: 485 MSCFD

Emissions:

 SO2 – 1,050 lbs 

 (H2S = 1.3%)

 NMHC – 170 lbs

 Methane – 250 lbs

Upset/Malfunction – Loss of a Major Compressor 

(4.2.1.4)

185-10 

N

 

3/20/10 Unit 110 Startup 

and U200 High 

Flow Conditions

On 3/20/10 Unit 110 Hydrogen Plant 

was scheduled to be started up. Prior 

to the startup there was high flow to 

the G-503 and G-540 compressors. 

The Comrpessors were shutdown due 

to high flow and poor gas quality. The 

Unit 110 startup subsequently 

occurred which resulted in off-spec 

hydrogen being sent to blowdown. 

The high flow prior to the 

Unit 110 shutdown was due 

to a Unit 200 D-203 Drum 

Wedge Plug Valve which 

was found to be cracked 

open.

Reinforce and review Wedge Plug 

Operation with Drum Switcher qualified 

operators.

COMPLETED 5/15/10 Duration: 5.5 hours

Flow: 1,569 MSCFD

Emissions:

 SO2 – 2,605 lbs 

 (H2S = 1.0%)

 NMHC – 322 lbs

 Methane – 845 lbs

High Base/Continuous Load (4.2.1.2)

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups (4.2.1.1)

198-10

N

4/27/10 Unplanned 

Shutdown of 3rd

Party Hydrogen 

Supplier

On 4/27/10 the 3rd party Hydrogen 

Plant that provides a significant portion 

of hydrogen to the refinery 

experienced an unplanned shutdown. 

This resulted in intermittent flaring. 

As reported by the 3rd party 

Hydrogen Supplier, the 

shutdown was due to a 

technician performing LDAR 

monitoring pulling a tag off of 

a control valve. The tag was 

attached to the actuator 

tubing for the control valve 

and when pulled the tubing 

came unattached, which 

resulted in the control valve 

assuming the fail safe 

position and shutting down 

hydrogen production. 

The 3rd party Hydrogen supplier 

trained their employees and their 

LDAR contractor on proper locations 

to hang tags. They also trained them 

on proper ways for tag removal 

(cutting, not pulling)

COMPLETED approx. 5/30 Duration: 29.75 hours

Flow: 2,656 MSCFD

Emissions:

 SO2 – 1,354 lbs 

 (H2S = 1.59-0.01%)

 NMHC – 1,455 lbs

 Methane – 985 lbs

Fuel and Hydrogen Gas Balance (4.2.1.1) –

unplanned Huydrogen supplier shutdowns.

223-10

N

6/7/2010 Unit 110 Planned 

Shutdown

Unit 110 was scheduled for a planned 

turnaround. During the shutdown 

Hydrogen is sent to the flare blowdown 

system. The G-503/540 Flare Gas 

Recovery Compressors are shutdown 

when high volumes of Hydrogen are 

sent to blowdown.

n/a – Planned Shutdown No equipment specific prevention 

measures identified since these were 

planned activities. 

n/a Duration: 6.83 hours

Flow: 2,520 MSCFD

Emissions:

 SO2 – 1,140 lbs 

 (H2S = 0.3%)

 NMHC – 340 lbs

 Methane – 970 lbs

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups & Shutdowns

249-10

N

7/20/10 PG&E Voltage Sag A voltage sag occurred in the thirdparty power supply. This resulted in 

flaring due to the loss of the flare 

The third-party supplier has 

been unable to identify the 

root cause of the voltage 

No specific prevention measures were 

identified by ConocoPhillips because 

the primary cause was the voltage sag 

n/a Duration: 21.63 hours

Flow: 1,220 MSCFD

Upset/Malfunction – Loss of a Utility 349-10

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

compressors and some other major 

pieces of equipment. In addition, a 

number of units had to be shutdown 

following the voltage sag. This 

resulted in the flaring of unscrubbed 

gas. 

sag. in the electricity supplied by the thirdparty utility supplier.

ConocoPhillips did meet with PG&E 

about the potential cause of the failure 

and power dips. PG&E reported they 

are undertaking a Modular Protection 

Automation & Control (MPAC) 

upgrade. This will replace all of the 

existing 115kV solid state relays with 

the latest microprocessor based relay 

standard to provide more line 

reliability and quick diagnostic tools. 

During a meeting with PG&E COP 

Business Manager also requested 

PGE to perform additional 

surveillance and increase the 

frequency of the preventative 

maintenance programs to the OleumMartinez and Oleum-Christy line

Emissions:

 SO2 – 3,540 lbs 

 (H2S = 2.27%)

 NMHC – 880 lbs

 Methane – 270 lbs

8/13/10 Unit 110 Startup & 

F-3 Work

The Unit 110 Hydrogen Production 

Plant started up after a shutdown 

period on August 13, 2010. Per the 

Unit 110 start-up SOP, Unit 200 began 

re-circulating the Flare Gas Recovery 

Compressors due to the high volume 

of hydrogen being sent to the recovery 

system, which can damage the 

compressor and decrease the Btu 

content of recovered gas. Recirculating the compressors results in 

flaring of all gases typically recovered 

through the compressors as well as 

the excess raw Hydrogen. This 

resulted in the flaring of unscrubbed 

gas.

n/a - Planned Shutdown No equipment specific prevention 

measures identified since these were 

planned activities. 

n/a – planned turnaround Duration: 6.32 hours

Flow: 2,610 MSCFD

Emissions:

 SO2 – 4,870 lbs 

 (H2S = 1.1%)

 NMHC – 1,320 lbs

 Methane – 940 lbs

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups.

393-10

N

9/3/10 Unit 110 Startup & 

F-3 Work

During this flaring event, two separate 

work activities were coordinated in 

order to minimize flaring. This resulted 

in one flaring event of unscrubbed gas 

instead of two different events had the 

activities been completed at different 

times and decreased the amount and 

duration of flaring that otherwise would 

have occurred.

The Unit 110 Hydrogen Production 

Plant started up on September 3, 2010 

after a brief shutdown period. Prior to 

the startup of Unit 110, it was 

determined that maintenance was 

n/a - Planned Shutdown No equipment specific prevention 

measures identified since these were 

planned activities. 

n/a – planned turnaround Duration: 5 hours

Flow: 1,619 MSCFD

Emissions:

 SO2 – 2,650 lbs 

 (H2S = 1%)

 NMHC – 750 lbs

 Methane – 340 lbs

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups.

430-10

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

required on the F-3 Water Seal Drum, 

which is an integral vessel in the Fuel 

Gas Recovery System. This work, 

which involved replacing the F-3 drain 

piping, was conducted during the Unit 

110 startup to minimize flaring at the 

refinery. Had the F-3 work been 

conducted on its own, it would have 

resulted in flaring due to the need to 

shutdown the Fuel Gas Recovery 

Compressors. The coordination of 

these two activities minimized flaring 

from the refinery. 

9/13/10 AL Unplanned 

Shutdown

The Refinery’s third-party Hydrogen 

Plant, Air Liquide, experienced an 

unplanned shutdown. As reported by 

Air Liquide, the cause of the shutdown 

was due to a faulty thermocouple on 

an Induced Draft (ID) fan bearing 

which resulted in loss of hydrogen 

production from this source. The 

Refinery had one of its two hydrogen 

plants in operation at the time. The 

Refinery’s larger hydrogen plant was 

down for maintenance. The loss of 

Hydrogen from Air Liquide resulted in 

multiple refinery upsets. Unit 246, Unit 

250 and Unit 240 Plant 2 Second 

Stage Charge were shutdown. Due to 

the loss of hydrogen and subsequent 

shutdown of units and rate reductions, 

the fuel gas system pressured up, 

which resulted in flaring. The flaring 

was of a combination of scrubbed and 

unscrubbed gas. 

Third party unplanned 

shutdown

The third party supplier 

provided cause and corrective 

action:

The Multilin controller for the 

ID Fan motor shutdown on a 

high temperature indication at 

the bearing. The plant was 

operating normally at 67% 

capacity. When the Multilin 

motor protection relay 

indicated a high termpature 

on temperature probe No. 7 

(motor bearing) the relay 

stopped the motor, per 

design. 

The root casue was 

determined to be an 

installation issue where a 

larger gauge wire was 

installed on a smaller guage 

terminal block connectior. 

When the ID Fan and motor 

was replaced in 12/09, the 

new wire was not equal to the 

original installation and it was 

not well secured by the knife 

blade terminal block 

connector. 

No specific prevention measures were 

identified by ConocoPhillips because 

the primary cause was the voltage sag 

in the electricity supplied by the thirdparty utility supplier.

Third party corrective actions:

1. Terminal block incorrect size for 

installed wiring on C-102 motor. 

Replace terminal block with one 

that accepts installed wiring size. 

2. Verify wiring terminal block on C101 motor is correct. Replace 

terminal block with one that 

accepts installed wiring size. 

3. Wiring may become loose. 

Epoxy seal new wiring terminal 

block to prevent terminals from 

coming loose. 

4. Installed instrument cable was 

not sized correctly for motor RTD 

terminals. Develop QA 

inspection procedure for 

acceptance of newly installed or 

replaced instrumentation.

5. Personnel with limited access to 

the Mulitlin software and training 

to support plant personnel. 

Identify sufficient personnel 

resources and have them trained 

to access Multilin software. 

See the corrective actions associated with 

the 10/22/2010 event. After repeated 

events with the shutdown of the 3rd Party H2 

Plant measures were put in place to 

minimize impact of recurrence.

Third party corrective action status.

1. COMPLETED 9/13/2010

2. COMPLETED 9/13/2010

3. COMPLETED 9/13/2010

4. COMPLETED 6/13/2011

5. COMPLETED 12/31/2010

Duration: 3.22 hours

Flow: 600 MSCFD

Emissions:

 SO2 – 2,340 lbs 

 (H2S = 2.34%)

 NMHC – 430 lbs

 Methane – 180 lbs

Fuel and Hydrogen Gas Balance (4.2.1.1) –

included unplanned Hydrogen supplier 

shutdowns

436-10

N

(3rd party) 
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

9/25/10 Unit 240 G-425 

Level Indicator 

Failure

On September 25, 2010 at 

approximately 3:14 P.M. an increase in 

fuel gas system pressure led to flaring 

of treated fuel gas. At approximately 

4:30 P.M. the G-503 Fuel Gas 

Recovery Compressor was circulated 

due to high liquid level. Although the 

G-540 Compressors were in operation, 

the circulation of the G-503 

Compressor resulted in flaring of 

unscrubbed gas. 

Unit 240 Plant 4 LIC 429 

Level Controller Malfunction

1, Operate the F-429 Knock Out Drum 

in manual (i.e. take 4 LIC 429 out of

service) COMPLETED 9/25/10

Duration: 4.32 hours

Flow: 354 MSCFD

Emissions:

 SO2 – 791 lbs 

 (H2S = 1.35%)

 NMHC – 200 lbs

 Methane – 100 lbs

 Upset/Malfunction – Failure of Instrumentation

 Upset/Malfunction – Loss of Fuel Gas Recovery 

Compressor / High Liquid Level 

431-10

N

10/6/10 3

rd Party Hydrogen 

Plant Unexpected 

Shutdown

At approximately 4:40 PM the 

Refinery’s third-party Hydrogen Plant, 

Air Liquide, experienced a sudden 

shutdown. As reported by Air Liquide, 

the cause of the shutdown was due to 

a valve issue on their Pressure Swing 

Adsorber (PSA). When the PSA valve 

stuck it led to a shutdown of their 

Reformer Heater due to high firebox 

pressure. The Refinery had one of its 

two hydrogen plants in operation at the 

time. The Refinery’s larger hydrogen 

plant was down for maintenance. The 

loss of Hydrogen from Air Liquide 

resulted in multiple refinery upsets. 

Feed was removed from Unit 246, Unit 

250 and Unit 240 Plant 2 Second 

Stage Charge. Due to the loss of 

hydrogen and subsequent shutdown of 

units and rate reductions, the fuel gas 

system pressured up, which resulted in 

flaring of scrubbed and unscrubbed 

gas. 

Following the Air Liquide Hydrogen 

Plant shutdown, approximately 20 

MMSCFD of fuel and feed gas that is 

normally supplied by the refinery to Air 

Liquide was diverted to the refinery 

fuel gas system. This excess gas 

caused the refinery fuel gas system to 

pressure up which resulted in 

approximately 674 MSCF of sweet fuel 

gas being sent to the flare from 

October 6 to 8, 2010. During the upset 

a relief valve (PSV 069) at Unit 240 

Plant 2 relieved prematurely. Its 

setpoint is 290 psig, it relieved at 

approximately 250 psig. This resulted 

The primary root cause was 

due to the sudden shutdown 

of the third-party Hydrogen 

Plant. As described above, 

ConocoPhillips did implement 

measures to minimize flaring 

during the upset. Listed 

below is a prevention 

measure completed in respect 

the the relief valve which lifted 

following the upset. 

The third party H2 Plant 

supplier did provide root 

cause and corrective actions. 

The Steam Methane 

Reformer tripped on high box 

pressure when the PSA went 

from 12-bed to 10-bed 

operation. The root cause of 

the trip was inadequate PV1611 response. The 

response resulted in a 

feedback mismatch of greater 

than 20% that exceeded 7 

seconds. This feedback 

mismatch caused the PSA to 

go from 12 to 10-bed. The 

consequential disturbance in 

off-gas flow as the PSA 

adjusted to the new operating 

mode then caused an upset in 

the furnace pressure control 

ultimately leading to a plant 

trip. 

Inspect and repair PSV069. 

See the corrective actions associated 

with the 10/22/2010 event. After 

repeated events with the shutdown of 

the 3rd Party H2 Plant shutdown, 

measures were put in place to 

minimize impact of recurrence.

The third party supplier provided the 

following prevention measures.

1. Operators have to reduce PC412A (off gas flare relief) from 6 

psi to 4 psi to account for high off 

gas pressure. Investigate 

feasibility and implement a DCS 

response based on PSA signal 

of bed switch over event.

2. C-102 damper actuator 

responds slowly. 

a. Tune PC-402 

damper system.

b. C-102 damper 

inspection/discovery 

is scheduled.

3. Initiating event for PSA beds 

tripping off, not logged. Ensure 

alarm logger is running while 

plant is up.

4. No means of monitoring valve 

on-line performance. Investigate 

feasibility of AMS.

5. PSA UOP specifications do not 

match valve specifications. 

Investigate changing valve 

COMPLETED, approximately during the 

week of 10/6/2010

Status of corrective actions provided by 

Third party

1. COMPLETED 6/15/2011

2. 

a. COMPLETED 6/15/2011

b. COMPLETED 6/15/2011

3. COMPLETED 10/8/10

4. COMPLETED 12/31/10

5. COMPLETED 6/15/2011

Duration: 31.5 hours

Flow: 1,815 MSCFD

Emissions:

 SO2 – 4,650 lbs 

 (H2S = 1.56%)

 NMHC – 1,110 lbs

 Methane – 535 lbs

Fuel and Hydrogen Gas Balance – including 

unplanned Hydrogen supplier shutdowns

473-10

N

(3rd party)
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

in additional flow, primarily Hydrogen, 

to the flare from 6:00 PM until 8:00 PM 

on October 6, 2010. Prior to the Air 

Liquide shutdown the G-503 Fuel Gas 

Recovery Compressor was down for 

maintenance. The G-540 Fuel Gas 

Recovery spare compressors were in 

service. During the upset the G-540 

Fuel Gas Recovery compressors 

remained operational. 

specifications to match UOP and 

monitoring valve local alarms.

6. Possible contamination. 

Inspection of IA header 

scheduled for turnaround.

7. PSA has not been tuned at 

higher rates. Tune PSA bed at 

higher rates. 

6. COMPLETED 6/15/2010

7. COMPLETED 11/15/2010

10/22/10 3

rd Party Hydrogen 

Plant Unexpected 

Shutdown, Cogen 

and Refinery 

Shutdown

The Refinery’s third-party Hydrogen 

Plant, Air Liquide, that provides a 

significant portion of hydrogen to the 

refinery, experienced a sudden 

shutdown. The shutdown of the 

Hydrogen Plant led to the shutdown of 

several process units and the refinery 

Steam Power Plant (SPP). Without 

steam, the majority of the refinery units 

were required to shutdown. These 

shutdowns resulted in flaring of 

scrubbed and unscrubbed gas on 

October 22, 2010 which then 

continued intermittently until October 

23, 2010.

Air Liquide Shutdown 1. COP intends to operate Plant 4 

Hydrogen Plant until Air Liquide 

completes actions to improve 

reliability.

2. COP has teamed with Air 

Liquide in an engineering study 

to improve reliability.

1. COMPLETED.

2. COMPLETED during 2011 2nd Qtr 

2011 t/a.

Duration: 29 hours 

Flow: 12,657 MSCFD

Emissions:

 SO2 – 17,422 lbs 

 (H2S = 0.66%)

 NMHC – 4,330

 Methane – 2,745

Fuel and Hydrogen Gas Balance including 

unplanned Hydrogen supplier shutdowns

Upset/Malfunction Loss of Utility (steam, air, 

cooling water, power)

475-10

N

(3rd party)

Fuel Gas System Pressure 

Increased

1. Identify and implement solutions 

for fuel gas system pressure 

increase when AL shutdown. 

2. Revise the Refinery Emergency 

Operating Procedure (EOP-21) 

to better address AL shutdowns.

1. COMPLETED – PRV added during 

June 2011 t/a to divert fuel gas to flare 

during upset.

2. COMPLETED 3/1/2011

Condensate blowin into 

GT23C by air purge

1. Revised the SPP Turbine 

emergency shutdown procedure 

to block in the steam injection for 

all operating turbines if the 

steam injection is lost for any 

reason.

2. Evaluate changing the air purge 

drop out to include a manual 

reset before it can be activated 

after a drop-out event.

1. COMPLETED.

2. COMPLETED 11/1/2010. An 

alternative to the manual reset was 

identified to be an improved 

mitigation. EOP-501-SPP was 

updated to reflect a procedural 

change step.

Loss of SPP instrument air 1. Revise the SPP Turbine 

emergency shutdown procedure 

to block in the instrument air to a 

a shutdown turbine to prevent 

loss of instrument air.

2. Repair the PCV-905 pressure 

regulator to ensure that it will 

fully open when the SPP 

instrument air drops below 80 

psig.

3. Inspect the SPP instrument air 

1. COMPLETED

2. COMPLETED

3. COMPLETED during 2011 t/a’s.
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

system for leaks at next t/a. 

10/27/10 Unit 240 DIB 

Overhead Hydrate 

Line Plug

On October 27, 2010 at approximately 

1:30 A.M. flaring of unscrubbed gas 

commenced at a relatively low volume. 

At that time ConocoPhillips also 

discovered a hydrate plug in the Unit 

240 Plant 3 D-301 overhead system. 

The rate of flaring increased over time. 

At 5:18 AM the G-503 Fuel Gas 

Recovery Compressor was shutdown 

which resulted in additional flaring. 

ConocoPhillips cleared the hydrate 

plug around 6:10 AM. The G-540 and 

G-503 Fuel Gas Recovery 

Compressors were put in service at 

7:10 AM and 7:45 AM respectively, 

once ConocoPhillips determined the 

plugging issue had been resolved. 

D-301 Overhead Temperature 

dropped below 65 F during 

startup.

Update Unit 240 Plant 2/3 startup 

procedures to specify that overhead 

temperature should not be below when 

65 F when feed from Plant 2 is 

introduced. 

 TOP-PL2-202-Section 1 Startup

 TOP-PLT2-202-Section 2 Startup 

COMPLETED Duration: 7 hours

Flow: 2,997 MSCFD

Emissions:

 SO2 – 11,420 lbs 

 (H2S = 2.29%)

 NMHC – 1,650 lbs

 Methane – 860 lbs

Upset/Malfunction – Equipment Plugging 472-10

N

1/22-27/2011 Fuel Gas Balance Turnarounds were taking place at units 

that included large combustion 

sources during January 2011. Due to 

the number of process units in 

turnaround, there were periods where 

all of the fuel gas produced could not 

be consumed. Due to the imbalance in 

the fuel gas system, the additional fuel 

gas that could not be consumed by the 

refinery process heaters was flared. 

Periods of fuel gas imbalance where 

the flow exceeded the BAAQMD 

reporting threshold of 500,000 

standard cubic feet per day (scfd) 

occurred from January 22 until January 

27, 2011. During this period, only 

excess treated (scrubbed) fuel gas 

was flared. In addition, a large volume 

of nitrogen was used to depressure 

and purge one of the units as part of 

its shutdown. This nitrogen was sent 

directly to the flare.

No specific prevention 

measures were implemented 

but measures were taken to 

minimize the quantity of 

material flared. 

n/a n/a Duration: 128.42 hours

Flow: 16,802 MSCF

 SO2 – 415 lbs 

 (H2S = 0.01%)

 NMHC – 9,620 lbs

 Methane – 3,186 lbs

Reduced Consumption of Fuel Gas – Fuel Gas 

Imbalance (Section 4.2.1.3)

137-11

N

2/15/2011 Unit 110 Startup The Unit 110 Hydrogen Production 

Plant started up on February 15, 2011 

after a planned shutdown. Per the 

Unit 110 start-up SOP, Unit 200 began 

re-circulating the G-503 Flare Gas 

Recovery Compressor due to the high 

volume of hydrogen being sent to the 

recovery system, which can damage 

this compressor. During this period 

each of the G-540 Flare Gas 

Compressors were put in service. They 

No new prevention measures 

or corrective actions were 

identified. The Unit 110 

startup is a planned activity 

that will re-occur in the 

future. 

 

 Due to the unplanned 

shutdown with the third-party 

H2 Plants as detailed in the 

10/22/10 event the Plant 4 

n/a n/a Duration: 2.16 hours

Flow: 641 MSCFD

Emissions:

 SO2 – 700 lbs 

 (H2S = 0.67%)

 NMHC – 127 lbs

 Methane – 128 lbs

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups

138-11

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

can handle more varied gas quality 

and the fuel gas was not negatively 

impacted by the excess hydrogen 

being added. The flaring of 

unscrubbed gas and hydrogen 

occurred during this flare event.

H2 plant was kept in 

operation for reliability 

purposes. This resulted in 

additional Unit 110 Startups 

and Shutdowns when the 

plant is long on Hydrogen 

production in association 

with other unit shutdowns. 

2/21/2011 Unit 240 DGA 

Upset, Fuel Gas 

balance & Plant 4 

Shutdown

An electrical outage at the Diethylene 

Glycol Amine (DGA) pumps, located at 

Powerhouse No. 3 in the Unicracker 

Complex, resulted in higher than 

normal concentrations of H2S in the 

fuel gas system. This resulted in a fuel 

gas upset which started in the Refinery 

Fuel Gas A (RFG A) and later migrated 

to the Unit 233 fuel gas system. RFG 

A that normally would be fed to the 

third party Hydrogen Plant was 

dropped out to prevent unit damage. 

Since RFG A is used as feed and fuel 

this upset resulted in a sudden fuel 

gas imbalance. The G-503 and G-540 

Flare Gas Recovery Compressors 

were circulated as part of 

implementing Emergency Operating 

Procedure (EOP) 12 “Total Loss of 

DGA Circulation”. Following the upset 

there was a period of fuel gas 

imbalance the following day since the 

large Unit 240 B401 Hydrogen Plant 

remained shutdown. This flare event 

resulted in the flaring of unscrubbed 

and scrubbed gas. 

High resistance due to 

connection issue.

1. Properly clean and inspect 

Bus connections during 

maintenance periods.

2. Consider performing 

ultrasonic testing 

preventative maintenance 

of powerhouses and 

substaions.

1. Ongoing with unit turnarounds.

2. Ongoing with unit turnarounds.

Duration: 37.5 hours

Flow: 7,652 MSCF

Emissions:

 SO2 – 8,614 lbs 

 (H2S = 1.38%)

 NMHC – 5,559 lbs

 Methane – 1,988 lbs

Upset / Malfunction – Loss of a Utility 192-11

n

Equipment Problems related 

to this upset.

1. Replace aluminum Bus 

Bars with copper Bus 

Bars.

2. Consider relocating 4GM415A starter to the Plant 

31 MCC. 

1. COMPLETED 11/4/11

2. COMPLETED 6/29/12

4/4/2011 Voltage Sag 

resulting in Fuel 

Gas Overpressure

On April 20, 2010 a voltage sag 

occurred in the third-part power supply. 

This resulted in flaring of unscrubbed 

gas due to the loss of two fuel gas 

compressors and some major pieces 

of equipment. A number of units were 

temporarily impacted by the voltage 

sag. 

No specific prevention 

measures were identified by 

ConocoPhillips because the 

primary cause was the 

voltage sag in the electricity 

supplied by the third party 

supplier. 

The third party electricity 

supplier did report that they 

found a flashed inulator 

approximately 3 miles from 

n/a n/a Duration: 15.75 hours

Flow: 820 MSCF

Emissions:

 SO2 – 163 lbs 

 (H2S = 0.15%)

 NMHC – 607 lbs

 Methane – 195 lbs

Upset/Malfunction (4.2.1.4) – Loss of a Utility 338-11

N

(3rd party)
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

the Christie substation 

nearest to Oleum – North 

Tower – Martinez Junction. 

Although they did not know 

the exact cause of the flash 

the third party scheduled it for 

replacement during the 

following month. 

5/13 – 14/11 Unit 200 Steaming 

for Shutdown and 

G-540 Fuel Gas 

Compressor 

Shutdown

The Unit 200 Coker/Crude unit was 

beginning a major turnaround. 

Steaming was being conducted at the 

unit to allow for entry and maintenance 

work to begin. Due to the high 

temperatures which occur during 

steaming the G-540 Flare Gas 

Recovery Compressors could not 

remain in operation. The G-503 Flare 

Gas Recovery Compressor had been 

shutdown prior to the turnaround for 

control system upgrades. Flaring of 

unscrubbed gas occurred. 

No new prevention measures 

or corrective actions were 

identified. The Unit 200 

turnaround and associated 

steaming is a planned activity 

that will re-occur in the future. 

n/a n/a Duration: 39.5 hours

Flow: 6,503 MSCF

Emissions:

 SO2 – 11,510 lbs 

 (H2S = 1.72%)

 NMHC – 960 lbs

 Methane – 1,144 lbs

Maintenance, Turnaround, Startup, and 

Shutdown – Equipment Preparation for 

Maintenance, Equipment Steaming

377-11

N

5/21/2011 MP30 & Unit 200 

Shutdown Steaming 

and Maintenance 

Preparation

On May 21, 2011 flaring occurred in 

association with steaming being 

conducted as part of the Unit 200 

Crude/Coker turnaround. The majority 

of the flow was through the Main Flare 

10” line which vents directly to the 

flare. This resulted in the flaring of 

unscrubbed gas. 

No new prevention measures 

or corrective actions were 

identified. The Unit 200 

turnaround and associated 

steaming is a planned activity 

that will re-occur in the future

n/a n/a Duration: 8 hours

Flow: 665 MSCF

Emissions:

 SO2 – 473 lbs 

 (H2S = 0.43 %)

 NMHC – 630 lbs

 Methane – 38 lbs

Maintenance, Turnaround, Startup, and 

Shutdown (4.2.1.1) – Equipment Preparation for 

Maintenance, Equipment Steaming

378-11

N

6/2/2011 Unit 110 Startup The Unit 110 Hydrogen Production 

Plant started up on June 2, 2011 after 

a planned shutdown. Per the Unit 

110 start-up SOP, Unit 200 began recirculating the G-540 Flare Gas 

Recovery Compressors due to the high 

volume of hydrogen being sent to the 

recovery system, which can damage 

this compressor. The G-503 Flare Gas 

Compressor had been shutdown prior 

to this activity and would not have 

minimized flaring emissions had it 

been in operation. Flaring of 

unscrubbed gas occurred during this 

event. 

No new prevention measures 

or corrective actions were 

identified. The Unit 110 

startup is a planned activity 

that will re-occur in the 

future. 

Due to the unplanned 

shutdown with the third-party 

H2 Plants as detailed in the 

10/22/10 event the Plant 4 

H2 plant was kept in 

operation for reliability 

purposes. This resulted in 

additional Unit 110 Startups 

and Shutdowns when the 

plant is long on Hydrogen 

production in association 

with other unit shutdowns. 

n/a n/a Duration: 2.75 hours

Flow: 1,060 MSCF

Emissions:

 SO2 – 1,408 lbs 

 (H2S = 0.80%)

 NMHC – 144 lbs

 Methane – 105 lbs

Maintenance, Turnaround, Startup, Shutdown –

Hydrogen Plant Startups

422-11

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

6/5/2011 Unit 110 Unplanned 

Shutdown due to 

SPP Upset

On June 5, 2011 an unplanned 

shutdown of the Unit 110 Hydrogen 

Plant occurred. This occurred due to 

low refinery air pressure which 

shutdown the Unit 110 Pressure Swing 

Adsorber. Flaring of unscrubbed gas 

occurred immediately following the 

shutdown and then during the startup 

which was initiated approximately 

three hours following the shutdown. 

Unit operator inadvertently 

closed the B boiler feed 

water valves.

Consider conducting an alarm 

rationalization review and DCS/Display 

changes to highlight SOLs and allow 

operators to more readily distinguish 

between turnins on the DCS displays.

COMPLETED 12/15/2011 Duration: 5 hours

Flow: 1,681 SCFD

Emissions:

 SO2 – 1,033 lbs 

 (H2S = 0.37%)

 NMHC – 274 lbs

 Methane – 221 lbs

Maintenance, Turnaround, Startup, Shutdown 

(4.2.1.1) – Hydrogen Plant Startup/Shutdowns

428-11

N

6/8 – 9/2011 Unit 246 

Depressuring to 

MP30 Flare due to 

Planned Shutdown 

& Steaming of E301 and Unit 240 

Plant 2 

On June 8, 2011 Unit 246 was shutting 

down for maintenance work. As part of 

the unit shutdown and in order to 

prepare for maintenance and entry the 

unit is depressured and purged. The 

unscrubbed material is vented directly 

to the MP-30 Flare. In addition to the 

Unit 246 shutdown work the 

Unicracker E-301 exchanger was 

being steamed to restore its heat 

transfer rate. When this exchanger is 

steamed the discharge is vented to 

blowdown and then to the flare.

No new prevention measures 

or corrective actions were 

identified. These two 

activities were planned 

maintenance activities that will 

re-occur in the future. 

n/a n/a Main and MP30 Flare 

Totals

Duration: 26.50 hours

Flow: 1,288 SCFD

Emissions:

 SO2 – 3,833 lbs 

 (H2S = 1.86%)

 NMHC – 166 lbs

 Methane – 119 lbs

Maintenance, Turnaround, Startup, and 

Shutdown – Equipment Preparation for 

Maintenance, Equipment Steaming

Maintenance, Turnaround, Startup, and 

Shutdown – Equipment Preparation for 

Maintenance, Depressuring and Purging

424-11

N

6/20 – 21/2011 Unit 246 and 

Unicracker Startup 

Associated Flaring 

and G-540 Startup 

Issue

On June 20, 2011 Unit 246 was 

starting up after being shutdown for 

maintenance work. During the startup 

materials from the unit are sent to 

blowdown until they are on-grade. 

There were numerous other units 

startups taking place on this day 

including the Unit 200 Coker/Crude 

Complex and MP-30 Complex. During 

these unit startups and while the Unit 

246 materials were sent to blowdown 

flaring of unscrubbed gas occurred 

G-540 common discharge 

pressure setpoint change.

Return setpoint from 70 to 80 psig. COMPLETED Duration: 23.25 hours

Flow: 830 MSCF

Emissions:

 SO2 – 4,981 lbs 

 (H2S = 3.6%)

 NMHC – 406 lbs

 Methane – 146 lbs

Maintenance, Turnaround, Startup, and 

Shutdown – High Base Load

Upset/Malfunction – Loss of a Compressor

429-11

N

7/8/2011 Unit 110 Planned 

Startup

Unit 110 was shutdown on June 19, 

2011 without any significant flaring. 

The Unit was shutdown since one of 

the primary unit’s which utilizes its high 

purity Hydrogen was shutdown for 

maintenance. The Unit 110 Hydrogen 

Production Plant started up on July 8, 

2011 after the planned shutdown.

Flaring of unscrubbed gasses occurred 

during the startup. 

The primary cause for flaring 

was due to the startup of Unit 

110.

No new prevention measures or 

corrective actions were identified. 

The Unit 110 startup is a planned 

activity that will re-occur in the future. 

Turnaround pre-planning is 

conducted to minimize emissions 

associated with the startup. 

n/a Duration: 3:10 hours

Flow: 1,282 MSCF

Emissions

SO2 – 2,160 lbs

(H2S = 1.01%)

NMHC – 770 lbs

Methane – 315 lbs

Maintenance, Turnaround, Startup, and 

Shutdown – Hydrogen Plant Startups

423-11

N

7/23/2011 3

rd Party Electricity 

Supplier Voltage 

Sag

On July 23, 2011 a voltage sag 

occurred in the refinery's third-party 

power supply. The G-503 Flare Gas 

Recovery Compressor and other major 

pieces of equipment were impacted by 

A voltage sag occurred in the 

electricity delivered by the 

refinery's third-party supplier. 

The third-party supplier 

reported that a transformer 

No specific prevention measures were 

identified by ConocoPhillips because 

the primary cause was the voltage sag 

in the electricity provided by the 

refinery's third-party supplier. The 

n/a Duration: 4:04 hours

Flow: 422 MSCF

Emissions

Upset/Malfunction – Loss of a Utility 462-11

N

(3rd party)
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

the voltage sag which resulted in 

flaring. Several process units were 

also impacted by the voltage sag. The 

flaring of unscrubbed gasses occurred. 

relay opened unexpectedly 

on the Oleum/Martinez line. 

third-party electricity supplier was able 

to re-close the relay that unexpectedly 

opened, which restored voltage to the 

line. 

SO2 – 3,671 lbs

(H2S = 5.24%)

NMHC – 249 lbs

Methane – 32 lbs

9/12/11 G-501 Wet Gas 

Compressor Failure

The Unit 200 Crude/Coker unit was 

being started up on Sunday, 

September 11, 2012. As part of the 

unit startup the G-501 Wet Gas 

Compressor, which is the compressor 

for the Coker’s main fractionator, was 

in the process of starting up. On 

September 12, 2012, the second day 

of the unit startup, the G-501 Wet Gas 

Compressor shutdown. The flaring of 

unscrubbed gasses occurred. 

Top Tower Temperature Too 

Low

1. Clarify and change start-up 

procedure to ensure the top 

tower temperature reaches a 

clearly defined temperature 

prior to starting crude charge. 

2. Ensure that refresher training 

for the Coking section start-up 

procedure includes an 

emphasis regarding the critical 

nature of removing water from 

the tower, and following the 

procedure regarding when to 

introduce the wedge valve 

body steam. 

1. COMPLETED February 21, 2012

2. COMPLETED February 21, 2012

Duration: 37:43 hours

Flow: 1,547 MSCF

Emissions

SO2 – 5,543 lbs

(H2S = 2.42%)

NMHC – 717 lbs

Methane – 297 lbs

Upset/Malfunction – Loss of a Major Compressor 547-11

N

Liquid Carryover 1. Review the setting for the HighHigh Level trip for the G-501 Wet 

Gas Compressor and assure 

that there is enough time to 

protect the compressor from 

liquid carry-over. Ensure 

adequate wind down time for the 

compressor is included in alarm 

set points.

2. Establish a Safety Operating 

Limit for the Wet Gas 

Compressor KO Drum. 

1. Evaluation COMPLETED 4/25/13. 

Determination that existing trips were 

adequate. 

2. COMPLETED 4/25/13

Liquid Removal Issues 1. Ensure the turbine driven reflux 

pump (G-215A) is considered a 

critical pump in the G-501 

Compressor startup procedure. -

1. COMPLETED

9/25/11 G-501 Wet Gas 

Compressor Startup

The Unit 200 Crude/Coker unit was 

being started up on Sunday, 

September 11, 2012. On September 

12, 2012, the second day of the unit 

startup, the G-501 Wet Gas 

Compressor failed. (See 

ConocoPhillips flaring root cause 

analysis for September 12, 2011 which 

provides details regarding the Wet Gas 

Compressor failure.) After repairs had 

been made to the G-501 compressor it 

was put back into Wet Gas Service on 

September 25, 2011. During the 

Planned startup of the G-501 

Wet Gas Compressor

No new prevention measures or 

corrective actions were identified. 

The switch from G-503 from Wet Gas 

service to Fuel Gas Recovery service 

was a planned activity to restore the 

G-501 and G-503 to normal 

operation. The G-503 Fuel Gas 

Compressor is designed to be put 

into Wet Gas Compressor service to 

optimize the amount of gases routed 

back to fuel gas during periods of 

time when the G-501 Wet Gas 

Compressor is out of service. During 

n/a Duration: 1:12 hours

Flow: 120 MSCF

Emissions

SO2 – 770 lbs

(H2S = 3.9%)

NMHC – 70 lbs

Methane – 40 lbs

Maintenance, Turnaround, Startup, & Shutdown 

– Compressor System Repairs

548-11

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

startup of the compressor and 

transition of the G-503 compressor out 

of Wet Gas Compressor service there 

was a period of flaring of unscrubbed 

gas for a little over one hour.

the switching process refinery 

personnel followed a detailed 

Operating Procedure to perform this 

activity. This ensures the necessary 

steps to perform the compressor 

switch and startup are performed in a 

safe and efficient manner. This 

minimizes the period of time in which 

flaring occurs. 

9/29/11 Unit 110 Planned 

Startup

Unit 110 was shutdown on September 

8, 2011. The Unit 110 Hydrogen 

Production Plant was re-started up on 

September 29, 2011 after the 

shutdown. During the startup of Unit 

110 there was flaring of unscrubbed 

gasses. 

 

The primary cause for flaring 

was due to the startup of Unit 

110.

No new prevention measures or 

corrective actions were identified. 

The Unit 110 startup is a planned 

activity that will re-occur in the future. 

Turnaround pre-planning is 

conducted to determine means for 

reducing flaring.

n/a Duration: 3:07 hours

Flow: 1,299 MSCF

Emissions

SO2 – 1,640 lbs

(H2S = 0.76%)

NMHC – 326 lbs

Methane – 240 lbs

Maintenance, Turnaround, Startup, and 

Shutdown – Hydrogen Plant Startups

546-11

N

11/29/11 G-503 Flare Gas 

Compressor 

Maintenance

The G-503 Flare Gas Recovery 

Compressor was scheduled for 

Planned Maintenance in December 

and was shutdown in preparation for 

the maintenance. To provide flare gas 

recovery while G-503 was out of 

service, the G-540 Flare Gas Recovery 

Compressors were put in service. 

However, the volume of gas in the 

blowdown system was at a level where 

all the gases could not be recovered 

with the G-540 compressors at all 

times throughout the day. This 

resulted in the flaring of unscrubbed 

gases that were not treated for sulfur 

removal.

The volume of gas in the 

blowdown system was more 

than the G-540 Flare Gas 

Compressor capacity.

The G-540 Fuel Gas Recovery 

Compressors were installed in 2009 

to allow for unplanned and planned 

maintenance to take place on the G503 Compressor while reducing 

flaring. Prior to the installation of the 

G-540 Compressors all gas would 

have been sent to the flare during 

periods of maintenance. 

n/a Duration: 10:13 hours

Flow: 764 MSCF

Emissions

SO2 – 1,347 lbs

(H2S = 1.16%)

NMHC – 254 lbs

Methane – 163 lbs

 Maintenance, Turnaround, Startup, and 

Shutdown – Compressor Maintenance

063-12

N

12/5/11 Unplanned 3rd Party 

Hydrogen Plant 

Shutdown

On December 5, 2011 the Refinery’s 

third-party Hydrogen Plant that 

provides a significant portion of 

hydrogen to the refinery experienced 

an unplanned shutdown. This resulted 

in flaring of unscrubbed gases 

intermittently on December 5, 2011

from units that shutdown due to the 

loss of hydrogen or experienced unit 

upsets. . 

3

rd Party Root Action Item : 

Broken weld on ID Fan Jack 

Shaft

No specific prevention measures were 

identified by ConocoPhillips to prevent 

the loss of Hydrogen because the 

primary root cause was due to the 

unplanned shutdown of the third-party 

Hydrogen Plant. 

Repair ID Fan Jack Shaft COMPLETED 12/5/11

Duration: 5:35 hours

Flow: 230 MSCF

Emissions

SO2 – 1,025 lbs

(H2S = 2.71%)

NMHC – 140 lbs

Methane – 30 lbs

Fuel and Hydrogen Gas Balance – Including 

unplanned Hydrogen supplier shutdowns

108-12

N

(3rd Party)

1/16/12 Unit 110 Startup 

Following 

Unplanned 

Shutdown

Unit 110 experienced an unplanned 

shutdown on January 15, 2012. 

During the process of Unit 110 startup 

there is flaring of unscrubbed gases. 

The cause of the shutdown 

was due to the failure of the 

Process Logic Controller 

(PLC) at Unit 110. The PLC 

failed due to a hardware 

Replace CPU COMPLETED 1/16/12 Duration: 4:45 hours

Flow: 1,628 MSCF

Emissions

Unset/Malfunction – Control System Failure

Maintenance, Turnaround, Startup, and 

Shutdown – Hydrogen Plant Startups

157-12

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

failure of the Central 

Processing Unit (CPU) which 

is the PLC processor. 

SO2 – 2,870 lbs

(H2S = 1.06%)

NMHC – 840 lbs

Methane – 370 lbs

1/18 – 1/20 Fuel Gas Balance –

3

rd Party H2 Plant 

not taking RFG A 

Gas

On January 18, 2012 the third-party 

Hydrogen Plant took their feed gas 

coalescer out of service for a filter 

replacement. Due to the observation 

of higher than anticipated liquids in the 

feed gas the Air Liquide Plant blocked 

out the RFG A feed gas as a 

precautionary measure. The RFG A is 

a feed gas generated by the refinery 

and sent to Air Liquide. This resulted in 

a fuel gas imbalance at the refinery 

and the flaring of scrubbed gases. 

Liquids in RFG A 1. Evaluate the effectiveness of the 

piping installed at the RFG 

A/RFG B boundary and 

determine if the installation 

should be modified and 

upgraded. 

2. Third party Hydrogen Plant to 

evaluate the need to increase 

water removal capabilities. A tie 

in to be provided for potential 

future additional water filter. 

1. COMPLETED 3/31/2012

2. COMPLETED tie-in 3rd Qtr 2012

Duration: 55:20 hours

Flow: 11,939 MSCF

Emissions

SO2 – 198 lbs

(H2S = 0.01%)

NMHC – 11,501 lbs

Methane – 2,808 lbs

 Reduced Consumption of Fuel Gas 

(4.2.1.3) 

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets

158-12

N

E-424 temperature outlet too 

low.

Provide a temperature controller on the 

E-424 compressor discharge cooler. 

This project will allow the discharge 

temperature to be controlled so that 

during cool ambient conditions and 

reduced flowrates, the RFG A gas 

temperature can be maximized to 

prevent condensation of water. 

COMPLETED 10/18/12

2/16/12 U110 and U250

Planned Shutdown

On February 16, 2012, steps were 

taken to shut down Unit 110 Hydrogen 

Production Plant for a scheduled 

shutdown to conduct major 

maintenance. Unit 250 was also 

conducting a turnaround during this 

period. Nitrogen purging of a Unit 250 

compressor took place during this 

period. These activities resulted in the 

flaring of unscrubbed gases. 

The primary cause for flaring 

was the scheduled shutdown 

of Unit 110 Hydrogen Plant

and Unit 250 for a major 

turnaround to conduct 

planned maintenance. 

Equipment and process 

vessels had to be cleared in 

order to provide a safe 

environment for personnel 

entry.

No new prevention measures or 

corrective actions were identified. 

The turnaround activities are planned 

activities that will re-occur in the 

future. Turnaround pre-planning was 

conducted in order to identify means 

for reducing flaring that may occur.

n/a Duration: 5:07 hours

Flow: 1,642 MSCF

Emissions

SO2 – 2,800 lbs

(H2S = 1.37%)

NMHC – 670 lbs

Methane – 260 lbs

 Maintenance, Turnaround, Startup, 

Shutdown – Hydrogen Plant Startups and 

Shutdowns

 Equipment Preparation for Maintenance

159-12

N

3/1 – 3/5/12 Fuel Gas Imbalance Maintenance turnarounds were taking 

place at units that included large 

combustion sources during March, 

2012. Due to the turnaround, there 

were periods where all of the fuel gas 

produced could not be consumed. Due 

to the imbalance in the fuel gas 

system, the additional fuel gas that 

could not be consumed by the refinery 

process heaters was flared. During 

this period, only excess scrubbed fuel 

gas was flared. 

The primary cause of the 

flaring was the shutdown of 

refinery fuel gas consumers 

for planned maintenance. 

This resulted in a fuel gas 

imbalance. More refinery 

fuel gas was being produced 

than could be consumed 

while maintaining compliance 

with other environmental 

limits, such as the Sulfur 

Dioxide limit at the Steam 

Power Plant. 

Turnaround pre-planning was 

conducted that identified the potential 

for fuel gas imbalance. No specific 

prevention measures were 

implemented but measures were 

taken to minimize the quantity of 

material flared. 

n/a Duration: 99 hours

Flow: 8,752 MSCF

Emissions

SO2 – 140 lbs

(H2S = 0.01%)

NMHC – 4,600 lbs

Methane – 4,350 lbs

Reduced Consumption of Fuel Gas – Fuel Gas 

Imbalance

242-12

N

3/14/2012 Unit 110 Startup 

after Planned 

Unit 110 underwent a planned startup 

on March 14, 2012 following a planned V-4 leaking relief valve 1. Reseated and re-lapped the 1. COMPLETED 3/15/12

Duration: 10:48 hours  Maintenance, Turnaround, Startup, 

Shutdown – Hydrogen Plant Startups

259-12
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

Shutdown unit turnaround. This resulted in the 

flaring of unscrubbed gases. 

The primary cause for flaring was due 

to the startup of Unit 110. There was 

some additional flaring associated with 

the unplanned Unit 110 shutdown due 

to the leaking V-4 relief valve and a 

leaking gasket at the relief valve. 

 

relief valve.

2. Replace the gasket to one with 

different dimensions. Update 

documentation to ensure new 

model gasket will be utilized in 

the future. 

2. COMPLETED 3/15/12

Flow: 2,170 MSCF

Emissions

SO2 – 2,080 lbs

(H2S = 0.6%)

NMHC – 940 lbs

Methane – 390 lbs

 Upset/Malfunction – Leaking Relief 

Valves

N

3/16/2012 Unit 110 Startup Unit 110 underwent a planned startup 

on March 14, 2012 following a planned 

unit turnaround. As described in the 

Flare RCA for March 14, 2012, a 

leaking steam relief valve was 

discovered. This required Unit 110 to 

be shutdown, the relief valve repair 

made, and the unit restarted. Unit 110 

restarted on March 16, 2012. The 

compressor recirculation results in 

flaring of unscrubbed gas. 

See 3/14/2012 for root cause 

and corrective actions.

n/a n/a Duration: 3:28 hours

Flow: 883 MSCF

Emissions

SO2 – 1,330 lbs

(H2S = 0.9%)

NMHC – 350 lbs

Methane – 170 lbs

Maintenance, Turnaround, Startup, 

Shutdown – Hydrogen Plant Startups

260-12

N

3/19/2012 Fuel Gas Balance –

SPP Turnaround

Maintenance turnarounds were taking 

place at units that included large 

combustion sources during March, 

2012. Due to the turnaround, there 

were periods where all of the fuel gas 

produced could not be consumed. Due 

to the imbalance in the fuel gas 

system, the additional fuel gas that 

could not be consumed by the refinery 

process heaters was flared. Periods 

of fuel gas imbalance where the flare 

flow exceeded the BAAQMD reporting 

threshold of 500,000 standard cubic 

feet per calendar day (scfd) occurred 

from March 19 until March 21, 2012. 

During this period, only excess 

scrubbed fuel gas was flared. 

The primary cause of the 

flaring was the shutdown of 

refinery fuel gas consumers 

for planned maintenance. 

This resulted in a fuel gas 

imbalance. More refinery 

fuel gas was being produced 

than could be consumed 

while maintaining compliance 

with other environmental 

limits, such as the Sulfur 

Dioxide limit at the Steam 

Power Plant. 

Turnaround pre-planning was 

conducted that identified the potential 

for fuel gas imbalance. No specific 

prevention measures were 

implemented but measures were 

taken to minimize the quantity of 

material flared. 

n/a Duration: 48.5 hours

Flow: 3,428 MSCF

Emissions

SO2 – 57 lbs

(H2S = 0.01%)

NMHC – 2,920 lbs

Methane – 1,020 lbs

Reduced Consumption of Fuel Gas – Fuel Gas 

Imbalance (Section 4.2.1.3)

243-12

N

3/26/2012 Fuel Gas Balance –

AL stopped taking A 

Gas

On March 26, 2012 the third-party Air 

Liquide Hydrogen Plant took their feed 

gas coalescer out of service for a filter 

replacement. The filter required 

replacement due to an increase in 

back pressure on the filter. In order to 

prevent potential liquids in the feed 

gas, the Air Liquide Plant blocked out 

the RFG A feed gas as a precautionary 

measure. The RFG A is a feed gas 

generated by the refinery and sent to 

Air Liquide. This resulted in a fuel gas 

Liquids in RFG A 1. Evaluate the effectiveness 

of the piping installed at 

the RFG A/RFG B 

boundary and determine if 

the installation should be 

modified and upgraded. 

2. Third party Hydrogen Plant 

to evaluate the need to 

increase water removal 

capabilities. A tie in to be 

provided for potential 

1.Temporary piping to blow down was 

added for the bleed at the low point in the 

RFG A gas line prior to going to Air Liquide 

COMPLETED 3/31/12 

2.COMPLETED tie-in 3

RD Qtr 2012..

Duration: 33 hours

Flow: 4,028 MSCF

Emissions

SO2 – 67 lbs

(H2S = 0.01%)

NMHC – 3,260 lbs

Methane – 1,045 lbs

 Reduced Consumption of Fuel Gas 

(4.2.1.3) 

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets

253-12

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

imbalance at the refinery and the 

flaring of scrubbed gases. 

future additional water 

filter.

E-424 temperature outlet too 

low

Provide a temperature controller on the 

E-424 compressor discharge cooler. 

This project will allow the discharge 

temperature to be controlled so that 

during cool ambient conditions and 

reduced flowrates, the RFG A gas 

temperature can be maximized to 

prevent condensation of water. 

COMPLETED 10/2012

4/25/2012 RFG A out of Air 

Liquide and Fuel 

Gas Balance

On April 24, 2012 the RFG A feed gas 

to the third-party Air Liquide Hydrogen 

Plant was blocked out as a 

precautionary measure in preparation 

for planned turnaround activity. This 

resulted in a fuel gas imbalance at the 

refinery and the flaring of scrubbed 

gases. As the pressure built up in the 

fuel gas system on April 25, the 

amount of gas and increase in 

pressure caused water in the D-7 Hot 

Coker Blowdown drum to overflow. 

The water contained H2S and caused 

local H2S alarms to trigger. In order to 

maintain the liquid level in the D-7 

drum and prevent the H2S alarms, the 

G-503 flare gas recovery compressor 

was put into circulation to relieve the 

pressure on the fuel gas system and 

the D-7 Drum. This resulted in the 

flaring of unscrubbed gases. 

Sour seal water from D-7 

was automatically flushed to 

an open process sewer that 

caused H2S alarm.

1. Relocate the D-7 level 

transmitter to increase pressure 

activation from 2.2 psig to 4.5 

psig. This will prevent pressure 

fluctuations from tripping the 

quench water valve. 

2. Reduce H2S in seal water by 

increasing minimum seal water 

flow and/or setting up routine 

quench water flushes. 

1. COMPLETED 6/1/12

2. COMPLETED 9/26/12

Duration: 19 hours

Flow: 2,795 MSCF

Emissions

SO2 – 5,600 lbs

(H2S = 1.2%)

NMHC – 1,470 lbs

Methane – 550 lbs

 Maintenance, Turnaround, Startup, and 

Shutdown (4.2.1.1)

 Reduced Consumption of Fuel Gas 

(4.2.1.3) 

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets

 Emergency (4.2.1.5) – Local H2S alarms 

near D-7 drum

297-12

N

Location of Unit 233 

pressure control valve tie in 

to flare system at D-7.

Evaluate a project to re-route the Unit 

233 pressure control valve flare 

system tie-in location. Consider a tiein location directly to the flare line 

downstream of 19F-3. 

Target 12/15/15 which corresponds to 

necessary equipment outage.

4/26 – 5/1/12 Fuel Gas Imbalance 

During UK T/A

In late April, 2012, a planned shutdown 

was conducted at the Unicracker 

Complex to perform scheduled 

maintenance on several units. Flaring 

occurred on May 19, 2012 while the G540 Flare Gas Recovery Compressors 

were shutdown. The Flare Gas 

Compressors were shutdown during 

the Unit 244 Reformer Catalyst 

Activation startup procedure which led 

to flaring of unscrubbed gas. 

The primary cause of flaring 

was the shutdown of the G540 Flare Gas Recovery 

Compressors during 

hydrogen and nitrogen purge 

steps. 

Preplanning was conducted to 

identify periods of expected flaring to 

identify means for minimizing flaring. 

Communication between the Unit 200 

Operator that operates the Flare Gas 

Recovery Compressors and Unit 244 

takes place in advance of this work 

occurring. This ensures that the 

activity is planned and the period in 

which the flare gas recovery 

compressor is shutdown is 

minimized.

n/a Duration: 114 hours

Flow: 18,000 MSCF

Emissions

SO2 – 623 lbs

(H2S = 0.01%)

NMHC – 10,050 lbs

Methane – 3,700 lbs

Reduced consumption of fuel gas – fuel gas 

imbalance (4.2.1.3)

306-12

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

5/19/12 Unit 244 Catalyst 

Reactivation and 

Nitrogen Purging

A planned shutdown was conducted at 

the Unicracker Complex to perform 

scheduled maintenance on several 

units. Flaring occurred on May 19, 

2012 while the G-540 Flare Gas 

Recovery Compressors were 

shutdown. The Flare Gas 

Compressors were shutdown during 

the Unit 244 Reformer Catalyst 

Activation startup procedure which led 

to flaring of unscrubbed gas. 

Preplanning was conducted 

to identify periods of 

expected flaring to identify 

means for minimizing flaring. 

Communication between the 

Unit 200 Operator that 

operates the Flare Gas 

Recovery Compressors and 

Unit 244 takes place in 

advance of this work 

occurring. This ensures that 

the activity is planned and 

the period in which the flare 

gas recovery compressor is 

shutdown is minimized. 

n/a n/a Duration: 12.83 hours

Flow: 4,300 MSCF

Emissions

SO2 – 2,260 lbs

(H2S = 0.32%)

NMHC – 2,130 lbs

Methane – 800 lbs

 Maintenance, Turnaround, Startup, 

Shutdown – Unit startup (Section 

4.2.1.1)

303-12

N

5/23-5/29/12 Unit 240 Plant 3 

Unscheduled SD 

and Unit 246 D-803 

Overhead to Flare

The Unit 246 Hydrocracker D-803 

stripper overhead was routed to the 

flare gas recovery system as a result 

of the unscheduled shutdown of Unit 

240 Plant 3. The addition of the D-803 

stripper overhead gases to the flare 

gas recovery system led to periods 

where the refinery’s flare gas recovery 

compressors could not compress all of 

the gas in the system due to gas 

quantity. During these periods

unscrubbed gas was flared due to the 

addition of the D-803 overhead.

The D-803 stripper overhead normally 

goes to Plant 3 in the Unit 240 UK. 

When the UK Plant 3 is shutdown, 

however, the D-803 stripper overhead 

is routed to the flare gas recovery 

system. On May 23, 2012, UK Plant 3 

needed to be shut down to repair a 

leak that was found in the E-316 fin fan 

cooler. The E-316 fin fan cools the UK 

Plant 3 D-305 Fractionator bottoms 

stream.

E-316 Fin Fan Leak repair E-316 Fin Fan Leak repair - Rerolling of 320 tubes in areas 

where the E-316 leaks occurred 

followed by the re-start of UK 

Plant 3. Plant 3 

COMPLETED 5/27/12 Duration: 111.5 hours

Flow: 8,970 MSCF

Emissions

SO2 – 7,815 lbs

(H2S = 0.38%)

NMHC – 6,790 lbs

Methane – 1,665 lbs

 Upset/Malfunction - Loss of Air Fin 

(4.2.1.4) 

 Reduced Consumption of Fuel Gas 

(4.2.1.3) 

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets

 Maintenance, Turnaround, Startup, and 

Shutdown (4.2.1.1)

320-12

N

E-316 Design Review the process in Plant 3 to 

determine if the E-316 fin fan unit can 

be replaced with shell and tube heat 

exchanger. 

Target 6/7/2015

5/31-6/1/12 Unit 110 Planned 

Startup following 

Shutdown

Unit 110 underwent a planned 

shutdown on May 3, 2012 due to lower 

hydrogen demand related to planned 

turnaround activity at the Unicracker 

complex. Flaring of unscrubbed gases

occurred in association with the Unit 

110 startup. 

None, this was a planned 

startup with anticipated flaring. 

n/a n/a Duration:3.58 hours

Flow: 448 MSCF

Emissions

SO2 – 2,220 lbs

 Maintenance, Turnaround, Startup, 

Shutdown – Hydrogen Plant Startups

311-12

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

(H2S = 2.9%)

NMHC – 280 lbs

Methane – 80 lbs

7/24/12 UK Relief Valve 

Leak following T/A

After the start-up of the Unicracker (UK) 

Complex following a turnaround, Phillips 

66 detected a low rate of flare flow at 

the Main Flare (in the range of 300,000 

to 400,000 scf per day of unscrubbed 

gas). Upon investigation it was 

determined the UK Plant 2 100 lb. relief 

valve (2HV023) on the 2F-201 High 

Pressure (HP) Separator was the 

source of the flow to the flare. 

During this period, there were three 

instances (7/24/12 to 7/27/12, 8/1/12 

and 8/4/12 to 8/6/12) where H2S in the 

flare samples indicated that more than 

500 pounds of SO2 had been emitted 

and/or more than 500,000 scf of vent 

gas were flared during a calendar day. 

All three instances were caused by the 

UK 2HV023 relief valve leaking to the 

Main Flare which resulted in the flaring 

of unscrubbed gas. 

UK Plant 2 100 lb Relief Valve 

(2HV023) Leaking to Flare

Block in existing 2HV023 relief valve 

and install new one in alternate 

location.

COMPLETED 8/12/12 Duration:72 hours

Flow: 1,308 MSCF

Emissions

SO2 – 1,580 lbs

(H2S = 0.74%)

NMHC – 790 lbs

Methane – 330 lbs

 High Base/Continuous Load – Leaking 

Relief Valve (4.2.1.2)

 Upset/Malfunction – Leaking Relief 

Valves (4.2.1.4)

435-12

N

8/1/12 UK Relief Valve 

Leak following T/A

“ “ “ Duration:24 hours

Flow: 545 MSCF

Emissions

SO2 – 300 lbs

(H2S = 0.33%)

NMHC – 340 lbs

Methane – 100 lbs

“ 437-12

N 

(on-going)

8/4/12 UK Relief Valve 

Leak following T/A

“ “ “ Duration:72 hours

Flow: 1,212 MSCF

Emissions

SO2 – 1,677 lbs

(H2S = 0.83%)

NMHC – 704 lbs

Methane – 336 lbs

“ 441-12

N 

(on-going)

8/24/12 UK Unplanned 

Shutdown

On August 24, 2012 at approximately 

1:00 PM, Unit 240 Plant 2 had an 

unscheduled shutdown. During the 

shutdown, the unit de-pressured 

directly to the main flare, bypassing the 

flare gas recovery compressors. 

Gases were also vented to the flare 

during the subsequent startup. The 

shutdown and startup resulted in the 

flaring of unscrubbed gases. 

The Unit 240 Plant 2 shutdown and 

subsequent startup caused the 

pressure to build up in the fuel gas 

system, which led to periodic flaring of 

scrubbed gases. The increase in fuel 

gas flow to the flare can cause water in 

the D-7 blowdown drum to overflow. 

The water can contain H2S and cause 

local H2S sensors to alarm. To 

Lack of policy for process trip 

systems to be placed in 

Bypass while maintenance 

work is being performed on 

the tripped software. “

“Develop a task safety analysis form 

specific to Process Control work tasks. 

COMPLETED 5/28/12 Duration:61 hours

Flow: 18,470 MSCF

Emissions

SO2 – 98,680 lbs

(H2S = 3.81%)

NMHC – 13,229 lbs

Methane – 1,922 lbs

 Reduced Consumption of Fuel Gas (4.2.1.3)

 Upset/Malfunction (4.2.1.4) – control system 

failure 

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets 

 Maintenance, Turnaround, Startup, and 

Shutdown (4.2.1.1)

474-12

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

maintain the liquid level in the D-7 

drum and prevent the H2S alarms, the 

G-503 flare gas recovery compressor 

was put into circulation to reduce the 

pressure on the fuel gas system and 

the D-7 Drum. This resulted in the 

flaring of unscrubbed gases. 

Sour seal water from D-7 

automatically flushes to an 

open process sewer that 

causes an H2S alarm

1. Relocate the D-7 level 

transmitter to increase pressure 

activation from 2.2 psig to 4.5 

psig. This will prevent pressure 

fluctuations from tripping the 

quench water valve. 

2. Reduce H2S in seal water by 

increasing minimum seal water 

flow and/or setting up routine 

quench water flushes.

1. COMPLETED 6/1/12 as part of a 

previous Flare Event (4/25/12). This 

corrective action may have reduced the 

severity of this flare activity.

2. COMPLETED 9/26/12

Location of U233 pressure 

control valve tie-in to flare 

system at D-7

Evaluate a project to re-route the Unit 

233 pressure control vavle flare 

system tie-in location. Consider a tiein location directly to the flare line 

downstream of 19F-3. 

Target 12/15/15 which is linked with 

equipment/flare system outage. 

8/27/12 RFG A Backed out 

of AL due to Higher 

than Normal Sulfur 

Content

Portions of the Unicracker Complex 

were in startup on August 27, 2012 

following an unplanned shutdown (see 

ESDR-474-12). At approximately 

11:27 PM, flaring began when the third 

party Hydrogen Plant blocked out feed 

gas (RFG A) from Phillips 66 due to 

unexpectedly higher than normal sulfur 

content. Flaring of scrubbed fuel gas 

occurred until the following day at 

approximately 5:17 PM due to high 

fuel gas system pressure. 

Natural Gas was added to 

RFG A upstream of D402 

rather than downstream. 

1. Natural gas should be added 

downstream of D-402. 

2. Add a tag on the D-402 

upstream natural gas line to 

indicate this should not be 

utilized. 

1. COMPLETED approx. 

10/17/2012.

2. COMPLETED 11/27/12

Duration: 17.9 hours

Flow: 2,266 MSCF

Emissions

SO2 – 100 lbs

(H2S = 0.01 %)

NMHC – 8,650 lbs

Methane – 458 lbs

 Reduced Consumption of Fuel Gas – 

Fuel Gas Imbalance (Section 4.2.1.3)

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets

503-12

N

9/10/12 Unit 110 Hydrogen 

Vent Fire

On September 10, 2012 at 

approximately 7:00 AM, the G-503 

flare gas recovery compressor was 

circulated due to a large amount of 

hydrogen being sent to the flare gas 

recovery system. In some cases, too 

much hydrogen can cause the heating 

value of the fuel gas to be too low, 

which requires the compressor to be 

shut down. At the time the compressor 

was being circulated, there was excess 

hydrogen being produced at the 

refinery during the startup of the third 

party Air Liquide Hydrogen Plant (Air 

Liquide). The excess hydrogen being 

produced by the Unit 110 Hydrogen 

Plant was sent to the flare gas 

The Unit 110 operating 

procedure (REOP-21) does 

not adequately address Unit 

110 atmospheric vent 

operating parameters.

1. Revise REOP-21 "Emergency 

Loss of Hydrogen," to include a 

note regarding the Unit 110 

atmospheric hydrogen vent 

operating limitations. 

2. Review creation of a new 

normal operating procedure 

(NOP) for operation of the Unit 

110 atmospheric hydrogen vent 

and how to respond to high 

flow. COMPLETED 

12/20/2012

 COMPLETED 1/9/2013

COMPLETED 1/9/2013

Duration:10.25 hours

Flow: 5,628 MSCF

Emissions

SO2 – 11,587 lbs

(H2S = 1.24 %)

NMHC – 1,760 lbs

Methane – 620 lbs

 Emergency, flame at Unit 110 

atmospheric hydrogen vent (4.2.1.5)

 Hydrogen Gas Balance – excess 

hydrogen production following startup or 

shutdown(4.2.1.1)

499-12

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

recovery system. Circulation of the G503 flare gas recovery compressor 

resulted in the flaring of unscrubbed 

gases. 

10/3/12 U246 

Depressurization to 

Flare and Planned 

SD

On October 3, 2012 Unit 246 was 

being shut down for maintenance 

work. As part of the unit shutdown, 

and to prepare for maintenance and 

entry, the unit was depressured and 

purged. The purged material was 

vented directly to the MP-30 Flare and 

resulted in the flaring of unscrubbed 

gases. 

No new prevention measures 

or corrective actions were 

identified. These activities 

were planned maintenance 

activities that will re-occur in 

the future. 

n/a n/a Duration:28.5 hours

Flow: 5,265 MSCF

Emissions

SO2 – 87 lbs

(H2S = 0.01%)

NMHC – 150 lbs

Methane – 986 lbs

Maintenance, Turnaround, Startup, and 

Shutdown – Equipment Preparation for 

Maintenance, Depressuring and Purging

537-12

N

10/4/12 U240 Plant 2 

Unplanned SD due 

to failure of G-203B 

H2 Make Up 

Compressor

On October 04, 2012, Unit 240 Plant 2 

had an unscheduled shutdown at 

approximately 9:05 PM caused, in part, 

by the failure of the 3rd stage of the G203B Hydrogen Makeup Compressor. 

Prior to the shutdown at approximately 

5:50 PM, the G-203B Hydrogen 

Makeup Compressor at Unit 240 

developed a mechanical issue that 

resulted in one of the relief valves 

lifting and releasing hydrogen to the 

flare. Gases were also vented to the 

flare during the subsequent startup 

after repairs of the G-203B 

Compressor were complete. The 

shutdown and startup resulted in the 

flaring of unscrubbed gases. 

1. D-203 Catalyst Bed 4 

had temperature 

gradient prior to the 

incident

a. Expand the Unit 240 Plant 2 

Reactor Operating Guidelines 

to improve temperature 

gradient management and 

actions to take to minimize 

gradients. 

b. Improve reactor temperature 

alarming. Consider installing 

alarms on the DCS and OIS 

Target board. 

d.c. Provide refresher training on 

The Plant 2 Reactor Operating 

Guidelines and training on 

emergency events. 

a. COMPLETED 3/25/13

b. COMPLETED 3/25/13 Upon 

detailed review it was 

determined that existing 

monitoring was consistent with 

industry best practices and per 

P66’s internal 

recommendations. Thus, no 

additional monitoring was 

added.

c. COMPLETED 8/29/13

Duration:22.6 hours

Flow: 7,111 MSCF

Emissions

SO2 – 22,100 lbs

(H2S = 2.25 %)

NMHC – 2,479 lbs

Methane – 941 lbs

 Reduced Consumption of Fuel Gas 

(4.2.1.3)

 Maintenance, Turnaround, Startup, and 

Shutdown (4.2.1.1)

 Upset/Malfunction – Loss of other 

compressors (G-203B) (4.2.1.4)

577-12

N

2. G-203B shutdown 

because of lube oil 

injection system failure. 

Complete the Failure Analysis 

Summary Report and implement 

recommended actions. 

COMPLETED report 12/17/12, Associated 

action items 1/31/13.

3. Initiation of a project to 

re-route the Unit 233 

pressure control valve 

flare system tie-in 

location. 

Install a tie-in location directly to the 

flare line downstream of 19F-3. 

Target 12/15/15 which is linked with key 

equipment outage. 

1/18/13 U246 Unplanned 

Shutdown due to 

failure of 8G-826B 

Forced Draft Fan

On January 8, 2013, the Unit 246 

Heavy Gas Oil Hydrocracker had an 

unscheduled shutdown. During the 

shutdown, the refinery’s G-503 flare 

gas recovery compressor was taken 

offline due to gas quality concerns due 

to the large amount of hydrogen being 

sent to the flare gas recovery system. 

The G-503 flare gas recovery 

VFD Cabinet High 

Temperature

Install exhaust fans in the enclosure to 

direct hot air out of the enclosure. 

COMPLETED 4/10/13 Duration:9 hours

Flow: 227 MSCF

Emissions

SO2 – 970 lbs

(H2S = 2.64 %)

NMHC – 183 lbs

 Upset/Malfunction - Loss of Forced Draft 

Fan, 8G-826B (4.2.1.4) 

 Maintenance, Turnaround, Startup, and 

Shutdown (4.2.1.1)

071-13

N
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

compressor does not operate properly 

with high amounts of hydrogen and 

can be permanently damaged. Two of 

the liquid ring compressors were in 

operation, but could not compress all 

of the gas being sent to the flare. This 

resulted in the flaring of unscrubbed 

gas.

Methane – 46 lbs

D-803 Overhead Offgrade to 

blowdown during Startup

1. Revise startup procedure 

to notify Unit 200 when D803 is going to blowdown. 

Unit 200 may be able to 

delay drum switches and 

work to optimize flow to 

the flare gas system. 

2. Revise startup procedure 

to include increased D803 Overhead sampling 

frequency to once per 

hour. This will allow the 

on grade determination to 

be made more quickly 

and reduce the time the 

material goes to 

blowdown. 

3. Revise startup procedure 

to increase maximum D803 Overhead on-grade 

specification to 5 ppm 

total sulfur from 2 ppm to 

minimize the time the 

material goes to 

blowdown. 

COMPLETED 2/4/13

COMPLETED 2/4/13

COMPLETED 2/4/13

4/11/13 U246 Unplanned 

Shutdown due to 

G801 Charge Pump 

Failure

On April 10, 2013, the Unit 246 Heavy 

Gas Oil Hydrocracker had an 

unscheduled shutdown. As part of the 

unit shutdown the unit was 

depressured. The depressured 

material was vented directly to the MP30 Flare and resulted in the flaring of 

unscrubbed gases.

1. Routine equipment 

rounds did not include 

explicit instructions 

regarding G-801 motor

oil levels and related 

parameters 

Update the Operator Rounds sheets 

to include explicit instructions to 

check the G-801 motor oil level 

gauges, temperature of oil supply 

tubing at each branch from the 

header pipe, levels in constant level 

oiler, oil return flow rate and bearing 

housing air-purged seal air pressure 

each shift. 

COMPLETED 5/2/13 Duration:7 hours

Flow: 1,167 MSCF

Emissions

SO2 – 814 lbs

(H2S = 0.42 %)

NMHC – 127 lbs

Methane – 210 lbs

 Upset/Malfunction – Equipment failure 

which results in an immediate or controlled 

unit shutdown (e.g. charge pump failure) 

(4.2.1.4) 

 Maintenance, Turnaround, Startup, and 

Shutdown – Equipment Preparation for 

Maintenance, Depressuring and Purging

162-13

N

2. No back up oil supply 

in the event the supply 

orifice becomes 

blocked. 

Install an additional level gauge and a 

constant level oiler on the G-801 

motor’s bearing housings to allow 

changes in oil level to be more 

apparent to Operators, and to provide 

a back up supply of oil in the event 

the flood lube supply orifice is 

COMPLETED 4/20/13
Attachment H 

ESDR No. – Internal document tracking number. 

Recurrent Failure – Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operating in a normal or usual manner. Recurrent is two times or more in a 5 year period. (BAAQMD 12-12-401.4.3) 

Att H Rev 2 Prevention Measures June 2006 – Present FMP.doc 

Date Process or 

Equipment Item

Flaring Event Description Root Cause Finding Action Item(s) Proposed Dates/Status Duration, Flow & 

Emissions

Consistency with Flare Minimization Plan 

(12-12-406.3)

ESDR No.

Recurrent

Failure?

blocked. 

6/10/13 Removal of RFG A 

Feed to Air Liquide 

due to Presence of 

Atomized Oil

On June 10, 2013, the Air Liquide 

Hydrogen Plant located next to the 

refinery experienced a sudden 

increase in differential pressure in its 

coalescer filter. Feed gas referred to 

as RFG A flows through the coalescer 

from the Phillips 66 Rodeo Refinery to 

the Air Liquide Hydrogen Plant and 

then on to its Hydrogen Reformer. At 

approximately 11:00 AM RFG A was 

shutout by Air Liquide. This resulted in 

flaring of scrubbed gases. During the 

upset, flow from the Unicracker D-301 

Debutanizer triggered an alarm. Flow 

was diverted from the Unit 233 Fuel 

Gas System to the flare to respond to 

the alarm and to minimize additional 

unit impacts. This resulted in the 

flaring of unscrubbed gases. Flaring 

occurred intermittently from June 10 

through June 11, 2013 at 9:25 PM. 

1. 4-PIC-176 Incorrect 

Calibration and 

Erroneous Pressure 

Indication

1. Re-calibrate 4-PIC-176. 

2. Update 4-PIC-176 

calibration documentation 

to reflect necessary 

pressure offset 

adjustment for glycol filled 

leg. . 

3. Consider adding a 4-PIC176 low pressure alarm 

set at 145 psig.

1. COMPLETED 6/28/13

2. COMPLETED 8/26/13

3. COMPLETED 9/6/13. 

Low pressure alarm was 

added as originally 

premised.

Duration:22 hours

Flow: 1,818 MSCF

Emissions

SO2 – 786 lbs

(H2S = 0.27 %)

NMHC – 1,516 lbs

Methane – 348 lbs

 Reduced Consumption of Fuel Gas 

(4.2.1.3) 

 Upset/Malfunction (4.2.1.4) - Failure of 

Instrumentation 

 Upset/Malfunction (4.2.1.4) – fuel gas 

quality upsets

227-13

N

3. 5-FIC-015 

Conservative High 

Flow Alarm Set Point -

Adjust 3 FIC 015 High Flow Alarm 

Set Point from 2.5 MMSCFD to 5 

MMSCFD to allow for more sour gas 

to be vented to U233 fuel gas system 

rather than to blowdown. 

COMPLETED 7/30/13

4. Air Liquide Coalescer 

Location -

Meet with Air Liquide to discuss 

possibility of relocating existing 

coalescer on RFG A to upstream of 

120-FIC-115 control valve or to 

provide a new Knock Out vessel 

upstream of 120-FIC-115. 

COMPLETED 8/15/13. On-going 

discussions are continuing about feasibility 

of this project. 
Flare Minimization Plan, BAAQMD 12-12

Phillips 66, San Francisco Refinery 

BAAQMD Plant 16 







Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT I 

STORAGE, TREATMENT, & RECOVERY SCHEMATIC 

Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

ATTACHMENT J 

(Reserved) 
Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

Attachment N 

Cost Effectiveness Calculation Background Material 
Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

Cost Curves for Major Equipment 




Flare Minimization Plan, BAAQMD 12-12 

San Francisco Refinery 

BAAQMD Plant 16 

Cost Effective & Emission Calculations for 

Storage, Treatment, and Recovery Cases 1 - 4