# facility_information

energy_management_plan_description:
Heater O2 optimization, steam waste reduction, strategic energy reduction capital expenditures

notes:
Part II - 1 - 2010 Fuel Consumption: Included in still gas

Part II - 1 - 2010 Fuel Consumption/Still Gas: EIA810-Dry Gas/Fuel Gas/Nat Gas/LPG Burned

Part II - 1 - 2010 Fuel Consumption/Catalyst Coke: EIA810 - FCC Coke

Part II - 1 - 2010 Fuel Consumption/Natural Gas, Coal, Purchased Electricity, Purchased Steam: EIA820

Part II - 1 - Hydrogen Purchased: [CBI]

Part II - 3 - Applicable federal regulations: LDAR plan includes elements of 40 CFR 60 subpart VV; 40 CFR 60 subpart GGG; 40 CFR 61 subpart J; 40 CFR 61 subpart V

Part II - 3 - LDAR/Average methane concentration: Data not available

Part II - 3 - LDAR/Number of Pump Seals in Heavy Liquid Service:  Estimated based on total number of pumps minus pumps monitored by LDAR

Part II - 3 - LDAR/Valves in Heavy Liquid Service: Not monitored by LDAR, unknown

Part II - 3 - LDAR/Flanges and connectors: Flanges and connectors have not been counted

Part II - 3 - LDAR/Flanges and connectors: Flanges and connectors have not been counted

Part II - 3 - LDAR/Open-ended lines: Do not monitor open-ended lines

Part II - 3 - LDAR/Compressor seal monitoring: Exempt due to audible alarms, monitored if AVO

Part II - 3 - Pressure Relief Devices/Routed to atmosphere in Liquid Service: Only monitored when lifted

Part II - 15 - Facility Level/Average VOC content: This is composite value : water phase is 48  ppm per R Eshraghi calcs; oil phase contribution is approx gasoline/distillate grade HCs from 2010 BWON

Part II - 15 - Facility Level/Average wastewater generation and benzen concentration: Taken from process data for 2010 BWON TAB Report

Part II - 15 - Wastewater Systems: There are two (2) oil/water separators and two (2) dissolved air/gas flotation systems on site

Part II - 16 - Loading Racks/Typical Operating Hours: Loading racks Loading Truck-J007 and Loading Rail-J010 were installed in 2010 and did not operate for the entire year


notes:
A documented target assist ratio is not available for Flare P009
A documented target assist ratio is not available for Flare P008


notes:
ConocoPhillips Ponca City Refinery
Facility ID number: OK2C0950
Refinery ICR Component 1 Notes

•	Overall - Blanks cells represent either no data available or entry not applicable. 

•	Part 1 Question 11: (Annual Revenue 2010) COP US R&M Revenue.

•	Part 1 Question 13b: (Relationship to Parent Company) Although this question is somewhat incomprehensible to ConocoPhillips in that the "facility" does not have a Board of Directors and for other reasons, we believe that this statement "best" applies of the three statements offered.

•	Part 1 Question 15:  Cumulative 2010 production, % used on site, % shipped by tank ship, % shipped by barge, % shipped by rail car and % shipped by pipeline considered CONFIDENTIAL BUSINESS INFORMATION.

o	P-Ps are sold by pipeline as Unfinished Oils – Naphthas and lighter
o	Sour resid sold by truck and Slurry clarified oil is sold by rail as Unfinished Oils – Residuum
o	FCC coke burn is considered Petroleum Coke – Catalyst for this report
o	Carbon black is sold by pipeline as Petrochemical Feedstocks – Naphtha <401°F end-point

•	Part 1, Question 16: Unit Actual Throughput considered CONFIDENTIAL BUSINESS INFORMATION.    
o	Refinery groups No. 1 CVU and No. 1 TSU with No. 1 CTU as single unit
o	Refinery groups No. 2 CVU with No. 2 CTU as single unit
o	Refinery groups No. 4 CVU with No. 4 CTU as single unit
o	No. 1 H2 Plant and No. 2 H2 Plant measured at 60ºF and 1 atm.  Used 0.946 to convert to 32ºF and 1 atm.
o	WWTS includes WP ORU, EP, ORU, Coker ORU, 1SWS, 2SWS, ASU, and GWASU
o	SP Loading Rack is not currently in use, but has a permitted capacity

•	Part 2, Section 1, Table 1-1: Fuel consumption considered CONFIDENTIAL BUSINESS INFORMATION.

•	Part 2, Section 1, Question 3: Hydrogen purchased considered CONFIDENTIAL BUSINESS INFORMATION.

•	Part 2, Section 1, Question 4: The energy management plan is as follows:

ENERGY MANAGEMENT PLAN

Objective
The program’s objective is to analyze energy usage both in the short term (daily and weekly) and long term (1 to 5 years). Use this analysis to make decisions on equipment operation and maintenance, capital projects and utility use and contracts. 

Key Components of Plan

Monitoring Operation of Equipment
1.	Heater and boiler excess O2 targets have been determined and incorporated into the Operations Information System (OIS) which uses a target based format to maintain these variables in a desired range. Deviations from the target range triggers the need for a report from the Console Supervisor to explain the variance and the steps required to return to the target range if possible.
2.	Weekly review of heater O2 targets with refinery Operations, Engineering and Maintenance supervision to evaluate the economics of missed targets and discuss both operational and equipment changes needed to return to target levels.
3.	Monthly review with refinery management of performance on corporate Key Energy Variables (KEV's) with discussion on next steps needed for performance improvements.
4.	Corporate Annual Heater and Boiler efficiency benchmarking is used to develop both performance standards (excess oxygen, stack temperatures, etc.) and system improvements to achieve realistic goals for efficient operation of heaters.
5.	A biannual survey is performed for evaluation by Solomon Associates to calculate an energy based index based on refinery complexity and throughput. This information reports gaps in the different areas of energy use (i.e. – fuel produced steam) which identifies deficient areas as compared to top performers.  

Equipment Surveys  
1.	A refinery steam team has been assembled and travels to different areas of the refinery repairing steam leaks and surveying steam traps.   
2.	An ambient acoustic survey has been performed to detect and quantify leaks in the refinery air system.
3.	An combustion tuning survey is performed on all heater by an independent 3rd party consultant every 2-4 years to develop operation guidelines for efficient operations and recommended repairs or instrument modifications to improve efficiency of the combustion process.
4.	Exchanger fouling monitoring program has been developed for use by area engineers to determine the economics of cleaning exchangers in preheat trains and those associated with crude unit distillation columns. Reports are developed with the results of cleaning and the recommended exchangers to be cleaned.

Project Development
An Energy Performance Checklist was developed and is used for all new capital projects.  Through the use of data monitoring, equipment, data surveys, and corporate Energy Network best practices projects ideas are identified to improve equipment performance in energy use.  These projects are ranked in terms of cost, energy savings, T/A timing, and ROI.  The projects are presented to management for potential approval of further development.  Examples of these projects are the installation of exchangers to reduce tank rundown temperatures and increase preheat to boiler feedwater.

•	Part 2, Section 1, Table 1-2: Air Preheat use, air preheat temperature, disposition of electricity, steam pressure, disposition of steam and percent steam to blowdown considered CONFIDENTIAL BUSINESS INFORMATION.  

o	When viewed in whole, Table 1-2 appears to be for the typical "boiler house" function of generating utilities, specifically steam and electricity.  The second sentence adds energy recovery from process unit flue gas (FCC, fluid coker, SRU tail gas unit incinerator).  This only power boilers, FCC waste heat boilers (WHBs) associated with the regenerator flue gas (not pumparounds), Calciner WHBs associated with flue gas, SRU WHBs associated with flue gas downstream of tail gas clean up and incinerator, and cogeneration heat recovery steam generators (HRSGs) are included here.  Steam generation from fluid coker flue gas would also be included. Steam generation from steam methane reformers is included on Section 10, Table 10-1 Hydrogen Plant and Vent Information.  Thus the steam generation from SMRs should not also be included in Table 1-2.
o	Steam is not discarded from the boiler, thus no steam blowdown.

•	Part 2, Table 1-3: Steam consumption for processing considered CONFIDENTIAL BUSINESS INFORMATION.  

o	To avoid "double counting" of steam and/or energy, report only the "net" consumption of steam.  If a unit uses more steam than it produces report the consumption as a positive value.  If a unit is a net producer of steam, report the consumption as a negative value.  The steam associated with process unit waste heat steam generators (convection section of fired heaters and pumparound waste heat steam generators) should be included here instead of in Section 1, Question 5, Table 1-2.  Include steam consumptions such as stripping steam and uses where steam is condensed (tracing, reboilers, vacuum condensers).  Steam used in a letdown turbine is still steam coming out and is not consumed.

•	Part 2, Table 2-1: Average heat input rate, total operating hours in 2010, air preheat use, typical air preheat temp, other efficiency measures, % total operating hours fired on primary fuel in 2010, % total operating hours fired on secondary fuel in 2010, operating hours fired < 25% of capacity in 2010 and operating hours fired between 25% and 50% in 2010 considered CONFIDENTIAL BUSINESS INFORMATION.

o	H-6008 rated heat input capacity based on permitted annual average as the heater only operates a small fraction of the time, burners rated at 8.8 MMBtu/hr
o	Rated heat input rate are permitted rates
o	Average 2010 heat input is a flow weighted average
o	NSPS Ja limits and other requirements regarding heaters and fuel gas systems are currently stayed.

•	Part 2, Table 3-1: Average methane concentration in process fluid that contacts equipment in gas service was not included because any value would have been a very rough estimate and we chose not to include potentially erroneous information. CPC Loading Rack not subject to LDAR program. HL and LL Pump counts came from a report generated by the LDAR monitoring database (the computer based LDAR tracking program). LL and GV Valve counts came from the LDAR monitoring database.  HL Valves and all Connector Counts estimated using EPA Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017) Appendix A.  

o	Olefins Processing counts included in Alky counts
o	No. 4 HDT components are included in No. 2 CRU component counts
o	Product Blending and Distillate Blending counts included in WP Tank Farm count
o	No.1 CVU and TSU components have been counted under No. 1 CTU
o	No. 2 CVU components are counted under No. 2 CTU
o	No. 4 CVU component are counted under No. 4 CTU
 
•	Part 2, Table 3-1: The open ended lines were compiled as follows; a count of Light Liquid and gas OEL’s was received from the LDAR monitoring database , to get the number of heavy liquid OELs we created a ratio between the number of Light Liquid valves in a unit and the number of LL OELs in the unit, this ratio was then applied to the heavy liquid valves to get the number of HL OELs, the calculated value for the HL OELs was then added to the LL OELs to get the total number of OELs.  The number of OELs monitored is the number of LL/gas OELs.

•	Part 2, Table 3-2: Fuel gas systems component counts are included in Table 3-1.  Number of components in natural gas service is estimated.  Average given is approximate for all units. Natural gas components are not subject to LDAR program.

•	Part 2, Table 3-3: Total number of PRD, number of controlled gas PRD, number of controlled liquid PRD, number of atmospheric gas PRD, number of atmospheric gas PRD with rupture disk, number of atmospheric liquid PRD and number of atmospheric liquid PRD with rupture disk are considered CONFIDENTIAL BUSINESS INFORMATION.  Total PRD’s include PRD's in any service water (steam) or hydrocarbon, hydrocarbon PRD's that relieve back to process are included in this count. PRD Monitoring Plan is as follows: All PRD are audio/visually inspected once a year.  Detection of leaks at that time is sensory.  If there is a reason to suspect that an RV has opened, then the LDAR team is sent to check it out and monitor using method 21 monitoring.

o	Olefins Processing counts included in Alky counts
o	Product Blending and Distillate Blending counts included in WP Tank Farm count
o	No.1 CVU and TSU components have been counted under No. 1 CTU
o	No. 2 CVU components are counted under No. 2 CTU
o	No. 4 CVU component are counted under No. 4 CTU

•	Part 2, Section 4, Question 2a and 2b: quantity of unstabilized crude oil and pressure considered CONFIDENTIAL BUSINESS INFORMATION.

•	Part 2, Section 4, Table 4-1: Total throughput, year tank last degassed and year anticipated for next degassing considered CONFIDENTIAL BUSINESS INFORMATION. Pressurized tanks without height data are spheres. A throughput for tank T-0680 was not able to be determined because it is a storm water overflow tank.  The following tanks do not have throughputs and/or future depressurization dates because they were either out of service in 2010 or are currently out of service: T-0920, T-0170, T-0178, T-0116, T-0177, T-0540, D-0775, D-0776, T-0627, PCPT T-4, T-0133, T-0138. The cavern is not degassed.  The cavern is a 405ft by 405ft square with columns.  Tanks T-0603 and T-0604 are not owned by ConocoPhillips, data availability for these tanks was limited.  Tanks PCPT E-1, PCPT E-2, PCPT E-3, PCPT E-4, & PCPT E-5 (owned by ConocoPhillips Pipeline Company) are new tanks, only three years old, they have not yet been degassed, future degassing info was also unavailable. 

•	Part 2, Section 5, Table 5-1: CCU feed capacity, recycle/resid capacity, Percent hydrotreated feed, typical coke burn rate, weighted average sulfur, weighted average nickel and weighted average vanadium considered CONFIDENTIAL BUSINESS INFORMATION.

•	Part 2, Section 5, Table 5-2: All E-cat and Fines data considered CONFIDENTIAL BUSINESS INFORMATION. Not all metal concentration information requested is available.

•	Part 2, Section 7, Table 7-1: Coke production capacity, type of coke produced, height of single coke drum, diameter of single coke drum, typical coke drum outage, typical coke drum pressure when first vented to atmosphere, typical coke drum temperature when first vented to atmosphere, typical water height in coke drum when first vented to atmosphere, complete coke drum cycle time, coke drum feed cycle time, coke drum steam purge time, coke drum water quenching time, coke drum depressurization vent time, coke drum coke cutting time, and coke drum preheat/standby time are considered CONFIDENTIAL BUSINESS INFORMATION.

o	Height of single coke drum measured tangent to tangent
o	Typical coke drum outage measured from top tangent
o	Typical water height in coke drum when first vented to atmosphere measured from bottom tangent – Pressure drain method used
o	Quench water disposition section contains two answers: recycled to unit and used as quench water and used as coke cutting water.

•	Part 2, Section 7, Table 7-2: Typical percent feed rate by material and maximum percent feed rate by material considered CONFIDENTIAL BUSINESS INFORMATION.  Other material is decant oil.

•	Part 2, Section 8, Table 8-1: Operating pressure, Hydrogen production rate, average annual regeneration frequency, average annual regeneration time, depressure/purge cycle vent disposition control, purge process type, coke burn off cycle vent disposition/control, coke burn off cycle duration, rejuvenation cycle vent disposition/control, reduction or activation cycle vent disposition/control considered CONFIDENTIAL BUSINESS INFORMATION. Coke burn-off cycle duration per cycle is in hours.

•	Part 2, Section 10, Table 10-1: Reformer Deaerator Vent flow rate for No. 1 H2 Plant estimated based on calculations from unit design.  No. 2 H2 Plant deaerator vent does not exist. No.2 N2 Plant has both “Refinery fuel gas augmented with additional methane” & “Methane”.

•	Part 2, Section 11, Table 11-1: No notes.

•	Part 2, Section 12, Table 12-1: Temporary Flare only operates during periods of flare shutdown/maintenance.  Refinery does not use a target assist ratio.

•	Part 2, Section 13, Table 13-1: 
o	Coker Gas Plant Amine Contactor is primary receiver of gas from coking unit - Div C FG Amine Contactor receives gas primarily from SGP, No. 2 Cryo, No, 5 HDT, and the Coker and WP/NP FGRU (thus receives small amounts of gas from the coking unit).
o	Each treatment unit serves multiple units.  
o	No data is available for total sulfur at this refinery.
o	NSPS Ja limits and other requirements regarding fuel gas systems are currently stayed.

•	Part 2, Section 14, Table 14-1: 
o	Y-9 is once through and does not use any chemical additives / disinfection.
o	R&D East – East, R&D East – South, and Park Tower are non-contact cooling towers.

•	Part 2, Section 15, Question 2a and 2b: Daily Average WWTS Flow Rate reported in gallons per minute. The Total Annual Benzene (TAB) quantity of the facility in 2010 is reported in mega grams.

•	Part 2, Section 15, Question 3c: Average VOC content of wastewater generated via tank draw downs in 2010, ppmw, data is not available.

•	Part 2, Section 15, Table 15-1: For the Equalization Tanks, two federal regulations apply.

•	Part 2, Section 15, Table 15-2:  See Appendix B

•	Part 2, Section 16, Table 16-1: South Plant Loading Rack currently out of service, throughput capacity is the permitted capacity.  CPC Loading Rack Throughput capacity is the permitted capacity.

•	Part 4, Table 1: Demolition cost, primary equipment cost, auxiliary equipment cost, instrumentation & monitor cost, sales tax and freight costs, total purchased equipment costs, installation costs, total installed cost, operating labor cost, maintenance labor cost, electricity cost, water cost, steam cost, liquid chemical cost, solid chemical cost, compressed air cost, other costs, total utility costs, waste disposal cost, supplies and parts replacement costs, other annual costs and total operating and maintenance costs considered CONFIDENTIAL BUSINESS INFORMATION.

•	Part 4, Table 2: Number of days process shutdown, total capital costs and change in total annual operating costs considered CONFIDENTIAL BUSINESS INFORMATION. 

•	Part 5, Question 2: Qualified CEMS data for CO, NOx, and SO2 on Fluidized Catalytic Cracking Units and NOx on process heaters and boilers requires O2 monitoring via CEMS.  These O2 CEMS must also be routinely quality assured at a cost.


energy_management_plan_description:
Refinery has an Energy Cooridnator that tracks and monitors Fuel Use, Steam Use, Condensate Recovery and Refinery Heater Performance measures such as % excess Oxygen.  Reduction in excess oxygen has been one of the primary benefits of this program.

notes:
General Facility Information--General Tab:  The annual revenues for both Tulsa East and Tulsa West are combined and not reported separately.

General Facility Information--General Tab:  The Dun and Bradstreet number is the Dun and Bradstreet number of Holly Tulsa Refinery and Marketing, LLC.

General Facility Information--Parent Company Tab:  All employees within the Holly Corporation structure are employed by Holly Logistics Services, LLC, a subsidiary of Holly Corporation, and are not directly employed by Holly Corporation. Total employees of Holly Logistics Services, LLC, are 1,638.

General Facility Information--Process Units Tab:  FCCU-FGT defined to reflect the fuel gas treatment process at the FCCU unit

General Facility Information--Process Units Tab:  DHTU-FGT defined to reflect the fuel gas treatment process at the DHTU unit

Part II, Section 3--LDAR Tab:  Zero open-ended lines are monitored.  All OEL are repaired immediately upon detection.

Part II, Section 8--Catalytic Reforming Unit:  Average annual regeneration time--Regeneration works continuosly for this unit

Part II, Section 13--Fuel Gas Treatment Units:  For both the FCCU-FGT and the DHTU-FGT Estimated annual average H2S concentration in the treated fuel gas exiting the treatment unit: Not Sampled, Total Fuel gas (varying mixture of plant produced gas and natural gas) has a continuous H2S analyzer 2010 average H2S - 7.1 ppm

Part II, Section 16--Product Loading Tab:  Product loading capacity throughputs are estimated using best available methods.


notes:
Component 1-Part I
General Facility Information--General Tab:  The annual revenues for both Tulsa East and Tulsa West are combined and not reported separately.

General Facility Information--General Tab:  The Dun and Bradstreet number is the Dun and Bradstreet number of Holly Tulsa Refinery and Marketing, LLC.

General Facility Information--Parent Company Tab:  All employees within the Holly Corporation structure are employed by Holly Logistics Services, LLC, a subsidiary of Holly Corporation, and are not directly employed by Holly Corporation. Total employees of Holly Logistics Services, LLC, are 1,638.

General Facility Information--Process Units Tab:  
Unit ID--Unifiner:  Steam consumption for this unit is included in steam consumption of #2 Platformer unit.  
Unit ID--Light Ends Recovery Unit:  Steam consumption for this unit is included in steam consumption of CDU unit.  
Unit ID--MEK Unit:  Steam consumption for this unit is included in steam consumption of Lube Extract Unit.
Unit ID--WWT Unit:  Steam consumption for this unit is included in steam consumption of Decoker unit.
Unit ID--Gasoline Truck Loading Rack, Diesel Rail Loading, Coke Truck Loading, LOB Truck Loading, LOB Rail Loading, Wax Truck Loading, Wax Rail Loading, Extract Truck Loading, Extract Rail Loading, Propane/Butane Truck Loading and Jet A Truck Loading:  Steam consumption for these units is included in steam consumption of Transfer & Shipping unit.

Component 1-Part II, Section 3
LDAR Process Units Tab--Zero open-ended lines are monitored.  All OEL are repaired immediately upon detection.

Component 1-Part II, Section 16
Product Loading Tab--All product loading capacity throughputs are estimated using best available methods.

Component 1-Part III
For all non-routine emissions events:  event duration and quantity of pollutant released determined by engineering calculations with best data available at the time of the event.


legal_owner_name:
Valero Refining Company - Oklahoma, a Michigan corporation

dunn_bradstreet_number:
24-712-2161 (under Canadian Ultramar Company)

notes:
Notes:
1.	Part I and Part II, Section 3: Process units 100, 400, 450, 500, 560, 900, 1000, 1300, 1900, and 2400 are split into sub-units in Part I by using A, B, C, etc.  For the steam consumption and process unit equipment leaks data, these process units as a whole are represented by the unit ID of one of the sub-units.  For example, when 100A is listed as the unit ID, it is actually representing the collective data from 100A, 100B, and 100C.
2.	Part I: Unit 450A was an isomerization unit that was replaced in December 2010 by Unit 450B, a BenSat process unit.
3.	Part II, Section 9: Additional SRU back-up controls include sulfur shedding and general plant flare.
4.	Part II, Section 11: Additional federal regulations for atmospheric vent T-107 include 40 CFR part 63, subpart A and 40 CFR part 60, subpart A.
5.	Part II, Section 15: There is only one atmospheric vent for the wastewater treatment plant. There are no drain system or conservation vents, only PVRVs.
6.	The following fields were left blank because the values are unknown:
•	Part 2, Section 1: Percent Steam to Blowdown
•	Part 2, Section 3: Average methane concentration in process fluid for the process units section
•	Part 2, Section 5: Recycle/Resid Capacity
•	Part 2, Section 15: Average VOC content of wastewater generated via tank draw downs, average concentration of organic HAP for each process stream, and average VOC concentration for each process stream


notes:
Note 1: Part 1 - General Facility Information, Process Units - CDU idled temporarily due to economic reasons and customer facility shutdowns. Estimate of "normal" throughput during this period is 4,436 BPCD.  

Note 2: Part 2 Section 12, Flares - F-2 is a vapor recovery flare for loading operations at L-1. It operates only when tank vessel volume is displaced during loading operations. Flare operating hours are estimated for 2010 by taking the total number of trucks loaded and multiplying that by loading time. No concurrent loading activity was assumed for this estimate.


energy_management_plan_description:
Energy Star Partner of the Year with Sustained Excellence rating. KEVs are used to min aux fuel to the CO Boilers, recover more C3+ from fuel, reduce steam use via advanced controls at UDEX and optimize reflux rates, and improve FOE/bbl consumption.

notes:
Section 3: Equipment leaks: no site generated methane data is available.  Section 3:PRDS.  Number of PRDs that release to atmosphere is known. Number that release to control devices, flares or fuel gas system is estimated.  Section 15:  VOC content of waste water not measured at site. Average HAP content in wastewater is average of 22 HAPS ranging from 0.0003 to 12.36 ppmw. All waste water is collected at oil water seperator and sent to an off site municiple POTW for treatment. HAP content of individual unit wastewater is not measured. Levels indicated are at discharge point of oil water seperator.


legal_owner_name:
Sunoco, Inc. (R&M) / Atlantic Refining and Marketing Corp.

plant_name:
Sunoco, Inc. (R&M) - Philadelphia Refinery

energy_management_plan_description:
For the past two years, Sunoco has received the Energy Star Partner of the Year Award.  The refinery's energy conservation program focuses on energy awareness and operational improvements to utilize energy more effectively in everyday operations.

notes:
In Part II, Section 1 (Energy management), 38 Boiler and 2H-9 were out of service in 2010.     For Part I, Part II Section 3 (Equipment Leaks), and Part II Section 15 Wastewater Collection and Treatment, there are multiple "Unit IDs" for the same unit (1232: 1232-1, 1232-2, 1232 (LDAR1) and (LDAR2); 1332: 1332 (LDAR1) and 1332 (LDAR2); GP B&S: GP B&S (LDAR1) and GP B&S (LDAR2); PB B&S: PB B&S (LDAR1) and PB B&S (LDAR2)).  This occurs because some units are grouped together while other units are divided apart during LDAR and wastewater collection and treatment activities.  The facility has two FCCU units: 1232 and 868.  The facility has two catalytic reforming units: 860 and 1332.  Steam and throughput data are presented with the these units and not with the hybrid units used to define LDAR or wastewater collection and treatment activities.  In Part II, Section 12 (Flares), PB South Yard South Flare is out of service.  There were no data provided for the lower heating value of multiple flares (PB South Yard North, GP 1231, GP 1232 and GP 433) due to the variable nature of the stream composition.


notes:
Part I, Process Units - Unit 742 Vacuum Distillation - The rest of this note is CBI.

Part I, Process Units - Unit 739 Catalytic Hydrocracking - The rest of this note is CBI.

Part I, Process Units - Unit 735 Desulfurization/Hydrotreating - The rest of this note is CBI.

Part I, Process Units - Unit 05 Other (Fuel Gas Compressor) - Units of flow are MSCFH.

Part I, Process Units - Unit 102 is the combined trains of the Units 41 and 42 Sulfur Recovery units.

Part II, Processes - Section 14 Cooling Water - Chemical additions for each cooling tower are:
Stony Creek GB - 67 gal/day bleach, 7 gal/day NaBr
Marcus Hook GB - 113 gal/day bleach, 13 gal/day NaBr
Alky Cooling Tower - all in gal/day - 7.1 (bleach), 1 (Y7BH972), 0.75 (Nalco-184), 2 (Y9BH1246), 3.5 (CI2OUT 110)
Southside Cooling Tower - all in gal/day - 15.2 (bleach), 7.1 (sulfuric acid), 4.8 (Y9BH1246), 2.4 (BPC68095), 1.3 (Y7BH972)
Benzene Recovery Unit  Cooling Tower - all in gal/day - 3.8 (bleach), 3.0 (Y9BH1246), 2.09 (CI2OUT 1100), 0.57 (BPC68570), 0.3 (Y7BH972)

Part IV, Cost Data - Process and Equipment Changes - The changes made to Unit 34 described were also made to Unit 35 and included in the cost data.


energy_management_plan_description:
Facility Energy use is tracked on a monthly basis. As equipment is replaced such as moters and light ballast, they are replaced with energy rated equipment. There is no written procedure or plan but documentation has been kept to track usage and purchases


legal_owner_name:
Valero Refining Company - Tennessee, L.L.C., a Delaware limited liability company

name_of_parent_company:
Valero Energy Corporation, a Delaware Corporation

notes:
Part 1, Process Units, Steam Consumption Rates for 19-PTU/WWT, 23-River Dock, and 24-Tank Farm are included in the steam consumption for Unit 41-Utilities.

Part 2, section 1 - "Does this refinery have a facility energy management plan?" keep as CBI

Part 2, section 2 - "Total operating hours in 2010 (hr)", "Other energy efficiency measures", " Percent of total operating hours process heater fired with primary fuel", and "Percent of total operating hours process heater fired with secondary fuel in 2010" - all kept as CBI

Part 2, section 3 - All of the Facility-Level Questions - keep as CBI

Part 2, section 3, Equipment Leaks - Gas Systems, these values are only for pipeline natural gas systems.  All refinery fuel gas system components are included on Equipment Leak-Process Units.  The methane content of MLGW natural gas is 95.6 percent.

Part 2, section 4 - All of question 2, all of question 3, and "Total throughput for all materials sotred in the tank in 2010 (bbl)" - keep as CBI

Part 2, section 8 - "Operating pressure (psig)", "Average annual regeneration frequency (cycllic and semi-regen units; regeneration cycles/year)", "Average annual regeneration time (hours/year)", "Depressurization/purge cycle vent disposition/control", "Purge process type", Coke burn-off cycle duration per cycle", "Rejuvenation cycle vent disposition/control", "Reduction or activation cycle vent disposition/control", and "Chloriding agent" - keep as CBI

Part 2, section 9 - "Primary sulfur pit maintenance time in 2010 (hr/yr)" - keep as CBI

Part 2, section 13 - "Does this treatment unit receive gas from a coking unit?", "Average fuel gas flow rate into treatment unit (scfm)", "Estimated operating hours in 2010", "Types of sulfur compounds in the untreated fuel gas", "Estimated annual average H2S concentration in treated fuel gas exiting the treatment unit (ppmv)", and "Estimated annual average total sulfur concentration in the treated fuel gas exiting the treatment unit (ppmv) - keep as CBI

Part 2, section 14 "Cooling Water Flow/Reciculation Rate (gal/min)", Water Make-up Rate (gal/min)" "Gas or Chemical Additive/Disinfection Method", "Gas or Chemical Addition Rate Value", "Gas or Chemical Addition Rate Unites (volume or mass per time)

Part 2, section 15 - Wastewater Generation Information.  This data is not available on a process unit basis.  The values for the WWTP effluent are reported here.

Part 2 section 15 - Question2b, 2c and "For steam and sour water strippers, also provide average steam usage rates in 2010 (lb/hr)" answered is considered CBI.  

Part 2, section 16 "Typical annual operating hours (hr/yr)" and "Does the facility or parent company own the vessels being loaded?" are both considered CBI

Part V, Monitoring Data - Moisture content is listed as zero since all CEMS include a sample conditioner to remove moisture before analyzing gas sample, i.e. all pollutant concentrations are reported on a dry basis.  Moisture is not directly measured or reported.


notes:
Part II/Section 1/ Electricty and Steam Generation/(a) 150lb waste heat boiler/boiler heat input and steam generating capacity are estimates-----------------------------------------------------------------Part II/Section 2/Process Heaters/general/rated heat input capacity is estimated based upon plant process flow diagram for heaters F-11, F-12, F-13 and F-31---------------------------------------- Part II/Section 2/Process Heaters/NOx Controls/NOx control type for heaters F-11, F-12, F-13 and F-31 are all LoNOx and type of LoNOx is estimated to be staged fuel low NOx burners-------Part II/Section2/Process Heaters /H301 and H501, percent of total operating hours process heaters fired with secondary fuel estimated to be 2% attributed to startups----------------------------Part II/Section 3/Equipment Leaks/LDAR and Pressure Relief Devices are estimated using both correlation factors based upon EPA estimate protocol table 2-4 for small refineries and equipment count ratios from associated approved state air permit applications for all heavy liquid components and for all components in Reformer-NHT, DHT, L-3 (fuel oil loading rack) and RL-1 (railcar loading rack).---------------------------------------------------------------------------------------------------Part I/Process Units/Reformer-NHT data represents combined process types for both catalytic reforming unit (Semi-regenerative) and hydrotreating-naphtha reformer feed-------------------------Part II/Section 13/Fuel Gas Treatement Units/general/estimated annual average Sulfur concentration is based upon estimated sulfur content in estimated average H2S.---------------------Part V/Log of Source Tests and Monitoring Data Provided/1 Fuel Gas System CMS H2S Monitoring/ fuel gas flow rate represents a varying mixture of natural gas and fuel gas and is estimated from total of all plant heaters and boiler fuel usage for 2010.----------------------------------Part II/Section 4/Storage Tanks/Floating Roof Tank estimates include:1) all primary rim seals estimated to be mechanical-shoe seal, 2) all secondary rim seals estimated to be rim mounted seals and 3) all guidepoles estimated to be solid


notes:
[1] Part I - WWTU Steam Consumption is provided in Part II, Section 15. [2] Part II, Section 1 Electricity and Steam Generation Information - the reporting tool links data from one steam boiler to another. We could not fix this database scripting error; therefore, the data is provided in a spreadsheet included in this submittal. [3] Part II, Section 2 - 77HYDGNHTR_note was added because 77HYDGNHTR could not be found in drop down list.  When trying to add the system said it was already entered, but again it was not in the drop down list. Use 77HYDGNHTR_note because it is the entry that was updated. [4] Part II, Section 4 - 37TANK0326 also subject to 40 CFR Part 63 Subpart G - Database would not allow two "Other" entries even though specifications were different. [5] Part II, Section 9 - 69SRU Backup Control also includes "Divert to other SRU" and "Sulfur shedding". 71SRU Backup Control also includes "Sulfur shedding". [6] Part II, Section 14 - ID# 09LCHCTR is actually 09LDHCTR [7] Part II, Section 15 - There are no open wastewater vents to atmosphere.


notes:
Methane concentrations are given in mol %. Emissions without Process unit IDs are from Storage Tanks. The annual revenue is for all Western Refineries. Name of the parent company - Owned by Western Refining LP, LLC its limited partner, and Western Refining GP, LLC, its general partner. Western Refining Company, LP is managed by its general partner, Western Refining GP, LLC. The Alky I&II and butamer throughputs are in terms of feed (not production).

 

Some process units had turnarounds/shutdowns in 2010.  The typical yearly throughputs w/o turnarounds and FCC shutdowns are: 

FCC (Unit ID 111) = [CBI]

DHT (Unit ID P-39) = [CBI]

F-101 (Unit ID F-101) = [CBI]

Rhen (Unit ID P-41) = [CBI]

Naphtha Splitter (Unit ID PU-4A) = [CBI]

AFU Poly feed (Unit ID PU-8) = [CBI]


energy_management_plan_description:
The form of the Energy Management Plan is not defined by the ICR.  Delek does not have a written document titled "Energy Management Plan"; however, Delek has implemented a number of energy best practices as part of other programs or processes.

notes:
Part 1: The Process unit throughput capacities for the SRU's are in units of LT/D (long tons per day), Lacking density of throughput material to make necessary conversion to compatible units; SRU refers to SRU#2.                    Table 13 - this version of the runtime tool did not allow us to add informtion for the Amine unit although it was defined.  See submittal spreadsheet.  Information was included there. Table 16 - would not allow for a complete submittal see submittal spreadsheet.


notes:
For Part II, Section 1 Energy, Facility Energy Management Plan:
Energy consumption is monitored and reported monthly to management.  Any anomalies are addressed.  On going program to identify projects to reduce energy in each department.  Energy reduction projects - The Gasoline Benzene Reduction project reconfigured the light hydrocarbon processing section to be more energy efficient, The Heavy Naphthalene project reduced energy consumption of the process.

For Part II, Section 3 Equipment Leaks - the equipment counts have varying monitoring frequencies and leak definitions.  For example, the equipment is monitored monthly if a leak is detected, otherwise the frequency reverts to quarterly after 2 consecutive passing months.  The equipment monitoring frequencies and leak definitions shown are the most stringent required.  Also, for units 2.2, 6, 7, 42, and Other (Utilities) there are mulitple units present with the suffix "LDAR" and a number.  These units are only in the database to allow separate equipment counts for LDAR purposes since they can be subject to different monitoring requirements.

For Part II, Section 5, Catalytic Cracking Units - Both the 29 and 40 FCCU have 2010 Weighted average Nickel and Vanadium concentrations in combined feed that measure less than 0.00005 wt%.

For Part II, Section 15 Wastewater Collection and Treatment - the Borger WWTS has 4 sour water strippers that are subject to BWON (40 CFR 61, Subpart FF).


legal_owner_name:
Diamond Shamrock Refining Company, L.P., a Delaware limited partnership

physical_address:
301 Leroy Street, Three Rivers, Texas 78071

mailing_address:
Post Office Box 490, Three Rivers, Texas 78071-0490

name_of_parent_company:
Valero Energy   Corporation, a Delaware corporation


legal_owner_name:
Diamond Shamrock Refining Company, L.P, a Delaware limited partnership

legal_operator_name:
Diamond Shamrock Refining Company, L.P, a Delaware limited partnership

name_of_parent_company:
Valero Energy Corporation, a Delaware Company


energy_management_plan_description:
Heater Specialist position created to improve heater efficiencies and keep track of energy projects. Long term projects include LPG recover, steam trap/leak initiative, installing steam generators, installing a flue gas turbine at the FCCU.

notes:
For FCCU - The recycle capacity is not used continuously.


notes:
1) Section I throughput information is not applied to OMCC unit - tank farm. This information is provided in Part II Section 4 - Storage Tanks.

2) Section 15 - Wastewater; oil/water separators. The facility uses aboveground storage tanks to achieve oil/water separation rather than an API.


plant_name:
CITGO Refining & Chemicals L.P. (CITGO East Plant Refinery)


plant_name:
CITGO Refining & Chemicals L.P. (CITGO West Plant Refinery)


legal_owner_name:
Valero Refining – Texas, L.P., a Texas limited partnership

name_of_parent_company:
The ultimate parent company is Valero Energy		 Corporation, a Delaware corporation

notes:
Facility Information 1-Question 15
1.FacilityInformation.Question 15 – Production data from EIA-810 Form submittals.  
1.Question 16 – Unit Throughput Capacities from EIA-810/820 Form data and Solomon data.
1.Question 16.Marine Loading.Unit Throughput Capacity–Throughput capacities based on permitted rates.
Energy Management – 2-1 Table 1-2
2.1.TABLE 1-2.B-1 – Percent Steam to Blowdown – Represents an annual average derived from blowdown quantities listed in the 2010 BWON TAB Report  and actual 2010 steam generation rates
2.1.TABLE 1-2.B-2 – Percent Steam to Blowdown – Represents an annual average derived from blowdown quantities listed in  the 2010 BWON TAB Report  and actual 2010 steam generation rates
2.1.TABLE 1-2.B-4A – Percent Steam to Blowdown – Represents an annual average derived from blowdown quantities listed in the 2010 BWON TAB Report  and actual 2010 steam generation rates
2.1.TABLE 1-2.B-5 – Percent Steam to Blowdown – Represents an annual average derived from blowdown quantities listed in the 2010 BWON TAB Report  and actual 2010 steam generation rates
2.1.TABLE 1-2.B-5A – Percent Steam to Blowdown – Represents an annual average derived from blowdown quantities listed in the 2010 BWON TAB Report  and actual 2010 steam generation rates
Energy Management – 2-1 Table 1-3
2.1.TABLE 1-3.Steam Consumption – Consumption rates determined on a system-wide basis
Process Heaters – 2-2 Table 2-1
2.2.TABLE 2-1.116-H-125A.116REF2 - Rated heat input capacity – Includes Heaters 116-H-125B and 116-H-125C 
2.2. TABLE 2-1.116-H-125B.116REF2 - Rated heat input capacity is included in the total for Heater 116-H-125A
2.2. TABLE 2-1.116-H-125C.116REF2 - Rated heat input capacity is included in the total for Heater 116-H-125A 
Equipment Leaks 2-3 Table 3-1
2.3.TABLE 3-1.Average methane concentration in process fluid that contacts equipment in gas service throughout the process – Data was not readily available for all listed process units
2.3.TABLE 3-1.Components in Heavy Liquid Service, Gas and Liquid Sampling System Components – Components were estimated using the EPA EEPPR suggested correlation factors.
2.3.TABLE 3-1.Components in Heavy Liquid Service – Visual inspections are performed on these components; however, these were not counted as monitored components
Equipment Leaks 2-3 Table 3-2
2.3.TABLE 3-2.Components in Fuel Gas and Natural Gas Service – Components in fuel gas service are included with the component counts listed on Table 3-1.  Components in natural gas service were estimated using a correlation developed by Valero.
2.3.TABLE 3-2. Natural Gas Systems – Average methane concentration in process fluid that contacts equipment in gas service throughout the process – Concentrations based on permitting data.
Storage Tanks – 2-4
2.4. Actual Tank Throughputs – Throughputs based on tank level changes.
2.4. Tank T-10.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4. Tank T-11.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4. Tank T-123.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4. Tank T-124.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4. Tank T-126.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4. Tank T-134.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4. Tank T-135.Horizontal tank – Listed diameter corresponds to tank’s length.  Listed height corresponds to tank’s diameter
2.4.All Pressure Vessels.Maximum True Vapor Pressure of Hydrocarbons – Obtained from on-line MSDS and/or databases
Delayed Coker – 2-7
Notes contained in the CBI submittal.
Catalytic Reforming Units 2-8
2.8.116REF2.Coke Burnoff Cycle Duration – Listed in hours
Sulfur Recovery Units 2-9
2.9.141SRU. SRU Back-up Controls/ Reduction Measures – Multiple options, beginning with primary measure: 3 Divert to other SRU; 4 Sulfur Shedding; 1 Dedicated SRU Flare
2.9.195SRU. SRU Back-up Controls/ Reduction Measures – Multiple options, beginning with primary measure: 3 Divert to other SRU; 4 Sulfur Shedding; 1 Dedicated SRU Flare
Hydrogen Plant Vent 2-10
2.10.129SMR.Other Atmospheric Vent – Does not emit VOC emissions, only carbon dioxide and hydrogen
Flares 2-12
2.12.EP-Flare.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12.HCU-Flare.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12.REF2-Flare.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12.SRU1-FLARE.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12. SRU2-FLARE.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12.SWS- FLARE.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12.WP-Flare.Flare Location – Latitude and longitude coordinates obtained from Google Earth
2.12.EP-Flare.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
2.12.HCU-Flare.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
2.12.REF2-Flare.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
2.12.SRU1-FLARE.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
2.12. SRU2-FLARE.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
2.12.SWS-FLARE.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
2.12.WP-Flare.Typical lower heating value – Not known since flare is not equipped with flow meters or analyzers
Fuel Gas Treatment 2-13
2.13.General – Amine contactors are located at Unit 141ARU, although both 141 ARU and 195 ARU have amine regeneration capabilities
2.15.Question 2a.Average daily WWT flow rate – Flow rate to WWT is metered
2.15.Question 3a.Estimated quantity of tank draw downs – Obtained from 2010 BWON TAB Report
2.15.Question 3b.Estimated quantity of benzene in tank draw downs – Obtained from 2010 BWON TAB Report
2.15.TABLE 15-2.Average Wastewater Generation Rate – Wastewater generation rates for all listed process units are conservative estimates as none of these flow rates are metered
Loading Operations – 2-16
2.16.176.Unit ID – Marine loading occurs at five different docks: 3, 4, 6, 7, and 11
2.16. 176.Capacity loading throughput – Based on permitting data
2.16.179.Capacity loading throughput – Based on permitting data; includes diesel and sulfur loading.
2.16.176. Typical annual operating hours – Represents operating hours for the marine terminal, which includes loading and unloading operations
2.16.179. Typical annual operating hours – Represents operating hours for the truck terminal, which includes loading and unloading operations
2.16.179. Control Device – Emissions from sulfur loading are controlled by an incinerator; no controls are used for loading diesel
Non-Routine Emissions – Part 3
Volatile Organic Compounds – Listed emission rate represents unspeciated organic constituents only.  The total VOC emission rate for each event would be the sum of emission rates of all listed organic constituents plus the emission rate listed for Volatile Organic Compounds


energy_management_plan_description:
Stack O2 levels are controlled to 3% on most fired heaters, none targeted >7% O2. Steam venting has been reduced to almost none. Worn insulation (except tank farms) and 100+ steam traps were replaced. Total energy usage dropped by 15% due to energy mgmt.


notes:
Component	 1 	Part 1		Section 1 Facility Information	

Annual Revenue is U.S. Downstream (Refining and Lube Marketing) earnings after income tax

Question 13 - Number of employees in parent company:  The total number of employees in the parent company is based on regular employees at 2010 year end.

Question 16 – Unit Throughput units are different for the following unit IDs:

SCU2 – LT/D
WWTP, SWU, and Benzene Strippers (WWS) – MGD
CLEU3 – STEPII and Girbotol – MMcf/cd

Question 16 – Process Type. The areas listed below have more than one process type.  Therefore a secondary ID has been created to document the second process, but for the remaining portion only the primary ID will be used for the remaining portion of the ICR submittal.

Primary ID	Secondary ID
RACKS	RACKS – Rail
HU6 	HU6 – kero/jet fuel
HU9	HU9 - Naptha Splitter
PS3	PS3 - Vacuum
PS7	PS7 - Vacuum
PS8	PS8 – Vacuum

Question 16 – Process Type.  A secondary ID OM-HON has been created for OM, in order to document the Equipment Leaks information for multiple regulatory requirements, with different component counts.

Facility Information	Question 16 – Process Type. The areas listed below have more than one process type.  Therefore a secondary IDs have been created to document the product loading that happens in this process unit.  This ID will be used for the Loading section portion only.  The primary ID will be used for the remaining portion of the ICR submittal.


Primary ID	Secondary ID
FXK	              FXK-L
SCU2	              SCU-L


Question 16 – Process Type. The areas listed below have more than one process type.  Therefore a secondary IDs have been created to document the fuel gas treating systems, which will be used for the fuel gas treatment section portion only.  The primary ID will be used for the remaining portion of the ICR submittal.


Primary ID	Secondary ID
FXK	            FXK T-309
FXK	            FXK T-314
HDU1	            HDU1 T-702
HU9		HU9 T-361
HU9		HU9 T-381
GF1		GF1 T-252
Treaters	PS8 T-851
Treaters	PS8 T-852
Treaters	PS8 T-854
Treaters	PS8 T-855
HU6		HU6 T-103
HU4		HU4 T-402
Girbotol	PG T-804
Girbotol	PG T-805
Girbotol	PG T-852
Girbotol	PG T-801
Girbotol	PG T-802
Girbotol	PG T-807
HU10		HU10 T-902
HU10		HU10 T-903


Component	 1 	Part 2		Section 1 Energy Management	

Question No. 4 Energy Management Plan:

ExxonMobil’s energy management system for Downstream and Chemical operations, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.

GEMS is based on a three-step approach to performance improvement:
• Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
• Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
• Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.

GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic indicators focus on system health and implementation of improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom line performance for corporate and plant management.

As part of the energy management process ExxonMobil conducts GEMS Assessments at sites to deliver best practices and measures.  The Assessment progresses through three stages:
• It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local operations and practices.
• Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major equipment, and utilities systems to identify gaps.  The team also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste heat recovery projects.
• The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of operational improvement and facilities enhancements along with other business and investment needs.  All ExxonMobil refineries in the U.S. are in the GEMS program, and the initial energy management Assessments were performed a number of years ago.  Our sites are now in the implementation phase of this process.


Component	 1 	Part 2		Section 3 Equipment Leaks	

Table 3-1 Average methane is estimated based on a flow weighted average concentration of gas streams on each unit and reported in wt%.

Racks -  N/A since this system only loads liquid material.

Table 3-2 Average methane (wt %) is for natural gas only, since the fuel gas components are included with data in Table 3-1.

Component	 1 	Part 2		Section 4 Storage Tanks	

Table 4-1 Total throughput for all materials stored in the tank in 2010:

Tank 601 throughput is not recorded since it only receives recycle water
Tank 602 throughput is [CBI]

Component	 1 	Part 2		Section 5 Catalytic Cracking Units 	

Table 5-1 Is there a CO boiler or other combustion device after CCU regenerator?
FCCU2 has CO furnaces which are only used during cold startup.
Component	 1 	Part 2		Section 7 Delayed Coking Unit	

Table 7-1 The typical pressure, temperature and water height when opening drum to the atmosphere are a combined average from all 4 drums.

Table 7-2 Delayed Coking Unit Feed Information.   

% Feed  is a Vol %.   The feed information does not include the quench step.
The “Other” feed component is [CBI].


Component	 1 	Part 2		Section 8 Catalytic Reforming Unit	

Table 8-1 Hydrogen Production Rate (purified basis) (MMscf/cd at 0°C and 1 atm): [CBI]

Table 8-1 Coke Burn-off Cycle Duration per Cycle

HF3 is 56 hours/cycle
HF4 is 52 hours/cycle

Component	 1 	Part 2		Section 9 Sulfur Recovery Unit	

Table 9-1 Unit ID for SRU.

SCU2 unit is comprised of 4 Claus reactors, 4 pits, 3 Tail Gas Units, 2 absorbers,  and 1 Atmospheric vent.  There are 3 incinerators which are used for Startup/Shutdown.

Table 9-1 Primary Sulfur Pit Maintenance Time in 2010 (hr/yr)

Is reported as actual hours when pit was venting emissions during maintenance to atmosphere or incinerator.


Component	 1 	Part 2		Section 12 Flares	

Table 12-1 Typical Lower Heating Value of Waste Gas (Btu/scf @ 60°F) for flares are listed below:

Flare ID	Typical Lower Heating Value of Waste Gas (Btu/scf @ 60°F)
FLARE17	>300
FLARE18	>300
FL19		340-800
FL20		>300
FL21		>300
FL22		340-800

Component	 1 	Part 2		Section 14 Heat Exchange

System	Table 14-1 Gas or Chemical Additive/ Disinfection Method and addition rate per each Heat Exchange system is listed below:


HE System ID 	Gas or Chemical Additive		Addition Rate Value	Units 
CT8FUG		2 Sodium hypochlorite			80		GPD
			99 Other (Dispersant: HPS1)			2		GPD
			99 Other (Corrosion Inhibitor: PO4)		2.7		GPD
			99 Other (Corrosion Inhibitor: HRA)		0.6		GPD
			99 Other (pH Control Sulfuric Acid)		43		GPD

CT9FUG		2 Sodium hypochlorite			150		GPD
		99 Other (Corrosion Inhibitor/Dispersant: PO4/HPS1)	33	GPD
			99 Other (Corrosion Inhibitor: PO4)		8.5		GPD
			99 Other (Corrosion Inhibitor: HRA)		10		GPD

CT11FUG		2 Sodium hypochlorite			50		GPD
		99 Other (Corrosion Inhibitor /Dispersant: PO4/HPS1)	5.5	GPD
			99 Other (Corrosion Inhibitor: PO4)		1.5		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.7		GPD

CT16/24FUG		2 Sodium hypochlorite			150		GPD
			99 Other (Dispersant: HPS1)			14		GPD
			99 Other (Corrosion Inhibitor: PO4)		18.5		GPD
			99 Other (Corrosion Inhibitor: HRA)		7.2		GPD
			99 Other (pH Control Sulfuric Acid)		64		GPD

CT29FUG		2 Sodium hypochlorite			25		GPD
		99 Other (Corrosion Inhibitor/Dispersant: PO4/HPS1)	4.2	GPD
			99 Other (Corrosion Inhibitor: PO4)		1.1		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.3		GPD

CT30FUG		2 Sodium hypochlorite			22		GPD
		99 Other (All-In-One Product: HPS1, AEC, HRA, PO4) 	2.3	GPD

CT46FUG		2 Sodium hypochlorite			60		GPD
		99 Other (Corrosion Inhibitor/Dispersant: PO4/HPS1)	10.1	GPD
		99 Other (Corrosion Inhibitor: PO4)			2.5		GPD
		99 Other (Corrosion Inhibitor: HRA)			3.1		GPD

CT58FUG		2 Sodium hypochlorite			225		GPD
			99 Other (Dispersant: HPS1)			12		GPD
			99 Other (Corrosion Inhibitor: PO4)		16.3		GPD
			99 Other (Corrosion Inhibitor: HRA)		3.4		GPD
			99 Other (pH Control Sulfuric Acid)		37		GPD

CT61FUG		3 Calcium hypochlorite			150		GPD
		99 Other (Corrosion Inhibitor/Dispersant: PO4/HPS1)	18	GPD
			99 Other (Corrosion Inhibitor: PO4)		4.5		GPD
			99 Other (Corrosion Inhibitor: HRA)		5.5		GPD

CT62FUG		2 Sodium hypochlorite			150		GPD
			99 Other (Dispersant: HPS1)			4		GPD
			99 Other (Corrosion Inhibitor: PO4)		5.3		GPD
			99 Other (Corrosion Inhibitor: HRA)		2.1		GPD
			99 Other (pH Control Sulfuric Acid)		25		GPD

CT66FUG		2 Sodium hypochlorite			75		GPD
			99 Other (Dispersant: HPS1)			2.1		GPD
			99 Other (Corrosion Inhibitor: PO4)		2.8		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.1		GPD
			99 Other (pH Control Sulfuric Acid)		19		GPD

CT68FUG		2 Sodium hypochlorite			60		GPD
			99 Other (Dispersant: HPS1)			1.9		GPD
			99 Other (Corrosion Inhibitor: PO4)		2.6		GPD
			99 Other (Corrosion Inhibitor: HRA)		1		GPD
			99 Other (pH Control Sulfuric Acid)		26		GPD

CT71FUG		2 Sodium hypochlorite			20		GPD
		99 Other (All-In-One Product: HPS1, AEC, HRA, PO4) 	3.7	GPD

CT76FUG		2 Sodium hypochlorite			160		GPD
			99 Other (Dispersant: HPS1)			7.3		GPD
			99 Other (Corrosion Inhibitor: PO4)		9.8		GPD
			99 Other (Corrosion Inhibitor: HRA)		2.1		GPD
			99 Other (pH Control Sulfuric Acid)		57		GPD

CT78FUG		2 Sodium hypochlorite			180		GPD
		99 Other (Corrosion Inhibitor/Dispersant: PO4/HPS1)	4.5	GPD
			99 Other (Corrosion Inhibitor: PO4)		1.1		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.4		GPD

CT80FUG		2 Sodium hypochlorite			180		GPD
			99 Other (Dispersant: HPS1)			15.6		GPD
			99 Other (Corrosion Inhibitor: PO4)		21		GPD
			99 Other (Corrosion Inhibitor: HRA)		4.5		GPD
			99 Other (pH Control Sulfuric Acid)		65		GPD

CT84FUG		2 Sodium hypochlorite			80		GPD
		99 Other (Corrosion Inhibitor /Dispersant: PO4/HPS1)	4.5	GPD
			99 Other (Corrosion Inhibitor: PO4)		1.1		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.4		GPD

CT85FUG		2 Sodium hypochlorite			100		GPD
			99 Other (Dispersant: HPS1)			3.4		GPD
			99 Other (Corrosion Inhibitor: PO4)		4.5		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.8		GPD
			99 Other (pH Control Sulfuric Acid)		39		GPD

CT87FUG		2 Sodium hypochlorite			85		GPD
			99 Other (Dispersant: HPS1)			3.4		GPD
			99 Other (Corrosion Inhibitor: PO4)		4.5		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.8		GPD
			99 Other (pH Control Sulfuric Acid)		19		GPD

CT88FUG		2 Sodium hypochlorite			25		GPD
		99 Other (Corrosion Inhibitor/Dispersant: PO4/HPS1)	3.9	GPD
			99 Other (Corrosion Inhibitor: PO4)		1		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.2		GPD

CT89FUG		2 Sodium hypochlorite			115		GPD
			9 Other (Dispersant: HPS1)			4.5		GPD
			99 Other (Corrosion Inhibitor: PO4)		6.1		GPD
			99 Other (Corrosion Inhibitor: HRA)		1.3		GPD
			99 Other (pH Control Sulfuric Acid)		56		GPD



Component	 1 	Part 2		Section  15 Wastewater	

Table 15-2 Process Unit ID

SWU – represents all the process units feeding the SWU
Benzene Stripper (WWS) - represents all the process units feeding the Benzene Stripper (WWS)

Component	 1 	Part 3		Non-routine Emissions	

The following compounds listed below were reported as PM10-PRI: 

Date of Release	Pollutant Name
5/5/2010		Phosphoric Acid


notes:
1-	1	-11-	Facility Information	-Annual Revenue is U.S. Downstream (Refining and Lube Marketing) earnings after income tax
1-	1	-16-	Facility Information-Coker Gas Plant included with Coker. North BRU and South BRU included with Crude Units.  Wax blending included with Ketone 2. GCP-3 included with FCC.  Dualayer included with HDC. GP5W included with FCC.
1	-1-	1	-Energy Management	-Coker Gas Plant included with Coker. Lube Pumpers included with Furf 1 & 2 HDF, and Ketone 2 Units. Merox and MRU included with Alky/MTBE. Wharf, OMCC-1, OMCC-2, EWT, and Yard Utilities included with Ethyl. Flare System included in individual units.
1	-4-4	-Energy Management	Energy Management Plan:

ExxonMobil’s energy management system for Downstream and Chemical operations, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.

GEMS is based on a three-step approach to performance improvement:
	Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
	Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
	Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.

GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic indicators focus on system health and implementation of improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom line performance for corporate and plant management.

As part of the energy management process ExxonMobil conducts GEMS Assessments at sites to deliver best practices and measures.  

The Assessment progresses through three stages:
	It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local operations and practices.
	Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major equipment, and utilities systems to identify gaps.  The team also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste heat recovery projects.
	The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of operational improvement and facilities enhancements along with other business and investment needs.  All ExxonMobil refineries in the U.S. are in the GEMS program, and the initial energy management Assessments were performed a number of years ago.  Our sites are now in the implementation phase of this process.  

1	-3	-Table 3-1-	Equipment Leaks-	Fuel gas is included in quarterly monitoring. Coker Gas plant included with Coker. Wax Blending included with Lube Pumpers.  Flare System included in individual units. 
1-	3	-Table 3-1	-Equipment Leak- Table 3-3	 Coker Gas Plant included with Coker.  SAM included with HDC.  
1	-12-	12-1-Flares-	Flares are not dedicated to any single unit.
1	-13	-13-1-	Fuel Gas Treatment	-The possibility exists for other sulfur compounds but it is unknown.
1	-15-	15-1-	Wastewater-15-1	North and South BRU uses Nitrogen instead of steam as a stripping agent
3-	1	1	-Non-Routine Emissions	-The following chemicals and their associated events described below could not be entered into the database because they were not included on the EPA’s CAS list for the ICR.

The pollutants are listed with the following information; Pollutant Name, CAS, Quantity of pollutant released, and determination method.

01/09/2010 – PP4 GTG41 Generator Breaker Trip - H2SO4, 7664-93-9, 1.20 lbs, Calculated 
2/19/2010 - GP5E #3 Deisobutanizer South Reboiler Tube Leak – Butanes, NA, 1224.60, Calculated
2/26/2010 - ISOM H2 Makeup Line Leak – Pentenes, NA, 1.30, Calculated
4/24/2010 - Coker #3 Drum Crack – Butanes, NA, 4.90, Calculated   Butenes, NA, .40, Calculated
 Pentanes, NA, 3.40, Calculated
5/15/2010 - GP5E #2 Deprop RV Lift (CT#21 Power Failure) – Butanes, NA, 2127.50, Calculated
6/16/2010 - Coker #7 Drum Top Head Leak – Butanes, NA, 8.80, Calculated
 Butenes, NA, 1.10, Calculated 
Octanes, NA, 7.90, Calculated
 Pentanes, NA, 6.50, Calculated
10/29/2010 - Malfunction	Coker #6 Drum Crack - 2-ethylthiophene, 872-55-9, 4.96, Calculated
 Butanes, NA, 67.86, Calculated
 Butenes, NA, .98, Calculated
 Decanes, NA, 14.78, Calculated
 Decene, 872-05-9, 11.24, Calculated
 Heptane, 142-82-5, 18.03, Calculated
 Heptene, NA, 15.06, Calculated
 Heptene (cyclo), NA, 628-92-2, 17.06, Calculated
 Hexane, 110-54-3, 39.02, Calculated
 Hexane (cyclo), 110-82-7, 11.64, Calculated
 Hexene, 592-41-6, 33.06, Calculated
 Hexene (cyclo), 110-83-8, 6.40, Calculated
 Nonane, 111-84-2, 18.51, Calculated
 Nonene, NA, 13.35, Calculated
 Octene, NA, 19.40, Calculated
 Octene (cyclo), 931-88-4, 16.27, Calculated
 Pentanes, NA, 33.79, Calculated
 Pentene, NA, 10.18, Calculated
11/3/2010 - ISOM Stabilizer Feed Line Pinhole Leak – Pentanes, NA, 157.30, Calculated
11/12/2010 - Coker Depropanizer Feed Line Pinhole Leak – Butenes, NA, 3.01, Calculated


plant_name:
Flint Hills Resources, LLC Corpus Christi West Refinery

energy_management_plan_description:
Refer to the cover letter that was included with this submittal

notes:
Refer to the cover letter, "RE: Flint Hills Resources, LLC Corpus Christi West Refinery - Component 1 Information Collection Request (ICR) Response", dated May 31, 2011, that accompanied the database response.  The document attached to the letter is intended to supplement FHR’s answers to Component 1 of the ICR (the “Supplement”).  In the Supplement, FHR provides an explanation of how specific Parts/Sections/Question numbers (“Question Numbers”) were answered by FHR for the ICR.  The explanations may include a discussion of FHR’s specific process and its understanding or interpretation of the question followed by an in depth discussion of the data or information used in FHR’s response to that question.  FHR intends that its electronic responses to Component 1 of the ICR and any accompanying certification of that information be read in conjunction with any information contained in the Supplement.


plant_name:
Flint Hills Resources, LLC Corpus Christi East Refinery

energy_management_plan_description:
Refer to the cover letter that was included with this submittal.

notes:
Refer to the cover letter, "RE: Flint Hills Resources, LLC Corpus Christi East Refinery - Component 1 Information Collection Request (ICR) Response", dated May 31, 2011, that accompanied the database response.  The document attached to the letter is intended to supplement FHR’s answers to Component 1 of the ICR (the “Supplement”).  In the Supplement, FHR provides an explanation of how specific Parts/Sections/Question numbers (“Question Numbers”) were answered by FHR for the ICR.  The explanations may include a discussion of FHR’s specific process and its understanding or interpretation of the question followed by an in depth discussion of the data or information used in FHR’s response to that question.  FHR intends that its electronic responses to Component 1 of the ICR and any accompanying certification of that information be read in conjunction with any information contained in the Supplement.


energy_management_plan_description:
Developed 5-yr roadmap plan for energy efficiency improvement based on benchmarking study, energy assessments, and engineering studies. The plan is currently being implemented. Estimated 2010 energy reduction achieved was 1.1 Trillion Btus.

notes:
"Component","Part","Field","Notes"

"All","All","All","All data provided is based on the most readily available data as necessary to be able to respond in accordance with the mandated schedule of the ICR.  Houston Refining does not believe EPA allowed adequate time to prepare a response.  Requests for extensions of the deadline were filed by NPRA and API on behalf of the refining industry – these were denied by EPA.   We are submitting the best information available to us within the allotted time, and will  correct, update, or revise, the data being provided as per the requirements under section 114 of the Clean Air Act.  Efforts were made to provide a complete response, but some areas of the response remain incomplete due to time constraints or because the data is not readily available. "

"1","All","CBI","In addition to the fields designed to be claimed as CBI by the ICR Component 1 database, the following fields have been identified by LBI as potentially containing Confidential Business Information, and have been removed from the Non-CBI version of the database:
Catalytic Cracking Units
     Percent of CCU Feed that is Hydrotreated
     Recycle / Resid Capacity
     Typical Coke Burn Rate at Capacity
Catalytic Reforming Unit
     Operating Pressure
Cooling Water Systems
     Gas chemical additive rate and units
Delayed Coking Unit
     Coke Production Capacity
     Feed Capacity
     Typical Quench Water Flow Rate during Quenching Cycle
Facility Information - Products Produced
     % shipped by barge
     % shipped by pipeline
     % shipped by rail car
     % shipped by tank ship
     % shipped by tank truck
     % used onsite
Process Heater Data
     Rated heat input capacity
     Total operating hours in 2010
Process Units
     Steam consumption for the processing unit in 2010
Storage Tanks
     Total throughput for all materials stored in the tank in 2010
Fuel Gas Treatment
     Average fuel gas flow rate into the treatment unit
     Estimated operating hours in 2010
     Fuel gas flow rate at treatment unit capacity
Loading Operations
     Capacity loading throughput
     Typical annual operating hours
Wastewater Collection
     Steam and Sour Water Strippers total average steam usage rates for each stripper
     Daily average WWTS flow rate for all WWTS at the facility (or average discharge rate if wastewater is treated off-site)"

"1","1","Process Unit Data","Process Unit designations used for responses are not always consistent between data provided for emissions inventory and EIA reporting purposes because of applicable regulatory or reporting requirements.  Units have been combined or split as needed to be responsive in a manner that is intended to avoid double counting.  For example, crude distillation units that consist of both an atmospheric and vacuum distillation operation have been split for capacity reporting to be consistent with the EIA reports, but are combined when reporting equipment leak component counts because applicable regulations require the counts to be grouped and treated as a single unit.
"

"1","1","Process Unit Data - Unit Actual Throughput and Throughput Capacity","Values for throughput are reported for units with unit operations that meet the definition of process unit.  Throughputs are not provided for other 'process units' such as tank farms and loading operations. "

"1","1","Annual Revenue in 2010 ($)","The annual revenue listed is that reported to the SEC on Form 10-K for the Refining and Oxyfuels Segment of LyondellBasell Industries N.V. for 2010.  Note that this includes revenues for other refining and oxyfuels production worldwide.  Data is not available to be reported for Houston Refining LP by itself."

"1","5","CEMS Data","CEMS Data for Cooling Towers, Flares, and the Marine Vapor Combustor are not provided because these CEMS systems do not meet the criteria in 40 CFR 60 Appendix F.  These systems are in place as a result of state requirements (30 TAC 115 and 117) and are not required to follow all criteria in Appendix F."

"1","5","CEMS Daily Template, Tab CEMS_Daily_732_CO, CEMS_Daily_732_NOx, and CEMS_Daily_732_SO2, Production Rate","Daily production rate specified is the coke burn-off rate."

"1","5","CEMS Daily Template, Tab CEMS_Daily_732_CO, Average Emission Value field","CO concentration specified is uncorrected for stack O2 or moisture."

"1","5","CEMS Daily Template, Tab CEMS_Daily_732_CO, CEMS_Daily_732_NOx, and CEMS_Daily_732_SO2, Moisture % field","Moisture content specified as volume percent."

"1","5","CEMS Daily Template, Tab CEMS_Daily_732_NOx, Average Emission Value field","NOx concentration specified is uncorrected for stack O2 or moisture."

"1","5","CEMS Daily Template, Tab CEMS_Daily_732_SO2, Average Emission Value field","SO2 concentration specified is uncorrected for stack O2 or moisture."

"1","2","Section 12 - Flares: Operating Hours","All flares have continuous sweep and may have continuous flow from PRV leakage.  Other than these streams, primary flow is from maintenance, start-up, shutdown, or upset events."

"1","2","Section 12 - Flares: Management Plan","Root cause analyses are triggered based on exceeding a reportable quantity, which can be triggered based on SO2 emissions or flow depending on composition associated with the event."

"1","5","CEMS Daily Template, Tabs CEMS_Daily_435_SO2 and CEMS_Daily_435_CO, Moisture Content","Stack moisture content is not a measure parameter for the 435 thermal oxidizer.  All measured parameters (CO and SO2) are conditioned (dried) prior to analysis."

"1","5","CEMS Daily Template, Tabs CEMS_Daily_435_SO2 and CEMS_Daily_435_CO, Production Rate","The 435 thermal oxidizer handles waste gas from both the 433 and 434 tail gas treatment units.  Daily production rate specified is the sulfur make (long tons per day) from both tail gas units."

"1","5","CEMS Daily Template, Tabs CEMS_Daily_440_SO2 and CEMS_Daily_440_CO, Moisture Content","Stack moisture content is not a measure parameter for the 440 thermal oxidizer.  All measured parameters (CO and SO2) are conditioned (dried) prior to analysis."

"1","5","CEMS Daily Template, Tabs CEMS_Daily_440_SO2 and CEMS_Daily_440_CO, Production Rate","The 440 thermal oxidizer handles waste gas from the 439 tail gas treatment unit.  Daily production rate specified is the sulfur make (long tons per day) from the 439 tail gas treatment unit."

"1","5","CMS Daily Template, Tabs CMS_Daily_Mixing_Pot_H2S and CMS_Daily_Mixing_Pot_BTU, Production Rate","Daily production rate specified is the fuel gas flow from the mixing pot (point of CMS measurement) to the refinery, in thousands of standard cubic feet per hour (MSCF/Hr)."

"1","2","Section 16 Product Loading","Loading capacities and controls are presented for hydrocarbon liquid loading operations based on what was implied with the listed potentially applicable regulations.  Loading of sulfur, petroleum coke, and other materials that are not hydrocarbon liquids are not included."

"1","2","Section 16 Product Loading","Only materials with a vapor pressure greater than 0.4 psia are controlled using marine vapor combustor."

"1","2","Section 16 Product Loading","Loading capacities are based on permit authorized loading rates for liquid hydrocarbons."

"1","2","Section 16 Sulfur Recovery Units","The 430 Sulfur Recovery Unit ID refers to equipment associated with the entire sulfur recovery complex, including the Claus trains, tail gas treaters, and thermal oxidizers, etc.  Detailed information is provided by Claus Trains to keep from double counting capacity or data."

"1","2","Section 16 Sulfur Recovery Units","The ICR Component 1 Tool allows only one entry for backup controls/reduction measures.  The primary back up is to route gas to another SRU, but sulfur shedding, other work practices, and a plant flare can also be used if needed."

"1","2","Section 8 Catalytic Reforming Unit","The refinery has two catalytic reforming units.  The 735 Unit was idle in 2010.  Hydrogen rate is based on listed capacity not 2010 production, which was zero.  The reformer section of the 734 unit was permanently shut down more than 10 years ago.  "

"1","2","Section 11 Other Atmospheric Vents","Listed atmospheric vents are for vacuum systems on lube oil production units, handling materials with extremely low volatility.  Units have periodic monitoring requirement to demonstrate that VOCs are < 20 ppmv."

"1","2","Section 11 Other Atmospheric Vents","Data is included for other atmospheric vents for which data is readily available.  Data is not readily available for analyzer vents (which have not been considered a significant source of emissions).  Data is also not readily available on pneumatically operated valves that use natural gas for actuation."

"1","2","Section 3 Equipment Leaks ","For all units, the monitoring frequency specified is the monitoring frequency for the majority of components in the given component type and material phase.  The leak definition specified is the most stringent leak definition monitored against (usually 500 ppmv) for a given unit, component type, and material phase."

"1","2","Section 3 Equipment Leaks ","Counts for sample connections are not stored in our leak detection and repair database and are not readily available."

"1","2","Section 3 Equipment Leaks ","Component counts for the 630 and 631 are combined and reported with the 631 unit because these units were originally considered a single process unit."

"1","2","Section 3 Equipment Leaks ","Component counts for most of the units associated with the sulfur recovery complex are grouped with 430-UNIT (the sulfur recovery complex) rather than as subsystems."

"1","2","Section 3 Equipment Leaks ","Component counts for the 831, 832, and 833 units are combined and reported with the 533 unit because these units were originally considered a single process unit."

"1","2","Section 3 Equipment Leaks ","Component counts are not provided for units that are idle and have been emptied and degassed.  These components have been flagged as inactive in our leak detection and repair database."

"1","2","Section 3 Equipment Leaks ","Counts for components in natural gas service are not readily available, and could not be completed within the time allowed for response.  The number of components in natural gas service is insignificant compared to the number in refinery fuel gas service."

"1","2","Section 3 Equipment Leaks ","Counts for components in refinery fuel gas service are effectively double counted by being listed both in Table 3-1 and Table 3-2.  Fuel Gas collection, treatment, and distribution systems are integral to each process unit and have been included in regulatory periodic reports.  Removing the fuel gas components from the process unit level information could mislead the regulatory development process.  Note that the mandatory reporting tool did not support breaking the components down by process unit, so they have been grouped for the system as a whole."

"1","2","Section 3 Equipment Leaks ","Open ended lines are not allowed under state and federal rules.  Components with a cap, blind flange, or double block and bleed system have not been counted as open ended lines.  The posting to the FAQs (stated as 5/27/11) regarding this topic was too late for any tabulation to be made."

"1","2","Section 3 Equipment Leaks ","Monitoring frequencies are based on Method 21 monitoring, and do not include audio, visual and olfactory (AVO) monitoring, and monitoring using thermal imaging.  The posting to the FAQs (stated as 5/27/11) regarding this topic was too late for any change to be made.  Also, since AVO monitoring is more frequent - up to several times daily - the responses would be misleading."

"1","2","Section 13 Fuel Gas Treatment Units","Average H2S content is based on overall average at combined mixing pot for all fuel gas treatment units.  The units are not monitored individually.  Total reduced sulfur is estimated based on a ratio of 1.9:1 (Total Sulfur:Hydrogen Sulfide) based on testing."

"1","2","Section 13 Fuel Gas Treatment Units","Fuel Gas Treatment units are sections of other process units.  They have been broken out to allow entry into the electronic reporting tool."

"1","2","Section 13 Fuel Gas Treatment Units","Fuel Gas Treatment unit capacities are estimated based on peak daily average rates rather than design data."

"1","2","Section 15 Wastewater Collection and Treatment","Data is available for total flows and benzene - both of which have been gathered to support compliance with 40 CFR 61 Subpart FF.  Data is generally not available for overall VOC and HAP content by process unit, and would require further testing to characterize these streams at the point of generation.  "

"1","2","Section 15 Wastewater Collection and Treatment","Wastewater which is handled in a closed sour water system is quantified when leaving the sour water stripper (the FF point of generation)."

"1","2","Section 15 Wastewater Collection and Treatment","Data is provided for vents from closed or covered wastewater collection processes that have vents to atmosphere."

"1","2","Section 15 Wastewater Collection and Treatment","Only pre-treatment is conducted on site (sour water stripping, FF stripping, and oil water separation).  All other treatment is conducted off-site by a POTW prior to discharge. "

"1","2","Section 1 Energy Management","Steam generators from waste heat are listed only if on exhaust gas lines per ICR instructions."

"1","2","Section 6 Fluid Coking Units","Houston Refining does not have a fluid coking unit."

"1","2","Section 10 Hydrogen Plant Vent","Houston Refining does not have a hydrogen plant vent."


energy_management_plan_description:
Marathon constantly evaluates and implements a wide range of projects and programs to improve energy performance, and to drive strategic business planning at each location. We have corporate Energy Technologists and Energy Engineers at each refinery.

notes:
Part I General Facility Information 

Question 11:  The 2010 Marathon Oil Corporation revenue was $72,321 million.  The 2010 Refining, Marketing & Transportation segment revenue was $62,487 million.
Question 13: Name of Parent Company - Prior to and including June 30, 2011: Marathon Oil Corporation; After June 30, 2011: Marathon Petroleum Company LP.

Question 16: Unit 14 (Gas plant/light ends distillation/LPG production): Gas Plant is for entire refinery and thus capacity and throughput were not specified, Units 87-1 and 87-2 (Sulfur Recovery Units): Individual SRU production is not measured, only a total.  Therefore, an average rate is shown for each unit.

Part II, Section 1. Energy Management

Table 1-3, Unit 2779 (WWTS): Steam consumption includes steam used in the Sour Water Stripper.

Part II, Section 2. Process Heaters

H-94(Direct Fired Heater for FCC Regenerator Combustion Air): Only used for startup, therefore operating time is very low.  

Part II, Section 3. Equipment Leaks

Question 2:  The IR Camera is used on a non-routine basis to find leaks, check tank seals, etc.
Table 3-1, Unit ID 87-1 and 87-2: There are no fugitive components in the SRU.  The natural gas components are included in Unit ID TXCNAT.
Table 3-1, Unit ID 85:  Fugitive components of Unit 85 are included in Unit 14.
Table 3-1 General Note: The fugitive components in the "Other" column are CLVS.
Table 3-2 Unit ID 2753: Compressor seal is for the Off Gas Compressor.
Table 3-3. Pressure Relief Devices Unit ID 85: PRDs of Unit 85 are included in Unit ID 14.
Table 3-3. Pressure Relief Devices Unit ID 2753: PRDs for the fuel gas system are included in the individual units.
General Note: All components in CLVS vent to a flar.


plant_name:
Motiva Enterprises LLC Port Arthur Refinery

energy_management_plan_description:
Focusing efforts to reduce the amount of oxygen that would be running in the furnaces by about 1 to 1.5%.  Minimized steam leaks, implemented a technical monitoring program that evaluate energy conspumption monthly.

notes:
•	The equipment leaks answers reflect LDAR monitoring and does not include the normal audio, visual and olfactory monitoring conducted during normal daily operations, which does identify and repair leaks in a timely manner
•	The fugitive emission sources for VPS2 Atm, include the fugitive sources for both VPS2 Atm and VPS2 Vac.  
•	The fugitive emissions for the VPS4 Atm include the fugitive sources for both the VPS Atm and VPS4  Vac.
•	The fugitive emission sources for the West Side Gas Plant also include the fugitive emissions from the WAGS unit
•	NSGP Caustic contains the fugitive emissions for the NSGP High and Low and the MVHPS unit


energy_management_plan_description:
Daily activities include: Energy fired heater and boiler oxygen management, a steam trap repair program, a steam leak repair program, heat exchanger maintenance.  Energy performance checklists and periodic audits are done to review energy use.

notes:
Please see excel file "TX3B1240 Component 1 Notes" for all notes related to this submittal.


legal_owner_name:
The Premcor Refining Group, Inc. a Delaware Coporation

name_of_parent_company:
Valero Energy Coporation, a Delaware Corporation

notes:
Section 1
General Facility Information
Part1.Process Units – Steam consumption for process units is gross.      

Part1.Process Units.Docks - Docks has a unit id for fugitive component purposes only.             

Part1.Process Units.CPC (off-site chem. Plant) - CPC (off-site chem plant) has a unit id for wastewater generation purposes only.                                                                                               

Part1.Process Units.E-02-SRUCK - 2010 actual throughput is in LTPD.                     

Part1.Process Units.E-03-SRUCK - 2010 actual throughput is in LTPD.                  

Part1.Process Units.F-Loading - 2010 actual throughput is in LTPD.                      

Part1.Process Units.Fuel Blending - Is only entered for fugitive component purposes only.          

Part1.Process Units.ATU-7841 - Is only entered for fugitive component purposes only.            

Part1.Process Units.ATU-7842 - Is only entered for fugitive component purposes only.             

Part1.Process Units.AVU-146 VAC - AVU-146 Steam usage 2010 is included with AVU-146.         

Part1.Process Units.AVU-147 VAC - AVU-147 Steam usage 2010 is included with AVU 147.        

Section 2
Energy Management
Part2.Section 1.Energy Management Plant - Energy Plan:  No specific plan in place, but energy management is important to the facility and energy projects are undertaken.  

Section 3
Equipment Leaks
Part2.Section 3.Heavy liquid components - Although Heavy Liquid fugitive components are monitored with visual inspections, this monitoring has not been included in the Number of Monitored Components.                                                                                                        

Part2.Section 3.Pressure Relief Devices – The total PRDs may not equal the sum of the PRDs routed to the flare and the PRDs to the atmosphere, the difference are routed back to the process.

Part2.Section 3.AVU-146 VAC.Fugitives - AVU-146 VAC fugitive counts are included with AVU-146.                                                                                                        

Part2.Section 3.AVU-147 VAC.Fugitives - AVU-147 VAC fugitive counts are included with AVU-147.  

Section 4
Storage Tanks
Part2.Section 4.Tanks – Throughputs based on tank level changes.               

Part2.Section 4.Tanks – Tank T-2165, T-2166, and T-2167 the diameter equals the length because they are horizontal pressure tanks.               

Section 5
Catalytic Cracking Units
Part2.Section5.FCCU-1241.Recycle/Resid Capacity (bbl/cd) – FCCU-1241 has no recycle/resid  capacity, therefore 0 was entered.                                                              
                                                                                                                                                                          
Section 8
Catalytic Reforming Units
Part2.Section8.CRU-1344.Coke burnoff Duration per cycle - CRU-1344 has a continuous Coke burnoff, that is why -88 is entered.                                                              

Section 12
Flares
Part2.Section 12.Flares – Flare locations taken from google earth.                                                      

Section 14
Heat Exchange Systems
Part2.Section 14.CT-314.Cooling Water System VOC/HAP Concentration - Cooling Tower is not in VOC service, so no selection was made.                                                      

Part2.Section 14.CT-316.Cooling Water System VOC/HAP Concentration - Cooling Tower is not in VOC service, so no selection was made.                                                                   

Section 15
Wastewater Collection and Treatment
Part2.Section 15.AVU-146 VAC.Average Wastewater generation rate - AVU-146 VAC average wastewater generation rate is included with AVU-146.                                                   

Part2.Section 15.AVU-147 VAC.Average Wastewater generation rate - AVU-147 VAC average wastewater generation rate is included with AVU-147.

Section 16
Product Loading Operations
Part2.Section 16.Product Loading.F-843-13 – Loading rate for F-843-13 is in TPY.

Part2.Section 16.Product Loading.F-843-14 – Loading rate for F-843-14 is in TPY.


legal_operator_name:
Shell Oil Company.  Effective January 1, 2011, Shell Oil Products Company LLC employees conduct the operations at this facility on Shell Oil Company’s behalf.

plant_name:
Deer Park Refining Limited Partnership (EIA ID# 1339570101)

energy_management_plan_description:
Purpose is to have a governance of how energy consuption is monitored, measured, and optimized.  See full description in notes field.

notes:
ARU 6/7 units in MMGal/Day, COGEN units in MW                                                         

Energy Management Plan Description

Purpose of the Energy Management plan is to have a governance of how energy consumption is monitored, measured, and optimized.  Goal is to optimize on a daily basis large energy-Consuming equipment and facilitate sound decisions at the unit around maintenance and programs to reduce energy consumption. Lastly, the Energy Management System will dictate how future energy improvement opportunities are tracked and driven, and how external benchmarking targets are set.
                
Key aspect of the plan are:

1.	Energy Management Structure at equipment, unit and site level.
2.	Energy Metrics at equipment, unit and site level.
3.	Roles & Responsibilities of Energy Management
4.	Site-wide Energy Programs: Maintenance of Systems
5.	Future Improvements & Site Benchmark Targets                
Key Energy Reductions
                
•	Implementation of a Furnace air trap program (to reduce air leaks on the Furnaces)
•	Implementation of a steam trap program (yearly survey of steam traps at the site and 
  perform repairs basis there priority)
•	Boiler blow down minimization (reduce heat lost by blowing less material)
•	Heat exchanger cleanup program (reduced steam consumption by increasing heat exchange   performance)
•	Excess Oxygen optimization in the Furnaces
•	Enhances in advance control system at key areas to reduce energy consumption

UVAMBAIRMON emissions test is shown to be associated with the Coker unit in the database but was not actually assoicated with a unit.  Testing was conducted in the NW and SE corner of the site.

For the wastewater generation units, the entry for CR3 is intended to include the flows from all units from the hydroprocessing units (CR3, HP1, HDU1, SGP, SHCU, PLAT2, PSA).


notes:
BTB Refining only uses purchased sweet pipeline quality natural gas; feed and heavy hydrocarbons product streams generate no methane vapors


legal_owner_name:
Valero Refining-Texas, L.P., a Texas limited partnership

notes:
Part2.Section1.13-H-01C.Boiler Heat Input Capacity – HHV assumed
Part2.Section1.30-B-02.Boiler Heat Input Capacity – HHV assumed
Part2.Section1.30-B-03.Boiler Heat Input Capacity – HHV assumed
Part2.Section1.WHB-HOC-600.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-HOC-150.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-HOC-50.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-SRU1&2-600.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-SRU1&2-50.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-SRU3-400.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-SRU3-50.Steam Generating Capacity – Typical for 2010
Part2.Section1.WHB-OLEFLEX.Steam Generating Capacity – Typical for 2010
Part2.Section1.13-H-01B Steam.Steam Generating Capacity – Typical for 2010
Part2.Section1.CRU Steam.Steam Generating Capacity – Typical for 2010
Part2.Section1.VAC Steam.Steam Generating Capacity – Typical for 2010
Part2.Section1.GDU Steam.Steam Generating Capacity – Typical for 2010
Part2.Section1.HDS Steam.Steam Generating Capacity – Typical for 2010
Part2.Section1.ALKY Steam.Steam Generating Capacity – Typical for 2010

Part2.Section3.Heavy liquid components – Although heavy liquid fugitive components are monitored with visual inspections, this monitoring has not been include in the Number of Monitored Components.

Part2.Section4.Tank “height” – For tanks 74-TK-37, 74-TK-38, 74-TK-39, 74-TK-40, 74-TK-41, and 74-TK-42 the lengths of these horizontal pressure tanks are reported as the diameter and the diameter as the height.
                                                                                                                          Part 2.Section5.HOC.Recycle/Resid Capacity – Slurry recycle not used.

Part2.Section9.SRU1&2.Type of Tail Gas Treatment Unit – Sulften, which is the same as SCOT except for heating is by exchanger rather than inline firing
Part2.Section9.SRU1&2.SRU Back-up Controls/ Reduction Measures - Additional SRU Back-up controls are: sulfur shedding and general flare.
Part2.Section9.SRU3.Primary Sulfur Pit – One pit is shared between the SRUs and the questions are answered for SRU1&2.
Part2.Section9.SRU3.SRU Back-up Controls/ Reduction Measures - Additional SRU Back-up controls are: sulfur shedding and general flare.

Part2.Section12.Flare Location – Data obtained from Google Earth

Part2.Section15.BUTAMER.Process Unit ID – also units LEU04, LEU18, Powerhouse
Part2.Section15.OLEFLEX.Process Unit ID – also OCTENE


notes:
Energy Management – Part II, Section 1
2.1 Energy intensity is a common metric for the industry and while we do not have a written plan, we do have an energy management program in place with dedicated resources designed to optimize energy use.
Sulfur Recovery Unit (SRU) - Part II, Section 9
Low Sulfur feed and Redundancy are additional SRU Back-up Controls/ Reduction Measures for both SRUs.  
Storage Tanks – Part II, Section 4
Maximum true vapor pressure calculated based on the maximum monthly average ambient temperatures.  Also, the unit for the minimum height of floating roof above the floor at the shell when landed is foot.


legal_owner_name:
Valero Refining -Texas L.P., a Texas limited partnership

name_of_parent_company:
The ultimate parent company is Valero Energy Corporation, a Deleware Corporation

notes:
1.1.Annual Revenue - Annual Revenue is considered more than confidential business information and is readily available from other sources.
1.1 SULFLOAD - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 DOCK 16 - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 DOCK 20 - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 DOCK 22 - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 DOCK 56 - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 DOCK 57 - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 TANK FARM - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 UTILITIES - The process unit capacity and actual throughput data was not provided, because this unit is not a "production" unit.  This Process Unit was solely created to provide data for another section in Component 1.
1.1 ROSE Steam Consumption - Included in the steam consumption for the GOHT Process Unit.
1.1 GOHT SRU Steam Consumption - Included in the steam consumption for the GOHT Process Unit.
1.1 DHT AMINE Steam Consumption - Included in the steam consumption for the DHT Process Unit.
1.1 MDHT AMINE Steam Consumption - Included in the steam consumption for the MDHT Process Unit.
1.1 GOHT AMINE Steam Consumption - Included in the steam consumption for the GOHT Process Unit.
1.1 COKER AMINE Steam Consumption - Included in the steam consumption for the COKER Process Unit.
1.1 GDU AMINE Steam Consumption - Included in the steam consumption for the GDU Process Unit.
1.1 FGRU AMINE Steam Consumption - Included in the steam consumption for the FGRU Process Unit.

2.1 Boiler Heat Input Capacity (MMBtu/hr) - Waste heat boilers and steam generators are not fired units and therefore do not have a heat input capacity.
2.1 Percent Steam to Blowdown - No data is available to provide a reasonable estimate for this parameter for the steam generation units.

2.3 Average Methane Concentration - Data is not available in the specified units of measurement.
2.3 FGRU Pressure Relief Devices - PRD information was not available for this unit.
2.3 INALK Pressure Relief Devices - PRD information was not available for this unit.
2.3 DOCKS Pressure Relief Devices - PRD information was not available for this unit.
2.3 GOHT SRU Pressure Relief Devices - PRD information was not available for this unit.
2.3 DHT AMINE - Included in the DHT Process Unit.
2.3 MDHT AMINE - Included in the MDHT Process Unit.
2.3 GOHT AMINE - Included in the GOHT Process Unit.
2.3 COKER AMINE - Included in the COKER Process Unit.
2.3 GDU AMINE - Included in the GDU Process Unit.
2.3 FGRU AMINE - Included in the FGRU Process Unit.
2.3 DOCKS - Includes component counts for DOCK 16, DOCK 20, DOCK 22, DOCK 56, and DOCK 57.

2.4 T-096 Degassing - No degassing information was available for this tank.
2.4 T-322 Degassing - No degassing information was available for this tank.
2.4 T-323 Degassing - No degassing information was available for this tank.
2.4 T-324 Degassing - No degassing information was available for this tank.
2.4 T-325 Degassing - No degassing information was available for this tank.
2.4 T-326 Degassing - No degassing information was available for this tank.
2.4 T-327 Degassing - No degassing information was available for this tank.
2.4 T-464 Degassing - No degassing information was available for this tank.
2.4 T-538 Degassing - No degassing information was available for this tank.
2.4 T-539 Degassing - No degassing information was available for this tank.

2.5 FCCU.Recycle/Resid Capacity – Not applicable since there is no recycle/resid because the unit is continuous.

2.8 #2 Reformer Average Annual Regeneration Time - Not applicable because the CRU is a continuous catalytic reforming unit.
2.8 #2 Reformer Coke Burn-off Cycle Duration per Cycle - Not applicable because the CRU is a continuous catalytic reforming unit.

2.13 Estimated Annual Average Total Sulfur - Information to provide a reasonable estimate was not available.

2.15 Tank drawdowns (i.e. total quantity, benzene concentration, and VOC concentration)- There is not data available to provide reasonable estimates of tank drawdowns for 2010.
2.15 GDU Average Benzene Concentration - Not enough data available to accurately estimate concentration and not recorded in TAB.
2.15 Tank Farm Average Benzene Concentration - Not enough data available to accurately estimate concentration and not recorded in TAB.
2.15 Average Concentration of Organic HAP - Not enough data available to accurately estimate concentration.
2.15 Average VOC Concentration - Not enough data available to accurately estimate concentration.
2.15 LRU Wastewater Generation Information - The information for the LRU is included in the SATS GAS Process Unit.

2.16 SULFLOAD - Includes sulfur loading for GOHT SRU and SRU #3.


energy_management_plan_description:
-	Started up new Boiler (#6) replacing less efficient temporary boiler
-	Completed Furnace Optimization Training
-	Began construction on boiler feed water enhancements
-	Optimized reformer furnaces by improving damper and excess oxygen control


notes:
Due to a 2009 explosion at the refinery, the refinery was operating just the No.1 Crude Unit and Vacuum Unit during 2010. Data in report reflects only No.1 Crude Unit and Vacuum Units in operation during 2010.
LDAR data and/or equipment leak data is not provided for units that were not in service during 2010 since these units were gas-free; therefore, no emissions.
Fuel to refinery for 2010 was natural gas only from local natural gas provider, Qwestar. 
No Non-Routine emission events occurred during 2010.
Refinery operates under State of Utah Approval Order DAQE-AN0101240022-09.
The North and South Rail Spurs are used to load heavy products only such as asphalt, wax, VGOs, AGOs, etc.


notes:
Section 3:  Components from the Amine Unit and the Sulfur Treatment Plant are included in the HDS Unit, but the PRDs were separated by unit.  Components in the Truck Loading are included in the Tank Farm                                                                                                                                                                                                                                                    Section 5:  The coke burn-off cycle duration per cycle is listed as 2 hours.                                                                                                                                                                                                                                                    Process Unit Information:  The Vacuum Unit has been shut down since 2007.


legal_operator_name:
Holly Refining & Marketing Company - Woods Cross LLC

energy_management_plan_description:
Regular PMs on all energy consuming equipment, oxygen monitoring optimization of fired heaters/boilers based on excess stack O2, replacement of old motors with high efficiency motors, monitoring/cleaning of crude preheat exchangers, steam trap maintenance

notes:
All employees within the Holly Corporation structure are employed by Holly Logistics Services, LLC, a subsidiary of Holly Corporation, and are not directly employed by Holly Corporation.  Total employees of Holly Logistics Services, LLC are 1,638.
All production shown is from the EIA reports.  Therefore, some cumulative production is shown as less than zero, and percentages of disposition for materials shipped off site are for only that portion of the product that was shipped.
Most actual througputs are taken from the internal accounting system.  SDA throuput came from the process historian.  Straight Run Gas Plant throughput was based on the depentanizer bottoms make, according to the ICR instructions. Rail car unloading was estimated, and tank truck loading was ratioed, based on estimated capacity and the tank car loading throughputs.
2010 fuel consumption was taken directly from EIA reports.
Some information on boiler heat input capacity, steam generating capacity, and percent steam to blowdown could not be found or was not available.  These fields were identified with the code for "unknown" (-99).
For heaters 68H2 and 68H3, the entered data appear to show that the heat input rate for 2010 exceeded the maximum heat capacity.  This is because the ICR program allows entry of the capacity to one decimal place (0.8), whereas it rounds the input rate to a whole number (0.7 is rounded to 1).
Information for light liquid pump seals, gas vapor and light liquid valve counts, and compressor seals are taken from the LDAR Database.  The heavy liquid pump count was taken from a P&ID review.  The heavy liquid valve count was estimated by ratio of (heavy pumps)/(light liquid pumps)*(light liquid valves).  Flanges and connectors were estimated as the total component count multiplied by 2.  All potential OELs are normally plugged and therefore the count of actual OELs is zero, and monitoring is done by observation during component monitoring.  The sampling system count is from the results of a contracted Sample System Comprehensive Review.  Average methane concentration were estimated from predominant streams in various units where data existed as follows:  Unit 4 from 04DEC2OH, Unit 6 from 06STBLZROHG, Unit 7 from 07C4MAKE, Unit 10 from 10SDASOLVENT, Unit 11 from 11DEC2OH, Unit 12 from 12STBLROH, Unit 13 from 13STBLZROHG, Unit 20 from 20_STRIPOHGAS, and Units 16, 17, 21 and 51 from Fuel Gas.
Leak definitions and monitoring frequencies vary within units, depending on applicable regulations.  The most common leak definitions and monitoring frequencies are provided for each unit.
Atmospheric pressure relief devices are monitored after a release.
Only VOC measured in wastewater is Benzene.  Data is from the 2010 BWON TAB.
BWON tested Tank draw downs from tanks 129, 101, 102, 121, 126, 132, 145, 128, 100, 104, 105, 107, 135, 146, 106, 109, 131, 108, 323, 72, 71, and 166.
Loading of product from Unit 45 is handled in Unit 87.
THC emissions reported as VOC.


notes:
Western Refining Yorktown Inc. Notes 

Part 1

General 
•Information was provided in the form 810.
•Contacts were provided by Bonnie McMichael
•Refinery Type was provided by William Hogge.
•Production numbers for each month were provided in the 810.
•11.  $8,070,110,000: "Revenue is for all refineries."
•December 31,2010- 44 Employees-  Typical operations there are 245 employees
•13(b)(iii).  " Western Refining Yorktown, Inc. and Western Refining Southwest, Inc. are separate companies with separate boards of directors."
•Process unit throughput was based on normal operations at capacity before idling.
Section 2
1-Energy Management-
•Steam information provided by William Hogge, and Tom Pastella.
•Information for fuel consumption provided by the PUMs and Energy Reports, to calculate normal operations for the year from monthly averages from January through August.(fuel consumption *(12/8)= Total Consumption)
2-Process heaters-
•The heater hours provided were the times that the units ran during 2010 (facility went idle in September). Units percentages were calculated while refinery was in full operation through August.  (Direction from EPA phone conversation )
•Information taken from SOI, training manuals and from William Hogge.
3-  LDAR-
•All information was provided by LDAR and PRV spreadsheets, and the LDAR plan from Bonnie McMichael
•Treating and Product blending were combined into oil movements total components.
•GTU and SRU components are together and listed under the SRU because data for the PRDs are available only for the SRU.
•Natural gas component estimate for process heaters and boilers is on average 5 per piece of equipment for process heaters and boilers.  Provided by Jane Kelley.
•Refinery fuel gas valves were subtracted from the total number of components to calculate the process unit valves only. 
4- Storage tanks-
•This information was pulled from numerous record keeping environmental and engineering spreadsheets. (Master tanks list)
• Information that is not provided is assumed to be unrecorded.
Section 5 Catalytic Cracking Unit-
•Information provided by William Hogge and Wanda Stevens.
•E-cat data used from contractor excel database.
Section 6  Fluid Coking-  (is not performed at Western Refining Yorktown)
Section 7 Delayed Coking Units-
•Information provided by William Hogge and Wanda Stevens.
Section 8 Catalytic Reforming Units-
•Information provided by William Hogge and Jane Kelley.
Section 9 Sulfur Recovery Units-
•Information provided by William Hogge , Tom Pastella and Keith Mishoe.

Section 10 Hydrogen Plant Vents-
•Information provided by William Hogge , Tom Pastella and Keith Mishoe.
Section 11 Other Atmospheric Vents- general flare, sulfur shedding, management plan
•Information provided by Bonnie McMichael.
•All components associated with the COMBO were attributed to the FCCU
Section 12 Flares-
•Information provided by various facility personnel
Section 13 Fuel Gas Treatment Units-
•Information provided by William Hogge , Tom Pastella and Keith Mishoe 
Section 14 Exchange Systems-
•Information provided by various facility personnel

Section 15 Wastewater Collection and Treatment-
•Information provided by various facility personnel

Section 16 Product Loading Operations-
•Iformation provided by various facility personnel

Part III-
Non- Routine Emissions
•Taken from various CEMs reports for the year

Part IV- Cost Data (optional)  not preformed

Part V- Emissions Monitoring and Source Test Data


energy_management_plan_description:
Heaters Oxygen, steam trap program, sootblower surveys, flare minimization, sour water monitoring, EII calculation


notes:
Process Heater ID corresponds to emission unit ID used in WEDs report.  

SRU consists of two parallel 3-stage Claus plants.  All sour gas combines to one knockout drum and combined feed splits to both SRU trains.  Either Claus plant can be lined to either tail gas unit or both Claus plants can be lined to #1 TGU.  

For Startup/shutdown non-routine emissions, the date in which the non-routine emissions started is listed.  The quantity of emissions reported represents the total pollutant emissions over the course of the entire period between shutdown and startup.


plant_name:
Shell Oil Products US- Puget Sound Refinery

energy_management_plan_description:
PSR strives to improve site energy performance through  projects, operational excellence--monitoring and optimizing process unit energy targets, and a highly reliable focused maintenance approach to our equipment.

notes:
Part 1: General Facility Information
Puget Sound does not have a specific D&B number- used the parent company D&B number.
Annual revenue is for parent company (includes Shell Pipeline as well).
Number of employees is estimated.
Due to inconsistencies in the EIA-810 reports, products produced information is from Solomon study.
Process units based on Solomon study and Title V air permit.
Crude, Vacuum, DCU, FCCU, Poly, BHU, Nonene capacities from Solomon study. The remainder are from process engineers.
Steam consumption was not available for some individual units and some units could not be split out (eg CRU1/ISOM, Alky1/Nonene/BHU, Utilities/RPS/EP/Dock/Rail Rack/Truck Rack, FCCU/FCCU Fuel Gas, HTU1/HTU1 Fuel Gas, HTU2/HTU2 Fuel Gas, HTU3/HTU3 Fuel Gas, Crude/Vacuum Tower). 
Part 2 Section 1: Energy Management
Fuel consumption from Solomon study.
Part 2 Section 2: Process Heaters
No comments
Part 2 Section 3: Equipment Leaks
Component counts for Fuel gas systems are based on reasonable estimates. Counts of heavy liquid components (valves, pumps, and connectors) are based on estimates. Sample station numbers are based on reasonable estimates based on sample station survey. No OELs were reported in 2010. Components in Utilities, Cogen, and Flare are included in Fuel gas component counts.
Methane concentration is process gases (non-fuel gas) are unknown- no reasonable estimates exist.
PRD quantities are based on reasonable estimates as a definitive count does not exists. Could not determine the number of PRD in BHU, ISOM, Nonene, and Rail Rack units. Alky1 PRDs include Nonene and BHU PRDs. CRU-1 PRDs include ISOM PRDs. 
Part 2 Section 4: Storage Tanks
Vapor Pressure was estimated for butane, propane, and isobutane.
Bullet style tanks have length listed in the height field. Sphere are listed by diameter. Throughputs were not available for some tanks.
Part 2 Section 5: Catalytic Cracking Units
Recycle mode is typically only used during startup or upsets- not normal operation.
Part 2 Section 6: Fluid Coking Units
Not applicable
Part 2 Section 7: Delayed Coking Units
DCU composition information from Solomon study.
Part 2 Section 8: Catalytic Reforming Units
No comments
Part 2 Section 9: Sulfur Recovery Units
SRU-3  does not have a sulfur pit. Sulfur is stored in tanks. Tank vents are educted into the base of the SRU-3 incinerator.
SRU-4 sulfur pit vents are educted into the SRU-4 incinerator.
SRU-3 and SRU-4 share common feed headers.
Part 2 Section 10: Hydrogen Plant Vents
Not applicable
Part 2 Section 11: Other atmospheric vents
Vents are listed by analyzer shelter location. There may be multiple analyzers sharing a common vent.
Analyzer vents can generally be routed to the flare or to atmosphere. No controls were identified due to this configuration.
Part 2 Section 12: Flares
Flare gas heating value is estimated based on fuel gas heating value. Flares typically combust gas only during startup, shutdown, or malfunction but there are occasions where waste gas from normal operation is combusted.
Part 2 Section 13: Fuel Gas Treatment
No comments
Part 2 Section 14: Heat Exchange Systems
Chemical addition rate for MPCC cooling tower is not available.
Part 2 Section 15: Waste Water Treatment
Average benzene concentration is estimate based on 2010 TAB. Average HAP and VOC concentrations were estimated from the benzene concentration using a scaling factor which was derived from the Treatment Efficiency Study. No sample data other than the Treatment Efficiency Study was available to provide estimates.
Wastewater vent include vents on the collection system and the primary treatment plant.
Part 2 Section 16: Loading operations
Loading hours were estimated.
Part 3: Non routine emissions
Data from monthly NWCAA reports.
Part 4: Cost Data
Optional- Not applicable
Part 5: Emissions monitoring and Source Test Data
CEMS and CMS data in Excel file.


notes:
General Comments
The Tesoro Anacortes Refinery was shut down for several months during 2010. Therefore, much of the process operating data reported in this ICR is unrepresentative in comparison to normal operation. 
In addition to using "-99" to indicate "unknown" per EPA's suggestion, Anacortes Refinery has elected to use "-88" to indicate "not applicable" and "-90" to indicate CBI.
Where Tesoro has determined that a drop-down field is entitled to confidential treatment, Tesoro has intentionally left that drop-down field blank in its Non-CBI submittal, i.e., Database Version 3, to reflect CBI claim.
When asked to provide "State, local, or Tribal air regulation(s)", Anacortes Refinery has elected to reference its Air Operating Permit ("AOP") filed with the Northwest Clean Air Agency, dated January 26, 2010, rather than list individual regulations. Section 4 of the AOP lists Generally Applicable Requirements. Section 5 of the AOP lists Specifically Applicable Requirements. Section 6 lists Common Requirements. Due to the general nature of this reference, there could be some cross-references that are not applicable.
The Unit Throughput Capacity reported in Part I Process Units Tab for the RFGB is based upon the rated capacity of our Amine 1 and Amine 2 treatment units. Steam consumption data reported in the same section is based upon steam used at the amine regen. Other data reported in Part II Section 13 on RFGB is based on the outlet of the refinery fuel gas blend drum (V-213).
The Tank Farm and Flares units are declared as units solely to ensure that all of the LDAR components are reported in Part II Section 3, therefore only readily available information is included.
Part I. Process Units Tab. The Tesoro Anacortes Refinery was shut down for several months during 2010 after a fire at one the processing units. Therefore, much of the process operating data reported in this ICR is unrepresentative in comparison to normal operation. Tesoro has provided an estimate of the expected “normal” 2010 processing rates in the enclosed DVD labeled “Confidential Business Information”, and is identified electronically as"Contains_CBI_Tesoro_Anacortes_2010_throughputs_if_ normal.pdf".
Part I. General Tab. Annual Revenue in 2010. Tesoro has provided the total combined annual revenue for all of its facilities in operation in the USA.
Part I. Products Produced Tab. Percentages of disposition of products by transport method are the percent of 2010 production shipped. The percentages do not include the existing inventories/receipts that were also shipped during 2010.
Part I. Process Units Tab. CCU Unit Throughput Capacity. (1) Total CCU Feed Capacity is equal to the Solomon capacity. Total CCU Feed Capacity in industry is Fresh Feed Capacity. Therefore the same number is being reported for Part I and for Part II Section 5 (see additional notes below). (2) Recycle Capacity is not included in Total CCU Feed Capacity. 
Part I. Process Units Tab. WWT Unit. Steam Consumption in 2010 excludes steam reported in Part II Section 15 for the sour water stripper.
Part II Section 1. 2010 Fuel Consumption Tab. Other - Gas (MMcf) reported is propane.
Part II Section 1. Energy Management Plan Tab. While the Anacortes Refinery does not have a formalized energy management plan, the refinery practices good energy management through various practices and procedures, including but not limited to efficient furnace operations, steam trap management, heat integration, and other various process control parameters. 
Part II Section 2. General Tab. Rated Heat Input Capacity excludes pilot gas heat input.
Part II Section 2. General Tab. Average Heat Input Rate in 2010 is the average of operating days, not calendar days. Average Heat Input Rate excludes pilot gas heat input.
Part II Section 3. Facility-Level Questions. Tesoro does not own or have ready access to optical or thermal imaging devices for detecting leaks.
Part II Section 3. Process Units. All Units. In its LDAR database, the Anacortes Refinery tracks components which service gas/vapor, light liquid/gas, and light liquid. For this ICR, Anacortes has included valves which service light liquid/gas as "Gas" and pumps which are in light liquid/gas service as "Light Liquid".
Part II Section 3. Process Units. All Units. Anacortes is not required by State or Federal requirements to monitor heavy liquid components. The data submitted includes a combination of actual component counts and estimates developed for the purpose of responding to this ICR.
Part II Section 3. Process Units. All Units. LDAR Tab. The average methane content will vary significantly across the process units and is difficult to estimate. Therefore, Tesoro does not monitored methane content in the facility.
Part II Section 3. Process Units. All Units. LDAR Tab. Pump Seals Tab. Tesoro has identified the number of light and heavy liquid pumps, not the number of pump seals. In addition to monthly monitoring via Method 21, Tesoro sensory monitors its pumps weekly.
Part II Section 3. Process Units. All Units. LDAR Tab. Open-ended Lines Tab. For purposes of this response, Tesoro will define “open ended line” as it is defined in the NSPS. Under NSPS, open-ended line (“OEL”) “means any valve, except safety relief valves, having one side of the valve seat in contact with process fluid and one side open to the atmosphere, either directly or through open piping.” Throughout 2010, Tesoro had no equipment designed or operating as an OEL. For regulated valves that are otherwise open to the atmosphere, Tesoro meets the NSPS by applying a cap, blind flange, plug, or second valve, which effectively changes the design to no longer meet the OEL definition. If the cap, blind flange, plug, or second valve is found to not be properly installed, the refinery takes steps to replace it. In 2010 there were no instances of OELs during our routine auditing.
Part II Section 3. Process Units. All Units. LDAR Tab. Compressor Seals Tab. Tesoro has indicated the number of compressors, not the number of compressor seals. For monitored compressors a reading greater than 10,000 ppm or a seal system failure constitutes a leak.
Part II Section 3. Process Units. All Units. PRD Tab. The total number of PRDs includes all rupture disks separately from PSVs, even when a rupture disk and PSV work in combination. (e.g. CU: Where 5 of 6 atmospheric PSVs have RDs, Tesoro  considers the total number of PRDs to be 11)
Part II Section 3. Process Units. All Units. PRD Tab. Atmospheric PRD Tabs. In addition to Method 21 monitoring after releases, PSVs are sensory monitored after releases.
Part II Section 3. Process Units. All Units. PRD Tab. Atmospheric PRD Tabs. Tesoro does not have a specialized system to monitor measured flow rate specific to PRD monitoring.
Part II Section 3. Process Units. RFGB Unit. LDAR Tab. Pump Seals Tab. Two leak definitions apply. Majority of pumps have a leak definition of 10,000 ppmv (Amine 1). Others have a leak definition of 2,000 ppmv (Amine 2).
Part II Section 3. Process Units. RFGB Unit. LDAR Tab. Valves - Gas Tab. Two leak definitions apply. About half of the valves have a leak definition of 10,000 ppmv (Amine 1). Others have a leak definition of 500 ppmv (Amine 2).
Part II Section 3. Gas Systems. No fuel gas/natural gas information is included since no data is available.
Part II Section 4. Tesoro has not included information for spheres or pressurized tanks used for storage of compressed Propane and Butane.
Part II Section 4. All Tanks. General Tab. Tesoro’s tank throughput is based on change in tank levels as used in Emissions Inventory Calculations.
Part II Section 4. All Tanks. Tanks with EFR or IFR Tab. Unit of measure for "Minimum height of floating roof above floor at shell when landed" is ft.
Part II Section 4. TK 89. Tanks with EFR or IFR Tab. Type of Primary Rim Seal is -99 (unknown).
Part II Section 5. General Tab. Calendar day averages may be unrepresentative of normal operation due to the CCU being down several months during 2010.
Part II Section 5. General Tab. (1) Total CCU Feed Capacity is equal to the Solomon capacity. Total CCU Feed Capacity in industry is Fresh Feed Capacity. Therefore the same number is being reported for Part I and for Part II Section 5. (2) Recycle Capacity is not included in Total CCU Feed Capacity. (3) The reported Recycle Capacity does not include Resid Capacity. Resid Capacity is included in the Fresh Feed Capacity. (4) Recycle Rate Capacity fluctuates broadly based upon total CCU Feed Rate.
Part II Section 6. This section is not applicable; the Anacortes Refinery does not operate a Fluid Coking Unit.
Part II Section 7. This section is not applicable; the Anacortes Refinery does not operate a Delayed Coking Unit.
Part II Section 8. General Tab. Tesoro has provided the UOM for the reported Hydrogen Production Rate as MMscf/cd (a calendar day average), which is unrepresentative because this process unit was down for several months in 2010.
Part II Section 8. General Tab. Operating Pressure: Tesoro is reporting the average reactor pressure [i.e., (Lead + Lag) ÷ 2]. 
Part II Section 8. General (cont.) Tab. The UOM for the Coke Burn-off Cycle Duration per Cycle is hr per burn per reactor.
Part II Section 9. This section is not applicable; the Anacortes Refinery does not operate a sulfur recovery unit.
Part II Section 10. This section is not applicable; the Anacortes Refinery does not operate a Hydrogen Plant.
Part II Section 11. Tesoro did not include in its response to the ICR vents to atmosphere associated with routine intermittent sampling.
Part II Section 12. While the Anacortes Refinery does not have a formalized flare management plan, the refinery minimizes flaring as a good business practice. Flaring events are quickly assessed and appropriately mitigated.
Part II Section 13. Annual average H2S concentration is measured at the outlet of the refinery fuel gas blender (V-213). The only fuel gas atmospheric vents that Tesoro is aware of are associated with operating the H2S analyzers.
Part II Section 13. General Tab. Average fuel gas flow rate into the treatment unit calculated at STP 60 degrees F and 14.7 psia. 
Part II Section 14. All Heat Exchange Systems. General Tab. In addition to a disinfectant, the Anacortes Refinery has a cooling water corrosion and scale inhibitor program. 
Part II Section 15. Facility Level Questions. Average VOC Content of Wastewater Generated via Tank Draw Downs: Tesoro has not analyzed VOC concentration (ppmw) and does not have a good method for estimating the value.  As a result, Tesoro has reported "Unknown". 
Part III. Tesoro will meet this requirement by submitting all agency reportable emissions that occurred during periods of startup/shutdown and component malfunction for the year 2010.
Part IV. The Tesoro Anacortes Refinery has elected not to include any cost data.
Part V. Tesoro will submit data for all CEMS that fall under the purview of Federal regulations. Quality assurance reports, e.g. RATAs and CGAs, are not included in Tesoro's ICR response.


notes:
ConocoPhillips Ferndale Refinery
Facility ID number: WA5A140
Refinery ICR Component 1 Notes

- Part 1, Question 11: This represents ConocoPhillips 2010 US R&M revenue.

- Part 1, Question 13b: Although this question is somewhat incomprehensible to ConocoPhillips in that the "facility" does not have a Board of Directors and for other reasons, we believe that this statement "best" applies of the three statements offered.

- Part 1, Question 15: Cumulative 2010 production, % used onsite, % shipped by tank ship, % shipped by barge, % shipped by rail car and % shipped by pipeline considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 1, Question 16: Unit Actual Throughput considered CONFIDENTIAL BUSINESS INFORMATION. Amine capacities in MMSCFD.  WWTP capacity in MMGal/day. Tank Farm Unit ID consists of storage tanks and offsites areas not otherwise listed. Boilers Unit ID contains steam generation equipment. Ambient Unit ID is the ambient met station.

- Part 2, Table 1-1: Fuel consumption considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Question 3: Hydrogen purchased considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Question 4: Brief description of Energy Management Plan: The Refinery has a robust plan that includes on-going monthly tracking of site-wide energy efficiency, an energy performance checklist used for projects, fired heater oxygen management, steam trap repair program, steam leak repair program, heat exchanger cleaning, waste heat steam generation, and systems to recovery excess gases (flare gas recovery). The Refinery also has a long term program to identify energy efficiency opportunities and implement those projects in the coming years.

- Part 2, Table 1-2: Air Preheat use, air preheat temperature, disposition of electricity, steam pressure, disposition of steam and precent steam to blowdown considered CONFIDENTIAL BUSINESS INFORMATION. Waste heat generators do not have heat input capacity nor steam generating capacity.

- Part 2, Table 1-3: Steam consumption for processing considered CONFIDENTIAL BUSINESS INFORMATION. These are net values. Database requires on a unit basis "Steam consumption for the processing unit in 2010 (tons/yr)", the EPA extraction tool gives this data a heading of "steam_demand_at_capacity" which is not was requested in the database. Ferndale has provided actual steam consumption for 2010.

- Part 2, Table 2-1: Avg heat input rate, total operating hours, air preheat use, typical air preheat temperature, other efficiency measures, % total operating hrs fired on primary fuel, % total operating hrs fired on secondary fuel, operating hrs fired <25% of capacity and operating hrs fired between 25% and 50% considered CONFIDENTIAL BUSINESS INFORMATION.  Due to the current stay of 40 CFR 63 Subpart DDDDD, this rule was not consideed for possible applicability.

- Part 2, Table 3-1: These are not actual counts of OELs.  OEL components are estimated via the Emissions Estimation Protocol for Petroleum Refineries Table 2-5. All heavy liquid pump, valve and connector counts are estimated.

- Part 2, Table 3-2: Number of components in natural gas service are estimated.

- Part 2, Table 3-3: Total number of PRD, number of controlled gas PRD, number of controlled liquid PRD, number of atmospheric gas PRD, number of atmospheric gas PRD with rupture disk, number of atmospheric liquid PRD and number of atmospheric liquid PRD with rupture disk are considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Question 2a and 2b: quantity of unstabilized crude oil and pressure considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Table 4-1: Total throughput, year tank last degassed and year anticipated for next degassing considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Table 5-1: CCU feed capacity, recycle/resid capacity, % hydrotreated feed, typical coke burn rate, weighted averge sulfur, weighted average nickel, weighted average vanadium considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Table 8-1: Operating pressure, Hydrogen production rate, average annual regeneration frequency, average annual regeneration time, depressure/purge cycle vent disposition control, purge process type, coke burn off cycle vent disposition/control, coke burn off cycle duration, rejuvenation cycle vent disposition/control, reduction or activation cycle vent disposition/control considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 2, Table 14-1: Chemical Disinfection Method - multiple disinfection methods are used with Sodium Hypochlorite as primary method.

- Part 2, Section 15, Questions 3(c): no VOC data available.

- Part 2, Table 15-2: no HAP or VOC data available.

- Part 2, Table 16-1: Type of control device or control technique is based on the highest level of control available - thermal oxidizer for the clean truck loading and vapor balancing for the LPG rail car loading.

- Part 4, Table 1: Demolition cost, primary equipment cost, auxiliary equipment cost, instrumentation & monitor cost, sales tax and freight costs, total purchased equipment costs, installation costs, total installed cost, operating labor cost, maintenance labor cost, electricity cost, water cost, steam cost, liquid chemical cost, solid chemical cost, compressed air cost, other costs, total utility costs, waste disposal cost, supplies and parts replacement costs, other annual costs and total operating and maintenance costs considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 4, Table 2: Number of days process shutdown, total capital costs and change in total annual operating costs considered CONFIDENTIAL BUSINESS INFORMATION.

- Part 5: For CEMS and CMS data, daily production/throughput rate (value) and daily production/throughput rate (units) considered CONFIDENTIAL BUSINESS INFORMATION.


notes:
For Part 1, Parent Company Tab - Astra West Coast Refining, Inc. (AWCR) is essentially a holding company.  There are five members of the Board of Directors for U.S. Oil & Refining Co. (USOR) with three of its members from outside the Astra organization, USOR’s CEO, and the Chairman of the Board who represents the interest of AWCR.  Although USOR is operated fairly independently from other Astra entities, it does have limited access to additional working capital within the greater Astra group.

For Part 1, Process Units Tab - 
During 2010, USOR underwent a refinery wide turnround, which involved shutting down many of the process units identified within this tab for over a month.  The following provides an estimate of the expected “normal” 2010 processing rates for those units whose processing rates were impacted by this refinery wide turnaround.

Unit ID (Normal Process Unit Throughput)

LCU  (32,817 bbl/cd)
LCVU  (4,957 bbl/cd)
CRU1 REF  (1,819 bbl/cd)
CRU2 REF  (2,317 bbl/cd)
CRU1 PT  (2,956 bbl/cd)
CRU2 PT  (4,056 bbl/cd)
DHU  (5,364 bbl/cd)
ISOM  (2,781 bbl/cd)
SRU2  (4.3  LT/cd)
LPG  (949 bbl/cd)
FGTU1  (4.7  MMcf/cd)
TKG  (81,590 bbl/cd)

For Part II - It is important to note that the prevention/cleanup of liquid releases (light liquids as well as heavy liquids) for the various equipment sections discussed in this Part are further regulated by the following federal and Washington state regulations:  40 CFR Part 112, 33 CFR Parts 154 and 156, 49 CFR Part 194 and WAC 173-182.

For Part II, Section 2 Process Heaters - During September/October 2010, the existing H-901 (identified as H-901 old) with a rated heat input capacity of 9.8 MMBtu/hr was replaced with a new H-901 (identified as H-901 new), which has a rated heat input capacity of 17.8 MMBtu/hr.

For Part II, Section 3 Equipment Leaks/Process Units - The average methane concentration in process fluid that contains equipment in gas service throughout the process units is estimated to be less than 0.1%.  Units that do not have an entry in this section do not contain equipment in gas service.

For Part II, Section 3 Equipment Leaks/Gas Systems - The values listed for average methane concentration in process fluid refer to methane concentrations in the refinery fuel gas and natural gas systems.

For Part II, Section 3 Equipment Leaks - Note that the components counts for the FGTU1 Unit are included in the Gas Unit, Refinery Fuel Gas.

For Part II, Section 4 Storage Tanks - Tanks that do not have a "last year degassed" entry
are new and have not had a first degassing/cleaning at this point in time. 

For Part II, Section 5 Catalytic Cracking Units - Note that U.S. Oil does not have a catalytic cracking unit.

For Part II, Section 6 Fluid Coking Units - Note that U.S. Oil does not have a fluid coking unit.

For Part II, Section 7 Delayed Coking Units - Note that U.S. Oil does not have a delayed cokiing unit.

For Part II, Sections 8 Catalytic Reforming Units - The pressures indicated refer to the operating pressure at the first reactor.

For Part II, Section 9 Sulfur Recovery Units - Note that U.S. Oil does not have any sulfur storage pits.  Sulfur is stored in storage vessels.

For Part II, Section 10 Hydrogen Plants - Note that U.S. Oil does not have a hydrogen plant.

For Part II, Section 12 Flare - Only process waste gas is flared during a process upset.  The typical lower heating value of the waste gas can vary because the flow can be from many sources and is of variable composition.

For Part II, Section 14 Heat Exchange Systems - Note that U.S. Oil adds a solution of sodium bromide to the cooling water to allow chlorine usage to be minimized.

For Part II, Section 15 Wastewater (Part a) - The estimated VOC concentration in waterdraw waste was based on the data available, which only included benzene, toluene, ethylbenzene, and xylene.

For Part II, Section 15 Wastewater (Part a) - Note that the wastewater system, including effluent discharge from the primary clarifier are regulated by NPDES discharge permit as per applicable federal and state regulations.

For Part III Non-Routine Emissions - See Attachment #1 for additional information on the non-routine releases identified in this part.

For Part IV APCD - The asphalt mist eliminator identified in this part has no specific operating costs since this unit has an interlock whereby it automatically starts when the liquid asphalt loading pumps are starts and continues to operate for several minutes after the liquid asphalt loading pumps are shut off.  During the asphalt railcar loading operation, the operator briefly inspects the asphalt mist eliminator to ensure that it is operating properly.  This asphalt mist eliminator currently serves the loading of a single grade of asphalt onto railcars.

For Part IV Cost Data for Process and Equipment Changes - The pressure/vacuum vent identified in this part were installed as part of a BACT determination as part of a 40 CFR 60 Subpart QQQ applicability determination.  The relief settings for these vents were set at 0.5 oz/in2 for both the pressure and vacuum settings.  These vents are removed, inspected and repaired once every 5 years.


notes:
All Parts and Sections – We have used the following codes throughout the database to represent information that is not applicable or unknown:
•	“-88” = Not applicable
•	“-99” = Unknown

Part I, Process Units – Steam consumption for individual refinery process units is not available but was approximated from 2010 total facility steam usage and an estimated steam balance.

Part II, Section 1: Energy Management – The values reported on form EIA-810 generated by corporate does not necessarily line up with the values in the facility’s records.  As an example, the facility records indicate 148 bbl propane used in 2010 and the EIA-810 lists 0 bbl propane used.  We have included values as listed on the EIA-810 report to be consistent with ICR instructions.

Part II, Section 2: Process Heaters - Heaters 24-H1, 24-H2, 24-H3, and 24-H4 share a common gas flow meter.  Individual usage for these heaters was determined based on the ratio of the individual heater's input capacity HHV to the combined heaters capacity, multiplied by the total heat input for all four heaters.

Part II, Section 2: Process Heaters – Regulatory applicability listed is as of December 31, 2010.

Part II, Section 2: Process Heaters – 2010 Heater usage, including: average heat input rate, operating hours less than 25% of rated capacity, and operating hours at 25-50% of rated capacity, was calculated in the following manner for most heaters: 
Fuel gas chromatograph data was collected for the year of 2010. Using the chromatograph data a heating value was calculated for the fuel gas (HHV was used for all the following calculations). 
- Most heaters are equipped with fuel gas flowmeters, this data is collected in the form of 24 hour averages. This data is kept for 1 month and if that data is not copied to another location, it is replaced with new data. As such, data that was not copied is lost. The majority of the heaters are monitored in the unit mass balances. From this recorded data firing duties were calculated using the fuel gas flowrate and higher heating value. 
This analysis was not possible for several heaters.  In these instances the following was done: 
•	Benzene Splitter Reboiler 93-H1: Daily charge rates to the heater were obtained from the Operator Logsheet. Using these daily charge rates and average inlet and outlet temperatures a Technical Services chemical engineer constructed a simulation of the heater to obtain the required duty. While 2010 heater efficiency data was not available, the engineer was able to use 2011 average efficiency data to estimate the actual firing of the heater for 2010. 
•	#1 HB Charge Heater Pre TA 5P-H4:  Fuel gas data for the heater post TA was seen to be unreliable as the meter read a fuel gas rate that was less than 1% of the maximum heater duty. Again, a Technical Services chemical engineer constructed a simulation similar to the Benzene Splitter Reboiler. With this simulation data, the engineer was able to obtain a MMBTU/HR/BPD parameter for determining heater firing rates. 
•	#1 HB Charge Heater post Turn Around (TA) for 95-H2:  Fuel gas data for the heater post TA was seen to be unreliable as the meter read a constant fuel gas rate despite swings in unit charge rates. When 5P-H4 was replaced with 95-H2 in 2010, Burns and McDonnell provided a Heat and Material Balances for the No. 1 HB. Using the enthalpy change across the heater and the design flow rate, a MMBTU/HR/BPD parameter was obtained. With this parameter, and average heater efficiency and reliable unit charge rate data, the engineer was able to develop daily firing rates. 
•	#2 HB Charge Heater 5P-H6:  Fuel gas data for the heater was found to be unreliable as it read a constant value for the majority of the year. As such the Heat and Material Balances from PCI Engineers, Inc. was used to determine the MMBTU/HR/BBL parameter. With this parameter and reliable unit charge rate data a MMBTU/HR value the Technical Services chemical engineer was able to calculate the heater firing rates.

Part II, Section 3: Equipment Leaks - #1 Hydrobon operates primarily in heavy liquid service (Kerosene hydrotreater); however, the unit can operate in light liquid service (Naphtha hydrotreater). There are 192 light liquid valves that are listed as out of service (OOS) with a reason of “#1 Hydro operating in distillate service”.  There are 5 light liquid pumps that are listed as out of service (OOS) with a reason of “#1 Hydro operating in distillate service”.  #1 DUF operates primarily in heavy liquid service; however, the unit can operate in light liquid service (Light Straight Run). There are 3 light liquid pumps that are listed as out of service with a reason of “#1 DUF operating in distillate service”.  There are 5 gas valves that are listed as out of service with a reason of “#1 DUF operating in distillate service”.  There are 100 light liquid valves that are listed as out of service with a reason of “#1 DUF operating in distillate service).

Part II, Section 3: Equipment Leaks – All DEA (Heavy Liquid) components are subtracted from their respective unit and accounted for in the Amine System.  Flare components for the #1 / #2 Hydrobon, #2 DUF, and Benzene Splitter are separated out.  For all other units, the flare components are included in the unit’s component count.  Asphalt Truck Load & Asphalt Rail Loading: Tank and conveyance piping components are included in the Asphalt Truck Loading count.  Truck Rack Loading, Fuel Oil Rail Loading, and Distillate Rail Loading: Tank and conveyance piping components are included in Truck Rack Loading count.  Connector counts are derived by multiplying the number of components by a connector factor of 2.5.

Part II, Section 4: Storage Tanks - For EFRT/IFRT the minimum height floating roof above floor at the shell when landed is provided in feet. 

Part II, Section 12: Flares – “Waste gas” for reporting the typical LHV of waste gas was interpreted as being refinery flare header sweep gas.  The sweep gas is primarily composed of natural gas and, therefore, the LHV was estimated to be 910 Btu/scf.    

Part II, Section 13: Fuel Gas Treatment Units - Fuel gas flow rate at treatment unit capacity and 2010 average fuel gas flow rate into the treatment unit are estimated values.

Part II, Section 15: Wastewater Collection & Treatment – NSPS QQQ is an applicable requirement to the refinery, but controls for QQQ are only applicable to GGU, benzene splitter, and portions of the WWTP.

Part III: Non-Routine Emissions - Emissions listed for this exercise are total emissions for each event, not just excess emissions.  Events not included in this listing are as follows:
•	H2S monitoring plan events.  These events do not produce excess emissions.  
•	Title V permit conditional deviations for which there are no quantifiable emissions on a mass basis (e.g. TGTU Incinerator Temperature < 1180 for SO2 Limit; FCCU Flue Gas Stack opacity >20%; etc.).  Sulfur compound emissions from the sulfur pit are a conditional deviation but calculated emissions from these events are available as of October 30, 2010 so events from that date forward are listed along with the H2S emissions.  
•	Pollutants during an event that do not exceed reporting thresholds are not included.


notes:
The Environmental Staff tasked with the ICR completion are already consumed with keeping the refinery in continuous compliance and maintaining recordkeeping and reporting accurately, which is a full-time job.  Although Environmental personnel have been focusing efforts on data collection and entry for the ICR, this EPA request is a secondary priority to Frontier’s utmost concern of maintaining the Environmental compliance of the refinery.  Therefore, the data provided is the best available response.  

It should be noted that the Cheyenne Refinery has just concluded a large FCCU turnaround and process engineers have not been able to assist with calculating and answering the more tedious questions of the ICR, such as energy management, maintenance oriented and process unit details.  These responses contain approximations and assumptions of the data available.  Some of the requested information was left blank as it was not easily found through research of historical data and design information.

Frontier Refining Inc. assumes that EPA will recognize the limitations of the information provided in the ICR response.  The data provided should be examined understanding the limitations, approximations and assumptions as it could easily be misunderstood or misinterpreted and lead to flawed rulemaking. 


Section 3 - Component counts are based on information taken out of Frontier's LEAKDAS program.  The open-ended lines reported are based on the EPA definition used in this request.  Frontier has identified sampling systems that need to be revised based on the definition.  Other open-ended lines do not exist at the facility because they are immediately corrected upon discovery.  Frontier does not inventory or monitor natural gas as part of the LDAR program, therefore there is no data reported for this section.  The fuel gas systems are accounted for in the various process units and are not separated in our LEAKDAS database.

Section 11 - There are no other atmospheric vents at the facility

Section 12- None of the flares/incinerators at the facility have a target assist ratio as all are designed for smokeless operation

Section 16 - Control devices only apply to gasoline and diesel loading.  All other hydrocarbon products are splash loaded.

Part III - Non routine emissions - Frontier did not have adequate time to manually enter all of the non-routine events for 2010.  Therefore, the database shows the total for all Coker, Crude, FCCU and SRP events.  The dates are arbitrary as it is a sum of all events for the particular unit.  Frontier submitted the CD ROM in the mail titled "emissions part.xls" spreadsheet which has each event broken down with a description of the event, time frame and emissions for the particular event.


notes:
1.  Garco Energy Douglas Refinery operated for only 10 days in 2010 after the facility had been shut down for some time and Garco Energy acquired the facility from the previous owner/operator.  Due to the limited operating time, many of the responses are not know at this time.  These numbers are estimates for 2011 per EPA's request.  Sections 5 - 11, 13-15 do not apply to this facility.  Where questions in applicable sections have been left blank the information is not available.  The facility does not have any CEMS or CMS.  Therefore this section has no response.


notes:
Still Gas is in MMSCF. 
WWT Benzene based on analytical of water at WWT plant, 100 ppmw.


notes:
2010 production rates were lower than a "normal" year as the refinery had two maintenance turnarounds during the year; one turnaround was an extended turnaround lasting approx 4 weeks.  Estimated "normal" production rates for 2010 are shown below:
  Alky - [CBI]
  Crude unit - [CBI]
  FCC - [CBI]
  HDS Unit - [CBI]
  LoCat Unit - [CBI]
  LoCat Unit - [CBI]
  NHT - [CBI]
  Reformer - [CBI]
  Vacuum - [CBI]

Energy Management - Hydrogen purchased.  WRC only purchases hydrogen for use during reformer regeneration.

LDAR - PRD - Gas to Atmosphere - Crude Unit:  WRC connected the 2 PRD in the crude unit to the flare in October 2010 during a major turnaround.

LDAR - PRD - Vaccum Unit:  No PRD listed as none are in VOC/LDAR service.

LDAR - LoCat.  Wyoming Refining Company operates only a single LoCat Unit even though Unit ID has listed LoCat-SRU and LoCat-FGS.  All LDAR information will be located in LoCat-FGS.  Sulfur production is listed using unit ID:  LoCat-SRU.

LDAR - No Data Available for "Average methane concentration in process fluid that contacts equipment in gas service throughout the process (ppmv):" for each LDAR Unit in Section 3. Equipment Leaks - Process Units.  

WRC does not have fluid coking or delayed coking units or hydrogen plant or atmospheric vents other than those listed in the Wastewater Treatment section.


# facility_information_joint_venture_partners

partner_name:
Valero Energy Corporation, a Delaware corporation


partner_name:
Prior to and including June 30, 2011: Marathon Oil Corporation; After June 30, 2011: Marathon Petroleum Company LP.


# federal_regulations_citations

federal_regulation_desc:
Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements            99 Other (specify) 40 CFR Part 60, Subpart GGG


federal_regulation_desc:
- Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGGa)


federal_regulation_desc:
NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)


unit_id:
#1 MEROX Unit              #2 MEROX Unit                    #3 MEROX Unit


federal_regulation_desc:
Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart J)


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Kb)


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Ka)


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart K)


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart Ja)


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart Ja)                                                99 Other - NSPS GGGa LDAR


federal_regulation_desc:
General Provisions (40 CFR part 60, subpart A)


federal_regulation_desc:
General Provisions (40 CFR part 63, subpart A)


federal_regulation_desc:
MON (40 CFR part 63, subpart FFFF) existing source requirements


federal_regulation_desc:
NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa)


federal_regulation_desc:
Other (specify) NSPS GGGa and Refinery Mact


federal_regulation_desc:
Steam Generation NSPS (40 CFR part 60, subpart Dc)


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements


federal_regulation_desc:
Refinery MACT 1 (40 CFR Part 63, subpart CC) existing source requirements


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart UU)


federal_regulation_desc:
BWON (40 CFR 61 Subpart FF), NSPS QQQ (40 CFR 60 Subpart QQQ)


federal_regulation_desc:
BWON (40 CFR 61 Subpart FF), OLD MACT (40 CFR 63 Subpart EEEE)


federal_regulation_desc:
Organic Liquid Distribution MACT (40 CFR part 63, subpart EEEE)


federal_regulation_desc:
Site Remediation MACT (40 CFR 63 Subpart GGGGG)


federal_regulation_desc:
Site Remediation MACT (40 CFR part 63, subpart GGGGG)


federal_regulation_desc:
BWON (40 CFR part 61, subpart FF), Site Remediation MACT (40 CFR part 63, subpart GGGGG)


federal_regulation_desc:
RMACT CC Existing; OLD MACT: 40 CFR 63 Subpart EEEE; SR MACT: 40 CFR 63 Subpart GGGGG


federal_regulation_desc:
OLD MACT: 40 CFR 63 Subpart EEEE; SR MACT: 40 CFR 63 Subpart GGGGG


federal_regulation_desc:
40 CFR 63 Subpart EEEE (Organic Liquid Distribution


federal_regulation_desc:
NSPS 40 CFR 60 Subpart A, NESHAP 40 CFR Part 61 Subpart FF


federal_regulation_desc:
Subject to Refinery NSPS (40 CFR part 60, subpart A), Subject to Refinery NSPS (40 CFR part 60, subpart J)


unit_id:
Fuel Gas Mix Drum, V-475 BTU Analyzer, 04AT821


unit_id:
Fuel Gas Mix Drum, V-701 BTU Analyzer, 97AT913


unit_id:
Fuel Gas Mix Drum, V-870 BTU Analyzer, 15AT072


unit_id:
Oil Mist Lubricating System Vents (Refinery-Wide)


federal_regulation_desc:
NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV)


federal_regulation_desc:
Gasoline Loading NSPS (40 CFR part 60, subpart XX)


federal_regulation_desc:
Other (Refinery NSPS (40 CFR part 60, subpart J)


federal_regulation_desc:
Benzene Waste NESHAP (40 CFR part 61, subpart FF)


unit_id:
Wastewater Junction Box Vents (142 Total)


federal_regulation_desc:
Refinery MACT 1 (40 CFR 63, Subpart CC) existing source requirements


unit_id:
FUEL GAS TREATING SYSTEM (V-1640) SYSTEM


unit_id:
Fuel Storage and Dispensing (Gasoline 15W)


unit_id:
Fuel Storage and Dispensing (Gasoline 16E)


unit_id:
HCU Fuel Gas Treatment (V-1011) Treatment


unit_id:
Other Non Process Units for Equipment Leak Reporting


federal_regulation_desc:
40 CFR 63 Subpart A, 40 CFR 60 Subpart A


unit_id:
(P4S1) Nine-Pos. Asphalt/Fuel Oil Tank Car Loading


unit_id:
(P4S3) Two-Pos. Asphalt Tank Truck - West Loading


unit_id:
(P4S5) Two-Pos. Asphalt/Fuel Oil Tank Truck - East Loading


unit_id:
(P4S7) Single Pos Asphalt Tank Truck Loading


federal_regulation_desc:
Other- MACT (40 CFR part 63, subpart EEEE)


federal_regulation_desc:
Other- NESHAPS (40 CFR part 61, subpart FF)


federal_regulation_desc:
Other- NESHAPS (40 CFR part 61, subpart FF), MACT (40 CFR part 63, subpart EEEE)


federal_regulation_desc:
Other-  NSPS (40 CFR part 60, subpart QQQ), NESHAPS (40 CFR part 61, subpart FF)


federal_regulation_desc:
3    Refinery NSPS (40 CFR part 60, subpart J)


federal_regulation_desc:
Steam Generation NSPS (40 CFR part 60, subpart D)


federal_regulation_desc:
Steam Generation NSPS (40 CFR part 60, subpart Db)


unit_id:
Hiperion Unit with Backup Iron Sponge Towers (399-D-6A/B)


unit_id:
(P8S18) Gasoline Loading Facilities No. 20


unit_id:
(P8S27) Gasoline Tank Truck Loading Rack No. 21


federal_regulation_desc:
CAA section 112(g) and section 112(j) (40 CFR part 63, subpart B)


federal_regulation_desc:
40CFR 61 SUBPART FF, 40 CFR 60 SUBPART QQQ


federal_regulation_desc:
40CFR 61 Subpart FF; 40CFR 60 Subpart QQQ


federal_regulation_desc:
40CFR 60 Subpart QQQ; 40CFR 61 Subpart FF


federal_regulation_desc:
40CFR 61 Subpart FF; 40CFR 60 Subpart QQQ;


unit_id:
Butanes/Butene Tank Truck Loading (D459)


unit_id:
Petroleum Distillate Tank Car Loading (D464)


unit_id:
Spent Sulfuric Acid Tank Truck Loading  (D1380)


unit_id:
Unit 240 Plant 2 G-203A Make Up Compressor


unit_id:
Unit 240 Plant 2 G-203B Make Up Compressor


federal_regulation_desc:
40 CFR 63 Subpart UUU; control device for SRU TGU bypass


federal_regulation_desc:
Title v permit includes MOA for coke storage/handling restrictions


federal_regulation_desc:
Refinery NESHAPS (40 CFR part 61, subpart FF


federal_regulation_desc:
40 CFR part 61 subpart FF, 40 CFR part 60 subpart GGG, 40 CFR part 60 subpart QQQ


federal_regulation_desc:
40 CFR part 61-subpart FF and 40 CFR part 60-subpart GGG


federal_regulation_desc:
40 CFR part 60-subpart GGG, 40 CFR part 61-subpart FF, and 40 CFR part 63-subpart CC


federal_regulation_desc:
40 CFR part 61-subpart FF and 40 CFR part 63-subpart CC


unit_id:
Unit 90 Cooling Water system Unit (90-CT-9000)


unit_id:
Unit 90 Cooling Water system Unit (90-CT-9002)


unit_id:
Unit 90 Cooling Water system Unit (90-CT-9004)


unit_id:
10A069 ( TDC ALA023, 21)  (Alky T-1062 overhead)


unit_id:
10A070 (TDC ALA071,72,73)  (Alky DIB Overhead T-1063)


unit_id:
11A001 (TDC ALA051,52,54)  (Alky R-1060 inlet and outlet)


federal_regulation_desc:
Gasoline Distribution (40 CFR part 63, subpart R)


unit_id:
17A011 (OM 011, 012 VLE and Alky rundown)


unit_id:
1A010 / A111 Jet Distillation (PSA101 / PSA995)


unit_id:
2AT503 Splitter Bottoms (VLA031 / 32 / 34 / 37)


unit_id:
39A0011 (TDC DMA011,12,13) (Dimersol stabilizer overhead T3901)


unit_id:
44A030 (MRU Heartcut tower side/bottom streams)


unit_id:
54A711/712 Sample Recovery Drum (54A711/712 Sample Recovery Drum)


unit_id:
54A711-T DSL Sulfur (54A711-T DSL Sulfur)


unit_id:
5A001 (HCU Heavy Hydrocrakate sample drum)


unit_id:
8A005 (TDC CLA005) (FCCU T-806 H2 scrubber)


unit_id:
8A050 (TDC CLA052)   (FCCU C5 product sulfur recovery tank vent)


unit_id:
8A060 (TDC CLA063)  (FCCU Hcn stribber bottoms T-807A)


unit_id:
D-141 Sample Recovery Drum (1A160 / 170 Sample Recovery Drum)


federal_regulation_desc:
- Refinery MACT 1 (40 CFR part 63, subpart CC)


federal_regulation_desc:
Refinery MACT 2 (40 CFR part 63, subpart UUU)


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) new source requirements


unit_id:
S-227 (C5/Heartcut/Mogas Component Storage Tank/Tk-1741)


federal_regulation_desc:
Other( 40 CFR Part 63 Exemption (63.640(d)(5)))


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC)


federal_regulation_desc:
Other (40 CFR 64: Compliance Assurance Monitoring)


federal_regulation_desc:
40CFR63 Subpart AAAAAAA; 40CFR60 Supart UU


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Ka and Kb)


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Ka and Kb),  40 CFR part 61 supbart BB


federal_regulation_desc:
40 CFR Part 63 Subpart CC and 40 CFR Part 60 Subpart VV


federal_regulation_desc:
40 CFR 63 Subpart CC and 40 CFR 60 Subpart VV


federal_regulation_desc:
40 CFR 60 Subparts J and VV, 40 CFR 63 Subpart CC


federal_regulation_desc:
40 CFR Part 60 (GGG); 40 CFR Part 63 (CC)


unit_id:
One Ten-Cell Induced Draft Cooling Tower


federal_regulation_desc:
40 CFR Part 63 Subpats CC (Group 2 Misc. Vent)


federal_regulation_desc:
Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF)


federal_regulation_desc:
Benzene Operations NESHAP (40 CFR part 61, subpart FF) and Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)


federal_regulation_desc:
Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF) and Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)


federal_regulation_desc:
Benzene Transfer (40 CFR part 61, subpart BB)


federal_regulation_desc:
Other (specify) Title I limit requires HON-equivalent work practices


federal_regulation_desc:
Other (specify) LAER - requires HON-equivalent controls


federal_regulation_desc:
Other (specify) Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF)


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements,


federal_regulation_desc:
Other (specify) Benzene Waste Operation NESHAP (40 CFR part 61, subpart FF)


federal_regulation_desc:
Other (specify) Marine Vessel Loading Operations (40 CFR part 63, subpart Y) existing source requirements


unit_id:
12AI0020; Gasoline Blending (Reid Vapor Pressure)


unit_id:
12AI0060; Gasoline Blending (Synthetic Distillation)


federal_regulation_desc:
Refinery NSPS (40 CFR Part 60, Subpart J)


unit_id:
66AI0010, 67AI0010; Reactor Effluent (O2)


unit_id:
69AI0231,0232; Recycle Gas (H2 Purity/O2)


federal_regulation_desc:
NESHAP for Benzene Waste Operations (40 CFR 61 Subpart BB)


unit_id:
A0285-R1 Caustic and Water Wash Col Gravity


unit_id:
A1129-HC H2 to C4001&C4004 Gravity Analyzer


unit_id:
C17062 N UNIFINER H2 RECYCLE COMP crankcase vent


unit_id:
C17198 VACUUM OVHD VENT GAS COMP crankcase vent


unit_id:
C17199 CRUDE OVHD VAPOR RECOVERY crankcase vent


unit_id:
C68800 HYDROGN MAKEUP RECYCL crankcase vent


unit_id:
C68801 STABILIZER VENT GAS crankcase vent


unit_id:
C69001 BOOSTER COMPRESSOR crankcase vent


unit_id:
C69002 BOOSTER COMPRESSOR crankcase vent


unit_id:
C69031 FLARE GAS RECOVERY crankcase vent


unit_id:
C6967 DES MAKE/RECYCLE COMP crankcase vent


federal_regulation_desc:
NESHAP for Benzene Storage Vessels (40 CFR 61 Subpart Y)


federal_regulation_desc:
40 CFR 60 Subpart QQQ, 40 CFR 61 Subpart FF


federal_regulation_desc:
40 CFR part 60, subpart J and subpart GGG


federal_regulation_desc:
Other NSPS Subpart A & J after CountryMark enters Consent Decree and will be subject to Ja if it comes to pass


federal_regulation_desc:
NSPS Subpart A & J after CountryMark enters Consent Decree and will be subject to Ja if it comes to pass


unit_id:
Naphtha Splitter Reboiler Heater, 900-H1


federal_regulation_desc:
40 CFR Part 63 Subpart DDDDD and Part 60 Subpart Ja


federal_regulation_desc:
NSPS 40 CFR PART 60 SUBPART QQQ FOR CLOSED VENT SYSTEMS


federal_regulation_desc:
OLD MACT (40 CFR part 63, subpart EEEE) and NESHAP Benzene Transfer Operations (40 CFR part 61, subpart BB)


unit_id:
#3 Crude Unit Raw Crude Gravity Analyzer


federal_regulation_desc:
HON (40 CFR part 63, subpart H) existing source requirements


federal_regulation_desc:
1    Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements


federal_regulation_desc:
Other (specify) 40 CFR part 60, subpart Dc 60.48g only


federal_regulation_desc:
HON (40 CFR part 63, subpart H) new source requirements


unit_id:
Deisobutanizer BTMS To ISOBUT Analyzer in BIU (2-027)


unit_id:
H2/HC Ratio N2 Lift Gas Analyzer 2-102-AT-88


unit_id:
HPCCR Heaters 2-102-B-1A, 1B & 1C/D NOx CEM


unit_id:
Moisture Analyzer on HP Seperator Gas 2-102-AT-73


unit_id:
Moisture on H2 Makeup Analyzer 2-035-AIT-3


unit_id:
NIR & Octane Analyzers for Gasoline Blending


unit_id:
Pitch Fuel Gas Drum H2S CEM/BTU Analyzer


unit_id:
Process Gas Hydrogen Analyzer 2-107-AT-7


unit_id:
SDA Heaters 2-31-B1, 2-31-B-2 O2 Analyzers


unit_id:
South Area Fuel Gas Drum H2S CEM/BTU Analyzer


federal_regulation_desc:
Other (specify) 40 CFR 61 Subpart FF, 40 CFR 63 Subpart DD


federal_regulation_desc:
Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements


federal_regulation_desc:
General Provisions (40 CFR part 61, subpart A)


federal_regulation_desc:
40 CFR Part 61 Subpart BB, 40 CFR Part 63 Subpart Y, 40 CFR Part 60 Subpart J


federal_regulation_desc:
40 CFR Part 63 Subpart Y, 40 CFR Part 60 Subpart J


federal_regulation_desc:
Other (3 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG))


unit_id:
108- SOUR CRUDE / REDUCED CRUDE TANK FARM


federal_regulation_desc:
Other (NSPS for Equipment leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)


federal_regulation_desc:
Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Kb) and 1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Kb) and 99 Other (specify) - 40 CFR 61, Subpart FF


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Ka) and 1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Kb), 1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements, and 99 Other (specify) - 40 CFR 61, Subpart FF


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart K) and 1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
NSPS for Storage Vessels (40 CFR part 60, subpart Kb) and and 99 Other (specify) - 40 CFR 61, Subpart FF


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) existing source requirements and 6 NSPS for Storage Vessels (40 CFR part 60, subpart Ka)


federal_regulation_desc:
Other - BWON (40 CFR part 61, subpart FF)


federal_regulation_desc:
Other (40 CFR 63 Subpart CC - modified HON option, 40 CFR 61 Subpart V (as referenced by 40 CFR 61 Subpart J))


federal_regulation_desc:
other (40 CFR 60 Subpart XX, 40 CFR 63 Subpart R)


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart J for SO2 only)


federal_regulation_desc:
Other (Refinery NSPS (40 CFR part 60, subpart J) for Claus 400 only)


federal_regulation_desc:
Other HON (40 CFR part 63, subpart G) existing source


federal_regulation_desc:
Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements                       3 Refinery NSPS (40 CFR part 60, subpart J for SO2 only


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) existing source requirements                                                99 Other HON (40 CFR part 63, subpart G) existing source


federal_regulation_desc:
Other HON (40 CFR part 63, subpart F and G) existing source, NSPS (40 CFR part 60, subpart Kb) existing source


federal_regulation_desc:
Other HON (40 CFR part 63, subpart F and G) existing source


federal_regulation_desc:
Other (specify)-NSPS QQQ (40 CFR part 60, subpart QQQ)


federal_regulation_desc:
Other HON (40 CFR part 63, subpart F and G) existing source, NSPS QQQ (40 CFR part 60, subpart QQQ


federal_regulation_desc:
- Other (40 CFR part 63, subpart Q), 99 - Other (NSR 40 CFR part 51)


federal_regulation_desc:
Other (NESHAPs 40 CFR part 63, subpart CC), (NSR 40 CFR part 51))


federal_regulation_desc:
Other (NESHAPs 40 CFR part 63, subpart CC)


unit_id:
12AI6600 - NOx - Platformer Charge Heater


unit_id:
15AI6631 - NOx - HGO Hydrotreater Charge Heater


federal_regulation_desc:
Other (NESHAPs 40 CFR part 63, subpart CC), (NSR 40 CFR part 51)


unit_id:
210AI0680/0682 - NOx & CO - SCR Outlet - Crude


unit_id:
210AI1516/1518 - CO & NOx - SCR Outlet - Vacuum


unit_id:
210AI2751A, B, C, D, F & G - GC - Crude Stabilizer Bottoms


unit_id:
212AI0508/0510 - NOx & CO - Platformer Heater


unit_id:
215AI1747/1749 - NOx & CO - HCU Fractionator Heater


unit_id:
22AI6026/27 - GC - Sats Gas Plant Depropanizer


unit_id:
243AI0060 - Heat Value - WOBBE - Fuel Gas Mix Drum


unit_id:
26AI3600/6022/23/24/6064 - GC - Gas Con Absorber Spliter Ovhd


unit_id:
26AI3682/83 - GC - Gas Con Debut Overhead


unit_id:
27AI4018 - IC4 - Alky Splitter Side Draw


unit_id:
27AI4031 - NC4 - Alky Splitter Ovhd Product


unit_id:
30AI6012/6013 - NOx & SO2 - FCCU Flue Gas Scrubber Outlet


unit_id:
46AI3611/12 - C2 & C3 - Propylene Splitter Heat Pump


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) existing source requirements                              7 NSPS for Storage Vessels (40 CFR part 60, subpart Kb)                                                          99 Other (specify) 40 CFR 61 NESHAP FF


unit_id:
55AI6118/6679 - NOx - CO - GDU Splitter Reboiler


unit_id:
56AI0583 - Sulfur - Distillate - New Distillate Hydrotreater


federal_regulation_desc:
Other (40 CFR 60.100)                                 99 Other (40 CFR part 63 subpart D)


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) existing source requirements                              99 Other (specify) 40 CFR 61 NESHAPS FF


unit_id:
67AI6045 - Distillation Analyzer - Gasoline Blender 1


unit_id:
67AI6332 - Distillation Analyzer - Gasoline Blender 2


unit_id:
Ballast Water Sump           N of Tk 55-3


unit_id:
Bunker Sump                     NW of Tk 200-5


unit_id:
East of Tank 200-1 FCCU/ALKY Tank Dewatering Sump


unit_id:
Kero Sump                    NW of Tk 150-14


unit_id:
Naphtha Tanks 35-2 and 55-4 Dewatering Sump


unit_id:
NIR Analyzer Sample Pot Vent - Gasoline Blender 1


unit_id:
NIR Analyzer Sample Pot Vent - Gasoline Blender 2


federal_regulation_desc:
40 CFR 61 SUBPART FF; 40 CFR 60 SUBPART QQQ


federal_regulation_desc:
40 CFR 61 SUBPART A; 40 CFR 61 SUBPART FF; 40 CFR 63 SUBPART CC; 40 CFR 64


federal_regulation_desc:
40 CFR 61 SUBPART BB; 40 CFR 63 SUBPART Y; 40 CFR 64


federal_regulation_desc:
40 CFR 61 SUBPART BB; 40 CFR 63 SUBPART Y


unit_id:
Distilling Unit Temporary Cooling Towers (6)


federal_regulation_desc:
40 CFR 60 SUBPART NNN; 40 CFR 63 SUBPART DDDDD


federal_regulation_desc:
40 CFR 60 SUBPART NNN; 40 CFR 63 SUBPART CC; 40 CFR 63 SUBPART DDDDD


federal_regulation_desc:
40 CFR 60 Appendix B; 40 CFR 60 Appendix F; 40 CFR 60 Subpart A; 40 CFR 60 SUBPART NNN; 40 CFR 63 SUBPART DDDDD


federal_regulation_desc:
40 CFR 60 SUBPART Db; 40 CFR 63 SUBPART UUU


federal_regulation_desc:
40 CFR 61 SUBPART J; 40 CFR 61 SUBPART V


federal_regulation_desc:
40 CFR 60 SUBPART QQQ; 40 CFR 61 SUBPART V; 40 CFR 63 SUBPART CC


federal_regulation_desc:
40 CFR 60 SUBPART A; 40 CFR 61 SUBPART A; 40 CFR 61 SUBPART J; 40 CFR 63 SUBPART A; 40 CFR 63 SUBPART YY


federal_regulation_desc:
40 CFR 60 Subpart QQQ, 40 CFR 63 Subpart CC


federal_regulation_desc:
40 CFR 61 Subpart FF, 40 CFR 63 Subparts CC, UUU; 40 CFR 64


unit_id:
C2-Basin #4 - Junction Box in Merox Area (near P-10-060)


unit_id:
C5-Junction box-Sump south of the East Plant Sump


unit_id:
EQT 0004 10-81 - Vacuum No.  2 Heater  F-52-1A


unit_id:
EQT 0005 11-81 - Vacuum No.  2 Heater F-52-1B


unit_id:
EQT 0012 14-81 - Coker No. 1 Heater No.1 F-53-1A


unit_id:
EQT 0014 14-81 - Coker No. 1 Heater No.2 F-53-1B


unit_id:
EQT 0017 16-81 - Coker No. 1 Heater No.3 F-53-1C


unit_id:
EQT 0028 2004-1 - Hydro Treater Heater No. 1 H-60-1


unit_id:
EQT 0031 2004-2 - Hydro Treater Heater No. 2 H-60-2


unit_id:
EQT 0032 2004-3 - Hydro Treater Heater No. 3 H-60-3


unit_id:
EQT 0033 2004-4 - Hydro Treater Heater No. 4 H-60-4


unit_id:
EQT 0052 36-81 - Coker No.1 Heater No.4 F-53-1D


unit_id:
EQT 0089 94-57 Fleet Diesel Storage T-04-23


unit_id:
EQT 0090 94-58 Fleet Gasoline Storage T-04-24


unit_id:
EQT 0094 94-GDU - Low Sulfur Gasoline Unit Heater


unit_id:
EQT0060 6-81  - DHT Stripper Reboiler F-15-05


unit_id:
2-97 (Cooling Water Tower Induced Draft)


federal_regulation_desc:
40 CFR Part 63, Subpart F - 40 CFR Part 63, Subpart G


federal_regulation_desc:
40 CFR part 63, subpart F - 40 CFR part 63, subpart G


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements; 40 CFR Part 63, Subpart QQQ


federal_regulation_desc:
Refienry MACT 1 (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
Refinery MACT 1 (40 CFR, subpart CC) existing source requirements


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements and 40 CFR Part 60, Subpart QQQ


federal_regulation_desc:
40 CFR part 63, subpart F, Subpart H and 40 CFR Part 63, Subpart CC


federal_regulation_desc:
40 CFR part 63, subpart G, 40 CFR part 63, subpart F


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements, 40 CFR Part 63, Subparts F and H


federal_regulation_desc:
40 CFR part 63, subpart F; 40 CFR part 61, subpart J; 40 CFR part 61, subpart V


federal_regulation_desc:
40 CFR Part 63, Subpart F; 40 CFR Part 61 Subpart J and V


federal_regulation_desc:
40 CFR Part 60, Subpart QQQ; 40 CFR Part 63, Subpart CC


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart Db)


federal_regulation_desc:
Other (Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements)


federal_regulation_desc:
Other (40 CFR 50, 52 Subp. Y, 63 Subp. DDDDD)


federal_regulation_desc:
Other (BWON, 40 CFR part 61, subpart FF)


federal_regulation_desc:
Other (not regulated for VOC equipment leaks)


federal_regulation_desc:
40 CFR Part 61, Subpart J, and Subpart V


federal_regulation_desc:
40 CFR  Part 61, Subparts J and V; and 40 CFR Part 63, Subpart F


federal_regulation_desc:
40 CFR Part 61, Subparts J and V; 40 CFR Part 63, Subpart F


federal_regulation_desc:
40 CFR Part 61, Subparts J and V; 40 CFR Part 63, Subparts F


unit_id:
Agrekko Temporary Cooling Tower in Sulfur


unit_id:
Refinery Wide Flow Meter Vents from Junction Boxes


unit_id:
Refinery Wide Vents from Manholes and Junction Boxes


unit_id:
Refinery Wide Water Seal Vents from Drains


federal_regulation_desc:
40 CFR Part 61, Subpart Y; 40 CFR Part 63, Subparts F and G


federal_regulation_desc:
Other (specify) 40 CFR Part 63, Subpart LLLL (Asphalt MACT)


unit_id:
No. 1 Crude Process Heater AA-012 (2H-1A)


federal_regulation_desc:
Other (NSPS GGG, Ref. MACT 1, CC, EPA FIP, Consent Decree)


federal_regulation_desc:
Other (specify) 40 CFR Part 52 Subpart BB - Montana


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart J, CO and PM Only


federal_regulation_desc:
Other (specify)   40 CFR Part 52 Subpart BB - Montana


federal_regulation_desc:
Other (specify)  40 CFR Part 52 Subpart BB - Montana


federal_regulation_desc:
Other (specify) 40 CFR Part 53 Subpart BB - Montana


unit_id:
iC4 flush and T405 bottoms strainer drain-1


unit_id:
iC4 flush and T405 bottoms strainer drain-2


unit_id:
TRA005 Dies/Lt. Dist Sulfur Sample System Vent


unit_id:
EUI 1C: Combination Unit / Refinery Flare


federal_regulation_desc:
NSPS Subpart Dc (40 CFR part 60, subpart Dc)


unit_id:
EUI 2C: HF Alkylation Unit Cooling Tower


unit_id:
EUI 3B: GHT Unit / Ultraformer Emergency Flare


unit_id:
API PreSeparator Channel 4 (Vent to TOU)


unit_id:
API PreSeparator Channel 5 (Vent to TOU)


unit_id:
API PreSeparator Channel 6 (Vent to TOU)


unit_id:
API PreSeparator Channel 7 (Vent to TOU)


unit_id:
API PreSeparator Channel 8 (Vent to TOU)


unit_id:
API PreSeparator Channel 9 (Vent to TOU)


unit_id:
Bag Dump Station/Mastermix Feeder-Train 1


unit_id:
BW Marine Terminal Barge Piers (Heavy Products)


unit_id:
BW Marine Terminal Barge Piers (Light Products)


federal_regulation_desc:
40 CFR 63 Subpar Y (RACT provisions only)


federal_regulation_desc:
40 CFR 61 Subpart FF, 40 CFR 61 Subpart V


unit_id:
Linden Terminal ULSD Rack (Bottom Loading)


unit_id:
Railcar Vent- Line No. 1 (see note below)


unit_id:
Railcar Vent- Line No. 2 (see note below)


unit_id:
SWPS Once Through Cooling Water (CW) System at 7PS


unit_id:
SWPS Once Through Cooling Water (CW) System at 7VPS


unit_id:
SWPS Once Through Cooling Water (CW) System at ABW


unit_id:
SWPS Once Through Cooling Water (CW) System at BIBFBW


unit_id:
SWPS Once Through Cooling Water (CW) System at CLEU


unit_id:
SWPS Once Through Cooling Water (CW) System at CNHBW


unit_id:
SWPS Once Through Cooling Water (CW) System at DSU-1


unit_id:
SWPS Once Through Cooling Water (CW) System at DSU-2


unit_id:
SWPS Once Through Cooling Water (CW) System at FCBW


unit_id:
SWPS Once Through Cooling Water (CW) System at FGBW


unit_id:
SWPS Once Through Cooling Water (CW) System at H2BW


unit_id:
SWPS Once Through Cooling Water (CW) System at HRU-1 (HPU)


unit_id:
SWPS Once Through Cooling Water (CW) System at ISOM-2


unit_id:
SWPS Once Through Cooling Water (CW) System at PFBW


unit_id:
SWPS Once Through Cooling Water (CW) System at POLYSP


unit_id:
SWPS Once Through Cooling Water (CW) System at POLYT


unit_id:
SWPS Once Through Cooling Water (CW) System at PRBW


unit_id:
SWPS Once Through Cooling Water (CW) System at USBW


unit_id:
25XY432/25XY433/25XY434, Pilot Fuel Gas Vent


unit_id:
25XY440/25XY441X25XY442, Main Fuel Gas Vent


unit_id:
64AT1059--HRG FROM COLD COND SEP (methane slip)


unit_id:
A-DHT Compressor BGOT Recycle Gas H2 (AT1729A-B)


unit_id:
Alky 1 DiB OVHD/C4 CONDENSER  (AT1506A-G)


unit_id:
Alky 3 DiB OVHD / C4 Product  (AT1442A-D / AT1443A-C)


unit_id:
Alstom Boiler Fuel Gas Mix Drum on-line GC (AI2013)


unit_id:
East (AI4211) and Hydrogen Furnace (AI4411) Fuel Gas Mix Drum on-line GC


unit_id:
FCC Regenerator exhaust line CO monitor (AR305)


unit_id:
FCC Regenerator exhaust line CO2 monitor (AR306)


unit_id:
FCC Regenerator exhaust line NOx monitor (AI303A)


unit_id:
FCC Regenerator exhaust line O2 monitor (AR307)


unit_id:
H2 Plant H2S/East FG Mix Drum H2S (AT1702/1802X)


unit_id:
Hydrogen Plant Feed process analyzer H2S/C1/C6+ (AI4430)


unit_id:
ISO 2 DeC3 BTMS C3/iC5  /  DeC3 OVHD C2/iC4  (AT4362A-B
AT4380A-B)


unit_id:
ISO 2 FCCU Rich Oil Abs BTMS C2/C3/H2S (AT4223)


unit_id:
ISO 2 Heavy Iso SIMDIST EP/90%/IBP  (AT4352A-C)


unit_id:
ISO 2 Light Iso SIMDIST 90%/RVP/C4  (AT4330A-D)


unit_id:
Loading - Rail Rack (Asphalt and Decanted Oil)


unit_id:
Other LDAR - Tank Farms, Blending, Loading


unit_id:
Reformer 1 analyzer on vent from the Flue Gas Scrubber Overhead Sample System (AI503).


unit_id:
Reformer 2 analyzer on vent from the Flue Gas Scrubber (PR556980) Overhead Sample System (AI4502).


unit_id:
Reformer 2 Recycle Gas C1-C6/H2 (AT4512B-G)


unit_id:
Sat Gas DeC3 OVHD/BTMS C2/iC4  (AT504A-B)


unit_id:
Sat Gas DeC4 OVHD/BTMS  AT506A-B
(A = A-D
B = E-H (Siemens))


unit_id:
Sat Gas DiB 1 OVHD/BTMS   C3, NC4 / iC4, iC5 (AT505A-B)


unit_id:
Sat Gas DIB2 OVHD/BTMS Prod C3/NC4  (AT561A-B/AT562A-B)


unit_id:
TRP SRU Rich Amine Flash Drum H2S  (AT5512)


unit_id:
TRP SRU TG2-TGTU XS H2  (AT5701/5703)
TGTU Tailgas H2S


unit_id:
Unsat 2nd Stg Abs Dry Gas C3/UC3/C1/CO2/UC2/C2/H2S  (AT302A-G)


unit_id:
Unsat DeC4 Btms - SIMDIST  (AT317 A-Q) - H2S +


federal_regulation_desc:
40 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J & A.


federal_regulation_desc:
40 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; 40 CFR Part 60, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J & A.


federal_regulation_desc:
41 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J.


federal_regulation_desc:
42 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J.


federal_regulation_desc:
43 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J & A.


federal_regulation_desc:
44 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J & A.


federal_regulation_desc:
40 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; 40 CFR Part 60, Subpart A


federal_regulation_desc:
40 CFR Part 63, Subpart DDDDD; 40 CFR, Part 60, Subpart Db; 40 CFR Part 63, Subpart A; 40 CFR Part 60, Subpart A


federal_regulation_desc:
40 CFR Part 61, Subpart FF; 40 CFR, Part 60, Subpart VV; 40 CFR, Part 61, Subpart V; 40 CFR, Part 60, Subpart GGG; 40 CFR, Part 63, Subpart CC; 40 CFR Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A


federal_regulation_desc:
40 CFR, Part 60, Subpart Db; 40 CFR, Part 63, Subpart DDDDD; 40 CFR Part 63, Subpart A; 40 CFR Part 60, Subpart A


federal_regulation_desc:
Alternative Monitoring Plan "Premcor Lima Refinery, LDAR Plan "


federal_regulation_desc:
40 CFR, Part 60, Subpart A; Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J.


federal_regulation_desc:
40 CFR 60 subpart GGGa; 40 CFR 61 subpart FF; 40 CFR 61 subpart J; 40 CFR 61 subpart BB; 40 CFR 61 subpart A; 40 CFR 63 subpart EEEE; 40 CFR 63 subpart S; 40 CFR 63 subpart A


federal_regulation_desc:
40 CFR 61 subpart J; 40 CFR 61 subpart BB; 40 CFR 61 subpart A; 40 CFR 63 subpart EEEE; 40 CFR 63 subpart S; 40 CFR 63 subpart A


federal_regulation_desc:
40 CFR Part 63 Subparts CC; Consent Decree - Comply with all the requirements of 40CFR Part 60,Subparts A & J as specified in paragraphs 231, 235.a. and 238.a.


federal_regulation_desc:
40 CFR Part 63 Subparts CC; 40 CFR Part 63 Subparts UUU; 40 CFR Part 60.18


federal_regulation_desc:
Concent Decree - Comply with all the requirements of 40CFR Part 60,Subparts A & J by 12/31/2010 or as specified in paragraph 97


federal_regulation_desc:
40 CFR Part 63 Subparts UUU; 40 CFR Part 60.18


federal_regulation_desc:
40 CFR Part 61, Subpart FF; 40 CFR, Part 60, Subpart VV; 40 CFR, Part 61, Subpart V; 40 CFR, Part 60, Subpart GGG; 40 CFR, Part 63, Subpart CC; 40 CFR Part 63, Subpart A; 40 CFR Subpart 60, Subpart A; 40 CFR Part 61, Subpart A


federal_regulation_desc:
Consent Decree:  All heaters and boilers are "affected facilities" and shall comply with 20 CFR, Part 60, Subpart J.


federal_regulation_desc:
HON (40 CFR part 63, subpart F) existing source requirements


federal_regulation_desc:
40 CFR 61 Subpart FF & 40 CFR 60 Subpart QQQ


federal_regulation_desc:
Part 70 Permit No. 2007-005-C limited to existing equipment.


federal_regulation_desc:
40 CFR 60 Subpart GGG, 40 CFR 63 Subpart CC


unit_id:
864 unit - 150 ft from 864 cooling tower


unit_id:
864 unit - 50 ft from 864 cooling tower-1


unit_id:
864 unit - 50 ft from 864 cooling tower-2


unit_id:
865/6 unit - Corner of unit adjacent to Bio plant


federal_regulation_desc:
40 CFR 63 Subpart Q, 40 CFR 63 Subpart F


unit_id:
H1 Heater - Unit 870 Tier II Low Sulfur Hydrodesulfurization Plant


unit_id:
H2 Heater - Unit 870 Tier II Low Sulfur Hydrodesulfurization Plant


unit_id:
A Compressor 1st stage Make-up and 1st stage Recycle High Pressure Distance Piece


unit_id:
A Compressor 1st stage Make-up and 1st stage Recycle Intermediate  Pressure Distance Piece


unit_id:
A Compressor 2nd stage Make-up, 3rd stage Make-up, and 2nd stage Recycle High Pressure Distance Piece


unit_id:
A Compressor 2nd stage Make-up, 3rd stage Make-up, and 2nd stage Recycle Intermediate Pressure Distance Piece


unit_id:
B Compressor 1st stage Make-up and 1st stage Recycle High Pressure Distance Piece


unit_id:
B Compressor 1st stage Make-up and 1st stage Recycle Intermediate  Pressure Distance Piece


unit_id:
B Compressor 2nd stage Make-up, 3rd stage Make-up, and 2nd stage Recycle High Pressure Distance Piece


unit_id:
B Compressor 2nd stage Make-up, 3rd stage Make-up, and 2nd stage Recycle Intermediate Pressure Distance Piece


unit_id:
C Compressor #1 Debut and #2 Debut High Pressure Distance Piece


unit_id:
C Compressor #1 Debut and #2 Debut Intermediate Pressure Distance Piece


unit_id:
C Compressor Deprop High Pressure and Intermediate Pressure Distance Piece


unit_id:
Diesel Compressor #1 Cylinder and #2 Cylinder High Pressure Distance Piece and 4 suction unloaders


unit_id:
Isocracker Booster Compressor #1 Cylinder and #2 Cylinder High Pressure Distance Piece and 4 suction unloaders


unit_id:
Kerosene Compressor #1 Cylinder and #2 Cylinder High Pressure High Pressure Distance Piece


unit_id:
VGO Make-up Compressor 1st stage and 3rd stage High Pressure Distance Piece


unit_id:
VGO Make-up Compressor 1st stage and 3rd stage Intermediate Pressure Distance Piece


unit_id:
VGO Make-up Compressor 2nd stage High Pressure Distance Piece


unit_id:
VGO Make-up Compressor 2nd Stage Intermediate Pressure  A Distance Piece


unit_id:
VGO Make-up Compressor 2nd Stage Intermediate Pressure  B Distance Piece


federal_regulation_desc:
NSPS for Equipment Leaks at Petroleum Refineries (40 CFR 60 Subpart QQQ)


federal_regulation_desc:
Refinery MACT 1 (40 CFR 63 Subpart CC) existing source requirments


unit_id:
COCTW0002 - Cooling Tower 2A (North-Pritchart)


unit_id:
COCTWFLUR - Cooling Tower 2B (South-FLUR)


unit_id:
CRUHT15H1A New crude unit vacuum unit heater


unit_id:
REFHT0123 No. 2 Platformer Heaters 1, 2, 3


unit_id:
REFHT50H4 No. 2 Platformer stabilizer reboiler


federal_regulation_desc:
Other (specify) HON (40 CFR Part 63, Subpart G)


federal_regulation_desc:
Other (specify) Refinery MACT (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
Other BWON (40 CFR Part 63, Subpart FF) existing source requirements


unit_id:
Fuel Gas Treatment (Unit 2800 Utilities)


federal_regulation_desc:
Other BWON (40 CFR Part 61, Subpart FF) existing source requirements


federal_regulation_desc:
Other (specify) NSPS Part 61, Subpart FF


federal_regulation_desc:
40 CFR Part 61, Subpart FF and 40 CFR Part 60, Subpart QQQ


federal_regulation_desc:
40 CFR Part 60, Subpart QQQ and 40 CFR Part 61, Subpart FF


federal_regulation_desc:
40 CFR Part 63, Subpart A and 40 CFR Part 63, Subpart G


federal_regulation_desc:
40 CFR Part 63, Subpart CC and 40 CFR Part 60, Subpart GGG


federal_regulation_desc:
40 CFR Part 63, Subpart H and Subpart CC


federal_regulation_desc:
40 CFR Part 60, Subpart GGG and 40 CFR Part 63, Subpart CC


federal_regulation_desc:
40 CFR Part 63, Subpart H and 40 CFR Part 63, Subpart CC


federal_regulation_desc:
40 CFR 61 subpart BB/40 CFR 63 subpart Y


federal_regulation_desc:
NESHAP (40 CFR part 61, Subpart Y), NESHAP (40 CFR part 61, Subpart FF)


federal_regulation_desc:
NESHAP (40 CFR part 61, Subpart FF), MACT (40 CFR part 63, Subpart GGGGG)


federal_regulation_desc:
40 CFR 63 Subpart G - HON existing source


federal_regulation_desc:
40 CFR Part 60, Subpart J and 40 CFR Part 61, Subpart V


federal_regulation_desc:
40 CFR 61, Subpart BB and 40 CFR 63 Subpart Y


federal_regulation_desc:
40 CFR Part 63 Subpart G - existing source


federal_regulation_desc:
BWON NESHAPS (40 CFR Part 61, Subpart FF) and HON MACT (40 CFR Part 63, Subpart G) existing source


federal_regulation_desc:
BWON NESHAPS (40 CFR Part 61, Subpart FF)


federal_regulation_desc:
Other (specify) 40 CFR part 60, subpart FF


federal_regulation_desc:
Other (specify) 40 CFR part 63, subpart Q


federal_regulation_desc:
Other (specify) 40 CFR Part 61, Subpart BB


federal_regulation_desc:
Other (specify) 40 CFR part 60, subpart Kb


federal_regulation_desc:
Other (specify) 40 CFR Part 63, Subpart G (HON)


federal_regulation_desc:
Other (specify) 40 CFR part 61, subpart FF


federal_regulation_desc:
Other (specify) 40 CFR part 63, subpat G


federal_regulation_desc:
Other (specify) 40 CFR part 63, subpart G


federal_regulation_desc:
Other (specify) 40 CFR part 61, subpart FF, 40 CFR part 63, subpart G


federal_regulation_desc:
Other (40 CFR Part 61, Subpart FF), (40 CFR Part 63, Subpart GGGGG)


federal_regulation_desc:
HON 40 CFR 63, Subpart G (existing sources)


federal_regulation_desc:
40 CFR 61 Subpart FF and HON 40 CFR 63, Subpart G (existing sources)


federal_regulation_desc:
40 CFR 60 Subpart QQQ and 40 CFR 61 Subpart FF and 40 CFR Part 63, Subpart GGGGG and HON 40 CFR 63, Subpart G (existing sources)


unit_id:
Refinery Fuel Gas Collection and Distribution System


federal_regulation_desc:
Other (40 CFR part 63, subpart Y. 40 CFR part 61, subpart BB)


federal_regulation_desc:
Refinery MACT 1 (40 CFR Part 63, Subpart CC) Existing Source Requirements


federal_regulation_desc:
Other (40 CFR part 61, subpart Y. 40 CFR part 61, subpart FF)


federal_regulation_desc:
Other (specify) 40 CFR part 61, subpart Y


unit_id:
Natural Gas Compents based on Fuel Gas Components


unit_id:
Induced and Dissolved Air Flotation Units


federal_regulation_desc:
NESHAP for Equipment Leaks (40 CFR Part 61 Subpart V)


federal_regulation_desc:
CNSTDCR; EPAFF (40CFR PART 61 SUBPART FF)


federal_regulation_desc:
CNSTDCR; VVRMACT; EPAFF (40 CFR PART61 SUBPART FF)


federal_regulation_desc:
40 CFR Part 60 Subpart J; 40 CFR Part 63 Subpart UUU; 40 CFR 60 Appendix F; 40 CFR 60.18; 40 CFR 63.11


unit_id:
Hydrogen Plant Vent on V5518 (HP1 CO2 stripper reflux accum)


federal_regulation_desc:
40 CFR Part 61, Subpart BB & 40 CFR Part 63, Subpart Y


unit_id:
Sour Water Stripping Unit No. 1 - Sulphur Unit


unit_id:
Supply and Distribution DOT - Truck/Tank Truck


federal_regulation_desc:
- Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements                                            5 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV)


federal_regulation_desc:
NSPS (40 CFR part 60, subpart GG), NSPS (40 CFR part 60, subpart KKKK)


federal_regulation_desc:
NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)                               7 HON (40 CFR  part 63, supart H) existing source requirements


federal_regulation_desc:
NSPS (40 CFR part 60, subpart GG), NSPS (40 CFR part 60, supart KKKK)


federal_regulation_desc:
(Refiney NSPS 40 CFR Part 60, Subpart J)


federal_regulation_desc:
Refinery NSPS (40 CFR part 60, subpart J)  and 99 (PSD Permit)


federal_regulation_desc:
(Subpart BB - Beneze Transfer Operations)


federal_regulation_desc:
40 CFR 60 - Subpart GGG - Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries


federal_regulation_desc:
40 CFR 61 Subpart CC, 40 CFR 61 Subpart FF


unit_id:
33-Tankage Pipeway & Truck Rack (LPG Loading Ops)


unit_id:
33-Tankage Pipeway & Truck rack (Truck Rack)


federal_regulation_desc:
40 CFR 63 Subpart Y, 40 CFR 60, Subpart J


unit_id:
Tk 300001/2 & Tk 80020/21/22 Waterdraw Systems


federal_regulation_desc:
40CFR60 Subpart XX - Standards of Performance of Bulk Gasoline Terminals


# federal_regulations_citations_wastewater_treatment

federal_regulation_desc:
BWON (40 CFR part 61, subpart FF) but exempt from control requirements.


federal_regulation_desc:
Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)


federal_regulation_desc:
BWON (40 CFR part 61, subpart FF) but exempted from control requirements.


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements


unit_id:
(P9S2) Wastewater Treating - Air Stripper


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements


federal_regulation_desc:
Refinery MACT 1 (40 CFR part 63, subpart CC)


federal_regulation_desc:
HON (40 CFR part 63, subpart H) existing source requirements


federal_regulation_desc:
The vent is subject to BWON (40 CFR part 61, subpart FF) control requirements.


federal_regulation_desc:
The unit is subject to BWON (40 CFR part 61, subpart FF) control requirements.


federal_regulation_desc:
Other (40 CFR part 60, subpart Kb); 1 BWON (40 CFR part 61, subpart FF) but exempted from control requirements.


unit_id:
EQT534 WCLA/TK0102 Aggressive Biological Treatment


unit_id:
EQT537 WCLA/TK0202A Pretreat Air Flotation


unit_id:
EQT538 WCLA/TK0202B Pretreat Air Flotation


unit_id:
Crude 2 (Sewer 10B, Sewer Drawing 10003200-320A-1129B)


unit_id:
Crude Terminal (29-01, Sewer Drawing 10003200-320A-1146B)


unit_id:
Crude Terminal (29-49, Sewer Drawing 10003200-320A-1146B)


unit_id:
GHU (Sewer 12C, Sewer Drawing 10003200-320A-1140B)


unit_id:
GHU (Sewer 12D, Sewer Drawing 10003200-320A-1140B)


unit_id:
Lab (Sewer 1A, Sewer Drawing 10003200-320A-1143B)


unit_id:
Mid East Tank Farm (63-67, Sewer Drawing 10003200-320A-1145B)


unit_id:
SouthWest Tank Farm (Sewer 5, Sewer Drawing 10003200-320A-1114B)


unit_id:
Sulfolane (Sewer 11, Sewer Drawing 10003200-320A-1133B)


unit_id:
Sulfolane (Sewer 9, Sewer Drawing 10003200-320A-1133B)


unit_id:
Truck Rail PetroChem (Sewer 36-13, Sewer Drawing 10003200-320A-1115B)


unit_id:
Waste Water Treatment Plant (No. 1 Surge, Sewer Drawing 10003200-320A-1110B)-1


unit_id:
Waste Water Treatment Plant (No. 1 Surge, Sewer Drawing 10003200-320A-1110B)-2


unit_id:
#2 Fuel Oil Pad Sump         E of Tk 75-1


unit_id:
Ballast Water Sump           N of Tk 55-3


unit_id:
Bunker Sump                     NW of Tk 200-5


unit_id:
East of Tank 200-1 FCCU/ALKY Tank Dewatering Sump


unit_id:
Kero Sump                    NW of Tk 150-14


unit_id:
Naphtha Tanks 35-2 and 55-4 Dewatering Sump


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) existing source requirements


federal_regulation_desc:
Other (specify) 40 CFR Part 52 Subpart BB - Montana


federal_regulation_desc:
40 CFR Part 60, Subpart A and 40 CFR Part 61, Subpart A


federal_regulation_desc:
40 CFR Part 60, Subpart A and 40 CFR Part 61 Subpart A


federal_regulation_desc:
40 CFR Part 60, Subpart J and Subpart GGG


federal_regulation_desc:
40 CFR Subpart G—National Emission Standards for Organic Hazardous Air Pollutants From the Synthetic Organic Chemical Manufacturing Industry for Process Vents, Storage Vessels, Transfer Operations, and Wastewater; MACT CC


unit_id:
0 None (no on-site wastewater treatment units present at facility)


federal_regulation_desc:
Refinery MACT (40 CFR part 63, subpart CC) new source requirements


unit_id:
6 Activated-sludge biological treatment unit

federal_regulation_desc:
HON (40 CFR part 63, subpart H) new source requirements


# flare_management_plans

flare_management_plan_desc:
Reporting tool would not allow this row to be deleted.


flare_management_plan_desc:
Simplified P&ID (process and instrument diagram) of flare gas header system


flare_management_plan_desc:
Procedures to reduce start-up and shutdown releases to the flare


flare_management_plan_desc:
Procedure to conduct a root cause and corrective action analysis for flare events exceeding a set SO2 emission level


flare_management_plan_desc:
Procedures for monitoring flow of gas to the flare


flare_management_plan_desc:
Procedures for monitoring sulfur content of flared gas


flare_management_plan_desc:
Description of streams from process units that can be directed to the flare


flare_management_plan_desc:
Operational procedures for specific process units to reduce releases to the flare during normal process operations


flare_management_plan_desc:
Procedures for monitoring Btu of flared gas


flare_management_plan_desc:
Procedures to conduct root cause and corrective action analysis for flare events exceeding a set flow rate level


flare_management_plan_desc:
Procedures for monitoring sulfur content of flared gas)


flare_management_plan_desc:
Other (1 Simplified P&ID (process and instrument diagram) of flare gas header system


flare_management_plan_desc:
Turnaround pre-planning, Historical tracking of flaring causes,  volume and emissions.


flare_management_plan_desc:
Policies, procedures, and equipment (i.e., flare gas recover and flare gas treatment) to address planned turnarounds and other scheduled maintenance, essential operational needs, or emergencies flaring


flare_management_plan_desc:
Not applicable. Do not have a flare management plan for minimizing flaring from this flare.


flare_management_plan_desc:
When NOX (estimate) reaches a set level, an alarm is triggered and a root cause analysis is done.


flare_management_plan_desc:
Simplified P&ID (process and instrument diagram) of flare header system


flare_management_plan_desc:
Procedures to reduce/minimize purge or sweep gas use


flare_management_plan_desc:
Other (BRRF is not required by regulation to have a flare management plan as such.These are current methods used, but are not part of a formal plan.)


flare_id:
EUI 1C: Combination Unit / Refinery Flare


flare_id:
EUI 3B: GHT Unit / Ultraformer Emergency Flare


flare_management_plan_desc:
T/A Preplanning & Historical Tracking of Flaring Events


flare_management_plan_desc:
T/A pre-planning and historical tracking of flaring volumes, emissions and causes.


flare_management_plan_desc:
Monitored by a continuous flow monitor and composition analyzer


flare_management_plan_desc:
Other (specify) Procedures for monitoring H2S of flared gas


flare_management_plan_desc:
Refer to the cover letter that was included with this submittal.


flare_management_plan_desc:
Refer to cover letter that was inlucded with this submittal


flare_management_plan_desc:
Monitor H2S of flare gas., monitor flare gas composition


flare_management_plan_desc:
Monitor H2S of flare gas., monitor flare gas composition.


flare_management_plan_desc:
Follow Consent Decree flare management plan.


# flare_reduction_measures

flare_reduction_desc:
This flare does not have a control device.


flare_reduction_desc:
Flare gas recovery system designed to recover 100 percent of flare gas during normal operations


flare_reduction_desc:
Root cause and corrective action analysis for flare events exceeding a set SO2 emission level


flare_reduction_desc:
This flare is used as a control device when loading Butane, Propane and Pentanes.


flare_reduction_desc:
This flare is a backup control device for the tank vapor recovery system


flare_reduction_desc:
Root cause and corrective action analysis for flare events exceeding a set flow rate level


flare_reduction_desc:
Established a redudant source of oxygen to prevent flaring events.  Requiring the third-party oxygen supplier to put the valve and control box on preventative maintenance schedule


flare_reduction_desc:
When NOX (estimate) reaches a set level, an alarm is triggered and a root cause analysis is done.


flare_reduction_desc:
Flare gas recovery system, but not designed to recover 100 percent of flare gas during normal operations


flare_reduction_desc:
Sour gas sources are blocked away from this flare.


flare_reduction_desc:
Flare loads have been shifted from the North flare into the South flare which has a Flare Gas Recovery system.


flare_reduction_desc:
This thermal oxidizer is only used to destroy vapors from filling benzene barges.


flare_reduction_desc:
Oil is skimmed from spent caustic tank CH-278.


flare_reduction_desc:
Hydrocarbon Flaring Pollution Minimization Plan


flare_reduction_desc:
Caustic treatment of the flare gas (include only caustic treatment used specifically to reduce SO2 emissions from the flare, not caustic treatment systems used the fuel gas system)


flare_reduction_desc:
Caustic scrubbing system for H2S / Total Sulfur Compounds


flare_reduction_desc:
Other (Flare only combusts vapor when the pressure control valve on the connected tanks open. Intermittent flow)


flare_reduction_desc:
Other (Flare only combusts vapor when the pressure control valve on the connected tank opens. Intermittent flow)


flare_reduction_desc:
Venting to the BRRF fuel gas system is maximized versus venting to the flare.


flare_reduction_desc:
Marine Vapor Recovery required by regulation


flare_reduction_desc:
Other management practice or work practice to reduce VOC (periodic relief valve leakthrough monitoring, relief valve inspection and maintenance program)


flare_reduction_desc:
Other management practice or work practice to reduce SO2 (periodic relief valve leakthrough monitoring, relief valve inspection and maintenance program)


flare_reduction_desc:
Other management practice or work practice to reduce NOX (periodic relief valve leakthrough monitoring, relief valve inspection and maintenance program)


flare_reduction_desc:
flare only used by plants with sweet streams


flare_reduction_desc:
Flare gas recovery system designed to recover 1 percent of flare gas during normal operations


flare_reduction_desc:
Determine cause of flaring once a preset flare flowrate is exceeded.


flare_id:
EUI 1C: Combination Unit / Refinery Flare


flare_id:
EUI 3B: GHT Unit / Ultraformer Emergency Flare


flare_reduction_desc:
Monitoring the flare system and adding flare gas recovery compressors as flare flow picks up.  Flares are monitored for smoking and steam is adjusted to minimize incomplete combustion.


flare_reduction_desc:
Conducting reviews of all planned start-up and shutdown activities, in order to assure that proper flare minimization procedures are identified and incorporated into the shutdown and start-up proceduresincomplete combustion.


flare_reduction_desc:
Flare used as a control device for marine loading


flare_reduction_desc:
Other management practice or work to reduce PM (Steam)


flare_reduction_desc:
Continuous monitoring of emissions by operators.


flare_reduction_desc:
Standard procedures for steam-assist to reduce visible emissions.


flare_reduction_desc:
Various steps are taken to minimize or cease unathorized flaring including (but not limited to) operational rate adjustments as necessary.


flare_reduction_desc:
Work practice to add steam to minimize smoking at flare.


flare_reduction_desc:
Work practice to route PSA tail gas to NPF directly instead of routing to FGR and tripping FGR for all streams.


flare_reduction_desc:
Other management practice or work practice to reduce PM (specify) - Steaming


flare_reduction_desc:
Sulfur Shedding Plan per the EPA Consent Decree


flare_reduction_desc:
Other (monitoring of flow and flare events)


# flares

operation_desc:
Combusts flare gas only during startup, shutdown, or upsets


operation_desc:
Combusts flare gas 4,000 hours per year or more


operation_desc:
Combusts flare gas less than 1,000 hours per year


flare_pilot_ignition_desc:
Spark ignition, every minute regardless of flow


flare_pilot_ignition_desc:
Spark Ignition, Triggerd by Loss of Ionization, John Zink InstafireTM


operation_desc:
Combusts flare gas 2,000 hours or more but less than 4,000 hours per year


flare_pilot_ignition_desc:
Other (specify), Utilizes flame front generator to start up flare pilots when flare is needed for loading of marine barges


flare_pilot_ignition_desc:
Spark ignition, triggered by manually or by low temp.


operation_desc:
Combusts flare gas less than 1,000 hours per year when in operation.  Was not in operation in 2010


flare_id:
EUI 1C: Combination Unit / Refinery Flare


flare_pilot_ignition_desc:
Continuous pilot flame with spark igniter triggered by thermocouple.


flare_id:
EUI 3B: GHT Unit / Ultraformer Emergency Flare


flare_pilot_ignition_desc:
Loading interlock, pilot only runs during loading


operation_desc:
Combusts flare gas1,000 hours or more but less than 2,000 hours per year


operation_desc:
Combusts flare gas only during startup or shutdown


# fluid_coking_unit_nox_controls

nox_control_desc:
Routed to off-site third-party cogeneration facility


# fluid_coking_unit_pm_controls

pm_control_desc:
Flexicoker - no atmospheric vent or exhaust


# fluid_coking_unit_so2_controls

so2_control_desc:
Flexicoker - Flexigas treated in Flexsorb


so2_control_desc:
Routed to off-site third-party cogeneration facility


# fluid_coking_units

produced_coke_handling_method_desc:
Enclosed conveyer to silo for loading/processing


produced_coke_handling_method_desc:
Enclosed conveyor with bag houses at transition points, to enclosed storage pile and truck loading facility, wetting only.


low_btu_gas_sulfur_removal_technique_desc:
Sterically-hindered amine scrubber (e.g., Flexsorb®)


# fuel_gas_systems

fuel_gas_system_id:
#1 MEROX Unit              #2 MEROX Unit                    #3 MEROX Unit


fuel_gas_system_id:
108- SOUR CRUDE / REDUCED CRUDE TANK FARM


fuel_gas_system_id:
A - Fuel gas components are included with data in Table 3-1


fuel_gas_system_id:
Refinery Fuel Gas Collection and Distribution System


fuel_gas_system_id:
Natural Gas Compents based on Fuel Gas Components


# fuel_gas_treatment_sulfur_compounds

fuel_gas_treatment_id:
FUEL GAS TREATING SYSTEM (V-1640) SYSTEM


fuel_gas_treatment_id:
HCU Fuel Gas Treatment (V-1011) Treatment


sulfur_compound_desc:
Other (The possibility exists for other sulfur compounds but it is NRA.)


sulfur_compound_desc:
Thiophene, Dimethyl sulfide (DMS),3-Methyl Thiophene,Diethyl Sulfide (DES),Ethyl isopropyl sulfide, 2-M-Thiophene,Ethyl Methyl Disulfide 
Dimethyl Tetrasulfide


sulfur_compound_desc:
Other (The possibility exists for other sulfur compounds but confirmation is NRA.)


sulfur_compound_desc:
Hydrogen sulfide (H2S), 2 Carbonyl sulfide (COS), 4 Mercaptans


sulfur_compound_desc:
Dimethyl sulfide, butyl sulfide, dimethyl disulfide, diethyl sulfide, diethyl disulfide


sulfur_compound_desc:
diemthyl disulfide, diethyl sulfide, 2, 5-dimethyl thiophene


sulfur_compound_desc:
dimethyl sulfide, butyl sulfide, dimethyl disulfide, diethyl sulfide, 2,5-dimethyl thiophene


# fuel_gas_treatment_sulfur_removal

fuel_gas_treatment_id:
Hiperion Unit with Backup Iron Sponge Towers (399-D-6A/B)

sulfur_removal_technique_desc:
Hiperion Technology [Absorption using Naphtha Quinone Solution and regeneration] with back up Iron Sponge Towers [H2S removal by contact and reaction with hydrated iron oxide on wood chips]


sulfur_removal_technique_desc:
Absorption using blend of amine(s) and TG-10 solvent


fuel_gas_treatment_id:
Fuel Gas Treatment (Unit 2800 Utilities)


# fuel_gas_treatment_units

fuel_gas_treatment_id:
FUEL GAS TREATING SYSTEM (V-1640) SYSTEM


fuel_gas_treatment_id:
HCU Fuel Gas Treatment (V-1011) Treatment


fuel_gas_treatment_id:
Hiperion Unit with Backup Iron Sponge Towers (399-D-6A/B)


fuel_gas_treatment_id:
Fuel Gas Treatment (Unit 2800 Utilities)


# generation_unit_energy_efficiency_measures

energy_efficiency_measure_desc:
Oxygen monitors used to control/limit excess oxygen


energy_efficiency_measure_desc:
Steam condensate return lines (to return condensate (hot water) to boiler)


energy_efficiency_measure_desc:
Boiler maintenance program to reduce scaling (other than soot blowing)


energy_efficiency_measure_desc:
Boiler maintenance program to maintain burners (other than soot blowing)


energy_efficiency_measure_desc:
Intake air monitors to optimize fuel/air mixtures


energy_efficiency_measure_desc:
Other (Specify) Boiler Feed Water Preheat from Process Streans, Automated Blowdown Control


energy_efficiency_measure_desc:
Other (Specify) Automated Blowdown Control, Steam Superheating using process waste heat.


energy_efficiency_measure_desc:
Blowdown steam recovery system for low pressure needs


energy_efficiency_measure_desc:
Steam expansion turbines (to recover energy from high pressure steam when steam is needed at lower pressures)


energy_efficiency_measure_desc:
Other (specify) Automated blowdown control, Boiler Feed Water preheat from Process Stream


energy_efficiency_measure_desc:
Other (specify) External Steam Separator, Automated blowdown control, Steam Superheating using process waste heat.


energy_efficiency_measure_desc:
Other (specify) Automated blowdown control


energy_efficiency_measure_desc:
Steam condensate return lines (to return condensate (hot water) to boi


energy_efficiency_measure_desc:
Other (specify) Periodically check flue gas Oxygen and adjust


energy_efficiency_measure_desc:
Flue Gas Recirculation, BFW PreHeat by Steam Exchange, BFW water treatment to minimize scaling


energy_efficiency_measure_desc:
BFW PreHeat by Steam Exchange, BFW water treatment to minimize scaling


energy_efficiency_measure_desc:
No physical intake air monitors other than burner curves now housed in the TDC as part of the DCS upgrade…Air Flow and Fuel Flow are measured and adjusted based on the performance curve that was generated


generation_unit_id:
Steam-Methane Reformer  Hydrogen Production Process Unit: H-15001 w/Exchangers (E-15001, E-15003, E-15004, E-15005 & E-15006)


generation_unit_id:
150# COKER  & VAC  WH STM TO HEADER--After Desuperheater


generation_unit_id:
MSCC Combined Waste Heat Steam Generation


energy_efficiency_measure_desc:
Boiler feed water preheat from CCU waste heat


# generation_units

generation_unit_description:
Steam Generation from Process Unit No. 25 H2 Plant


generation_unit_description:
Steam Generation from Process Unit No. FCC


generation_unit_description:
Steam Generation from Process Unit No. 9 HTU


generation_unit_description:
Catalytic Reformer #22 - Steam Generator


primary_fuel_type_desc:
Refinery fuel gas (mixture of natural gas and still gas or process gas)


generation_unit_description:
FCCU waste heat boilers (COB1, COB2, COB3)


generation_unit_description:
Utilities combined heat and power (COGEN)


generation_unit_description:
TGTU-A Steam Generator (Waste Heat Boiler)


generation_unit_description:
300 Claus Unit First Sulfur Condenser (Waste Heat Boiler)


generation_unit_description:
300 Claus Unit Second Sulfur Condenser(Waste Heat Boiler)


generation_unit_description:
600 Claus Unit First Sulfur Condenser (Waste Heat Boiler)


generation_unit_description:
600 Claus Unit Second Sulfur Condenser (Waste Heat Boiler)


generation_unit_description:
700 Claus Unit Second Sulfur Condenser  (Waste Heat Boiler)


generation_unit_description:
750 Claus Unit Vertical Sulfur Condenser (Waste Heat Boiler)


generation_unit_description:
3rd Stage Claus Converter Sulfur Condenser (Waste Heat Boiler)


generation_unit_description:
TGTU-B Steam Generator (Waste Heat Boiler)


generation_unit_description:
700 Claus Unit First Sulfur Condenser (Waste Heat Boiler)


generation_unit_description:
300 Claus Unit Rx Furnace/ Waste Heat Boiler


generation_unit_description:
600 Claus Unit Rx Furnace/Waste Heat Boiler


generation_unit_description:
700 Claus Unit Rx Furnace/Waste Heat Boiler


generation_unit_description:
750 Claus Unit Rx Furnace/Waste Heat Boiler


generation_unit_description:
H2P2 Steam Methane Reformer Waste Heat Boiler


generation_unit_description:
H2P1Steam Methane Reformer Waste Heat Boiler


generation_unit_description:
#3 HDS WHB X-334. Currently out of service.


generation_unit_description:
SRU Reaction Furnace WHB X-414. Primary fuel = acid gas.


generation_unit_description:
SRU #1 Condenser WHB    X-411. Primary fuel = acid gas.


generation_unit_description:
SRU #2 Condenser WHB    X-412. Primary fuel = acid gas.


generation_unit_description:
SRU #3 Condenser WHB    X-413. Primary fuel = acid gas.


generation_unit_description:
Hydrocracker Unit (Hydrocracker 2nd Stage) waste heat boilers


generation_unit_description:
Sulfuric Acid Mfg Plant waste heat boiler


generation_unit_description:
Tail gas reactor effluent process steam generator


generation_unit_description:
Cogen gas turbine driving electricity generator


generation_unit_description:
Hydrocracker process fired steam generator


generation_unit_description:
Steam Generator (coker gas oil pumparound)


generation_unit_description:
Steam from the convection sections of Crude Atmospheric Heaters 111B-1A and 111B-1B, and Crude Vacuum Heater 111B-2


generation_unit_description:
Steam from convection sections of Coker Heaters 113B-1, 113B-2, and 113B-3


generation_unit_description:
Steam Drum from convection sections fo Petrochem Reformer Heaters 123B-3 and 123B-4


generation_unit_description:
North Sulfur Reaction Furnace Waste Heat Boiler


generation_unit_description:
North Suflur Tail Gas Reactor Effluent Cooler


generation_unit_description:
FCC Main Column BTMS 1A Waste Heat Boiler


generation_unit_description:
FCC Main Column BTMS 1B Waste Heat Boiler


secondary_fuel_type_desc:
Low Btu fuel gas from flexicoking unit or other gasification process


generation_unit_description:
150-psig steam from Gofiner heater B-1002


generation_unit_description:
50-psig steam from TGTU waste heat boiler B-631


generation_unit_description:
Combustion Turbines, 600-psig steam header


generation_unit_description:
Combustion Turbines, 150-psig steam header


generation_unit_description:
#1 SRU Thermal Reactor Waste Heat Boiler


primary_fuel_type_desc:
Still gas or process gas only (not mixed with natural gas)


generation_unit_description:
#2 SRU Thermal Reactor Waste Heat Boiler


generation_unit_description:
Vacuum Unit Waste Heat Boilers - Heat Exchangers


generation_unit_description:
FCCU Waste Heater Boilers - Heat Exchangers


generation_unit_description:
FCCU Waste Heater Boiler - Heat Exchanger


generation_unit_description:
Coker Waste Heat Boiler - Heat Exchanger


generation_unit_description:
Coker Waste Heat Boiler Drum - Multiple Heat Exchangers


generation_unit_description:
Process Heater Waste Heat Boiler - Convection Section


generation_unit_description:
SRU Waste Heat Boilers - Condensor Heat Exchangers


generation_unit_description:
SRU Waste Heat Boilers - Condenser Heat Exchangers


generation_unit_description:
Process Waste Heat Boiler-Covection Section


generation_unit_description:
SRU Waste Heat Boiler - Condenser Heat Exchanger


generation_unit_description:
SRU Waste Heat Boiler - Reactor Effuent Cooler


generation_unit_description:
SRU Waste Heat Boiler - Condenser Heat Exchangers


generation_unit_description:
SRU Waste Heat Boiler - Reactor Effluent Cooler


generation_unit_description:
SRU Waste Heat Boiler - Reaction Furnace Exchanger


generation_unit_description:
SRU Waste Heater Boiler - Condenser Heat Exchanger


generation_unit_description:
Crude Distillation Waste Heat Boiler Drum - Multiple Heat Exchangers


generation_unit_description:
Crude Distillation Waste Heat Boiler Drum - Misc. Heat Exchangers


generation_unit_description:
Xylenes Waste Heat Boiler - Heat Exchanger


generation_unit_description:
FCC Regenerator Flue Gas Waste Heat Boiler


secondary_fuel_type_desc:
Refinery fuel gas (mixture of natural gas and still gas or process gas)


generation_unit_description:
Unit 025 FCCU flue gas 600# waste heat steam generator


generation_unit_description:
Unit 025 FCCU flue gas 50# waste heat steam generator


generation_unit_description:
Unit 234 incinerator waste heat exchanger


generation_unit_description:
ULSDHT Diesel Pump Around Steam Generator


generation_unit_description:
Reformer Charge Heater Waste Heat Boiler


generation_unit_description:
Platformer unit waste heat boiler (  Platforming Heaters (H-41-01 / 02 / 03) Conv. Sect.)


generation_unit_description:
Coker unit waste heat boiler (HCGO / HCGO  P/A and HCD Prod Steam Generators)


generation_unit_description:
Crude unit waste heat boiler (Resid steam generator A)


generation_unit_description:
Crude unit waste heat boiler (Resid steam generator B)


generation_unit_description:
GDU unit waste heat boiler (H-93-01 Conv. Sect.))


generation_unit_description:
FCC unit waste heat boiler (Flue Gas Cooler)


generation_unit_description:
FCC unit waste heat boiler (Catalyst Cooler)


generation_unit_description:
FCC unit waste heat boiler (Pumparound Steam Gen - E-82-873 A)


generation_unit_description:
FCC unit waste heat boiler (Pumparound Steam Gen - E-82-873 B)


generation_unit_description:
FCC unit waste heat boiler (Pumparound Steam Gen - E-82-824 C)


generation_unit_description:
FCC unit waste heat boiler (Pumparound Steam Gen - E-82-824 D)


generation_unit_description:
FCC unit waste heat boiler (Pumparound Steam Gen - E-82-824 E)


generation_unit_description:
SRU 1600 unit waste heat boiler (Furnace WHB)


generation_unit_description:
SRU 1600 unit waste heat boiler (Sulfur Condensers)


generation_unit_description:
SRU 30 unit waste heat boiler (Furnace WHB)


generation_unit_description:
SRU 30 unit waste heat boiler (Sulfur Condenser No. 1)


generation_unit_description:
SRU 30 unit waste heat boiler (Sulfur Condenser No. 2)


generation_unit_description:
SRU 3700 unit waste heat boiler (Furnace WHB)


generation_unit_description:
SRU 3700 unit waste heat boiler (No. 1 Sulfur Condenser)


generation_unit_description:
SRU 3700 unit waste heat boiler (No. 2 Sulfur Condenser)


generation_unit_description:
SRU 3700 unit waste heat boiler (No. 3 Sulfur Condenser)


generation_unit_description:
SRU 3700 unit waste heat boiler (No. 4 Sulfur Condenser)


generation_unit_description:
SRU 3700 unit waste heat boiler (TGU Reactor WHB)


generation_unit_description:
HTHC unit waste heat boiler (H-60-01/02/03/04 Conv. Section)


generation_unit_description:
HTHC unit waste heat boiler (CFHT Stripper Bottoms MP Steam Generator)


generation_unit_description:
Vacuum unit waste heat boiler (HVGO + VTB  Quench Stm Generator)


generation_unit_description:
Vacuum unit waste heat boiler (HVGO Product Stm Generator)


generation_unit_description:
F-8620 Auxiliary Steam Generating Burners


generation_unit_description:
83 - Vacuum Unit Waste Heat Steam Generator


generation_unit_description:
FCC Stack (FC95347) - Waste Heat Boiler (X6129)


generation_unit_description:
Crude Process Unit Vacuum Tower (T-106) Slop Wax Waste Heat Exchanger


generation_unit_description:
Crude Process Unit Vacuum Tower (T-106) Bottoms Waste Heat Exchanger


generation_unit_description:
Crude Process Unit Vacuum Tower (T-106) Bottoms Waste Heat Boiler


generation_unit_description:
FCCU Fractionation Tower T-201 Slurry Pumparound Waste Heat Exchanger


generation_unit_description:
FCCU #2 Catalyst Regenerator Flue Gas Waste Heat Exchanger


generation_unit_description:
#2 SRU Sulfur Condenser No.1 (Second Pass) Waste Heat Exchanger


generation_unit_description:
#2 SRU Sulfur Condenser No.2 (Third Pass) Waste Heat Exchanger


generation_unit_description:
DHDS Process Unit Fractionation Tower (T-603) Kerosene Pumparound Heat Exchanger


generation_unit_description:
DHDS Process Unit Fractionation Tower (T-603) Diesel Pumparound Heat Exchanger


generation_unit_description:
DHDS Process Unit Fractionation Tower (T-603) Bottoms Product Heat Exchanger


generation_unit_description:
CFHT Process Unit Fractionator (T-6502) Bottoms Product Pumparound Waste Heat Exchanger


generation_unit_description:
CFHT Process Unit Fractionator (T-6502) Bottoms Product Waste Heat Exchanger


generation_unit_description:
CFHT Process Unit Distillate Stripper (T-6503) Bottoms Product Waste Heat Exchanger


generation_unit_description:
Crude Process Unit Process Heaters H-102A & H-102B Flue Gas Waste Heat Exchanger H-104


generation_unit_id:
Steam-Methane Reformer  Hydrogen Production Process Unit: H-15001 w/Exchangers (E-15001, E-15003, E-15004, E-15005 & E-15006)

generation_unit_description:
SMR Hydrogen Production Unit Steam Generation System


secondary_fuel_type_desc:
Refinery Heavy fuel oil used but stopped August of 2010


generation_unit_description:
FCC Charge heater waste heat from process heater


generation_unit_id:
150# COKER  & VAC  WH STM TO HEADER--After Desuperheater

generation_unit_description:
150# COKER  & VAC  WH STM TO HEADER--After Desuperheater


generation_unit_description:
#1 Reformer (CCR) #1 Reformer waste heat boiler


generation_unit_description:
#2 Rheniformer #2 Rheniformer waste heat boiler


generation_unit_description:
#2 Sulfur Plant INCINERATOR Waste Heat Boiler


generation_unit_description:
#2 Sulfur Plant 45# SCOT Waste Heat Reclaimer


generation_unit_description:
Reformer No. 3 waste heat plus can supplement with Refinery Fuel


generation_unit_description:
STRAIGHT RUN ORTHOXYLENE COLUMN O.H. CONDENSER


generation_unit_description:
NO. 1 ORTHOXYLENE RECYCLE COLUMN OVERHEAD CONDENSER ORTHOXYLENE


generation_unit_description:
CRYSTALLIZER FEED COLUMN OVERHEAD CONDENSER


generation_unit_description:
RAFFINATE COLUMN STEAM GENERATOR NO. 2 PAREX


generation_unit_description:
EXTRACT COLUMN STEAM GENERATOR NO. 2 PAREX


generation_unit_description:
REACTOR FEED HEATER HDS / STABILIZER REBOILER HEATER HDS


generation_unit_description:
GOHT REACTOR CHARGE HEATER / Fractionator Reboiler


generation_unit_description:
XYLENE RECOVERY AUXILLIARY CONDENSER TOL FRAC


generation_unit_description:
HVGO PUMPAROUND WASTE HEAT BOILER MID PLANT CRUDE UNIT


generation_unit_description:
GAS OIL WASTE HEAT BOILER MID PLANT CRUDE UNIT


generation_unit_description:
BTX Charge Heater/BTX Intermediate Heater


generation_unit_description:
SLURRY PUMP AROUND STEAM GENERATOR WEST SIDE OF FCCU II FCCU II


generation_unit_description:
KERO STRIPPER BOTTOMS/LOW PRESSURE STEAM CONDENSER KEROSENE H.D.S.


generation_unit_description:
WASTE HEAT BOILER EXCHANGER SULFUR RECOVERY


generation_unit_description:
435 Tail Gas Thermal Oxidizer Waste Heat Boiler


generation_unit_description:
440 Tail Gas Thermal Oxidizer Waste Heat Boiler


generation_unit_description:
Sulfur Unit Incinerator Waste Heat Boiler


generation_unit_description:
Waste Heat Boiler from Atmospheric Heater


generation_unit_description:
Cogeneration waste heat and auxillary fired boiler


generation_unit_id:
MSCC Combined Waste Heat Steam Generation


# hydrogen_plant_vents

feedstock_desc:
Refinery fuel gas augmented with additional methane


psa_purge_disposition_desc:
Total CO2 is split - either vented to atmosphere, or sold to Praxair


psa_purge_disposition_desc:
Other (No PSA - refer to table 2-11 CO2 vent)


feedstock_desc:
Refinery process vent offgases, Low pressure reforming hydrogen


feedstock_desc:
Methane and Refinery fuel gas augmented with additional methane


hydrogen_purification_method_desc:
CO shift converter, CO2 Removal (MEA) section, and a methanator

feedstock_desc:
overhead gas from Light Ends Rectifier in Isom Plant (~50% C3, 10% C2, 10% C1 and 30% H2); can also feed Motor Propane (99.5% n-Propane) and n-Butane (emergency feed)


hydrogen_purification_method_desc:
Wet chemical (sulfinol) absorption of CO2 followed by methanation of residual CO, CO2.

psa_purge_disposition_desc:
CO2 primarily collected by third party, balance vented to atmosphere


psa_purge_disposition_desc:
Used as fuel in the reformer furnace and sent to flare


hydrogen_purification_method_desc:
High Temperature Shift, Low Temperatur Shift, Glycol Section, CO2 Removal, and methanator


hydrogen_purification_method_desc:
High Temperature Shift, Low Temperature Shift, Glycol Section, CO2 Removal, and methanator


feedstock_desc:
Hydrogen rich reformer product and HDS hydrogen rich purges


# incidence_reports_air_release_process_units

process_unit_id:
Other LDAR - Tank Farms, Blending, Loading


process_unit_id:
Fuel Gas Treatment (Unit 2800 Utilities)


# incidence_reports_air_releases

description_of_release:
The SCOT Tail Gas clean-up portion of the SRU was shut down to safely install a blind downstream of a failed bypass valve that was allowing high-H2S gas to leak into the H-1105 incinerator stack, resulting in a permit limit exceedance of SO2 in the stack.


description_of_release:
Carry-over of heavy hydrocarbons through the LPG feed into the Amine regeneration circuit and SRU caused upset conditions and reduced sulfur removal efficiency, leading to high SO2 in SRU incinerator H-1105.


description_of_release:
CoGen shutdown and Essential Power loss due to a frozen instrument air line caused Refinery shutdown and subsequent startup resulting in excess emissions, including heater O2, H2S in the main flare, SO2 in H-1105 stack, and acid/sour gas to the SRU flare.


description_of_release:
H2S in the main refinery flare exceeded permitted limits, but the concentration decreased too quickly for the source of the excess H2S to be determined.


description_of_release:
A breaker short caused an MCC fault and power loss to the SWS. Shutdown of the Hydrocracker to address this led to elevated SO2 in SRU incinerator H-1105 and H2S at the Main Refinery Flare, excess heater O2, and acid and sour gas flow to the SRU flare.


description_of_release:
A faulty flow transmitter triggered the safety shutdown sequence for the SRU during a process step change test, leading to elevated SO2 in SRU incinerator H-1105 and exceedance of the H2S limit in the refinery fuel gas system.


description_of_release:
The Hydrocracker Unit shut down due to low lube oil pressure during maintenance of a compressor’s lube oil controller, resulting in elevated SO2 in SRU incinerator H-1105 and H2S at the Main Refinery Flare, and O2 exceedences in the Hydrocracker heaters.


description_of_release:
The refinery underwent a planned shutdown for final tie-ins of the equipment associated with the Naptha Splitter project.  Excess SO2 emissions occurred during the planned shutdown and subsequent startup.


description_of_release:
Extraction Unit BRT Tower PSV-4079 was bypassed to the flare header during the 2010 turnaround shutdown.


description_of_release:
Crude 2 Stabilizer Overhead (V-2201) was steamed to the flare header during the 2010 turnaround shutdown.


description_of_release:
Crude 2 Stabilizer Overhead Receiver (V-2202) was steamed with the bypass around the PSV open during the 2010 turnaround shutdown.


description_of_release:
Crude 2 Overhead valve HC-2135 was opened to relieve to the flare header during the 2010 turnaround shutdown.


description_of_release:
Crude 2 Overhead valve HC-2135 was opened to relieve and steam to the flare header during the 2010 turnaround shutdown.


description_of_release:
Opened Extraction Unit Naphtha 1 Extractor to depressurize to the flare prior to draining vessel during the 2010 turnaround shutdown.


description_of_release:
Opened Extraction Unit Naphtha 1 Extractor to depressurize to the flare for a second time prior to draining vessel during the 2010 turnaround shutdown.


description_of_release:
Crude 2 vented to the flare header during a turnaround.


description_of_release:
Hose from the discharge of the LSR pumps was routed to the flare header during the 2010 turnaround shutdown in an effort to remove the light ends in Tank 201 and replace the fuel with heavier Naphtha.


description_of_release:
Relieved to flare from Crude 1 LPG during the 2010 turnaround shutdown.


description_of_release:
Light end material removed from LSR Tank 201 to flare to prevent cavitation of the LSR feed pumps to the heaters and boilers during refinery startup.


description_of_release:
During start-up of the No. 1 Crude Unit following the 2010 turn around, the shell side of the depropanizer feed was vented and drained to the flare.


description_of_release:
Planned flaring event during the startup of the Crude 2 Heater (H-2001) with new ultra low NOx burners following the 2010 maintenance turnaround.


description_of_release:
Planned flaring event during the start-up of the Extraction Unit following the 2010 maintenance turn around.


description_of_release:
A dip in power occurred which caused the refinery to go down.  Following the power dip, waste gas from the Extraction Unit was vented to the flare.


description_of_release:
Planned flaring event during the start-up of  the Crude No. 3 Unit.


description_of_release:
Visible emissions were observed from the Crude Unit 1 Auxiliary Heater.  No method 9 certified observer was present, and it is not known whether visible emissions exceeded the threshold of 20 percent for 6 minutes or greater.


description_of_release:
During the start-up of the Extraction Unit following a scheduled maintenance shutdown to repair piping, the unit was vented to the flare.


description_of_release:
Flaring of Crude 3 overhead while performing reflux/water kero flush work.


description_of_release:
Depropanizer overhead to the flare was opened while the refinery was started up from an approximately 6-hour TAPS outage.


description_of_release:
Depropanizer overhead to the flare was opened while the refinery was coming up from a 6 hr and 45 min TAPS outage.


description_of_release:
The depropanizer overhead to the flare was opened as the refinery started up from a 5-hour outage of the Trans-Alaska Pipeline System (TAPS).


description_of_release:
SRU and SCOT Furnaces shut down from liquids in natural gas fuel supply line


description_of_release:
South VRU was shutdown and vapors from truck rack flowed through to stack


description_of_release:
No. 1 Fuel Gas H2S content exceeded 160 ppm when one of the debutanizer pressured up


description_of_release:
Partial shutdown of the Refinery due to a loss of power from the utility company


description_of_release:
A process heat exchanger plugged causing the SCOT Unit to shutdown


description_of_release:
SRU and SCOT Furnaces shut down when the SCOT stripper level fell and the high level tripped in the SRU Knock-out drum


description_of_release:
IPF Test caused the SCOT Unit to shutdown


description_of_release:
During the start-up of the DHT, the sulfiding of the catalyst caused a swing in the SRU


description_of_release:
SCOT Unit flame-out occurred while adjusting the SCOT Unit furnace ignitor casuing the SCOT to shutdown


description_of_release:
Plugged regulator caused the lost of fuel gas proessure causing the SCOT unit to shutdown


description_of_release:
Shutdown 1 FGRU compressor - HC Incident


description_of_release:
Coker Stabilizer PSV pressure transmitter failure - HC Incident


description_of_release:
Amine Unit shut down due to power failure


description_of_release:
Amine Absorber due to issues with level from loss of reflux pumps


description_of_release:
Amine Absorber due to issues with level in Depropanizer OH Receiver


description_of_release:
Starting up the Gasoline Stabilizer, K-301 shut down - HC Incident


description_of_release:
Atmos OH vapors when 1201 Compressor shut down for maintanence


description_of_release:
MM Recycle when DMS Purifier Reflux Seperator opened


description_of_release:
Oil skimmer on DMS discharge sperator - AG Incident


description_of_release:
HC SD due to compressor motor relay trip - HC Incident


description_of_release:
Bringing temp up on reactor and fractionation sections


description_of_release:
High pressure in flare header - HC Incident


description_of_release:
Level instrument malfunction SD HC - HC Incident


description_of_release:
Depressuring light end section for inventory


description_of_release:
#2 H2P conducting PSA testing and tuning


description_of_release:
LP flare line pressured up while #2 H2P was send PSA off gas


description_of_release:
#1 H2P PSA went to 5 bed operation and flare header press increased


description_of_release:
strainers on separator pumps plugged during SU of CCR


description_of_release:
Frozen water line caused the filter to plug at the Cogeneration Unit (which is listed in the Energy Management section of the survey and not as a Process Unit in this survey).


description_of_release:
Seal failure at the Cogeneration Unit (which is listed in the Energy Management section of the survey and not as a Process Unit in this survey).  Had to order additional pump parts.


description_of_release:
Failed gasket on line.  Took unit down safely and repaired the gasket.  During malfunction, emissions were sent to the low pressure flare.


description_of_release:
Problems with the #25 Hydrogen Unit as well as the shutdown of the #8 ULSD HT unit when a compressor on #8 unit shutdown due to a high 2nd stage level caused by the loss of the reflux pump. Emissions were related to SSM maintenance.


description_of_release:
An emergency shutdown of the refinery due to an offsite power failure caused by Entergy.  Total emissions includes emissions associated with SSM Flaring.


description_of_release:
Refinery wide shutdown due to a lighting strike which caused a localized power failure to the Sulfur Plant and Utilities area, with a subsequent loss of instrument air. Total emissions include emission associated with SSM Flaring and various fuel burning.


description_of_release:
A lighting arrestor feeder at contractor village failed shutting down the south loop which resulted in localized power failure to the Sulfur Plant and utilities area.  Total emissions include emission associated with SSM Flaring and various fuel burning.


description_of_release:
The FCCU Waste Heat Boiler experienced a hole in the East side of the shell resulting in the release of SO2.


description_of_release:
Emergency shutdown of #7 FCCU on 11/26/2010 due to loss of Wet Gas Compressor (WGC) motor. WGC motor was replaced on 12/2/2010, and the FCCU was restarted.  Additionally, #5 and #14 units were restarted.Total emissions include emissions from SSM flaring.


description_of_release:
CalEMA SOx Exceedance SA Flare Fuel Gas Imbalance


description_of_release:
South H2 PSA System and Production heater D1465


description_of_release:
Hydrogen Gas Leak on the R-1 Heater at the Hydrocracker


description_of_release:
NAMD H2S Exceedence from Coker (K2 Start-Up)


description_of_release:
NAMD H2S Exceedence (Coker Amine Contractor)


description_of_release:
Unplanned Flaring due to Unit Upset at Isom


description_of_release:
No.1 Coker Frac Tower PRD Release 61PSV5023


description_of_release:
HDS B Compressor Trip Excess Emission Deviation


description_of_release:
Alky Swing Tower OH Accumulator Leak Breakdown


description_of_release:
Sulfur Plant Venting Loss of Instrument Air Tk 619 Venting


description_of_release:
Spill of three to four barrels of Avgast o ground


description_of_release:
Spill of 600 gallons of a 12% solution of sodium hypochlorite to ground


description_of_release:
Leak of 20 to 30 milliliters of hydraulic oil to bay


description_of_release:
Spill of 2 tablespons of cable preserver grease to bay


description_of_release:
SRU4 exceeded BAAQMD SO2 limit of 250 ppm / clock hour when sour water stripper #7 tripped offline.  Did not exceed NSPS Subpart J limit of 250 ppm 12 hour average


description_of_release:
Exceeded 160 ppm 3 hr average H2S limit in FXG when Flexsorb had a foaming event


description_of_release:
DHt heater exceeded permitted Nox limit of 25 ppm (3% O2) during a source test.  Test value = 26.08 ppm


description_of_release:
HGHT exceeded it permitted CO limit of 50 ppm during a source test (measured 141 ppm)


description_of_release:
Heater (F-66) exceeded its permitted CO limit of 400 ppm CO with a value of 450 ppm during a source test


description_of_release:
HRSG 1 (COGEN) exceeded daily allowable SO2 limit of 458 lbs/day on 9 days due to calculation error in alarm programming


description_of_release:
SRU4 exceeded BAAQMD SO2 limit of 250 ppm / clock hour due to failed eductor on sulfur pit.  Did not exceed NSPS Subpart J limit of 250 ppm 12 hour average


description_of_release:
CGP heater exceeded permitted CO limt of 400 ppm during source test with value of 800 ppm


description_of_release:
GTG 1 (COGEN) had Nox excess over 5 ppm limt when steam was lost to the combustion section


description_of_release:
H2S in fuel gas exceeded 3 hour rolling average


description_of_release:
H2S in fuel gas exceed 3 hour rolling average


description_of_release:
Flaring from over-pressurization of tower due to the loss of reflux flow to the tower


description_of_release:
The vacuum reader went positive for less than 1 minute due to the load on the Vapor Recovery System


description_of_release:
Total refinery shutdown was initiated by a loss of power from Department of Water and Power


description_of_release:
Power failure from Department of Water and Power transformer to refinery affected various equipment


description_of_release:
A compressor failed an audio/visual inspection. Compressor leaking VOC >50,000 ppm, which requires repair within 1 day. The compressor could not be immediately shutdown for repair because the companion compressor was down for maintenance.


description_of_release:
SCR lost NH3 flow when the NH3 flow controller tripped closed due to low blower speed resulting from a loose and worn drive belt


description_of_release:
The HCU Foul Water Flash Drum lost its liquid level when the level controller was 40% open.  This allowed the gas to carry over to tank 20426, D-639.


description_of_release:
Decrease of vacuum in the South Area Tank Farm resulted in the increase of pressure of two tanks that were receiving sour and stripped water.  As a result, the pressure/vacuum vents opened to atmosphere as designed.


description_of_release:
A regulator failed in the open position, resulting in high gas rate to compressor which caused it to trip


description_of_release:
Exceeded 250 ppm 12-hour rolling average


description_of_release:
Vent gas leaked for less than one minute from cracked suction piping on SRP sulfur vent blower after blower was shut down due to high vibration


description_of_release:
Hydrocarbon carryover came from refinery and caused an upset at SRP.  The load of gas overwhelmed the incinerator which struggled to maintain temperature.


description_of_release:
Vapor recovery compressor tripped. All vapors were vented to the flare.


description_of_release:
Vapor recovery compressor tripped.  All vapors were vented to the flare.


description_of_release:
Vapor Recovery Compressor 22K38 Shutdown- Flaring


description_of_release:
U24 Ammonia Injection Tank Empty- Level Gauge Broken


description_of_release:
Planned FCC,Alky, PTR,H2P2, HDT Shutdown.


description_of_release:
30F-1 / CO Boiler Shutdown/Start-up- Fuel Gas Regulator malfunction


description_of_release:
Planned HDT, H2 Plant, PrTr, FCC, Alky Shutdown


description_of_release:
72F2 API Incinerator Below Combustion Efficiency Temp


description_of_release:
FCC Slide Valve caused unit shutdown- emissions from Start-Up


description_of_release:
Power failure caused flaring, Reformer and #1 HDS atmospheric dampers to open, cogen to shut down and H-907 firebox to dip below 1400ºF


description_of_release:
Power failure caused flaring, Reformer and #1 HDS atmospheric dampers to open, cogen to shut down


description_of_release:
Power failure caused flaring, Reformer and HDS bypass stacks to open, Cogen shutdown, H-907 temperature dips


description_of_release:
H-101/102 burner management system failed, tripping the heaters and opening the bypass stacks


description_of_release:
H-102 fueled on fuel gas instead of natural gas


description_of_release:
SRU trim air valve malfunctioned causing the SRU to go off ratio, providing inadequate oxygen to SRU.


description_of_release:
High H2S in fuel gas due to problem with DEA system


description_of_release:
Flare release due to DHT vent gas compressor shutdown


description_of_release:
Flare release due to vapor recovery compressor not starting


description_of_release:
Flaring resulting from shutdown of HDT due to leaking flange


description_of_release:
Flaring due to low instrument air pressure


description_of_release:
LPG Flare pilot lights failed to stay lit


description_of_release:
Sulfur pit 1 vapor recovery system blower breakdown


description_of_release:
U 138 sulfur pit vapor recovery system blower breakdown due to vibration


description_of_release:
Sulfuric acid plant vapor recovery blower seal leak


description_of_release:
Flaring due to shutdown of Unit 118-Hydrogen Plant


description_of_release:
High sulfur in flare due to flare gas compressor issue


description_of_release:
High Nox associated with 90-B-401 ammonia flow


description_of_release:
Firewater engine exceeded annual operating hours


description_of_release:
Repair of DAF covers exceeding rule standards


description_of_release:
Water containing hydrocarbons entered excavated trench


description_of_release:
Flaring at UK flare due to loss of GB152 suction


description_of_release:
Nox emissions at cogen associated with Nox analyzer problem


description_of_release:
Opacity at South Flare due to compressors being down


description_of_release:
PM emissions from Cogen greater than limit from source test results


description_of_release:
Internal combustion engines exceeded annual operating hours


description_of_release:
Plugged vapor recovery line at Unit 138 sulfur pit


description_of_release:
Sulfur truck loading without operating vapor recovery system


description_of_release:
Nox emissions at 90-B-401 exceeded emission limit


description_of_release:
Flaring associated with restart of GB-152


description_of_release:
Ammonia injection nozzle plugged causing NOx emissions to rise from U2338 B-520/521 heaters.


description_of_release:
Unexpected excess rust buildup in U200 B-202 preheater combined with wash water to form visible emissions


description_of_release:
During a startup, a process analyzer malfunctioned leading to insufficient O2 to be added to the Claus process. This allowed SO2 to increase.


description_of_release:
Electrical issues caused an emergency shutdown of the K-1 Kiln at the Carbon Plant. During the shutdown, part of the exhaust flow bypassed the baghouse.


description_of_release:
A leaking oxidizer tank caused feed to be pulled and place the unit in hot standby. While in hot standby, possible excess air may have ignited undrained sulfur in the system leading to elevated SO2 levels.


description_of_release:
Unit 250 B-701 heater outlet temperature and duty were reduced while removing feed from the unit. Due to the reduction in temperature and duty, the SCR inlet temp dropped below allowed temperatue causing the ammonia injection to shutdown.


description_of_release:
Unexpected shutdown of third-party H2 caused feed to be pulled from unit. The heaters were operated in low firing mode leading to a low operating temperature. The SCR inlet temperature dropped below the minimum temperature causing a loss of ammonia.


description_of_release:
SO2 emissions exceeded the limit during a startup of the unit.


description_of_release:
Unexpected shutdown of third-party hydrogen supplier caused unplanned shutdown of refinery steam power plant. Lack of steam to the refinery flares caused visible emissions.


description_of_release:
Unexpected shutdown of third-party hydrogen supplier caused unplanned shutdown of refinery steam power plant. Without steam, the refinery was required to shutdown which led to several unit upsets.


description_of_release:
Unexpected shutdown of third-party H2 caused unplanned shutdown of refinery steam power plant. The refinery was required to shutdown which led to several unit upsets.The U235 tail gas incinerator temperature dropped below required operating temperature.


description_of_release:
Unexpected shutdown of third-party H2 caused unplanned shutdown of refinery steam power plant. The refinery was required to shutdown which led to several unit upsets including the Unit 110 H-1, Unit 240 B-101, and Unit 228 B-520 and B-521 heaters.


description_of_release:
Unexpected shutdown of third-party H2 caused unplanned shutdown of the refinery including U246. A NOx excess occurred after heaters were restarted in low firing. Due to the reduction in temperature caused loss of ammonia flow to the SCR.


description_of_release:
The Unit 246 B-801 SCR lost ammonia feed, due to a malfunction of the dilution air pump, for approximately 17 minutes which caused a NOx excess.


description_of_release:
Unexpected shutdown of third-party H2 caused unplanned shutdown of the refinery. NOx excess occurred after heaters were restarted in low firing mode.  The SCR inlet temp dropped below the min temp causing the loss of ammonia flow.


description_of_release:
The U246 B-801 NOx analyzer malfunctioned indicating a false low reading. As a result of the false low reading, the SCR ammonia injection rate decreased below its normal rate.


description_of_release:
The Unit 267 B-601/602 NOx CEM indicated a false low reading due to analyzer plugging. The SCR ammonia injection rate automatically adjusted flow below normal rate. The NOx concentration during this period was estimated using valid historical data.


description_of_release:
While shutting down SRUA for scheduled maintenance, unexpected levels of O2 were recorded during catalyst bed burnout.  This required re-direction of burn-off vapors from TGTU to incinerator stack to insure safe shutdown and minimize startup emissions.


description_of_release:
An electrical short at the flare vapor recovery (FVR) motor resulted in shutdown of both Tank & Flare VR compressors.  This resulted in a sudden increase in excess purge gas to VR that exceeded capacity of FVR compressor to result in unexpected flaring


description_of_release:
During startup of the A-side coker from scheduled maintenance shutdown, a liquid knockout pump failed.  This resulted in automatic safe shutdown of wet gas compressor, G212B, sending a sudden surge of excess gas to flare VR system and to flare.


description_of_release:
During scheduled maintenance shutdown of SRUB, the catalyst bed is subject to elevated temperatures, per written procedure, to safely remove sulfur from SRU for shutdown and to minimize startup emissions.  Sulfur Plant recorded TRS >300ppm 12-hr. ave.


description_of_release:
Electric lube oil pump motor failed resulting in automatic safe shutdown of G212A, coker wet gas compressor.  The abrupt shutdown of the compressor sent excess gases to the vapor recovery(VR) system to result in flaring.


description_of_release:
During startup of SRUB after scheduled shutdown for a repair, excess sulfur from SRUB exited the tail gas unit at elevated levels of TRS >300 ppm (12- hr. ave).


description_of_release:
Sudden & unexpected failure of drive coupling on coker wet gas compressor, G212A, resulted in abrupt shutdown of the compressor.  This sent a surge of excess gases to vapor recovery system(VR) that resulted in flaring.


description_of_release:
Following routine maintenance testing of the emergency-only back-up diesel air compressor, the automatic shutdown switch was inadvertently turned off at the control touch pad.  As a result, compressor remained at idle until switch returned to automatic.


description_of_release:
Loosened electrical wiring in B702 Tail Gas Combustor control box resulted in shutdown of the B702 on indications of flame loss.  This resulted when nearby, routine radiographic inspections interrupted fire-eye data transmission.


description_of_release:
A sudden & unexpected failure of a coker jet pump isolation switch followed by an electrical circuit box malfunction resulted in process upsets & cascading shutdown of the entire refinery.  Excess gases surged to Vapor Recovery system & were flared.


description_of_release:
Following a sudden and abrupt electrical failure, a shutdown of the entire refinery was determined necessary to check the status of equipment.  Equipment were purged sending excess vapors & purge gas to Vapor Recovery system and flared.


description_of_release:
Following a 8/01/10 emergency refinery shutdown, a portable jet pump was mobilized from Texas to cut partially solidified coke from coke drums to allow safe startup. Natural gas blanketing tank vapors were temporarily sent to main flare and combusted.


description_of_release:
During cold start-up of SRUs after 8/01/10 electrical malfunction, heat is used to warm the units per standard procedure.  As a result, elevated levels of SO2 were measured from incinerator stacks until Tail Gas Treatment Unit was fully online.


description_of_release:
An unexpected interruption in supplied electrical power to the B702 Tail Gas combustor controls resulted in automatic shutdown of combustor on flame out.  As a result, incomplete tail gas treatment sent elevated sulfur compounds out the TGTU stack.


description_of_release:
Indications of high liquid levels to the A-side coker wet gas compressor, G212A, resulted in abrupt, automatic safe shutdown of the compressor.  As a result, excess gases were sent at high rates to vapor recovery system that went to flare.


description_of_release:
Indications of high liquid levels to G212A coker wet gas compressor resulted in automatic safe shutdown of G212A.  Excess coker gases surged to Vapor Recovery system and were flared.


description_of_release:
Loosened wiring on switch for steam knockout pot resulted in false indications of high liquid levels at G212A wet gas compressor.  This resulted in automatic safe shutdown of G212A sending excess coker gas to Vapor Recovery and to flare.


description_of_release:
An emergency, facility-wide shutdown was determined necessary to assess damage from the 8/01/10 electrical circuit malfunction.  The equipment was safely purged to the tail gas stack and then incinerator stacks, per normal shutdown procedure.


description_of_release:
Excess oxygen was inadvertently introduced to Tank Vapor Recovery(TVR) system during Shands & Jur pressure control valve maintenance.  This resulted in automatic shutdown of TVR compressor to cause PRD to lift briefly on Recovered Oil storage tank,Tk101.


description_of_release:
Varec valve leakage at Tank Tank 551, a Pressure Distillate storage tank, resulted in release to air.  Incorrect set points on Varec resulted in failure to alarm operators of situation.  Worn seats & gaskets found on inspection.


description_of_release:
During maintenance activity, SRUB power switch was unexpectedly shutoff by falling debris to suddenly shutdown power to the unit.  This resulted in units overpressuring to send an abrupt surge of excess gas to Vapor Recovery(VR) system and flaring.


description_of_release:
VENTING #3 REFORMER AND #3 HDS UNITS FOR SCHEDULED MAINTENANCE; FGRC SHUTDOWN ON PRESSURE CONTROL.


description_of_release:
STARTING UP FCCU AND 4 GP, PRODUCING TOO MUCH FUEL GAS, NOT ENOUGH CONSUMERS, RFG MIXPOT FLARING.


description_of_release:
EMERGENCY SHUTDOWN OF #7 BOILER WITH FCCU UPSET


description_of_release:
H2S KO POT (V207) RELIEF TO FLARE HEADER AT ARU


description_of_release:
LEAK IN OVERHEAD LINE RELEASED SOUR WATER


description_of_release:
FIRE AT #3 HDS, DEPRESSURED THE UNIT TO FLARE HEADER. ALSO SCOT BLOWER FAILURE, SCOT REACTOR BYPASS VALVE MALFUNCTION.


description_of_release:
UNPLANNED SHUTDOWN OF SRU/SCOT FOLLOWING ISSUES AT CHEM PLANT. PROCEDURE CALLS FOR FGRC TO BE SHUTDOWN.


description_of_release:
IN PREPARATION FOR STARTUP OF SAP, HAD PROBLEM WITH ACID GAS FEED TO AIR RATIO CONTROL.


description_of_release:
SCOT BLOWER OVERLOADED WITH HIGH FLOW, TRIPPED OFF-LINE ON HIGH AMPERAGE FOR MOTOR.


description_of_release:
STARTING #2H2 PLANT UP, OFF SPEC H2 TO FLARE HEADER UNTIL QUALITY IMPROVES


description_of_release:
PACKING FAILURE ON SOUR WATER VALVES AT CHPS AT #3 HDS, REQUIRING A UNIT SHUTDOWN.


description_of_release:
OPERATIONAL ISSUES OCCURRING ON STARTUP.


description_of_release:
HCR EMERGENCY SHUTDOWN WHEN HIR WENT DOWN.DEPRESSURED TO FLARE, DECREASED #2H2 PLANT PRODUCTION.


description_of_release:
MAINTENANCE WORK ON WET GAS COMPRESSORS CAUSED H2S RELEASE.


description_of_release:
#2 H2 PLANT START-UP, PUTTING OFF-SPEC PRODUCT TO FLARE HEADER


description_of_release:
HCR STAGE 2 CHARGE PUMP TRIPPED OFFLINE AND THEN IIR COMPRESSOR TRIPPED. DEPRESSURED THE UNIT, CAUSING FLARING.


description_of_release:
FIRE ON TANK SEAL AT TK-650. COMBUSTION PRODUCT OF FIRE


description_of_release:
TOTAL POWER OUTAGE AT REFINERY. SLOW UNIT RESTART, WITH FLARE RECOVERY COMP NOT ON LINE UNTIL 11/14.


description_of_release:
#2H2 PLANT START-UP FOLLOWING FOLLOWING UNIT TRIP AND SUBSEQUENT REPAIRS.


description_of_release:
REFINERY WIDE POWER OUTAGE WITH LOSS OF SWITCHING STATION 7.


description_of_release:
SCOT BLOWER MOTOR HAD A SHORT IN THE WINDINGS AND TRIPPED THE UNIT OFF-LINE.


description_of_release:
#2H2 PLANT TRIPS OFF-LINE, PROBLEMS WITH PSA UNITS, HYDROGEN IMBALANCE


description_of_release:
Breakdown of boiler 86-B-9002 caused elevated CO emissions


description_of_release:
Hydrogen booster compressors shutdown caused high CO for 56-H-2 and Phase 1 Flare


description_of_release:
Fuel gas sulfur exceeded permitted limit of 100 ppm


description_of_release:
CO exceeded permitted limit of 40 ppm for 56-H-1/2 and no NH3 injected above 475 F in the SCR


description_of_release:
Loss of Ammonia flow to the SCR connected to 86-B-9002


description_of_release:
Breakdown for compressor 93-C-9001 resulted in a Rule 1118 flare event


description_of_release:
No NH3 injected above 475 F in the SCR which resulted in excess NOx emissions for 56-H-1/2


description_of_release:
Breakdown of compressor 44-C-4000 resulted in flare event


description_of_release:
Power interuption due to failure of Cable D on Bank 6 in IS 2233 (Phase A) for 86-B-9002


description_of_release:
CO exceeded permitted limit of 50 ppm for 86-B-9002


description_of_release:
CO exceeded permitted limit of 50 ppm, NOx exceeded permitted limit of 9ppm for 86-B-9002


description_of_release:
Scheduled shutdown of Diesel Hydrofining Unit


description_of_release:
Ammonia/H2S Fractionator Tower (T-2831) Valve Leak (28P081)


description_of_release:
Scheduled shutdown of Virgin Naptha Hydrofining Unit (VNHF) Reactor (R-101)


description_of_release:
Alky Unit Shutdown and C-2101A/B Maintenance


description_of_release:
Flaring due to C-101C Maintenance and C-2101B


description_of_release:
Flaring due to Hydrocracker Unit (HCU) Startup


description_of_release:
Flaring due to operational difficulties of Flare Gas Compressors C-2101A/B


description_of_release:
Flaring due to Emergency Depressuring of the Hydrocracker Unit (HCU) caused by Gas Turbine GT-401 Trip


description_of_release:
Flaring due to emergency shutdown of FCCU and subsequent restart attempts


description_of_release:
61 gallon crude oil with diesel fuel leak


description_of_release:
[2 Amine pumps malfunctioned, shutting down SCOT Unit] Excess SO2 - Tail Gas Unit Shut Down & By-pass


description_of_release:
[Upset of the HGU Extinguished Flare & Pilot] Flare & Pilot Extinguished


description_of_release:
[Auto-vent found open] Naptha TK202 Auto-Vent Open / Excess Emissions (62 Days)


description_of_release:
[Auto-vent found open] Naptha TK204 Auto-Vent Open / Excess Emissions (97 Days)


description_of_release:
[DHC Depressurization system being activated] Excess SO2 - DHC Shutdown & Release to Flare


description_of_release:
[Auto-vent found open] Naptha TK405 - Auto-Vent Open / Excess Emissions (32 Days)


description_of_release:
[Turbine Malfunction and Compressor Shutdown; DHC shutdown] Excess SO2 - TU601 Malfunction / DHC Shutdown & Release to Flare


description_of_release:
[Upset and by-pass of SCOT tail gas unit] Excess SO2 - TGU Upset and By-pass - exceeding CEMS limit


description_of_release:
[Upset in SCOT - Acidic gas vented to Flare] Excess SO2 & O2 - TGU Upset  - exceeding CEMS limit


description_of_release:
[2 DHC Shutdowns led to SO2 exceedence from Flare] Excess SO2 - DHC Shutdowns & Release to Flare


description_of_release:
[Power supply interruption; 2 DHC depressurizations ] Excess SO2 - Power Interuption / DHC Shutdown & Release to Flare


description_of_release:
[Valves unexpectedly closed during TGU maintenance] Excess SO2 - SRU2 Shutdown and TGU Bypass


description_of_release:
[DHC Debutanizer piping leak] Hydrocarbon Release - DHC Outlet Piping Leak


description_of_release:
[Flare & Pilot Extinguished] Flare & Pilot Extinguished


description_of_release:
[Steam Control Valve (not responsive)] Flare Opacity Excursion (Refinery Turnaround - Shutdown)


description_of_release:
[Crude Unit, Other units starting up] Flare Opacity Excursion (Refinery Turnaround - Startup)


description_of_release:
[Problems re-starting the Sulfur Recovery Units] SRP Re-start - Tail gas directly to H1391


description_of_release:
[SRU3 Analyzers deficiencies] Excess SO2 - Start-up of SRP


description_of_release:
[DHC Depressured] Excess SO2 - Unplanned DHC Shutdown & Release to Flare


description_of_release:
[DHC & TGU shutdowns] Excess SO2 - TGU Shutdown & By-pass; Amine Pump Repair & SCOT damaged


description_of_release:
[WTU CVS (closed vent syst)] Excess VOC Emissions from WTU to Carbon Cannisters after TOU re-started


description_of_release:
[SCOT unit shutdown] SCOT Shutdown & Tail Gas Unit By-Passed


description_of_release:
[CDU flow change] CDU Opacity Excursion (Crude switch)


description_of_release:
[Valves subject to MACT ] Addition of Sources to LDAR Program (Valves Subject to MACT previously overlooked)


description_of_release:
[9 OWS Junction Boxes (seal gaps)] Missed 2010 QQQ Inspection of 34 Junction Boxes


description_of_release:
Vacuum vent gas compressor shutdown due to high vibrations during Unit 107 re-start. Related to relief on 107E-22/23 lifting.


description_of_release:
Vacuum vent gas compressor shutdown due to high vibrations


description_of_release:
Vacuum vent gas compressor 844GB-4A/B shutdown intermittently during upset at Unit 107.


description_of_release:
Material sent to pump-out while 111E-5A&B were put back in service


description_of_release:
Coker wet gas compressor manually tripped caused Crude unit shutdown. Plus sulfur train was shutdown for scheduled maintenance.


description_of_release:
FCCU automatically shutdown by SIS after malfunction of main column bottoms system. FCCU was then re-started.


description_of_release:
Unplanned shutdown of C-train resulted in unit moves, affecting MEA regenerators. C-train Stretford absorber was plugged with condensed sulfur.


description_of_release:
Flaring when SP flare gas recovery compressor (844GB-401) shutdown on low suction pressure


description_of_release:
Train undergoing maintenance following C-train shutdown on 4/1/2010


description_of_release:
Flaring at 844C-1 due to installing blinds at Unit 217 (Sat. Gas Unit) battery limit in preparation for shutdown.


description_of_release:
Flaring during planned Crude/Sat. Gas slowdown due to warmer weather and increased venting of the atmospheric accumulator.


description_of_release:
Train was off-line and preparing for re-start


description_of_release:
Flaring caused by atmospheric tower overhead pressure due to hot outside air temperature


description_of_release:
Shutdown for maintenance (heat soak/catalyst burnoff)


description_of_release:
B-train start-up following maintenance. Flaring at 844C-1 due to pulling blinds at Unit 217 battery limit at end of shutdown in preparation for startup. Flaring when Unit 217 lowered liquid level in 17F-3 3rd stage suction drum to the flare during startup


description_of_release:
Intermittent flaring occurred when Unit 109 PSA valve 19112 failed. This caused PSA skid to auto switch from a 10 bed to 8 bed operation resulting in flare valve 09P-406 to open, sending mix of hydrogen, CO and CO2 to the flare.


description_of_release:
Loss of vacuum vent gas compressor caused flaring


description_of_release:
Flaring caused by unit tripping off-line due to malfunctioning breaker


description_of_release:
Unit sales gas sytem upset caused fuel gas flare


description_of_release:
Relief of fuel gas to the flare. Cause unknown


description_of_release:
Charge rate increase at crude heaters caused excess CO concentration.


description_of_release:
Unplanned plant shutdown due to loss the power


description_of_release:
Flaring occurred when relief valve opened during Unit 115 start-up


description_of_release:
Re-start of CO Boiler West FD fan following maintenance


description_of_release:
Flaring due to excess fuel gas when SPCT turbine was taken off-line for steam conservation (associated when planned shutdown of Aux Boiler).


description_of_release:
Flaring at 844C-1 when 44GB-403B compressor tripped out due to low sour water flow.


description_of_release:
Flaring when fuel gas system over-pressurized.


description_of_release:
Propane valve froze and led to propane being vaporized into fuel gas.


description_of_release:
Flaring due to crude unit main column overhead loss of cooling


description_of_release:
South Plant Flare Gas Compressor shutdown due to power flucuations


description_of_release:
Flaring when fuel gas system over-pressurized


description_of_release:
Flaring due to unplanned shutdown of FCCU casused by near lightning strike. Strike caused wet gas compressor to short out.


description_of_release:
Intermittent flaring due to FCCU startup and Crude Unit upset. D-train startup following FCCU outage


description_of_release:
Process upset.  Bringing new ULSD unit on line


description_of_release:
C-train shutdown due to SIS control problem. Feed rate at D-train increased and caused train to go off-ratio.


description_of_release:
Flaring due to loss of vacuum vent gas compressor


description_of_release:
Flaring due to problem with Unit 109 steam methane reformer


description_of_release:
Heater operation upset and train shutdown due to partial loss of power in the refinery. Air leakage in train caused sulfur on catalyst to oxidize. FCCU startup and line-out. Flare due to loss of power in SP due to electical fault at 15kV interruptor.


description_of_release:
Alky start-up vaporizing propane caused pressure swing in fuel heater. Loss flare gas recovery for 9 minutes, hydrogen going to fuel gas.


description_of_release:
FCCU shutdown intermittently due to power outage at Crude unit and for maintenance and evaluation. Train taken off-line during this time for maintenance.


description_of_release:
Train start-up following maintenance and FCCU start-up and line-out.


description_of_release:
U103 stripper overhead upset due to cold weather


description_of_release:
Release due to 44GB-4A/B vent gas compressor malfunction


description_of_release:
RV lifted following an upset in U102 causing flaring


description_of_release:
Flared sales gas from 12GB-401A due to local controllers for 2nd and 3rd stage KO drums being open


description_of_release:
Extreme cold temperatures, offgas line from Crude Discharge separator froze.  Opened valve to flare until frozen obstruction could be removed.


description_of_release:
The Amine Flash Gas Line to FCC froze, causing the North Amine Flash Drum to overpressure and relieve to the flare.


description_of_release:
Reformer booster compressor control valve was not responsive, resulting in compressor shutdown, resulting in fuel gas overpressure to the flare.


description_of_release:
Level indicator read a false value.  Once the receiver level was verified, the level was dumped to the stripper, and stripper overpressured to the flare.


description_of_release:
During routine safety checks on the Alky Unit High Integrity Protection System (HIPS), the HIPS inadvertently activated causing a unit shutdown and flaring.


description_of_release:
During inspection, found a vacuum breaker vent open on Tank 319, when the tank level indicator showed liquid level at 7.5', whereas design basis is vent opening at 5.33'.


description_of_release:
During shipment of finished gasoline from Tank 404 to pipeline, tank level indicated 5'11" when the operator shutdown pumps, whereas design is for vents to open at 5'.  Both roof vents were found open after the pumps were shutdown.


description_of_release:
Shortly after attempting to put the HGO side stream stripper in service, the Coker HGO circuit plugged off causing a lack of heating medium for the fractionating absorber, causing lighter ends to reach the Coker Debutanizer and overpressure to the flare.


description_of_release:
Level in knockout drum in the overhead system of the Coker rapidly increased, resulting in the Coker compressor shutting down and gases routed to the flare.


description_of_release:
Coke fines were dislodged in follow-up from another incident.  These fines increased fouling of a heat exchanger and decreased heat into the Coker fractionator.  The loss of fractionation resulted in overpressuring to the flare at a downstream unit.


description_of_release:
P01011 transmitter failed reading high. Control valve reacted (opened) to reduce tower pressure to the flare.


description_of_release:
A flue gas leak was identified by operations at the Expander Drop Out Boot (4-D-28), between the 3rd Stg Sep and the Expander Inlet Valve.


description_of_release:
A tube failure occurred in the FCC's West CO Boiler, resulting in a rapid loss of level in the steam drum, which in turn initiated a safety interlock to shut down the boiler.


description_of_release:
Unit upset caused by shutdown on 2-G-2 resulted in overpressure of 2-D-54 (2nd stage recontact sep).  The Inlet flange to the in service PSV leaked hydrocarbon to the atmosphere. Note: PSV did open at design pressure.


description_of_release:
Fuel gas sales and steam addition to front end of the main air blower was unable to remedy the fuel gas pressure increase before coke drum was switched to the blowdown sequence. Mix drum pressure valve P59081 opened to the flare.


description_of_release:
The pressure relief valve on the off-spec propane line frosted up, indicating that the RV was relieving to the flare.  An employee noticed the frosted line and the issue was addressed.


description_of_release:
During an Alky drier switch, the back pressure controller (P07047) closed to control the feed pressure.  One or more RV's in the feed section relieved to the flare when the controller failed to reopened.


description_of_release:
An upset in the feed to the gas plant led to 8-D-3, 8-D-4, and 8-D-22 lifting to the flare. These vessels were having high level problems, and some of the liquid was blown down to vents and drains (flare).


description_of_release:
Aux Sable's pipeline shutdown with no notification to ExxonMobil.  This caused high fuel gas header pressure. The high fuel gas header pressure caused HC59081 to open venting RFG to the flare.


description_of_release:
Storm caused refinery 600# steam header pressure to drop to about 495#, this did not allow the WGC to pump and flaring occurred.


description_of_release:
Noticed South flare flow F49003 increased. Upon investigation, found PSV52011 lifting to the flare header.


description_of_release:
PSV59081 opened to the flare due to fuel gas mix drum overpressure.


description_of_release:
During routine sampling of the General Cooling Tower, LEL was found to be elevated in the water sample. Upon investigation, the 6-E-7A/B (Coker Compressor Intercooler) was found to have a tube leak.


description_of_release:
6-G-14 compressor malfunctioned and shut down, resulting in unit flaring.


description_of_release:
Incorrect line-up of PGP caused PSV52011 to relieve to the flare.


description_of_release:
Tank 204 inspection identified a small, localized exterior corrosion hole, resulting in seepage to the tank roof.


description_of_release:
The Catalytic Hydro-Desulfurization (CHD) Unit’s Total Gas Compressor (3-G-71) experienced a seal failure that resulted in a loss of containment.  As a result, operators depressurized the CHD to the flare per emergency procedures.


description_of_release:
As a result of a seal failure (see CHD emergency shutdown), a ground fire occurred at compressor 3-G-71.


description_of_release:
As a result of responses to the CHD seal leak, fire and unit shutdown, hydrocarbon was carried over to the SSRU.  As a result, unconverted H2S passed into the SSRU tailgas cleanup unit.


description_of_release:
During the CHD emergency shutdown, a fire occurred at the flare thru FG Mix Drum (59-D-301)


description_of_release:
Intermittent pluming was observed at the NSRU sulfur pit air intake vent.  The eductor system was shutdown and vent piping was hydroblasted to clear the blockage and return the eductor to service.


description_of_release:
1st stage suction flow to 5-G-14, F05001, failed causing the 1st stage spillback to open 100% to 4-D-11 which resulted in P04018 opening to the flare.


description_of_release:
While a contractor was gauging Tank 224, a hole developed in the roof where he was standing to properly gauge the tank.


description_of_release:
P01009a (Atmos Tower) reached set point, and opened P01011SS (Selector Switch) to the flare.


description_of_release:
While x-raying was being performed in the SWS unit, the Acid Settler level (L07045) received a bad input and the HIP's system tripped the Alky Unit, resulting in a unit shutdown and flaring.


description_of_release:
Propane KOH Treater PSV started weeping propane to the flare.


description_of_release:
Intermittent pluming was observed at the North Sulfur pit.  A partial plug on the downstream piping was found to be restricting the flow of pit vapors to the Thermal Oxidizer.


description_of_release:
Unit abnormal operations (1C-14, 1C-34, 1K-1)


description_of_release:
Unicracker and DHT depressurization valves leaked


description_of_release:
64C-2 pressured up for unknown reason and relieved to flare


description_of_release:
Overhead fans froze causing venting to flare


description_of_release:
64C-3 overhead receiver bleeder was left open


description_of_release:
23PC0300 failed causing 23C-8 to relieve to the flare


description_of_release:
16PC1350 opened and vented 16C-2 blanket gas to the flare


description_of_release:
At approximately 2322 hours on March 14, 2010, the air valve to the 66F-1 Tail Gas Heater failed and caused the Plant 66 TGTU to shut down.


description_of_release:
A leak at the Penex unit required a unit shutdown


description_of_release:
Relief valve relieved to flare during reactor switch


description_of_release:
03PSV16 relieved due to chloride plugging in overhead fans


description_of_release:
Tank 21D-951 vacuum breaker was open while tank was at low-low operating level


description_of_release:
07PSV-9 on 7E-22 dryer heater leaked to flare


description_of_release:
73G-2b seal leaked to seal pot vented to the flare


description_of_release:
4K-2A second stage suction valve leaked causing 4PSV-11A to relieve to the flare


description_of_release:
1C-37 overpressured due to 1K-1 shutdown


description_of_release:
Top head of exchanger 7E-28 leaked to atmosphere


description_of_release:
1K-1 shutdown due to liquid carryover into knockout drum; relieved to flare


description_of_release:
merichem startup from FCCU unplanned shutdown


description_of_release:
1C-34 level indicator had false indication causing 1K-1 shutdown


description_of_release:
This release from the refinery flare system occurred due to the failure of the Crude Unit preflash overhead product drum (1C-37) level indicator, 01LC0580.


description_of_release:
Naphtha Splitter overpressured; bypass opened around PSV


description_of_release:
Naphtha Splitter overhead receiver bypass opened


description_of_release:
Seal on 77G-5A/B leaking; depressured to flare


description_of_release:
Startup from unplanned shutdown. Flared 1C-1 during startup


description_of_release:
1E-24B stopped running causing an overpressure


description_of_release:
Startup from Turnaround Maintenance. Flare 1C-1 during startup


description_of_release:
Unit shutdown due to Unit 16 shutdown for Turnaround maintenance


description_of_release:
Unit shutdown due to loss of hydrogen from the Platformer


description_of_release:
Unit startup after shutdown due to Unit 16 shutdown for Turnaround maintenance


description_of_release:
16K-3 shutdown due to electrical problems; vented excess hydrogen


description_of_release:
Water draw valves on 7C-10 were left open to the water draw boot which was vented to the flare


description_of_release:
07PSV-09 was frosted up and leaking to the flare


description_of_release:
07PC-0052 was frosted up and leaking to the flare


description_of_release:
Unit shutdown due to 16F-3 - emissions based on similar event on 11/21/10


description_of_release:
Abnormal operations caused sour water flash drum to overpressure and relieve to flare


description_of_release:
Unit shutdown; fire later at east side of unit


description_of_release:
CO exceedance above 500ppm due to a FCCU-1 CO Heater instrument air line failure.


description_of_release:
HTR-HP1 exceeded CO limit during startup due to low firebox temperatures and low combustion efficiency.


description_of_release:
SZU exceeded SO2 permit limit due to loss of caustic flow to scrubber


description_of_release:
HTR-BEU-H3 exceeded 200 ppm CO limit due to partial process unit shutdown


description_of_release:
FCCU-1 exceeded 500 ppm CO for a single hourly average due to a FCCU-1 CO Heater trip.


description_of_release:
VOC flare tripped due to loss of vacuum.  CH-278 conservation vent lifted twice causing VOC gases to vent to the atmosphere.


description_of_release:
HTR-BEU-H3 exceeded 200 ppm CO limit due to rapid change in BEU operating conditions due to an equipment leak


description_of_release:
HTR-BEU-H3 exceeded 200 ppm CO limit during startup


description_of_release:
North Property Flare, Aromatics North Flare, Aromatics South Flare, and FCCU-1 exceeded emission limits due to external power outage during rain and lightning storms..


description_of_release:
North Property Flare, Distilling West Flare, and FCCU-2 exceeded emission limits due to external power outage during rain and lightning storms.


description_of_release:
Distilling Flare exceeded 2000 ppm SO2 to flare (hourly average) due to pressure spike in the flare gas header.


description_of_release:
Distilling West Flare exceeded 2000 ppm SO2 to flare (hourly average) due to external power failure which shutdown the DCU-1 wet gas compressor.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) and 2000 ppm SO2  to atmosphere (hourly average) due to an external power outage which shutdown the FCCU-1 wet gas compressor.


description_of_release:
Distilling West Flare exceeded 2000 ppm SO2 to atmosphere (hourly average) due to external power outage during rain and lightning storms.


description_of_release:
North Property Flare, Distilling Flare, Distilling West Flare, WWTP, MP FGT, HTR-BEU-H3, HTR-VF4-H28, SRU-1, SRU-2A, SRU-2C exceeded emission limits due to an external power outage.


description_of_release:
North Property Flare gas recovery compressor shutdown per safe operating procedure for planned maintenance activity.


description_of_release:
Bypass of FCCU-2 air pollution control devices due to an electrical malfunction.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a pressure spike in the flare gas header.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) and 2000 ppm SO2  to atmosphere (hourly average) due to a loss of the FCCU-1 and FCCU-2 wet gas compressors.


description_of_release:
North Property Flare and Aromatics South Flare exceeded emission limits due to an external power outage.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) and 2000 ppm SO2  to atmosphere (hourly average) due to a FCCU-2 wet gas compressor trip.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) and 2000 ppm SO2  to atmosphere (hourly average) due to a partially obstructed suction line on the flare gas recovery compressor.


description_of_release:
Distilling Flare exceeded 2000 ppm SO2  to atmosphere (hourly average) due to a plugged pressure tap on a pressure control transmitter.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) and 2000 ppm SO2  to atmosphere (hourly average) due to a valve malfunction.


description_of_release:
Distilling West Flare exceeded 2000 ppm SO2  to atmosphere (hourly average) due to a valve malfunction.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to pressure spike in the flare gas header.


description_of_release:
LSG Flare pilots went out for 11 min due to the amount of steam going to the flare tip of the flare and deinventoy of the equipment.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) and 2000 ppm SO2  to atmosphere (hourly average) due to a power failure.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) during FCCU-2 and RAU process unit shutdown.


description_of_release:
Distilling Flare gas recovery compressor shutdown per safe operating procedure for planned maintenance activity.


description_of_release:
Distilling Flare exceeded 2000 ppm SO2  to atmosphere (hourly average) due to a FCCU-1 wet gas compressor drive motor malfunction.


description_of_release:
Distilling Flare startup following planned maintenance activity.


description_of_release:
Distilling Flare gas recovery compressor shutdown due to pluggage in a liquid line from a knock-out pot causing the Distilling Flare to exceeded 2000 ppm SO2  to atmosphere (hourly average).


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) during DU-2MC process unit startup due to a sour water stripper pump malfunction.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a FCCU-2 wet gas compressor mallfunction.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a heat exchanger leak.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a valve malfunction at FCCU-2.


description_of_release:
Bypass of FCCU-1 air pollution control devices due to damage to the FCCU-1 CO Heater


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to mechanical failure of the electrical controller on the FCCU-2 south air blower.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a water boot level controller malfunction.


description_of_release:
Emergency shutdown of the SZU due to process unit fire.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) during FCCU-2 and RAU process unit startup.


description_of_release:
MP FGT exceeded 162 ppm H2S (3-hour rolling average) due to loss of adequate fuel gas treating


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a change in pressure which caused a release of residual sour material from a prior incident downstream of the flare seal vessel.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to a level transmitter malfunction.


description_of_release:
North Property Flare exceeded 162 ppm H2S to flare (3-hour rolling average) due to pump malfunction.


description_of_release:
Flaring event - RV bypass open on Sour Water Stripper


description_of_release:
SRU A/B/C Trains trip and Tail Gas to Incinerator


description_of_release:
D-397 Disulfide oil vapors vented to atmosphere


description_of_release:
J-3G Wet Gas Compressor recycle and flaring


description_of_release:
J-3D flaring from loss of steam pressure


description_of_release:
D-1A Sour Water Drum vented to FCU flare


description_of_release:
D-341 RV bypass opened to lower pressure


description_of_release:
LPG leak downstream of T-3 control valve


description_of_release:
D-401 inlet line repairs and gas release


description_of_release:
Process Upset due to scrubber vent nozzle blockage


description_of_release:
Leak in the spent catalyst recirculation line


description_of_release:
Mechanical Failure standpipe sprung leak (shutdown)


description_of_release:
Mechanical Failure standpipe sprung leak (startup)


description_of_release:
Mechanical Failure quench column blockage


description_of_release:
Process upset Amine regenerator carryover to incinerator


description_of_release:
Startup of refinery after scheduled refinery turnaround


description_of_release:
NCRA personnel were inspecting a control panel on the recycle gas comprssor in the Unicracker.  When the control panel was opened an interlock was tripped and subsequently shutdown the unit.  This caused a low rate depressure to the flare


description_of_release:
A lightning strike on the local power grid caused a power fluctuation at the NCRA Refinery.  The power fluctuation tripped the recycle compressor in the Unicracker which caused a low rate depressure to the flare.


description_of_release:
Shutdown of the refinery for scheduled refinery wide turnaround


description_of_release:
Contractors caution tape was pulled into air fan for the CO Boiler which caused the CO Boiler and ESP to trip due to vibration in the fan


description_of_release:
Sample line on CEMs froze off causing a false high oxygen reading.  This in turn caused the safety interlock to trip the ESP.


description_of_release:
Analyzer malfunction caused the CO and O2 to spike.  This in turn caused the ESP to trip due to a safety interlock.


description_of_release:
A one inch slop line came apart and allowed slop oil to be released to the ground


description_of_release:
Level control in oily water sewer sump failed resulting in overflow


description_of_release:
Expansion sleeve leaked on piping at gasoline Tank J-12


description_of_release:
CAT Gasoline KO drum sight glass broke and leaked to the ground


description_of_release:
RV release of distillate to soil in Tank Farm


description_of_release:
Heavy rains resulted in a waste water treatment bypass.


description_of_release:
#2 Crude Line failed and began to leak underground


description_of_release:
Heavy rain resulted in waste water treatment system bypass.


description_of_release:
A gasoline spill occurred while trying to remove an old foam seal out of a tank.  The seal was to be replaced and had become saturated with gasoline.


description_of_release:
Oily Water Sewer overflow to storm water


description_of_release:
Naphtha line release due to a seal flush failure


description_of_release:
Draining vessels at turnaround caused waste water system to overflow to storm water.


description_of_release:
Release from opening flare line for Maintenance activities.


description_of_release:
Waste water surge resulted in API lift station over flow


description_of_release:
Acid gas flaring: When LPGT-1 pressure control valve failed to open, the amine acid gas from LPGT-1 went to the flare.


description_of_release:
Acid gas flaring due to SRU2 trip due to high level in KO drum caused by HC  from Gofiner.


description_of_release:
Flaring acid gas due to overpressure at AU1


description_of_release:
Acid gas flaring from SRU3 off-ratio resulting in SD of incinerator & SRU2/3


description_of_release:
Acid gas flaring from power blip resulted in multiple unit shutdowns.


description_of_release:
Acid gas flaring resulted from incinerator tripped and tripped SRU3.


description_of_release:
Excess tailgas emissions at incinerator due to overpressure at AU1


description_of_release:
Excess tailgas emissions due to power blip resulted in multiple unit shutdowns .


description_of_release:
HC flaring due to excess gases in flare header


description_of_release:
HC flaring resulted from lost east flare seal from PUG problems


description_of_release:
HC flaring resulted from failure of E compressor


description_of_release:
HC Flaring due to power loss during T-storm


description_of_release:
HC flaring from Alky #1 Rerun tower upset


description_of_release:
HC flaring resulted from J-160 Trip related to vacuum unit problems


description_of_release:
HC Flaring due to plant upsets & shutdowns


description_of_release:
Drain valve on F2616 open resulting in HC flaring


description_of_release:
HC flaring resulted from FCCU vented the Depropanizer feed surge drum due to high pressure; Then on 9/2 J-160 tripped


description_of_release:
HC flaring due to rupture disk on propane tank 204 failed;


description_of_release:
HC flaring due to Shutdown ARU & venting extractor tower & Gascon stripper tower high on pressure


description_of_release:
HC flaring due to planned shutdown HTU5 and FGRU


description_of_release:
HC flaring due to HTU5 Makeup Recycle H2 B compressor tripped leading to shutdown of HTU5


description_of_release:
HC flaring due to power blip resulted in multiple unit shutdowns


description_of_release:
HC flaring resulted from planned shutdown FGRU for HGU1 startup.  Includes J-160 trip


description_of_release:
J4401D down, J4401B stopped pumping resulting in HC flaring


description_of_release:
HC flaring due to depressured Isotherming reactor N2 to flare to repair leaking 3rd level dump nozzle


description_of_release:
A waxy oil was discovered on the alky lake that discharges to the Big Sandy River. Believed to be due to hydrocarbon in steam header


description_of_release:
Draining gasoline filter at blender and gasoline backed out of drain


description_of_release:
Cumene NESHAP line leaked at aliphatics manifold


description_of_release:
Pumped water to ditch line instead of OWS leading to sheen on outfall 007. Hydrocarbon LCO


description_of_release:
Bottom flange on filter pot was found leaking


description_of_release:
Water from NESHAP sewers overflowed into area around tank 860


description_of_release:
Pump was backing up in Sulfolane unit to the steam header that trapped out at 64 tank.


description_of_release:
Stripper overhead over pressurized and relieved to flare


description_of_release:
Cutter washing stock recycle line led to pump failure and leaked slop oil


description_of_release:
Stripper bottoms at Sulfolane unit to recovery column relief valve leaked


description_of_release:
Pin hole leak was discovered on Diesel Flush oil line in WWTP. Line went to Tank 890.


description_of_release:
During circulation of Cutter stock through #4 Vacuum unit, temporary piping blew out through gasket.


description_of_release:
Less than 1 gallon of fuel oil was leaked by fuel oil blowdown line pin hole leak.


description_of_release:
A NESHAP line was found leaking in the fuel gas area. 10 gallons leaked onto asphalt


description_of_release:
NPT overhead line leak found in the pipe rack


description_of_release:
Small leak was found in the NESHAP line near guard case going to the sewer.


description_of_release:
Leak ehen the H2 line developed a crack.


description_of_release:
Distillate was spilled when tubing blew off transmitter during unit startup.


description_of_release:
Flaring during startup of the Sat Gas Unit


description_of_release:
Pump was found leaking at the union. Pump was not running when leak was found. 4 gallons to gravel and 16 gallons to NESHAP.


description_of_release:
Leak in an old asphalt line put 5 gallons of asphalt to the soil.


description_of_release:
ADS Tower leak of liquid from behind insulation.


description_of_release:
Oil sheen found in ditch in South Area. Found kerosene line valve leaking.


description_of_release:
Vent hose was found to be leaking LCO at tank 153


description_of_release:
During excavation, underground abandoned pipe broke releasing 5 gallons of distillate


description_of_release:
Raffinate from piperack leaked into oily water sewer


description_of_release:
Out of service line leak led to one gallon of diesel on the surface of excavation water.


description_of_release:
Cooling water line leak put crude on gravel believed to have been in the pit prior to leak


description_of_release:
Relief valve in LPVGO relieved to flare due to an increase in overhead pressure


description_of_release:
While washing a line, residual gasoline spilled onto the ground


description_of_release:
Pin hole leak on gasoline pump to NESHAP


description_of_release:
Isobutane leak on isobutane recycle analyzer building.


description_of_release:
Leak from relief valve on VGO line to oily water sewer


description_of_release:
A plug came off of a pressure transmitter causing six gallons of slop oil to spill onto gravel.


description_of_release:
Sewer box overfilled into storm water ditch due to heavy rains causing less than 25 gallons of oil to be released into ditch. All free oil was contained.


description_of_release:
Rail car leak caused asphalt to overfill and spill over onto gravel.


description_of_release:
Leak was found in a NESHAP line going from Viney Branch terminal to a slop tank in the WWTP. Two gallons of oil leaked to the ground.


description_of_release:
Leak in the NESHAP line to the oily water sewer to soil.


description_of_release:
Loading of product containing 60% benzene over two days. VDU was not required.


description_of_release:
Relief valve on Amine scrubber relieved to flare.


description_of_release:
Acid gas line leaked from pin hole leak in Amine unit.


description_of_release:
ADS was found leaking in the center well line - 1 quart of CTLO.


description_of_release:
NNA flare drum line was found leaking by the centrifuge.


description_of_release:
NESHAP line had slight leak on Hydeal Blowdown line.


description_of_release:
A leak was found in the piperack north of the alky unit leaking 16.5 bbls of FCCU feed.


description_of_release:
Pump hose leak was found near tank 358. LCO found on the ground.


description_of_release:
Sulfolane leak was discovered leaking less than one gallon.


description_of_release:
A leak was found on the acid regenerator tower on the HF alky unit.


description_of_release:
Leak of old piping in old #2 Crude unit. 10 gallons of crude leaked.


description_of_release:
Upset in wastewater treatment system resulted in discharge of mixture of crude oil and refined products into river

notes:
1 gallon of crude is approximately 7 lbs. <1 gallon was released in this incident.  (Pollutant name of "Crude Oil" provided with CAS for benzene.)


description_of_release:
300 bbl Crude Oil Tank leaked onto the ground.

notes:
1 gallon of crude is approximately 7lbs. 100 bbls were released during this incident.  (Pollutant name of "Crude Oil (Sweet)" provided with CAS for benzene.)


description_of_release:
Exceeded furnace permit O2 lower limit during a change in unit rate.


description_of_release:
Exceeded permit limit
B-602
Unit Startup


description_of_release:
VOC removal less than 95%
F1 & F2 Tanks
Saturated carbon canisters.


description_of_release:
Exceeded permit limit
Pit Vent
Plugged air intake line


description_of_release:
Exceeded permit limit
Pit Vent
Instrument malfunction


description_of_release:
Exceeded permit limit
Pit Vent
Faulty wiring caused short shutdown of unit


description_of_release:
Exceeded permit limit
Sulften Vent
Loss of amine circulation when switching filters.


description_of_release:
Exceeded permit limit
TG-II Vent
Power Failure.  Loss of Amine Circulaiton


description_of_release:
Exceeded permit limit
B-602
Process upset


description_of_release:
Exceeded permit limit
B-602
Leaking Heat Exchanger


description_of_release:
Exceeded permit limit
Pit Vent
Unplanned blower shutdown


description_of_release:
VOC removal less than 95%
F1 & F2 Tanks
Carbon canister bypassed when PSV relieved.


description_of_release:
Exceeded furnace permit O2 upper limit due to unit upset caused by emergency shutdown of the Unicracker unit.


description_of_release:
Exceeded furnace permit O2 upper limit due to process upset (feed change).


description_of_release:
Exceeded furnace permit O2 upper limit when two of three furnaces in combined furnace were taken out of service.


description_of_release:
Exceeded furnace permit O2 upper limit when two of three furnaces in combined furnace were returned to service and fired at low rates.


description_of_release:
Exceeded furnace permit O2 upper limit due to sudden decrease in firing rates.


description_of_release:
Exceeded furnace permit O2 upper limit when one of three furnaces in combined furnace was taken out of service.


description_of_release:
Exceeded furnace permit O2 upper limit when one of three furnaces in combined furnace was returned to service.


description_of_release:
Malfunctioning relay switch on level controller resulting in the slurry boiler flooding and loss of the feed pump due to wet steam


description_of_release:
Overspeed trip test (TOST) being performed on air blower.


description_of_release:
Preheat exchanger being taken out of service


description_of_release:
Placing preheat exchanger back in service


description_of_release:
Sulfuric Acid Plant: Leak in acid plant blower. Total emissions including start-up following repairs.


description_of_release:
Desalter water to API and leaking RV bypassed caustic scrubber. Spent caustic replacedd, blocked in RV & RV.


description_of_release:
The API sump relief valve lifted contributing to an SO2 release from the flare.


description_of_release:
Sulfuric Acid Plant:startup following leak repairs


description_of_release:
H-3002 BACT Exceedance: Heater put on circulation. Heater was shutdown.


description_of_release:
H-3002 BACT Exceedance: during feed rate increase of heater, hit the max O2 limit because of advance controller adjustments. Reducted feed rate.


description_of_release:
H-3002 BACT Exceedance: Fuel Gas swing. Fuel gas self-corrected.


description_of_release:
H-3002 BACT Exceedance: Fuel Gas BTU increased. Feed rate decreased


description_of_release:
H-3001 BACT Exceedance: Heater startup following decoke


description_of_release:
H-3002 BACT Exceedance: Unit swing during feed rate increase. Feed rate was redcuced.


description_of_release:
H-3232 BACT Exceedance: slight change in feed rate resulting in decreased duty and increased O2. Decreased duty on heater.


description_of_release:
H-3002 BACT Exceedance: due to feed rate increase swing after a drum switch.


description_of_release:
H-3001 BACT Exceedance: Drum switch caused temperature swing resulting in BACT exceedace


description_of_release:
H-3232 BACT Exceedance: unit swing during a drum switch. Feed rate was reduced


description_of_release:
H-3001 BACT Exceedance:heater running max out swing during drum switch- reduced feed rate.


description_of_release:
H-3001 BACT Exceedance:heater running max out swing during drum switch- reduced feed rate..


description_of_release:
H-3001 BACT Exceedance: coke drum warm up and switch. Feed rate reducted


description_of_release:
H-3001 BACT Exceedance: heater rate reduced to allow for valve repair.


description_of_release:
H-3001 BACT Exceedance: Low pressure fuel gas swing, Feed rate reduced


description_of_release:
H-3001 BACT Exceedance:Heater swing. Feed rate reduced


description_of_release:
API Flare: reduction in caustic strength. Spent caustic replaced.


description_of_release:
Area  C: H-20002 shutdown because we lost  the reduced crude pump on #3 CTU


description_of_release:
Area C: H20002- A leak developed on the spare pump


description_of_release:
Leak in the amine gas feed line to #1 ECC in the #1 SRU Unit


description_of_release:
Leak was discovered coming out of insulation near a leg support to Control Valve Station L-715 on PS7   [Material Released = 1 gallon Crude]


description_of_release:
safety valve lifted when switching drum to blow down


description_of_release:
A small hole developed on the side of T-2 tower and leaked Flashed Crude to the atmosphere and deck.  Hole is located right below where F-1 transfer line enters T-2.


description_of_release:
The tail gas was routed to the incinerators when the boiler feed water tripped. The 12-hour rolling average SO2 limit of 250 ppm was exceeded.


description_of_release:
Corrosion caused the thermo well to fail exposing the thermocouple to line pressure.


description_of_release:
Power outage caused ID fan shut down. Damper failed to open.


description_of_release:
Flaring due to Depressured Acid Gas to Flare During Claus Shutdown


description_of_release:
blowers failed to swap causing the CO furnace to shutdown


description_of_release:
Flaring due to Steaming Acid Gas Line to Flare for Shutdown


description_of_release:
T-1 Safety Valve lifted during a unit upset


description_of_release:
Exceeded WGS hourly CO average while stabilizing unit operation after shutdown of PCLA-2


description_of_release:
Flaring due to PCLA instrument malfunction


description_of_release:
PCLA2 CO levels on the Wet Gas Scrubber increase after shutdown.


description_of_release:
After shutting down PCLA-2, WGS CO levels increase


description_of_release:
Leak in over head line after overhead condenser


description_of_release:
tower leaked crude oil to concrete and sewer.


description_of_release:
small hole in the purge depropanizer feed line


description_of_release:
Flaring due to HCLA D-105 Level Malfunction


description_of_release:
Flaring due to Alky Startup & PHLA T-30 Venting


description_of_release:
Pin hole leak in suction Inter-stage piping


description_of_release:
Seal leaked on fractionator bottoms pump


description_of_release:
Hydrocarbon leak on reactor overhead line


description_of_release:
Flaring due to PSLA Shutdown for turnaround


description_of_release:
Flaring due to shutting down meter for maintenance


description_of_release:
74FC035 opened when the air regulator froze.


description_of_release:
Interstage Knockout Pot to over pressure and lift the PSV to #2 Flare.


description_of_release:
Depressuring the depropanizer during shut-down for maintenance work.


description_of_release:
While starting up LEP liquid section, overhead receiver pressure was vented to #2 flare.


description_of_release:
SRU Train 2 tripped due to low combustion air pressure.


description_of_release:
During the restart of K406, a PSV lifted to #2 Flare.


description_of_release:
Compressor trip causing material to be routed to #1 Flare.


description_of_release:
An electrical short caused a pressure increase to FGR and staged the #1 Flare.


description_of_release:
Startup after repairs made during an SRU unit squat.


description_of_release:
During planned Claus unit switch to TGTU1, the SRU rich filters became plugged.


description_of_release:
SRU1 load increased causing a need for more MDEA circulation.


description_of_release:
Refinery loss of power due to fault to ground at one of the refinery power feeders.


description_of_release:
Refinery loss of power due to fault to ground at one of the refinery power feeders..


description_of_release:
In the process of shutting down the HCU, region 4 had to vent equipment to the flare.


description_of_release:
Power loss due to bus bar support short to ground on CFHT.


description_of_release:
The separator off gas valve vented to the #2 Flare.


description_of_release:
Hooked up hydrocarbon hose to drain and depressure to the #2 flare.


description_of_release:
SRU2 rich filters plugged, requiring isolation and replacement.


description_of_release:
Valve from #3 Deheptanizer was found to be leaking into #2 Flare.


description_of_release:
Refinery operations adjust to facilitate isolation of a line to mitigate previous incident, utilizing available flare gas capacity, resulting in intermittent flaring.


description_of_release:
Due to loss of feed from reformer as a result of planned shutdown resulting in the PSV relieving.


description_of_release:
FCC Charge Heater tripped on low flow, despite ok flow readings.


description_of_release:
When restarting the SRU circulation after a shutdown, the lean MDEA pump became vapor locked and could not be restarted until suction was established.


description_of_release:
PSV 3305 payed off shortly after starting K3305 due to a stuck discharge check valve.


description_of_release:
As a result of a planned Alky shutdown, material was sent to the #1 flare.  No permit limits or RQs were exceeded.


description_of_release:
Offgass compressor fin fan discharge check valve became stuck and psv relieved.


description_of_release:
A small leak was noted in the channel head of the Unit 027 Depropanizer feed/btms exchanger


description_of_release:
A small leak was noted from a bleeder in Unit 027, the HF Alky Unit


description_of_release:
A relief valve in Unit 211, the New Naphtha Hydrotreating Unit, inadvertently opened to the South Ground Flare below its set point.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 025, the Fluid Catalytic Cracking Unit (FCC Unit).


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 028, the Butane Isomerization Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to shutdown of offsite Shell Company Offgas Compressors.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Unit 046 Propylene Splitter Unit operating issues.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 027, the HF Alkylation Unit.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 055, Gasoline Desulfurization Unit


description_of_release:
Due to the weather, liquid froze in the Eocent Compressor Interstage Drum drain line causing the vacuum overhead to relieve to the South Flare


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to shutdown of Unit 022 Sats Gas plant which overpressured the fuel gas system.


description_of_release:
During the shakedown period of Unit 212, the new Platformer Unit, there was high H2S in the fuel gas which was routed to the South Ground Flare for a short period


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 014, the Distillate Hydrotreater Unit.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 020, the #1 Sulfur Recovery Unit.


description_of_release:
Fuel gas imbalance; flare fuel gas from Unit 021 due to fuel gas imbalance.


description_of_release:
The refrigeration unit in the RBS spheres Unit 066 malfunctioned during maintenance activities associated with the 2010 Maintenance Turnaround.  To relieve the pressure in the spheres, the excess pressure was routed to the RBS Emergency Flare


description_of_release:
Fuel gas imbalance; flare fuel gas from Unit 021 due to Maintenance Turnaround


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 011, the Naphtha Hydrotreater Unit.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 010, the Crude Unit.


description_of_release:
The off-gas compressors shut downin the Unit 010 Crude Unit due to liquid carryover into the compressor suction drum.  This tripped the compressors, opening the relief valve to the South Flare.


description_of_release:
The Unit 210 crude offgas compressor suction drum overpressured due to excess crude offgas from the Unit 222 Sats Gas Plant.  The high pressure relieved to North Ground Flare.


description_of_release:
While switching Unit 034 tailgas from the Unit 034 Thermal Oxidizer to the Unit 020 Thermal Oxidizer, Unit 034 pressure up causing acid gas to back out of the blower vent valve in Unit 034.


description_of_release:
A temporary power blip from the refinery's energy source (Entergy) caused multiple units to shutdown.


description_of_release:
A transformer breaker tripped causing multiple operating units in the refinery's expansion area to briefly shutdown.


description_of_release:
Bleeder valve was inadvertently left open during steam out of the stripper in Unit 032, the DEA Regenerator Unit.  This was a turnaround maintenance activity.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 005, the Coker Unit.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 056, the New Distillate Hydrotreater Unit.


description_of_release:
Water from the Unit 205 Coker Unit offline coke drum overhead line was inadvertently sent to the main fractionator, vaporized and overpressured the wet gas compressor suction drum to the North Ground Flare.


description_of_release:
The Deisopentanizer Overhead Accumulater overpressured, opening to the South Flare.


description_of_release:
Two pinhole leaks were discovered in a 3/4" pipe nipple in the Unit 043 Fuel Gas System.


description_of_release:
Flaring fuel gas from Unit 021 because of fuel gas leak in Domain 4.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to fuel gas imbalance.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to fuel gas imbalance.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 043 due to fuel gas imbalance and refinery upset.


description_of_release:
Emergency shutdown of the Unit 215 Hydrocracker Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 043 due to fuel gas imbalance and refinery upset


description_of_release:
Instrumentation malfunctions in the refinery's Unit 215 Hydrocracking Unit caused liquid material to be routed to the Unit 210 Crude Unit overhead system.  The caused the offgas compressor to shutdown as designed which relieved offgas to the North Flare.


description_of_release:
Portions of the Unit 215 Hydrocracking Unit were shutdown to allow the repair of a heat exchanger leak.  The depressured gas was relieved to the South Ground Flare.


description_of_release:
Normal shutdown for refinery maintenance turnaround for Unit 009, the Penex Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to both Sats Gas Plants (Units 022 & 222) products going to a bullet routed to the fuel gas system.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to upset in Unit 212 CCR Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Unit 222 Sats Gas Plant product going to a bullet routed to the fuel gas system.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Unit 222 Sats Gas Plant product going to a bullet routed to the fuel gas system


description_of_release:
Unit 210 Crude Unit offgas compressor suction drum was upset when excess liquid from Unit 215 Hydrocracker Unit was routed to the drum due to a bad level controller.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to Unit 212 CCR upset.


description_of_release:
A small leak occurred in the Unit 017 FCCU Merox suction line ot a relief valve; propylene was released to the atmosphere.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to high fuel gas make.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to upset in Unit 005 Coker Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to upset in Unit 005 Coker Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to high fuel gas make


description_of_release:
A small pinhole leak was the Unit 27 HF Alky Unit main fractionator relief valve inlet piping.  Unit was shutdown to repair the leak.  The Air Monitoring Team was dispatched.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to upset in Unit 027 HF Alky Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 due to upset in Unit 027 HF Alky Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 043 due to upset in Unit 027 HF Alky Unit.


description_of_release:
While cutting back feed rates to the Unit 025 FCC Unit, an adequate carbon balance was not maintained causing elevated CO in the flue gas.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to high fuel gas make (Domain 2 down).


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 043 & 243 mix drums due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 mix drum due to shutdown of offsite Shell Company offgas compressors and Unit 212 upset.


description_of_release:
Small leak from propylene loading hose at Unit 064 LPG Railroad Rack


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 & Unit 43 & Unit 243 due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Domain 4 sending excess H2 to the fuel gas system.


description_of_release:
Liquid material from the Unit 025 FCC Unit carried over into the fuel gas system.  The Air Monitoring Team was dispatched.


description_of_release:
Propylene truck relief valve opened prematurely when offloading propylene.  Truck was offloaded to the North Flare.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 21 & Unit 243 mix drum due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 21 due to shutdown of offsite Shell Company offgas compressors; lost power because of a storm.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 mix drum due to high fuel gas make.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 21 & Unit 243 mix drum due to high fuel gas make.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Sats Gas Plants Units 222 products going to a bullet routed to the fuel gas system.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 21 due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 and Unit 043 & 243 mix drums due to high fuel gas in system due to Unit 212 & Unit 007 ROSE Heater shtudown.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 mix drum due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Unit 222 Sats Gas Plant merox dryers were taken out of service causing C3 product to be vented to the North Ground Flare.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 and Unit 243 mix drum due to high fuel gas in system due to Unit 205 dumping C3s and C4s into the fuel gas system.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 and Unit 243 mix drum due to high fuel gas make


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 and Unit 243 mix drum due to high fuel gas make.


description_of_release:
Unit 020 Thermal Oxidizer tripped briefly.


description_of_release:
Unit 214 Kerosene Hydrotreater Unit relief valve lifted due to foaming problem in the unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Unit 027 Alky Unit dumping C3s & C4s into the fuel gas system.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 243 mix drum due to an upset in Unit 212 CCR Unit.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to Sats Gas Plant Unit 222 products going to a bullet routed to the fuel gas system.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 043 & Unit 243 mix drums due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Startup of the Unit 007 Rose Unit after unit maintenance (permitted).


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to high fuel gas make.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to high fuel gas make and Domain 1 going to fuel gas bullet.


description_of_release:
An instrument on the Unit 205 1st stage suction drum overhead compressor malfunctioned which cased the compressor to trip.  The overhead gas was vented to the North Ground Flare.


description_of_release:
Unit 010 stabilizer overhead relief valve lifted.


description_of_release:
Leak in the Unit 215 Hydrocracker Unit stripper overhead fans.  Flared to North Ground Flare.


description_of_release:
Due to a power failure, the Shell Company offgas compressors shutdown which resulted in excessive fuel gas which must be flared as a safety precaution.


description_of_release:
A 3/4" bleeder was inadvertently left open on Unit 005 1202 Coke Drum during warming.


description_of_release:
Shutdown of Unit 212 CCR Unit due to net gas pressure swing.


description_of_release:
The Unit 210 Crude Unit offgas compressor tripped which resulted in flaring to the North Ground Flare.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 and Unit 243 mix drum due to shutdown of offsite Shell Company offgas compressors.


description_of_release:
Isobutane sample station was left open to the South Flare.


description_of_release:
Due to an instrument malfunction, the inlet valve to the Unit 005 coker west gas compressor suction drum closed which shutdown the compressor.  Gas was routed to the Noth Ground Flare.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to imbalance of fuel gas between old and new plant.


description_of_release:
Due to an unexpected change in feed composition to Unit 015, the Heavy Gas Oil Hydrotreater, the high pressure stripper column over-pressured to the South Flare.


description_of_release:
Emergency shutdown of the Unit 025 FCC Unit due to an electrical breaker issue.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 due to startup of Unit 025 FCC Unit.


description_of_release:
Emergency shutdown of the Unit 025 FCC Unit due to a transformer issue.


description_of_release:
A loss of power to Unit 025 FCC Unit caused that unit to shutdown which resulted in less feed to the Unit 205 Coker Unit.  This caused the Coker wet gas bypass to open and the compressor suction drum to open to the North Ground Flare.


description_of_release:
Excess hydrogen was flared from Unti 055 Gasoline Desulfurization Unit due to inadventently opening a bypass valve.


description_of_release:
Fuel gas imbalance; flared fuel gas from Unit 021 and Unti 243 mix drum due to startup of Unit 025 FCC Unit.


description_of_release:
Fuel gas imbalance due to loss of charge pump in tank farm; flared from Unit 021.


description_of_release:
Initial cause due to false level indication on 70F-112 absorber.  T5 deviation for exceeding 160 ppm 3-hr avg. 4-1-10 (13:01 to 19:00) H2S and multiple heater permit limits (SO2)


description_of_release:
The Atmospheric Tower overhead compressor (1KT-201) on the VPS-1 Unit tripped due to a governor malfunction.  When the compressor was re-started, the discharge flow was increased to recover from the Atmospheric Tower pressure swing


description_of_release:
Operations swapped L/O off of L/O turbine DP-211 to ready the turbine for maintance work Monday morning.  The electric pump was started and there was a leak of lube oil flow due to a plugged lube oil filter.  P-101 charge pump lost lube oil to the gimble.


description_of_release:
Process upset at OL-5 due to introduction of non-condensibles to 175 lb steam system during startup of hydrogen plant.


description_of_release:
Upset at S3 Sulfur Plant due to introduction of non-condensibles into 175 lb steam system during startup of hydrogen plant.


description_of_release:
Process upset due to introduction of non-condensibles into 175 lb steam system during startup of hydrogen plant.


description_of_release:
Blower at RCCU tripped off-line, resulting in emergency shutdown of RCCU and RGHT.


description_of_release:
S2 Sulfur Plant experienced an unexpected shutdown. The shutdown of the S2 sulfur plant led to flaring at Shell's West Operations Elevated Flare (EPN 5-84) and OL5 Elevated Flare (EPN 6-84).


description_of_release:
Motiva’s Hydrocracker 1st Stage unit tripped off line causing an operational upset and shutdown of the Hydrocracking Unit (HCU) due to a governor oil back pressure valve failure on compressor K-1928.


description_of_release:
On June 16, 2010, the Motiva DHT vent gas compressor (K-5337) tripped due to multiple electrical faults caused by lighting from inclement weather in the area. The tripping of the compressor resulted in flaring at Shell Chemical’s OL-5 Elevated Flare.


description_of_release:
HCU relief valve RV-161 relieved prematurely to the HCU flare while the process unit was operating at a steady state.


description_of_release:
Hydrocarbon odor at Logistics due to railcar UTLX 950070 leaking. A mixture of butadiene and isoprene vapors was leaking from gaskets on the seat of the relief valve to the atmosphere.


description_of_release:
Flaring at RCCU Flare (EPN# 7-84) as a result of an upset of the OL5 Process Unit caused by a trip of a Shell Chemical-operated Utilities System Boiler and steam system upset during an unusually heavy rainstorm.


description_of_release:
Leaking butadiene line identified.  This line transports butadiene to the Wharf.  Once the issue was identified, the line was isolated and then de-pressured to the flare system.


description_of_release:
Leaking 1,3 butadiene line identified.  Once the issue was identified, the line was isolated and then de-pressured to the flare system. The leak was stopped once the line was de-pressured.


description_of_release:
Motiva’s RCCU unit tripped causing the main fractionator overhead accumulator to vent to the RCCU elevated flare, FE-201.Additional flaring occurred at the Shell Chemical LP (Shell) GO-1 Elevated Flare (EPN 1-90) during this incident.


description_of_release:
Motiva operators at the Diesel Hydrotreator (DHT) discovered the split range pressure controller, PC-2115, was opening to the Shell Chemical OL-5 flare in order to control the pressure of the DHT stripper overhead.


description_of_release:
The Flare Knock Out Drum, PV 191, filled with crude butadiene resulting in flaring at the Shell Chemical, LP West Operation Elevated Flare.


description_of_release:
An Instrument Protective Function (IPF) was activated for a high liquid level in the Motiva DHT Stripper Overhead Accumulator (PV-1987).  Subsequently, this resulted in flaring at Shell Chemical's OL5 Elevated Flare.


description_of_release:
Motiva's S2 and S3 sulfur plants tripped offline while analyzer FI-3677 was being calibrated at S2.


description_of_release:
Motiva experienced hysdrocarbon flaring at the Coker Flare (EPN 2-84). The release was caused by an unexpected shutdown of the Coker West as Compressor (K-2178) due to a loss in electrical power.


description_of_release:
DHT Sour Gas Compressor Discharge PSV lifted to N Flare


description_of_release:
Relieving Pressure from #2 HiJet from #1 Amine Low Pressure KO Drum (AA-V-202)


description_of_release:
#2 TGT Recycle Gas Bypassed to North Flare; #2 TGT Bypassed to #2 SRU Incinerator; #2 SRU SO2 >250 ppm, 12-HRA


description_of_release:
During startup of the 3700 Sulfur Recovery Unit (SRU), one or more analyzers malfunctioned causing an elevated release of SO2 and H2S.


description_of_release:
A main air blower malfunctioned causing elevated levels of SO2 to be released from the unit


description_of_release:
An unspecified malfunction caused the bulk air valve on the unit to close. Reduced combustion air to the SRU caued the unit to trip offline.


description_of_release:
Coker stub tower level indicator HCGO tray malfuctioned.The overhead coker fractionator columns overheated, flooding the overhead vessel.The liquid level exceeded the high set point, shut down the wet gas compressor and the vapors were sent to flares 1/2.


description_of_release:
The packaging on the Regen Slide Valve Stem had failed. To fix the packing leak, the FCC unit was shutdown and the valve was removed and sent to repair.


description_of_release:
Flaring of acid gas and sour water gas due to unplanned unit shutdowns. A power failure caused the CGHT, #2 Sulfur Plant, and #3 Sulfur Plant to shutdown.


description_of_release:
Flaring occurred due to an unplanned FCCU shutdown. The FCCU was shutdown due to an air blower failure.


description_of_release:
Gas oil was released to the SPCC containment area due to a leaking flange on an oil transfer line south of Tank 17.


description_of_release:
Flaring occurred during an unplanned #3 Sulfur Recovery Plant shut down due to a low waste heat boiler level.


description_of_release:
Flare Gas Recovery Unit was shutdown due to flaring of small amount of sour water gas.


description_of_release:
#2 Cogen Start-up.  Shutdown due to low N2 pressure and to blind for boiler T/A.


description_of_release:
#2 Cogen Start-up.  Shutdown to blind for boiler T/A.


description_of_release:
#2 Cogen Start-up after tripping.  #1 Cogen Start-up; Shutdown to blind for boiler T/A.


description_of_release:
#1 Cogen Start-up upon completion of boiler T/A and after checking diverter valve. Vilter and Mycom Compressor Shutdown.


description_of_release:
#1 Cogen Start-up after replacing filters.


description_of_release:
Truck flaring while loading at the rack.


description_of_release:
Venting CGHT Compressors for Maintenance.


description_of_release:
#2 Cogen Start-up after replacing filters. Solar water washed vanes on both Cogens.


description_of_release:
#1 Cogen Start-up after repairing fire eye.


description_of_release:
Pre Start-up of FCC Unit and Crude Preflash Tower.


description_of_release:
Crude Unit Upset. C-1701A/B tripped on high discharge temperature. #2 Cogen Start-up after changing inlet filters.


description_of_release:
#1 Cogen Start-up after changing inlet filters.


description_of_release:
Tk 106 Maintenance; Tk 114 Maintenance; Mycom Shutdown; Vilter was already down for repairs; and Flaring while switching to pipeline H2 with Vilter down.


description_of_release:
Tk 112 Maintenance and #2 Cogen Start-up after changing inlet filters.


description_of_release:
Tk 109 Maintenance and PSV on Alky Superheater lifted.


description_of_release:
#1 Cogen Start-up after changing inlet filters. FCC Debut Overhead Reciever flaring due to CW leak.


description_of_release:
Preparing Tk 111 for new product; #2 Cogen Start-up after shutdown on low N2 pressure; and Flared while attempting to swap C2501 compressors.


description_of_release:
Cogen Start-up after changing inlet filters.


description_of_release:
Tk 115 Maintenance; Tk 111 Maintenance; and Tk 111 Maintenance & Cogen Start-up after changing filters.


description_of_release:
Tk 116 Maintenance & FGRU Shutdown due to plugging; and Tk 116 Maintenance & Mycom Compressor still down.


description_of_release:
Preparing E-1511 exchanger for maintenance; and #1 Cogen Start-up after changing inlet filters.


description_of_release:
#2 Cogen Start-up after changing inlet filters.


description_of_release:
Flaring occurred due to an unplanned FCCU shutdown.  The FCCU was shutdown due to malfunctioning  flapper valve, which caused catalyst carryover.


description_of_release:
Tk 115 Maintenance; #1 Cogen Start-up after scheduled maintenance; and #2 Cogen scheduled maintenance.


description_of_release:
#2 Cogen and #1 Cogen Start-up after changing inlet air filters.


description_of_release:
Vilter down for maintenance.  Mycom tripped; and Flaring light ends from Tk 115.


description_of_release:
#2 Cogen Start-up after tripping while swapping CGHT compressors.


description_of_release:
#2 Cogen Start-up after tripping from overspeed trip.


description_of_release:
Reformer Shutdown due to high vibration on compressor.


description_of_release:
NHT/Reformer Shutdown and Loss of power to FGRU.


description_of_release:
#2 Cogen start-up after working on diverter valve; C-1701B shutdown; C-1701B shutdown on thermal capacitor temperature; and #1 Cogen Start-up after changing inlet filters.


description_of_release:
C-1702B tripped and #2 Cogen Start-up after tripping from overspeed trip.


description_of_release:
C-1701A tripped and Wiring repaired; #2 Cogen Start-up after tripping from overspeed trip; and #2 Cogen Start-up after replacing actuator.


description_of_release:
#2 Cogen Start-up after tripping on emergency stop.


description_of_release:
FCC Unit was shutdown and the regen slide valve stem was removed and sent for repair. When the FCCU was brought online, flaring occurred from the FCCU and from the Sour Water Stripper.


description_of_release:
Venting on Tank 118 and flaring Tank 109 while taking a sample.


description_of_release:
Variance was obtained to shutdown Enclosed Vapor Combustor to perform preventive maintenance as per the requirements of Unites States Coast Guard safety rules.


description_of_release:
Heater SCR malfunctioned due to an unexpected ammonia injection system trip resulting in increased Nitrogen Oxide emissions.


description_of_release:
Fire at Delayed Coking Unit's Coke Pots due to improper valve isolation sequence. This also resulted in a flaring event.


description_of_release:
TGT Level transmitter malfunctioned resulting in increased sulfur dioxide emissions from the TGT Incinerator


description_of_release:
Unexpected pressure increase in TGT absorber overhead resulted in increased sulfur dioxide emissions from the TGT Incinerator


description_of_release:
Coker Compressor tripped off-line due to unexpected foulant in the electric motor's water exchanger resulting in a flaring event


description_of_release:
FCC Process Unit Upset due to unexpected upset at the Crude Unit causing a loss of hot FCC feed. This resulted in a release from the FCC Regenerator Vent.


description_of_release:
Sour Water Stripper abnormal startup due to level indicator failure which resulted in a flaring event.


description_of_release:
Amine Stripper upset due to inconsistent feed quality causing the Claus units to trip offline flaring acid gas and causing high hydrogen sulfide emissions from all affected unit's heaters.


description_of_release:
Truck Wholesale Rack VRU failure of back pressure regulator causing gasoline spill, emissions are conservative estimate of evaporative losses prior to clean up.


description_of_release:
Complex I Reformer Debutanizer Overhead LPG piping leak.


description_of_release:
Leak in fin fan during regen cycle of Isom Cataylst


description_of_release:
Spill onto Ground @ LPG Bullets # 1 - # 5


description_of_release:
Area 01 Additive Line Leak, estimated minimal evaporation of VOC prior to clean up.


description_of_release:
Complex II Power Outage causing all units to shutdown and flaring


description_of_release:
Dock #3 slop oil tank overflowed to dock containment (Approx. 1-2 gal.).


description_of_release:
C4 to storage pinhole leak in rundown line.


description_of_release:
3/4 inch nipple on the product charge line at Tank 83 ruptured and released product to the diked area around the tank. Heavy semi-solid material, no LEL or H2S readings recorded, no potential off-site issues. There were no injuries.


description_of_release:
#2 SRU tripped. Fuel gas system exceeded 160 ppm 3-hr average for H2S. The average draeger value for the event was 800 ppm. Reportable on qtrly CEM and T-5 semi- annual reports.


description_of_release:
All three FGC's shutdown on high temp alarm. Problem with steam connections to flare gas drum. Based on flare line draegers given, excess emissions were estimated to be 210 lbs SO2 emitted from #3 flare. Reportable on T-5 semi- annual deviation report.


description_of_release:
Air Permit 0500-00005-V5, Point Source (B2001 CO Boiler/WGS). explosion in the Belco wet gas scrubber unit which has resulted in a long term loss of the scrubber. This scrubber was used as a SRU tail gas scrubber associated with SRU 2 and 3 units.


description_of_release:
#2 SRU tripped. FGC's running loaded, and are not routing gas to the flare. Amine scrubbing system was able to control most of the H2S. However, the Fuel gas H2S concentration did exceed permit limits


description_of_release:
Fuel gas H2S CEM out of compliance (>160 ppm). Compressor problems


description_of_release:
Digestor at wwtu overflowed.Estimated 50 bbls sludge/black water inside dike wall at T-79. Dike wall drains were left open and some ran into the road and into the north stormwater pond.


description_of_release:
Southwest corner of roof on Tank 61 (gasoline) sank. Material transferred to another storage tank and tank 61 was taken out of service.


description_of_release:
Ammonia level from sample taken on 5-5-2010 in outfall 001 exceeds 5.0 mg/L permit monthly average limit. While not a permit violation yet, it may contribute to one when monthly average is calculated. Value obtained from sample was 5.16 mg/L


description_of_release:
Resident complained about smell of Gas Oil Mixture.  Vidal Clay confirmed that sour crude began start up in evening and noticed a little odor in vicintiry of SC and sour vac but that was in the units.


description_of_release:
Ammonia level from sample taken on 5-12-2010 in outfall 001 exceeds 5.0 mg/L permit monthly average limit. While not a permit violation yet, it probably will be once the monthly average is calculated. Value obtained from the sample was 21.0 mg/L.


description_of_release:
Ammonia sample from 5-11-2010 failed ammonia. Sample concentration was 19.9 ppm. Permit limit is 5.0 ppm avg. Will exceed permit limits for the month of May for maximum (lbs/day) and monthly avg (ppm)


description_of_release:
Ammonia samples in outfall 001 on 5-18-2010 and 5-19- 2010 failed ammonia. Both sample concentration was 12.9 ppm. Permit limit is 5.0 ppm avg. Will exceed permit limits for the month of May for maximum (lbs/day) and monthly avg (ppm)


description_of_release:
Outfall 001 sampl;e collected on 5-25-10 over permit limit for ammonia. Value obtained was 12.8 ppm NH3. WWTU still having problems . Need considerable amount of sludge for aeration basins and full-time operators/testers.


description_of_release:
Ammonia concentrations over permit limits for 6-1, 6-2, and 6-9. Concentrations were 23.1, 21.8 and 34.3 ppm respectively.


description_of_release:
4 inch transfer hose separated from coupling (hose failure) while calibrating the header meters discharging approximately 10 bbls of crude oil. Estimated 8 bbls went off-site into the north-south concrete ditch on the south east side of the refinery.


description_of_release:
Black Smoke.  Confirmed due to power failure


description_of_release:
Plant power failure. #3 flare smoked > 20% opacity for approximately 3 hours and 20 mins. #6 boiler restarted at 3:28 pm and #5 boiler at 4:20 pm. Excess emissions estimated for the power failure during SSM @ #3 flare was 499 lbs SO2.


description_of_release:
Fuel gas CEM over 160 ppm permit limits for timeframe specified. High value obtained on 7-28-10 was 22,000 ppm H2S.


description_of_release:
Fuel gas CEM out of compliance >160 ppm H2S for 19 hours. High value draegered was 5000 ppm.


description_of_release:
All flare gas compressors were shut down due to leaks at the #3 flare. Estimated 250 lbs SO2 released to atmosphere from #3 flare.


description_of_release:
Received a call from Union Pacific of a 40 gallons or more spill of lube oil from railcar GATX 565. United States Environmental Services called out to clean up spill. Once vendor arrived at the railyard south of Baton Rouge, there was no oil spill.


description_of_release:
Both thermal oxidizers shutdown 4 times on high temp alarm at the Dynawave unit.


description_of_release:
Both Thermal oxidizers shutdown on high temp alarm 4 times each at the dynawave unit.


description_of_release:
Both thermal oxidizers on the Dynawave tailgas shutdown on high temp alarm. Permit condition requires Temp to be at or above 1000 degrees. Deviation reported on T-5 semi-annual and annual reports.


description_of_release:
Birds flew into electrical fuse panel and caused plant power failure. Flare emitted black smoke for 6 1/2 hrs before power was restored. Exceeded 500 lb SO2 RQ at 20:45.


description_of_release:
SO2 emissions from dynawave scrubber over 250 ppm for 6 hours. High value recorded for event was 686 ppm SO2.


description_of_release:
Both SRU's tripped, both Claus reactors came in on high alarm and shutdown. Both thermal oxidizers in the dynawave scrubber tripped on high temperature at 14:36. FGC's running which caused fuelgas system to go out of compliance as well.


description_of_release:
Both thermal oxidizers at the dynawave tripped. Tripped on high temperature shutdown alarm.


description_of_release:
North themal oxidizer tripped on high temp. at 15:08, back to 1000F at 16:40. South thermal oxidizer tripped on high temp at 15:30, back to 1000F at 17:00. North thermal oxidizer tripped again from 21:00 to 22:30 again on high temp.


description_of_release:
North thermal oxidizer tripped on high temp from 4:20 to 11:05 am. South thermal oxidizer tripped on high temp from 4:20 to 10:15 am


description_of_release:
#1 thermal oxidizer tripped 4 times. 7:18 to 7:30; 7:56 to 8:05; 8:35 to 8:45; and 10:37 to 10:42. #2 thermal oxidizer tripped 3 times. 7:22 to 7:25; 8:00 to 8:04 and 8:37 to 8:41.


description_of_release:
Fuel gas CEM over 160 ppm for 5 hour period.


description_of_release:
Fuel gas H2S CEM over 160 ppm. Problems with #2 amine stripper tower (low temps) and #3 SRU could not process all the acid gas.  Some acid gas was routed directly to the fuel gas system.  High value recorded was 2000 ppm H2S.


description_of_release:
Fuel gas H2S CEM over 160 ppm. Problems with #2 amine stripper tower (low temps) and #3 SRU could not process all the acid gas.  Some acid gas was routed directly to the fuel gas system


description_of_release:
Thermal oxidizers both tripped twice. Problems with #2 SRU which also tripped. Acid gas flow sent to #3 SRU. #3 SRU could not take all the flow and some of the acid gas off #2 SRU was vented to the flare gas recovery system.


description_of_release:
All 3 flare gas compressors shutdown on low suction pressure. Based on average H2S draeger readings of the flare line for the timeframe, it was estimated that 420 lbs SO2 was released from the #3 Flare.


description_of_release:
Permit Daily maximum(lbs/dy) Ammonia, exceeded permit limit on 11-3-2010 due to amine unit problems and high flow rates from rain event. The monthly average(lbs/dy) and monthly avg (mg/L) for ammonia were also over permit limits.


description_of_release:
The refinery lost power causing all units throughout the refinery to shutdown unexpectedly resulting in excess emissions.


description_of_release:
SO2 spiked in the incinerator caused by foaming.


description_of_release:
Shutdown of the unit for scheduled plant wide turnaround


description_of_release:
Startup of the unit following a plantwide scheduled turnaround.


description_of_release:
Startup of the unit following a plantwide scheduled turnaround.  In addition, there were several SO2 spikes in the incinerator due to multiple foaming issues in TGTU #2 amine system.


description_of_release:
FCC experienced a feed diversion (unit shutdown) due to a false FCC regenerator level indication. Subsequently, the FCC unit ESP's tripped due to high CO reading


description_of_release:
Overpressure of coke drum and PSV relieved to atmosphere.


description_of_release:
Flare event dut to power loss to compressors due to power supply interruption (feeder loss).


description_of_release:
Flare Release resulting from failure in level control indication.


description_of_release:
Planned flare release for 33 unit depressuring test.


description_of_release:
Compressor trip (17C1) resulted in flare release.


description_of_release:
Failed level instrument in 18 gas plant as FCC and 18 Unit were being started up.


description_of_release:
Compreessor trip offline in 27 H2 plant during lightning.


description_of_release:
Flare release due to a PSV failure in 38 unit.


description_of_release:
Flare release from excess gas as 23 coker unit shutdown.


description_of_release:
Flare release during startup of 23 unit.


description_of_release:
Flare release when compressor tripped offline in 33 unit.


description_of_release:
Flare release during 15 gas plant unit upset.


description_of_release:
Powerformer heater 32H5/6/7 exceeded 0.045 lb/mmbtu Nox limit during startup/shutdown condition. Heater has no express SSM or turndown allowance.


description_of_release:
33H31 heater exceeded 0.045 lb/mmbtu Nox limit during startup/shutdown condition. Heater has no express SSM or turndown allowance.


description_of_release:
71B-6 Boiler exceeded 0.045 lb/mmbtu Nox limit during startup/shutdown condition. Heater has no express SSM or turndown allowance.


description_of_release:
Powerformer heater 32H5/6/7 exceeded 0.045 lb/mmbtu Nox limit during malfunction condition. Heater has no express SSM or turndown allowance.


description_of_release:
37H3/4/5 heater exceeded 0.045 lb/mmbtu Nox limit during startup/shutdown condition. Heater has no express SSM or turndown allowance.


description_of_release:
Crude heaters 25H3, 25H1, and 25H4 exceeded 0.045 lb/mmbtu Nox limit during startup/shutdown condition. Heaters have no express SSM or turndown allowance.


description_of_release:
SRU tail gas unit tripped during heavy rain/weather


description_of_release:
Sulfur pit smoldering required brief steam to quench pit, resulted in a short pit venting out vent stack. FHR has no data to calculate brief H2S emission resulting.


description_of_release:
Relieving Pressure from DU to Flare, the depentanizer overhead gas was routed to flare


description_of_release:
#2 Sulfur pit vented to atmosphere for maintenance on sulfur pit vapor recovery system


description_of_release:
Reactor main column pressured up and upset following the isolation of 2 of 3 overhead trim coolers


description_of_release:
#2 Sulfur pit vented to atmosphere for maintenance on sulfur pit vapor recovery system on 3/16/2010 - 3/19/2010


description_of_release:
Malfunction as a result of blowing out the cat cooler fluffing air nozzle


description_of_release:
Amine unit upset causing high H2S in refinery fuel gas


description_of_release:
Amine unit upset caused the No. 3 SRU/SCOT to malfunction


description_of_release:
Heavy rainfall caused rapid cooling of equipment which resulted in a brief loss of stripping steam to the FWS


description_of_release:
Regenerator upset caused lower regenerator temperatures which led to a CO increase


description_of_release:
Amine unit malfunction causing high H2S in refinery fuel gas


description_of_release:
An isolation valve on the #2 vac tower overhead system that isolates it from the flare was mistakenly opened after a Pre-TAR construction job


description_of_release:
Shutdown of #2 SRU due to high liquid level in the Amine Acid Gas KO drum.  Sulfur pit VRS S/d for 2 hrs 40 min


description_of_release:
#2 Sulfur pit vented to atmosphere for maintenance on sulfur pit vapor recovery system for 1 hr 20 min


description_of_release:
Slurry recycle was routed to feed which caused the regenerator to get behind on coke burn which led to a CO increase


description_of_release:
A rapid decrease in reactor stripper level led to a CO increase


description_of_release:
Main air blower went into surge causing a loss in combustion air and low oxygen in regenerator which led to a CO increase


description_of_release:
A reduction in slurry make in the FCC led to a CO increase


description_of_release:
Backing out air from the regenerator in preparation for a rate decrease led to a CO increase


description_of_release:
Process upset gases flared-allowed by permit


description_of_release:
Process upset gases flares - allowed by permit


description_of_release:
Process upset gases flared - allowed by permit


description_of_release:
Spill of paraxylene to the ground, did not exceeded RQ


description_of_release:
Spill of benzene from tank sample circulation pump-did not exceed RQ


description_of_release:
Emergency shutdown due to prolonged freezing temperatures.


description_of_release:
Stripping steam to remove H2S from the system was started to late during the unit startup process


description_of_release:
Vessels and equipment were steamed to the flare system in preparation for entry during period of plant-wide shutdown.


description_of_release:
valve misalignment during startup of hydrogen processing unit


description_of_release:
Contamined the amine system with oil during activation of new catalyst after maintenance turnaround


description_of_release:
During this startup, amine circulation was not able to be promptly started because not enough pressure, and stripping steam was not able to be started because of low temperature


description_of_release:
Fire on Jan. 4, 2010 required incinerator shut down.  Exhaust was directed to a wet scrubber


description_of_release:
High SO2 concentrations in the Incinerator were caused by a minor Sulfur Pit fire in No. 2 SRU.

notes:
The fire occurred during the purging of the sulfur loading line with nitrogen. Once the cause of the high SO2 was identified operators took action to extinguish the fire.


description_of_release:
The Zone D SRU had high levels of SO2 in the Incinerator but the root cause has not been determined.

notes:
No operational abnormalities occurred during the time frame of the high emissions.  A  review of operational parameters for this and the 03/08/10 event, showed the unit appeared to go air short although acid gas flow rates were constant. Other connected operations were noted to be stable. Operations personnel believe a change in feed composition, such as an increase in ammonia from the sour water acid gas, may have changed the acid gas composition enough to cause the unit to go air short. Operations personnel are continuing to monitor the unit for potential causes of sudden high SO2 concentrations.


description_of_release:
The HDS Unit rapid depressuring valve (an equipment safety system) was undergoing an off-line system test after repairs had been performed.

notes:
A safety interlock was inadvertently activated during the test causing the depressuring valve to open to the flare. This depressuring system caused a complete unit shutdown which subsequently stopped the acid gas flow to the Zone D SRU causing an upset in operations.  Operators quickly worked to stabilize Zone D operations. Procedures for testing the rapid depressuring system were reviewed with refinery personnel to prevent recurrence.


description_of_release:
The FCC Atlas Blower PLC failed unexpectedly causing the blower to trip off-line and subsequently upsetting unit operations.

notes:
This caused high CO concentrations in the flue gas from the Regenerator. The FCC Electrostatic Precipitator has an SIS (safety interlock system) which prevents operation during periods of high CO concentrations in the flue gas. Consequently, high opacity emissions also occurred. Measured opacity was 37%.


description_of_release:
An HDS Unit maintenance shutdown reduced the amount of acid gas produced.

notes:
Due to the low amount of acid gas, the decision was made to shutdown the No. 1 SRU in order to replace the H2S:SO2 ratio controller.  The unit was shut down and burned-out. The unit was subsequently restarted (1/20).


description_of_release:
The HDS Unit shutdown reduced the amount of acid gas produced.  Due to the low amount of acid gas, the decision was made to shutdown the No. 1 SRU in order to replace the H2S:SO2 ratio controller.

notes:
The unit was shut down and burned-out.  Refer to 01/14/10 incident. The unit was subsequently restarted on 01/20/10. Slightly higher SO2 emissions occurred during the startup process.


description_of_release:
The SRU tripped off due to low air flow.  Acid gas was flared for a short time until the unit could be restarted.

notes:
A second similar incident occurred on 5/13/10 at which point it was determined that the TGTU feed valve (HIC79001) was closing without warning causing the unit to trip off. The HIC79001 valve positioner was replaced on 5/20/10 to prevent further incidents.


notes:
Refer to Zone E SRU incident dated 5/3/10.  On 5/20/10, maintenance was performed to replace the faulty HIC79001 positioner.  After completion of the change out the new positioner had to be calibrated. During the calibration process it was discovered that a second valve, HIC79002, was not in a fully open position. This subsequently caused high backpressure on the SRU tripping the unit due to low air flow. When HIC79002 was subsequently fully opened to correct the problem a pressure surge occurred which tripped the incinerator. Subsequent to stabilizing Zone E SRU & amine operations, the Zone D amine system was loaded up causing a high H2S concentration in the fuel gas system.


description_of_release:
Refer to Zone E SRU incident dated 5/3/10.


description_of_release:
The Zone A Tail Gas Treating Unit tripped offline at 7:45 a.m., resulting in both #1 and #2 SRU tail gas streams going directly to the incinerator stack. Both sulfur units stayed running throughout.

notes:
The TGTU tripped due to the main combustion air blower ("B" Blower) shutting down (C4454B) unexpectedly.  Process trends do not indicate any reason for the blower shut down and the blower was not tripped at the substation. On startup, the blower did restart, but was then shut down and the "A" Blower was put online as a precaution.


description_of_release:
A fire began in the #2 SRU sulfur day pit causing high SO2 emissions.

notes:
The operators first had to diagnose the cause of the high SO2 emissions was due to a fire in day pit. The vent line to the incinerator was then blocked in and steam was introduced into the pit for snuffing of the fire.


description_of_release:
The TGTU tripped off-line due to high amperage on the combustion air blowers. The trip caused high SO2 emissions.

notes:
The combustion air blowers have been running high amps due to a high pressure drop across the TGTU reactor caused by the catalyst being fouled. The acid gas charge rate was reduced as quickly as possible to minimize combustion air demand and the SRU tail gas was put back into the TGTU.  The TGTU catalyst was changed out during the October maintenance turnaround.


description_of_release:
The Atlas Air Blower, which supplies air to the FCC Regenerator, tripped offline for reasons unknown. The resulting loss of process air to the regenerator pushed the burn operation into an air-short condition.

notes:
The low O2 / high CO conditions in the regenerator caused the regenerator to cool rapidly. The reactor/riser also cooled and caused an interlock to divert feed from the riser to the main column. The operators were able to re-establish feed and stabilize the unit. The upset tripped the ESP resulting in high opacity readings from the stack. The unit operations were stabilized and the ESP grid was re-energized as soon as possible. Measured opacity was 35%.


description_of_release:
The fire eye on the Zone A TGTU incinerator "flamed out" which caused a trip of the oxidizer stack, #1 SRU, #2 SRU, and the TGTU.

notes:
It was not a true loss of flame but an instrument failure. Operators restarted the unit but the TGTU incinerator tripped off again a short time later.  The trips caused high SO2 concentrations in the incinerator stack and high H2S in the Zone A fuel gas.  However, no acid gas was flared. Operators quickly put SRUs back on-line followed by the TGTU. The fire eye was repaired to prevent recurrence of the problem.


description_of_release:
The TGTU combustion air blower tripped off unexpectedly. In attempts to switch to the spare blower, it would not start.  The tripped blower finally started after 30 minutes.

notes:
Once started, the SRUs were put back into the TGTU and out of the incinerator. The main combustion blower was checked by maintenance personnel and repaired.  In addition, the TGTU catalyst was changed out during the October maintenance turnaround.


description_of_release:
The Zone A SRU was shutdown for a planned maintenance turnaround.  High levels of SO2 occurred during the SRU burnout process (i.e.., firing the SRU without acid gas feed to remove elemental sulfur).


description_of_release:
A power flicker occurred shortly before 4:30 p.m. July 31, possibly due to thunderstorm in the area. Acid gas flaring occurred when the Zone D Sulfur Complex tripped off-line due to a power blip.


description_of_release:
No. 2 SRU tripped off-line due to low acid gas feed rate associated with the ULSD Fractionator shutdown on 11/14/10. This resulted in high SO2  emissions from the incinerator

notes:
The No. 1 SRU was eventually taken off-line and temporarily burned-out due to low acid gas feed rates. Refer to 11/16-17/10 incident.


description_of_release:
A tuning issue on the H2 Plant PSA caused the PSA off gas to be diverted to the atmosphere for 34 minutes (normal disposition is fuel to F-500).


description_of_release:
The FCC WGS (Wet Gas Scrubber) CO ppm and mass limits were exceeded for three block hours and the NOX mass limit was also exceeded for three block hours when CO Boiler #1 at the FCC tripped due to an instrument failure.


description_of_release:
The H2 Plant was shutdown briefly to perform some mechanical work.  The PSA feed gas was vented to the atmosphere for 27 minutes on the shutdown and the PSA off gas was vented to the atmosphere for 231 minutes on the start up.


description_of_release:
The PSA unit tripped due to a valve malfunction.  The H2 Plant was shutdown to repair the valve.  During the shutdown PSA feed gas was  vented to the atmosphere for 86 minutes.


description_of_release:
The PSA unit tripped due to a valve malfunction.  The H2 Plant was shutdown to repair the valve.  The F-500 NOx ppm limit was exceeded for 10 block hours during the shutdown.


description_of_release:
PSA Off gas was vented to the atmosphere for 81 minutes during the restart of the H2 Plant (normal disposition is as fuel to F-500).


description_of_release:
The H2 Plant F-500 NOx ppm limit was exceeded for six block hours during start up following valve repairs resulting from the valve malfunction and shut down on 6/16.


description_of_release:
Wet Gas Compressor, C2X at the FCCU tripped due to a faulty vibration probe. As a result, excess cat gas was flared until rates could be reduced enough to come into balance.


description_of_release:
The FCC WGS CO ppm and mass limits were exceeded for seven block hours during the shut down of CO Boiler #1 (as a result of a blown tube in the superheater section).


description_of_release:
The FCC WGS CO ppm and mass limits were exceeded for one block hour each following an unanticipated feed change due to an upset at an upstream unit.


description_of_release:
The Polypropylene Thermal Oxidizer CO mass limit was exceeded for one block hour following the shut down of the units Vent Recovery System due to a lightning strike.  This resulted in a temporary large increase in gas to the TOU (Thermal Oxidizer Unit).


description_of_release:
H2 Plant was shut down to replace unit catalyst.  Vented PSA feed gas (15 minutes) and PSA Off Gas (200 minutes) to the atmosphere during the shutdown.


description_of_release:
Vented PSA Off gas to the atmosphere for 113 minutes during the start up of the Hydrogen Plant (normal disposition is to the furnace, F-500).


description_of_release:
Waste Gases bypassed the Polypropylene Thermal Oxidizer for seven minutes when the TOU tripped when instrumentation momentarily failed due to a lightning strike.


description_of_release:
FCC Wet Gas Compressor C2X tripped due to a power dip, resulting in flaring until the FCC rates could be reduced to bring the gas back into balance.


description_of_release:
A total power failure (originating outside the refinery) in excess of 24 hours led to the following incidents which occurred during the shut down and subsequent start ups which commenced on 10/25 and lasted through 11/4. See Note for Full Description


description_of_release:
Acid Gas Flaring intermittently during the refinery shut down resulting from the total power failure.


description_of_release:
Hydrocarbon flaring during the refinery shut down resulting from the total power failure.


description_of_release:
On 11/16/10, operators began the process of desulfiding the Zone A No. 1 SRU due to low quantity of acid gas. The ULSD was down for maintenance and so there was not enough acid gas feed to operate both sulfur plants.

notes:
Subsequently, the No. 2 SRU tripped off-line due to low acid gas feed rate resulting in high SO2 emissions.


description_of_release:
A sudden increase in ULSD LCGO feed resulted in high SO2 emissions from the incinerator.

notes:
As the ULSD began raising both total charge rate and LCGO make, the rate of increase spiked the quantity of acid gas above the rate at which the Zone A SRUs could handle. The SRUs ran short on air due to the back pressure which in turn caused a high H2S concentration in the recycle from the TGTU.  The increase in the recycle gas further increased the back pressure problem upsetting SRU operations. Operators worked to stabilize unit operations as quickly as possible.


description_of_release:
A Zone E DCS system upgrade was being performed on 12/16/10.  While preparing the SRU for a DCS upgrade the unit trip buttons were inadvertently pressed during the interlock bypass step and the unit went off line.

notes:
This resulted in the SRU tail gas bypassing the TGTU being sent directly to the incinerator stack. The operators worked quickly to reestablish unit operations. To prevent another incident during future planned DCS upgrades, specific procedures have been established.


description_of_release:
The Zone A Incinerator had high SO2 emissions due to start-up related combustion of residual sulfur in No. 1 SRU and Condenser Seal Pot problems.

notes:
TGTU catalyst activation procedures also contributed to Incinerator emissions.  During the startup of the SRU natural gas is fired to allow the slow warm  of the SRU reactor beds and activate the catalyst prior to introduction of acid gas.  The catalyst must be heated to normal operating temperatures in order to obtain H2S recovery. In the warm-up process, some of the residual sulfur deposits in the equipment are released.  In this case this resulted in high SO2 emissions. Normal shutdown and startup procedures were followed but there was no indication the quantity of residual sulfur in the unit equipment would result in the high emissions.


description_of_release:
Zone A was in the process of increasing the acid gas feed rates  during the start-up of the #2 SRU. During this process, an acid gas valve that controls the flow of acid gas to the Zone D SRU suddenly closed.

notes:
his subsequently caused a pressure increase in the Zone A Amine Stripper. The high pressure caused the amine to become loaded with a high H2S concentration. The Stripper could not efficiently strip the sulfur resulting in a high H2S concentration in the fuel gas system.  It took several hours of operation to clean the amine. Note that the refinery fuel gas system H2S concentration did not exceed the permit limit and no fuel gas fired units exceeded permitted SO2 emission limits.


description_of_release:
High CO emissions occurred during the start-up of the FCCU which was extended by operating problems associated with processing severely hydrotreated feed. The high CO emissions occur during startup while burning torch oil to raise unit temperatures.

notes:
Opacity was high during the initial catalyst loading and circulation because the ESP cannot be energized until the unit comes to steady state operations. The FCC Electrostatic Precipitator has an SIS (safety interlock system) which prevents operation during periods of high CO concentrations in the flue gas which may occur during shutdown and startup of the unit. Measured opacity was 31 to 57%.


description_of_release:
The Zone E fuel gas had a high H2S concentration when the amine system became H2S saturated as operators were preparing to startup the Zone E SRU.

notes:
Note that the refinery fuel gas system H2S concentration did not exceed the permit limit and the Coker Heater did not exceed permitted SO2 emission limits.


description_of_release:
The Zone E SRU was shut down with the Coker to address safety concerns related to Coker Heater outlet elbows (refer to 10/30/10 incident, above).

notes:
As part of the shutdown process the SRU is put through a "burnout" to clear equipment of residual sulfur to prevent plugging and ensure safe operation on startup. No acid gas feed is sent to the unit during the burnout, but high SO2 emissions occur due to the residual sulfur compounds. Normally, the Zone E SRU is kept operating though the sharing of rich amine with Zone D, however, Zone D was shutdown for a scheduled maintenance.  Also, on startup the amine reboiler temperature was too low which resulted in some H2S break through when the Coker compressor was started up. The Coker procedures were revised to specify that the amine regeneration must be operational when the compressor is operating.


description_of_release:
Zone D fuel gas had a high H2S concentration due to a low amine contacting temperature during startup.

notes:
Most of Zone D's amine had been shipped over to the Coker amine surge tank during shutdown, so new amine was needed to fill the 300 unit. These conditions, in combination with a cold unit, contributed to a low amine temperature on startup. The cooler amine does not absorb H2S resulting in low H2S recovery.  Attempts were made to heat up the amine by starting circulation with the Coker. The amine was still not up to temperature when the sour fuel gas began to arrive at the LP amine absorber. The Zone D H2S concentration stayed elevated until the amine absorber warmed up. High H2S in the refinery fuel gas occurred.  Note that the refinery fuel gas system H2S concentration did not exceed the permit limit and no fuel gas fired units exceeded permitted SO2 emission limits.


description_of_release:
Unit upset associated with planned maintenance


description_of_release:
Excess emissions resulting from unit shutdown


description_of_release:
Unplanned maintenance of Flare Gas Recovery Unit


description_of_release:
Excess emissions resulting from burning torch oil as part of unit startup


description_of_release:
Excess opacity resulting from circulating catalyst as part of unit startup


description_of_release:
Erroneous output of fresh feed flow meter caused increase in CO concentration


description_of_release:
Frozen steam tracing and plugged pump in #3 Amine Regenerator


description_of_release:
Fuel Gas Combustion Device Stack Emissions


description_of_release:
FCC wet gas compressor inadvertently shutdown by instrument technician


description_of_release:
Untreated fuel gas routed to relief due to scrubbing unit pump malfunction


description_of_release:
Catalytic reforming unit and two hydrotreating units were being shutdown


description_of_release:
Fuel gas scrubbing unit problem - scrubber solution solidified in process lines, resulting in reduced scrubbing


description_of_release:
FCC wet gas compressor was shutdown to repair internal valves.


description_of_release:
Process piping taken out of service to clean a pressure controller


description_of_release:
Naphtha hydrotreater was shutdown as part of a reforming unit shutdown


description_of_release:
Diesel hydrotreater shutdown for reactor catalyst change-out


description_of_release:
Plant-wide electrical power failure resulting from local electric utility equipment failure


description_of_release:
FCC wet gas compressor was shutdown to repair internal valves


description_of_release:
Diesel hydrotreater was shutdown for a reactor catalyst change-out


description_of_release:
FCC wet gas compressor shutdown due to an unknown cause


description_of_release:
FCC wet gas compressor shutdown due to a process upset


description_of_release:
Diesel hydrotreater unit shutdown due to a high hydrogen knock-out pot level.


description_of_release:
Diesel hydrotreater was being shutdown for a reactor catalyst change-out


description_of_release:
FCC wet gas compressor shutdown due to an electrical power irregularity.


description_of_release:
WESP tripped during soot blows while voltage was near the lower limit


description_of_release:
Tank 725, roof landed during service change


description_of_release:
Tank 753, tank empty at beginning of 2010, filled Feb 2, 2010


description_of_release:
Tank 728, tank empty at beginning of 2010, filled Feb 18, 2010


description_of_release:
Lost power to WESP due to power outage triggered by snow storm


description_of_release:
Tank 753, tank landed on legs during service change


description_of_release:
Final tube condenser leak resulted in excess emissions at SRU


description_of_release:
Tank 729, roof landed on legs for service change


description_of_release:
Tank 723, roof unintentionally landed due to hung gauge


description_of_release:
WESP tripped multiple times during start-up coming out of turn-around


description_of_release:
Excess H2S in fuel gas lead to exceedance of SO2 limit at H-501


description_of_release:
Excess H2S in fuel gas lead to exceedance of SO2 limit at B-1


description_of_release:
Tank 764, tank roof inadvertently landed on legs


description_of_release:
Tank 750, tank roof landed on legs during transfer


description_of_release:
Tank 729, roof landed on legs during transfer


description_of_release:
Tank 729, roof landed on legs while tank cleaned and switched service


description_of_release:
Excess H2S in fuel gas lead to exceedance of SO2 limit at F-200


description_of_release:
Tank 752, drained, cleaned and removed from service


description_of_release:
Plugged Liquid Sulfur Seal Pot Caused High Incinerator SO2 Emissions


description_of_release:
Tank 753, drained, cleaned and removed from service


description_of_release:
Tank 725, drained, cleaned and removed from service


description_of_release:
Tank 728, tank roof inadvertently landed on legs


description_of_release:
WGS Scrubber Flowrate below limit due to power outage


description_of_release:
DDU and Combination Unit Restart resulted in excess emissions at SRU


description_of_release:
Unsteady operations at SRU lead to excess emissions


description_of_release:
A total of 115 open ended lines were found and repaired in 2010


description_of_release:
Release of Hydrogen Sulfide at Combination Unit Blowdown Stack During  Startup Operations Following Turnaround.


description_of_release:
SRU Incinerator tripped off-line during a swing in unit feed. Operations experienced difficulty restrting the incinerator, and acid gas was flared.


description_of_release:
CO Permit exceedences during refinery shutdown


description_of_release:
CO permit exceedences during refinery startup


description_of_release:
Mechanical valve on blower spill back failed open causing unit 1 to over pressurize.


description_of_release:
Over pressurization on vacuum unit during start-up.


description_of_release:
Unit 2 heater shut down.  Over pressurization on vacuum side of unit 2.


description_of_release:
Blower B801 tripped at caustic scrubber due to seal failure.


description_of_release:
Blower B800 tripped at caustic scrubber.


description_of_release:
Power dip caused fuel valves to close and blowers to trip.


description_of_release:
Over pressurization of atmospheric unit during shut down.


description_of_release:
Over pressurization of unit 1 during start-up.


description_of_release:
Exceeded NOx ppm limit for one block hour when ammonia feed to the F-500 SCR was momentarily lost due to pluggage in the feed line.


description_of_release:
Vented PSA (Pressure Swing Absorber) feed and off gas to the atmosphere for 20 minutes during unit shut down.


description_of_release:
FCCU (Catalytic Cracker) flue gas exhausted through bypass stack during startup.


description_of_release:
During FCCU start-up following a turnaround, excess FCCU gas was flared intermittently until all of the wet gas compressors could be started.


description_of_release:
CO mass emissions were exceeded for one block hour during the shut down of the FCCU which occurred due to an instrument failure.


description_of_release:
Flaring occurred during the shut down and subsequent restart of the FCCU due to an instrument failure.  Excess gas is flared until the wet gas compressors can be started.


description_of_release:
Vented PSA Off gas to the atmosphere during H2 Plant restart from turnaround.


description_of_release:
A PLC (Programmable Logic Controller) failure at the H2 Plant substation caused the PSA to trip which resulted in venting of PSA feed to the atmosphere for 48 minutes.


description_of_release:
A PLC failure at the H2 Plant substation caused the PSA to trip which resulted in an exceedance of the F-500 NOX ppm limit for fifteen block hours.


description_of_release:
A valve failure at the H2 Plant caused the PSA off gas to vent to the atmosphere for 110 minutes.


description_of_release:
An instrument failure at the H2 Plant caused the PSA to trip which resulted in the venting of the PSA feed gas to the atmosphere for 15 minutes.


description_of_release:
The F-500 NOx ppm limit at the H2 Plant was exceeded for one block hour following a trip of the PSA which was caused by an instrument failure.


description_of_release:
FCCU Flue Gas exhausted through bypass stack during startup of FCC following restoration of power.


description_of_release:
The FCC WGS CO mass limit was exceeded for six block hours during the FCC restart from the power outage.


description_of_release:
The H2 Plant NOX ppm limit was exceeded for eleven block hours on 10/30 and seven block hours on 11/4 to make repairs to the SCR B vaporizer. See note for full description


description_of_release:
The H2 Plant NOX ppm limit was exceeded for six block hours during the warm up of the F-500 furnace when an EIV (Emergency Isolation Valve) malfunctioned in the ammonia delivery system to the SCR. See Note For Full Description


description_of_release:
A freeze up on an overhead exchanger outlet line caused the atmospheric safety valve on the Light Ends Fractionation Column at LORU (Light Olefins Recovery Unit) to release to the atmosphere.


description_of_release:
During the restart of a transformer within the refinery electrical system (following the power failure); See note for full description.


description_of_release:
PSA Off Gas at the H2 Plant vented intermittently to the atmosphere over 85 minutes during a unit upset which occurred during a Critical Instrument check (normal disposition is to the furnace, F-500).


description_of_release:
PSA Off gas at the H2 Plant was vented to the atmosphere for 165 minutes during the shutdown of the unit to repair a tray in the Condensate Deaerator Drum.


description_of_release:
PSA Off gas at the H2 Plant was vented to the atmosphere for 405 minutes during the restart of the unit following repairs to the Condensate Deaerator Drum.


description_of_release:
Caustic Regen Unit Thermal Oxidizer tripped during the start up of the Refinery Fuel Gas Treating Unit.  This caused the API Separator Vent Gas to bypass the TOU for 18 minutes.


description_of_release:
PSA off gas at the H2 Plant was vented to the atmosphere during start up following the power failure (prior to being introduced as fuel gas to the furnace, F-500).


description_of_release:
Upset on Crude Unit 7 during crude oil feed change sent to North Flare.


description_of_release:
North flare gas recovery compressors shut down due to high operating temperatures


description_of_release:
Coker wet gas compressor shutdown due to low oil pressure.  North flare event


description_of_release:
High volume of propane to flare due to hot weather to North flare


description_of_release:
North flare event.  Flare gas recovery compressor inlet filters clogged, shuting down compressor


description_of_release:
South flare event.  Flare gas recovery compressors shutdown.


description_of_release:
South flare event.  FCCU Debutanizer PSV lifted to flare


description_of_release:
Soth flare event.  FCCU PSV on vessel 51-C-6 lifted to flare


description_of_release:
South Flare event.  Lost natural gas flow to CHD-1


description_of_release:
South Flare event.  Flare gas recovery compressors shutdown due to liquid level column malfunction.


description_of_release:
Soth Flare event. Repair ALKY evacuation line to flare


description_of_release:
Soth flare event.  CCR and NHT shutdown for planned maintenance event


description_of_release:
South Flare event.  CCR and NHT startup from planned maintenace event


description_of_release:
South flare event.  CCR hydrogen compressor malfunction


description_of_release:
South flare event.  FCCU wet gas compressor malfunction


description_of_release:
South flare event.  Carbon changout on CHD-1 ARU


description_of_release:
South flare event.  ALKY unplanned depropanizer shutdown and repair


description_of_release:
South flare event.  ALKY depropanizer unplanned shutdown and repair


description_of_release:
South flare event.  ALKY main fractionator malfunction


description_of_release:
South flare event.  ALKY depropanizer upset.


description_of_release:
South flare event. ALKY depropanizer upset


description_of_release:
South flare event.  CHD-1 planned shutdown.


description_of_release:
South flare event.  CHD-1 planned shutdown


description_of_release:
Liquid naphtha spill in Tank S-81 containment field


description_of_release:
Vacuum tower eductor gas to process heater


description_of_release:
High SO2 from flare exceeding 1.5 lb/hr NSR limit.  No specific unit.


description_of_release:
Drop in temperature due to loss of compressors


description_of_release:
Drop in catalytic regenerator temperature


description_of_release:
High Nox and CO for GC-1C during testing


description_of_release:
High Nox and CO for GC-1B during testing


description_of_release:
VRU on TRUCK unit shutdown to replace Z seal pump


description_of_release:
VRU on TRUCK unit failed to maintain MOPV.  Increased truck loading.


description_of_release:
VRU on TRUCK unit failed to maintain MOPV. Cause unknown.


description_of_release:
VRU on TRUCK unit shutdown to test system for air leaks


description_of_release:
High SO2 to flare from cat debutanizer.  Bottoms level control valve failed.


description_of_release:
Increase in steam generation caused insufficient burning of CO


description_of_release:
VRU on TRUCK unit shutdown to replace absorbent pump valve.  Exceedance of MOPV cause unknown.


description_of_release:
VRU on TRUCK unit exceedance of MOPV.  Cause unknown.


description_of_release:
Power loss caused excess emissions at flare.  No specific unit.


description_of_release:
Power loss caused excess SO2 emissions to flare.  No specific unit.


description_of_release:
High SO2 from flare caused by frozen water leg on GV-5.  No specific unit


description_of_release:
2010-01-05 W3401 depressure to flare prior to maintenance


description_of_release:
The cause of this event was the freezing of the differential pressure flow element for the South Alky Feed Preparation Unit (Unit 43) C3/C4 Splitter Tower (W-76) Bottoms Flow Indicator Controller (43FIC014).


description_of_release:
2010-01-13 to 01-15 W-76 flaring for maint


description_of_release:
The pressure in the Residuum Oil Supercritical Extraction-2 (ROSE-2) Solvent drum began increasing and was vented to the GOH flare. The increased pressure was caused by non-condensable gases coming out of the liquied butane solvent.


description_of_release:
Planned maintenance involving the following equipment was first depressurized and then purged with hydrogen to the GOH flare: Mild hydrocracker, main reactor, guard bed reactor, ULSD reactor, Reactor vent cooler separator.


description_of_release:
freezing of the water flushed from the Gas Unit Debutanizer Tower (W-58) to the Overhead Condenser (X-218) caused the pressure inside the Debutanizer Tower to increase above the set point of the pressure relief valve, vented to south plant flare


description_of_release:
The Mild Hydrocracker Unit was on circulation for 15 days for maintenance.  During this time, light compounds accumulated within the MHC.


description_of_release:
In order to inspect internally and to perform appropriate maintenance on the Acid Rerun Column, the operators shutdown the Alkylation Unit.  As a result, the feed to the Alkylation Unit, was redirected to the FCC flare.


description_of_release:
2010-03-19 Unit 33 C-693 Shutdown Flaring


description_of_release:
2010-03-21 Unit 33 C-693 Shutdown Flaring.


description_of_release:
the Isomorizarion Unit (Unit 20) Stabilizer (W-304) pressure increased and the Stabilizer (W-304) Relief Valve (RV2003) lifted, relieving the Isomerization (Unit20) Stabilizer (W-304) overhead pressure to the North Plant Flare (FL-400).


description_of_release:
2010-04-17 Unit 64 Hydrogen to flare (FL-404)


description_of_release:
2010-04-18 Excess Pressure to D-63 RV06020 to NP Flare (FL-400)


description_of_release:
2010-04-26 Unit 33 Hydrogen to GOH Flare


description_of_release:
2010-04-27 Unit 63 D-8805 to GOH (FL-404) scheduled start-up


description_of_release:
2010-04-27 to 04-29 Unit 08 T-77 to SP (FL-401) Planned Maintenance


description_of_release:
2010-04-29 Unit 06 D-63 planned maintenance


description_of_release:
Emergency Shutdown System in the PLC shut down SRU3 including diverting SRU3 from the Tail Gas Treating Unit to the Tail Gas Incinerator. Also, the hot oil furnace shut down due to the loss of flow.


description_of_release:
2010-05-05 Unit 34 D3404 RV3414 leaking to flare


description_of_release:
2010-05-06 Artesia EER IR ROSE2 D2502 RV2504 to GOH Flare (FL-404)


description_of_release:
2010-05-10 Unit 08 T-73 T-74 to SP (FL-401) Planned Maintenance


description_of_release:
2010-05-11 Vacuum Unit 21 leaking RV Purchased Gas to flare


description_of_release:
2010-05-12 Unit 02 D-140 vented to flare (FL-401) maintenance


description_of_release:
2010-05-13 Crude Unit 02 D-100 to SP flare (FL-401) Planned Maintenance


description_of_release:
The Mild Hydrocracker (Unit 34) Cold Low Pressure Separator (W-3405) was first depressurized, and then purged with nitrogen to the GOH Flare (FL-404) prior to planned maintenance.


description_of_release:
2010-05-14 ROSE2 Unit 25 relief through RV2504 to GOH Flare (FL-404)


description_of_release:
Unable to maintain the desired level within the Crude Unit Crude Pre-Fractionator, and debris on the screens for pumps reduced the flow rate from the bottom of the Crude Pre-Fractionator to the Crude Fractionator.


description_of_release:
2010-05-15 Vacuum Unit 21 D-202 to SP flare (FL-401)


description_of_release:
2010-05-24 Vacuum Unit D-202 flaring event


description_of_release:
2010-05-27 Vacuum Unit D-202 to SP flare (FL-401)


description_of_release:
2010-05-30 Unit 64 PSA Feed to GOH Flare (FL-404)


description_of_release:
2010-05-30 Unit 08 T-71 to SP (FL-401) Planned Maintenance


description_of_release:
2010-05-30 Isom Unit 20 D-385  to NP Flare (FL-400) event


description_of_release:
2010-05-30 Naphtha Unit 13 X-187 to NP Flare (FL-400) event


description_of_release:
2010-05-31 Unit 08 T-72 to SP (FL-401) Planned Maintenance


description_of_release:
2010-06-02 Unit 21 D-202 to SP flare (FL-401) Planned Startup


description_of_release:
2010-06-04 Crude Unit 02 W-16 RV to SP flare (FL-401) event


description_of_release:
Due to a mechanical malfunction of Sour Gas Compressor, the net flow to Pre-flash Crude Tower began decreasing.  As a consequence, the pressure in the Distillate Receiver increased and was released to the South Plant Flare.


description_of_release:
2010-06-21 Vacuum Unit C-111 D-202 Flaring


description_of_release:
2010-07-07 Planned maintenance Isom Unit flaring


description_of_release:
2010-07-10 Sats Gas Plant W-58 leaking to SP Flare (FL-401)


description_of_release:
2010-07-11 D-202 flaring due to H-19 tripping


description_of_release:
2010-07-13 Unit 09 Planned maintenance depressure D-629


description_of_release:
2010-07-14 to 07-15 Alky Unit 09 X-660 propane leak to cooling water


description_of_release:
From 07/15/2010 at ~10:15 to 07/15/2010 at ~10:30, the Alkylation Unit (Unit 09) Propane Bauxite Treater (D-0627) was depressurized and purged with nitrogen to the Alky Flare (FL-403) for planned maintenance work.


description_of_release:
Sealant fluid pumped into a clamp caused a small leak on the tube side of the exchanger to increase in size, allowing a larger volume of diesel to be released.


description_of_release:
2010-07-27 Hydrogen Unit 63 PSA Feed to GOH Flare


description_of_release:
2010-08-16 Unit 08 T-0072 depressured to SP Flare for Planned Maintenance


description_of_release:
2010-08-18 Excess Fuel Gas to Alky Flare (FL-403)


description_of_release:
Flaring event caused by the unexpected shutdown of the Crude Unit Off-Gas Compressor, and with both compressors down, the pressure in the Preflash Tower Overhead Receiver increased leading to the release to the flare.


description_of_release:
2010-08-31 Isom Unit D-282 depressured for planned maintenance


description_of_release:
The Off-Gas Compressor shutdown was caused by a worn discharge valve. Debris produced during the valve replacement caused second shutdown. Malfunctions led to the pressure increase that resulted in two releases to the flare.


description_of_release:
leak on the inlet piping on top of the Reactor.


description_of_release:
malfunctions contributed to the pressure increase in the Preflash Tower Overhead Receiver that resulted in two releases to the South Plant Flare


description_of_release:
Crude Unit Off Gas Compressors were shut down to replace a flow check. Pressure increased in the Preflash Tower Overhead and was vented to the South Plant Flare.


description_of_release:
2010-09-18 Sats Gas Plant Unit 35 D-762 RV to SP Flare (FL-401)


description_of_release:
2010-09-19 Sats Gas Plant Unit 35 D-320 to SP Flare (FL-401)


description_of_release:
2010-09-21 Excess Fuel Gas to GOH Flare (FL-404)


description_of_release:
2010-10-09 Crude Unit C-0302 S/D flaring


description_of_release:
leaks were found in the FCCU High Stage Cooler


description_of_release:
A leaking check flow valve located in the Off-Gas Compressor discharge line lead to the shutdown of the compressor. When the pressure in the Overhead Receiver Drum was ~ 70 psig, the operators vented off-gas to the South Plant Flare.


description_of_release:
Piping from the Sour Gas Compressor to the Pre-flash Crude Tower Overhead Receiver was partially plugged. Sour Gas Compressor shutdown, the pressure in Distillate Receiver exceeded the normal operating value and vented to the South Plant Flare


description_of_release:
Off-Gas Compressor drive belts were slipping.  Maintenance department shut down the Off-Gas Compressor to replace the drive belts


description_of_release:
Obstruction in the off-gas piping between the W-60 Surge Drum and Sour Gas KO Drum caused the system to overpressure.  The overpressure resulted in the release from the Preflash Tower Overhead Receiver Drum to the South Plant Flare.


description_of_release:
2010-11-20 Kerosene Unit (Unit 05) RV0316 NP Flare


description_of_release:
Obstruction in the Sour Gas Compressor discharge line may have restricted the gas flow to the Pre-flash Crude Tower, resulting in the release to the flare.


description_of_release:
2010-11-23 Crude Unit C-303 SD D-140 to SP Flare


description_of_release:
2010-11-24 Unit 63 D-8805 to GOH flare for planned startup


description_of_release:
2010-11-26 Naphtha Unit (Unit 13) D-44 vented to flare


description_of_release:
2010-11-30 Vacuum Unit C-111 shutdown D-202 to SP flare


description_of_release:
2010-12-06 Crude Unit C-0303 shutdown D-0140 to SP flare


description_of_release:
2010-12-07 SRU3 CCR H2 shutdowns, 2010-12-07 Units 63 and 64 flaring for startup


description_of_release:
The Hot Separator capillary Level Transmitter failed to provide accurate level readings.  The pressure Relief Valve directed the excess liquid to the flare knock out drum. Vapor was burned in the GOH Flare and the liquid was pumped to the slop tank.


description_of_release:
2010-12-19 to 12-20 D-770 Fuel Gas to GOH Flare


description_of_release:
Obstruction inside the Feed Surge Drum float column produced inaccurate level readings. Operators opened a 1-inch valve on the Feed Surge Drum overhead outlet to vent the excess pressure to the South Plant Flare


description_of_release:
2010-12-28  PBC (Unit 41) D-450 depressurized to flare for planned maint


description_of_release:
2010-08-10 Electric power failure shutdown


description_of_release:
2010-10-03 2010-10-03 Stabilizer T-103 flaring after H-102 leak to flare


description_of_release:
SRU#1 Shutdown causing sulfur bed to be combusted to the SRU#1 Thermal Oxidizer resulting in Excess SO2 Emissions


description_of_release:
2nd Stage ISO start up resulted in hydrocarbon carry over to the TRP SRU resulting in the flame going out and acid gas flaring to the east acid gas flare


description_of_release:
Coker wet gas compressor tripped off due to equipment freeze up resulting in flaring to the west flare


description_of_release:
Coker 3 in blowdown with less than 2 flare gas recovery compressors online


description_of_release:
Excess H2S in fuel gas due to an upset of the TRPAmine stripper


description_of_release:
TIU Mix Drum exceeded H2S limit due to an increase in fuel gas production overloading the amine scrubber.


description_of_release:
Loss flame at SRU #2/SRU#3 Thermal Oxidizer due to hydrocarbon carry over to the amine treater.


description_of_release:
Excess SO2 emissions at SRU #2/#3 Thermal Oxidizer due to Isocracker start up


description_of_release:
Increased fuel gas to the BGOT unit during startup resulted in excess NOx emissions above the daily average permit limit.


description_of_release:
Tank 172 exceeded the annual VOC emission limit set forth in the Title V permit due to spare tank outages.


description_of_release:
MCOH split range control valve opened to flare


description_of_release:
Hydrocarbon flaring occurred from safety pilot on Iso First Stage High Pressure Separator, LIU SGP and fuel gas mix drum, & process upset at the LIU Amine Unit resulting in acid gas flaring.  The H2S equaled 109 lb, which is above SARA & CERCLA limits.


description_of_release:
LIU amine process upset, flaring before flow sent to SRU.


description_of_release:
Freezing caused leaks at the O/H fan coils at the TGTU .  To repair, vent gas was routed to the SRU Acid Gas Flare during the repair.


description_of_release:
Isocracker startup and shutdown flaring.


description_of_release:
FCC wet gas compressor shutdown due to low lube oil pressure & Isocracker recycle compressor malfunction.  Overlapping events caused hydrocarbon flaring > 500 lb SO2 limit (SARA reportable).


description_of_release:
Isocracker shutdown flaring after makeup compressor trip.


description_of_release:
The Isocracker 1st stage High Pressure Separator dump valve allowed gas to leak to the LIU Flare.  Valve spring tension was increased and the stem rolled down 1 round.


description_of_release:
Startup flaring after sat gas plant tripped on loss of instrument air


description_of_release:
Naptha Splitter Overhead Safety lifted after the HIC off the Isom charge pump was opened to send some feed out to storage, as there was a high level in the feed drum.  This over-pressured the Light. Naptha to storage line causing the safety to lift.


description_of_release:
Liquid was discovered on the floating roof of Tank 006 during the attempt to conduct the annual seal inspection.  This was called in as a malfunction, and it was reported as a deviation under Title V and the permit-to-install (PTI) for Tank 006.


description_of_release:
The FCC feed rate was reduced in response to a leak on the outlet line of Coker Depropanizer reboiler.  The lower feed rates generated an increased amount of carbon monoxide (CO).


description_of_release:
During the annual seal inspection of Tank 215, product was found in some of the roof pontoons, and the cover on the abandoned gauge float well has some opening.


description_of_release:
The breaker for Cell A on the electrostatic precipitator (ESP) tripped off.  Electricians were called out to reset the breaker.  There were 5 exceedances of the 20% opacity limit.


description_of_release:
During the annual seal inspection for Tank 77, liquid was discovered on the floating roof and the gauge well cover was dislodged.


description_of_release:
The Coker compressor tripped on common trouble alarms resulting in Bubble Tower overhead vapor flaring at the FCC Flare.


description_of_release:
There was a 1 gallon spill of slop oil from a pinhole leak on the Tank 327 slop line at the Tank 298 manifold.  The line was inspected and clamped.  The spill is non-reportable and is covered under the petroleum exclusion.


description_of_release:
Startup flaring for commissioning of Liquid Ring Compressor


description_of_release:
A 3” long crack in the floating roof of Tank 323 caused tank contents to leak onto the roof.


description_of_release:
Liquid ring compressor shutdown, due to excess suction pressure.  The compressor was re-started.


description_of_release:
Process upset at LIU amine involving flooding of the amine stripper


description_of_release:
Reformer shutdown due to compressor failure.


description_of_release:
A leak in the capillary tube of the level indicator for the CO Boiler resulted in excess opacity emissions.  This was called in to the Ohio EPA as a malfunction


description_of_release:
During the annual seal inspection, there were two weep holes found in the floating roof, and one hole in the vacuum breaker


description_of_release:
During the annual seal inspection of Tank 84 (Slop Oil) there was product found on the floating roof, and approximately 40% of the primary seal was rolled over.


description_of_release:
During the annual seal inspection of Tank 173 (Slop Oil) there was product found on the floating roof from a weeping lap weld joint, and the ladder negotiator and center column seals are worn.


description_of_release:
The LIU liquid ring compressor was shutdown to conduct maintenance activities, as a result of which gas was vented to the flare.


description_of_release:
Annual seal inspection of Tank 208 discovered that roof pontoon #1 was wet, there was product weeping from #19 roof leg, there was an excessive gap in the secondary seal, and gaps in the seals of the gauge pole and radar pole wiper seal.


description_of_release:
Goose flew into power line affecting power to Isocracker and Sat Gas Plant


description_of_release:
Various units were shutdown due to a power outage caused by a goose that flew into electrical wires at the Buckeye Road Tank Farm.  This item reflects emissions prior to the decision to shut down the affected units. .


description_of_release:
Flaring was caused by fouling of the lean amine control valve.  There were two periods of acid gas flaring (AGF) from the LIU Amine Unit, resulting in 910 lb of SO2 emissions.


description_of_release:
Diesel Hydrotreater shutdown after power loss and attempts to restart compressor


description_of_release:
Claus II tripped due to electrical power problems.


description_of_release:
Low temperatures at Claus I thermal reactor, presumed (incorrectly) to be caused by hydrocarbon in acid gas, LIU Amine stripper off-gas to SRU was blocked in & sent to LIU H2S flare.


description_of_release:
The temporary air blower at the FCC shutdown and caused a reversal and subsequent shutdown of the unit.  This incident was reported as a malfunction and resulted in excess emissions of CO, Nickel Operating Value, and opacity.


description_of_release:
Pulled FCC feed because of FCC flow reversal (cat feed through the regenerator).


description_of_release:
TGTU flaring, caused by reversal at FCC and subsequent FCC shutdown


description_of_release:
During the startup of the FCCU, the wet gas compressor had to be shut down due to sudden and severe vibrations. The FCC feed rate was reduced to minimum and went on a low pressure operation.


description_of_release:
The incident noted above also resulted in SARA/CERCLA releases for H2S and H2SO4.  There were exceedances of the permit limits for opacity and CO, and one noise complaint.


description_of_release:
Individual flaring events combined pursuant to Consent Decree: 8/29/10 DHT Unit lost the feed charge pump, 9/1/10 Vac Unit off-gas compressor shutdown on low discharge pressure, 9/1/10 Acid gas flaring from the SRU Amine Regenerator & TGTU Accumulator


description_of_release:
Changing caustic from LPG wash tower, propane pressured out the bottom of the tower to Tank 482.  The vent on Tank 482 lifted & a combination of caustic & propane was released to the atmosphere.  The release did not exceed permit limit for Tank 482.


description_of_release:
The CO Boiler went down after losing both combustion air fans.  The boiler was relit, and started back up with just the west fan.  The boiler shutdown again due to the loss of the west fan, and the bypass stack was used.


description_of_release:
During the annual seal inspection of Tank 253, gaps were discovered in the ladder negotiator seal and there was liquid on the floating roof.


description_of_release:
The ESP went down due to loss of breakers.  Water seal on COB bypass stack lost when dump valve opened resulting in opacity exceedances. Fuse was replaced to reenergize all 3 cells in ESP, dump valve was closed & the water seal was reestablished.


description_of_release:
Process upset flaring involving Amine Acid Gas and TGTU


description_of_release:
A tube leak was discovered on CO Boiler on 9/28/10.  The leak continued to increase, boiler was shutdown to avoid disruption to steam balance.  The ESP was shutdown also to prevent any damage to the equipment prior to the FCC TAR.


description_of_release:
During the annual seal inspection of Tank 202, holes were found in the two abandoned floatwell covers, the bazooka guide seal was not sealing properly, and one vacuum breaker gasket had deteriorated.


description_of_release:
Annual seal inspection of Tank 135, a hole was discovered in the top course of the shell.  The rest of the top course was inspected with no other problems identified.  Safe fill height was reduced to 35’ for the tank operation.


description_of_release:
Water wash SWS and Amine AG knockout pots


description_of_release:
TGTU & Claus I shutdown to prevent malfunction of leaking outlet line. Vent gas from the NESHAP System & Acid Gas from LIU Amine routed to LIU Flare.  SO2 emissions during shutdown & Claus I startup covered under the permit limit.


description_of_release:
After acid gas flaring that had been sent to the LIU acid gas flare was returned to Claus I for processing.  Some flaring continued at P036 acid gas flare until an open valve was closed.


description_of_release:
During the annual seal inspection of Tank 352 (Sour Water) there was liquid discovered on the floating roof.  The SSM plan has been initiated.


description_of_release:
LIU amine AG flaring due to operator error


description_of_release:
Claus II sulfur pit vapors routed to inlet of SRU incinerator.  The incinerator stack SO2 CEMS went off-scale.  High levels of H2S breakthrough from the TGTU absorber to the incinerator appear to be the source of the release.


description_of_release:
Isocracker shutdown for planned maintenance in subsequent startup.


description_of_release:
Thawing one of the loading arms at the Aromatics Loading Rack, a small amount of benzene released from the packing, which sprayed the operator.  The operator was wearing the proper PPE, and the quantity of material released was below the RQ of 10 lbs.


description_of_release:
Butane leak detected at bypass valve of BBT tower FIC 671001near ground level.


description_of_release:
Mass emission rate calculation was being performed using the raw ppm vs the 0% O2-corrected ppm, resulting in lower CO emissions to be reported.  After calculation was corrected, the mass emission rate was high enough to exceed a permitted limit.


description_of_release:
Emergency Shutdown of the No. 5 FCC Unit was caused by a brief loss of power.  Power loss was caused by lightning strike interrupting power supply to distributed control system. Result: Flaring and Nox and CO rolling averages were briefly exceeded.


description_of_release:
South Plant wet gas compressor shutdown due to gas composition changes during Isom unit startup.  This resulted in flare gas overwhelming flare gas recovery unit and subsequent flaring.


description_of_release:
Failed instrumentation on the regenerator differential pressure control.


description_of_release:
Leaks were found within the South Plant Flare Gas Recovery Unit (FGRU), the unit was shut down for emergency maintenance.  Shutting down the FGRU caused flaring.


description_of_release:
Excess H2S and benzene emissions were caused by sour water entering into the wet gas scrubber for the No. 5 FCC.


description_of_release:
Permit limit exceedances: 500 ppmvd CO @ 0% O2 (1 hour); 160 lbs CO/Hr (1 hour).  The combustion conditions in the WHB for No.5 FCC caused the stacks CO to spike, the O2 monitor for WHB combustion was giving an incorrect reading.


description_of_release:
A fire at No.4 FCC heat exchanger X-6165 (caused by a channel head leak), caused an emergency shutdown of the Unit.  Flaring and exceedences resulted: 500 ppmvd CO(17hrs), 500ppmvd CO @0%O2(24hrs), 83.7lbs/hr CO(15hrs), 60ppmvd Nox@0%O2 7dayaverage (4days


description_of_release:
Permit limits for the No. 5 FCC were exceeded: 500 ppmvd CO @ 0% O2 (1 hour); 9/23/2010, process heater H-8602 exceeded 0.035 lbs NOx per mmBTU (144.75 hours) The FCC shutdown b/c of low lube oil pressure in the FCC air blower.


description_of_release:
On October 2, 2010, the No. 4 Fluid Catalytic Cracker was being shutdown for planned turnaround resulting in excess short-term CO limits.


description_of_release:
During No. 4 Fluid Catalytic Cracking Unit (FCCU) shutdown, in an attempt to increase the BTU content of the fuel gas stream, high H2S gas inadvertently back-flowed into the fuel gas system.


description_of_release:
No. 4 FCC unit restart was attempted resulting in excess short-term CO limits. The following emission limits were exceeded: 500 ppmvd CO, 500 ppmvd CO @ 0% O2, 150 ppmvd CO @ 0% O2 365-day average, 60 ppmvd NOx @ 0% O2 7-day average.


description_of_release:
Feed pump mechanical failure caused shutdown of No.4 Fluid Catalytic Cracking (FCCU) unit.  Off-gases which normally are routed to the No. 4 FCCU, had to be diverted to flare.


description_of_release:
Between the 12/14/10 shutdown and the end of 2010, emission limits were exceeded: 500 ppmvd CO, 500 ppmvd CO @ 0% O2, 83.7 Lbs/Hr CO, 150 ppmvd CO @ 0% O2 365-day average, 40 ppmvd NOx @ 0% O2 7-day average.


description_of_release:
The fuel gas valve to the sulfur recovery unit (SRU) hot oil heater froze off due to cold weather.  As the hot oil cooled, the temperature controller reduced the hot oil flow rate to keep the temperature up and the slowing hot oil circulation rate fell


description_of_release:
the FCCU main air blower bypass control malfunctioned by suddenly moving to the fully open position for no apparent reason, causing a process upset.  The FCCU was shut down and later when the acid gas feed to the sulfur recovery unit (SRU) fell below min.


description_of_release:
Sour water pumped to the sour water stripper (SWS) from the New North Flare sump that contained amines caused a process upset in the sour water stripper and the excess pressure on the system tripped out the sulfur recovery unit (SRU)


description_of_release:
Sour water pumped to the sour water stripper (SWS) from the New North Flare sump that contained amines caused a process upset in the MDEA stripper that resulted in liquid carryover into the reflux drum and knockout pot.


description_of_release:
the temperature sensor on the outlet of the sulfur recovery unit (SRU) hot oil heater failed, causing a low hot oil temperature.  The low temperature temporarily slowed the flow of acid gas through the amine treating section


description_of_release:
the belts on the sulfur recovery unit (SRU) hot oil heater failed causing the process heate to shutdown. When it shutdown, the SRU Claus section also shutdown and while the SRU was offline the sour gas feed to the unit was diverted to the flare.


description_of_release:
The sulfur recovery unit (SRU) was online, but only slightly above minimum turndown, when the acid gas flow fluctuated and the Claus burner shutdown due to the activation of the low flow acid gas trip.


description_of_release:
The sulfur recovery unit (SRU) Claus combustor developed a leak and the unit was shutdown for safety and for leak repair.  While the SRU was offline the sour gas feed to the unit was routed to the New North Flare.


description_of_release:
The investigation team concluded that the fin fan exchanger to the amine absorber, E48008A, was fouled and was not functioning efficiently. The higher temperature of the amine solution caused an unstable liquid level in the amine stripper


description_of_release:
A digital output card in the sulfur recovery unit (SRU) hot oil heater instrumentation failed, resulting in the loss of reboiler flow to the heater.


description_of_release:
The instrument control system in the sulfur recovery unit (SRU) failed, resulting in a blackout of the process. Because the operators could not monitor or control the process unit, the SRU was immediately shutdown.


description_of_release:
The instrument control system in the sulfur recovery unit (SRU) failed, resulting in a blackout of the process.


description_of_release:
Lightning struck the electrical substation supplying power to the refinery causing a power interruption that shutdown most of the refinery processes including the sulfur recovery unit (SRU)


description_of_release:
A high liquid level in the MDEA overhead accumulator carried over into the acid gas knockout pot, activated the high-level trip, and shutdown the Claus burner.


description_of_release:
a maintenance craftsmen attempted the repair of a VOC leak on a gate valve that was in service at the Alky unit. The valve was back-seated to prevent leakage while the valve packing was replaced but the valve did not seal off properly


description_of_release:
The SRU Claus burner tripped out due to a pressure swing that was caused by starting up the tail gas unit after a washout of the MDEA stripper column.


description_of_release:
The SRU Claus burner tripped out due to a pressure swing that was caused by a malfunction in the air rate controller of SRU Air Blower 49B001B.


description_of_release:
Contract insulators working in the sulfur recovery unit (SRU), in an effort to eliminate a tripping hazard, inadvertently wrapped an electrical extension cord around an SRU emergency shutdown switch.


description_of_release:
The bearings in the south air blower for the sulfur recovery unit (SRU) failed, causing the Claus burner to trip and shutdown the SRU.  While the SRU was down, the acid gas feed was routed to the New North (Peabody) Flare.


description_of_release:
While bypassing the high-pressure receiver at the FCC unit in order to repair a control valve air leak, a pressure swing in the equipment involved caused the pressure relief valve (PRV) on the second stage discharge of the wet gas compressor to open


description_of_release:
the fluidized catalytic cracking unit (FCCU) main air blower bypass control malfunctioned by suddenly moving to the fully open position for no apparent reason, causing a process upset.


description_of_release:
The SRU tail gas quench tower level transmitter failed causing the tail gas that is normally recycled back to the Claus unit to be routed instead to the incinerator.


