A0004 - OMES Part 3 O M.pdf

DEFENSE ENERGY SUPPORT CENTER DEFENSE ENERGY SUPPORT CENTER

OPERATIONS, MAINTENANCE, OPERATIONS, MAINTENANCE,

ENVIRONMENTAL AND SAFETY PLANENVIRONMENTAL AND SAFETY PLAN

Prepared For:

U.S. Army Engineering and Support Center Huntsville, Alabama and Defense Energy Support Center

Fort Belvoir, Virginia

September 2009

Prepared by:

1608 13th Avenue South, Suite 160

Birmingham, Alabama 35205 Contract No: W912DY-08-D-0001 DO 0006 NationView Project Number: 8080036

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EENNVVIIRROONNMMEENNTTAALL,, AANNDD SSAAFFEETTYY PPLLAANN

OOPPEERRAATTIIOONN,, MMAAIINNTTEENNAANNCCEE,, EENNVVIIRROONNMMEENNTTAALL,, AANNDD

SSAAFFEETTYY PPLLAANN

DEFENSE FUEL SUPPORT POINT

SAN PEDRO, CALIFORNIA

Prepared For:

U.S. Army Corps of Engineers

Huntsville Engineering & Support Center Post Office Box 1600

Huntsville, Alabama 35807-4301

September 2009

Contract No. W912DY-08-D-0001 Delivery Order 0006

NationView Project No. 8080036

Prepared By:

1608 13TH AVENUE SOUTH, SUITE 160

BIRMINGHAM, ALABAMA 35205

205.930.9494 ~205.930.9485 Fax and

POND & COMPANY

3500 PARKWAY LANE, SUITE 600

NORCROSS, GEORGIA 30092

678-336-7740 WWW.PONDCO.COM

Distribution authorized to the Department of Defense and U.S. DoD contractors only for administrative and operational use. Other requests for this document shall be referred to the Defense Energy Support Center DESC-W (Environmental Division), 8725 John J. Kingman Road, Fort Belvoir, VA 22060-6201.

September 2009 Revision No. 05

FOR OFFICIAL USE ONLY

http://www.pondco.com/

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Revision No. 05 September 2009

DDFFSSPP SSAANN PPEEDDRROO AACCRROONNYYMMSS

ACRONYMS

Acronym Definition

AFFF Aqueous film-forming foam

AGA American Gas Association

API American Petroleum Institute

ASA Anti-static additive

ASME American Society of Military Engineers

AST Aboveground storage tank

ASTM American Society for Testing and Materials

ATG Automatic tank gauge bbl Barrel (42 gallons)

Bph Barrels per hour

CAA Clean Air Act

CCR California Code of Regulations

CERCLA Comprehensive Environmental Response, Compensation, and Liability Act

CFR Code of Federal Regulations

COR Contracting Officer Representative

COTP Captain of the Port

CP Cathodic protection

CPR Cardiopulmonary resuscitation

CSFM California State Fire Marshal (Office of the State Fire Marshal)

CSLC California State Lands Commission

CWA Clean Water Act

DD DOD (form)

DESC Defense Energy Support Center

DFSP Defense Fuel Support Point

DLA Defense Logistics Agency

DOD Department of Defense

DOT Department of Transportation

EAP Emergency Action Plan

ES&OH MS Environmental, Safety, and Occupational Health Management System

°F Degrees Fahrenheit

FDSM Fuel Distribution System Mechanic

FDSO Fuel Distribution System Operator

FIFRA Federal Insecticide, Fungicide, and Rodenticide Act

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AACCRROONNYYMMSS DDFFSSPP SSAANN PPEEDDRROO

FPOCCO Fuel Pier Operator Control Center Operator

FOD Foreign object damage

FM Factory Mutual Research Corporation

FRP Facility Response Plan

FSII Fuel system icing inhibitor

FSO Fuel System Operator

GIS Geographical Information System

GOCO Government-owned contractor-operated gpm Gallons per minute

HAZWOPER Hazardous Waste Operations and Emergency Response

HW Hazardous waste

IAW In accordance with

ISGOTT International Safety Guide for Oil Tankers and Terminals

JFTOT Thermal stability

JP-5 Jet – A military turbine fuel

JP-8 Jet – A military turbine fuel with additives lb Pound

LEL Lower Explosive Limit

MAOP Maximum Allowable Operating Pressure

MARPOL International Convention for the Prevention of Pollution from Ships

MAWP Maximum Allowable Working Pressure

MIL-STD Military Standard

MOGAS Motor gasoline

MOP Maximum Operating Pressure

MOV Motor operated valve

MPMS Manual of Petroleum Measurement Standards

MSDS Material Safety Data Sheet

NFPA National Fire Protection Association

NOP Normal Operating Pressure

NPDES National Pollution Discharge Elimination System

NPMS National Pipeline Mapping System

NRC National Response Center

OCIMF Oil Companies International Marine Forum

ODS Ozone depleting substances

OES (California) Office of Emergency Services iv Revision No. 05 September 2009

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OHSICP Oil and Hazardous Substances Integrated Contingency Plan

OMES Operations, Maintenance, Environmental, and Safety (Plan)

OPA Oil Pollution Act

OSHA Occupational Safety and Health Administration

OSRO Oil Spill Removal Organization

OTTER Oil Transfer and Transportation Emission and Risk Reduction (Program)

PC Personal computer

PCB Polychlorinated biphenyl

PEL Permissible Exposure Limit

PHMSA Pipeline and Hazardous Materials Safety Administration

PLC Programmable Logic Controller

PMS Planned Maintenance Schedule psi Pounds per square inch psig Pounds per square inch, gauge

QAR Quality Assurance Representative

QI Qualified Individual

RCRA Resource Conservation and Recovery Act

RDO Redistribution Order

RP Reference Practices

RPM Revolutions per minute

RSTRENG Remaining strength

SAIC Science Applications International Corporation

SARA Superfund Amendment and Reauthorization Act

SCAQMD South Coast Air Quality Management District

SIOATH Source Identification and Ordering Authorization

SPCC Spill Prevention Control and Countermeasure (Plan)

TAS Terminal Assistant Superintendent

TLV Threshold Limit Value

TOCCO Terminal Operator Control Center Operator

TOSC Terminal On-Scene Coordinator

TPIC Terminal Person-in-Charge

UFC Unified Facilities Criteria

UL Underwriters Laboratories

UPS Uninterruptible Power Supply

UST Underground Storage Tank

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UW Universal waste

VOC Volatile organic compound

VPIC Vessel Person-in-Charge

WISM Water Separation Index - Modified vi Revision No. 05 September 2009

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7.3.1 Pipeline Failures .....................................................................................7-2

7.3.1.1 California Notification Requirements...........................................7-2

7.3.1.2 Federal Notification Requirements..............................................7-3

7.3.2 Releases of Fuel/Oil to Water.................................................................7-5

7.3.3 Releases to Land....................................................................................7-6

7.3.4 Response ...............................................................................................7-6

7.3.5 Emergency Escape Procedures and Escape Routes.............................7-9

7.4 Emergency Procedures for Fires........................................................................7-9

7.5 Emergency Procedures for Spills .....................................................................7-10

7.5.1 Releases to Land..................................................................................7-11

7.5.2 Releases to Water or Shore .................................................................7-11

7.6 Emergency Procedures for Hazardous Weather..............................................7-13

8 Training and Qualification Program .................................................8-1

8.1 Training ..............................................................................................................8-1

8.2 Persons in Charge..............................................................................................8-1

8.2.1 Terminal Person-in-Charge ....................................................................8-1

8.2.2 Vessel Person-in-Charge (VPIC)............................................................8-2

8.3 Operator Training ...............................................................................................8-3

8.4 Oil Spill Prevention Training ...............................................................................8-4

8.4.1 Operations and Supervisory Personnel ..................................................8-4

8.4.2 Management Personnel..........................................................................8-5

8.4.3 Additional Training..................................................................................8-5

Part 3 Operations and Maintenance 9 Operational Procedures and Guidelines ..........................................9-1

9.1 Operating Parameters ........................................................................................9-1

9.1.1 Operating Tank Capacities and Alarms ..................................................9-1

9.1.2 Maximum Operating Pressures ..............................................................9-3

9.1.2.1 Definitions ...................................................................................9-3

9.1.2.2 DFSP San Pedro MOP/NOP ......................................................9-4

9.2 Standard Operating Procedures.........................................................................9-5

9.2.1 Tank Gauging .........................................................................................9-5

9.2.2 Water Draw-off and Disposal..................................................................9-7

9.2.2.1 Drain Water from Underground Storage Tanks 42 – 47 .............9-7

9.2.2.2 Drain Water from Tanks 11, 14, and 17 to Tank 54....................9-8

9.2.2.3 Manually Drain Water from Tanks 2, 4, 6, 8, 9, 10, 12, 13, 15, 16, 18, 19, and 20 .............................................................................9-8

9.2.2.4 Transfer Slop Tank Contents to Waste Removal Truck..............9-9

9.2.3 Automatic Control System ......................................................................9-9

10 Normal Operations.........................................................................10-1

10.1 Receive Fuel from Fuel Tanker/Barge..............................................................10-1

10.1.1 Process and Responsibilities................................................................10-1

10.1.2 Safety and Environmental Protection ...................................................10-5

10.1.3 Quality During Transfer.........................................................................10-6

10.1.4 Procedure .............................................................................................10-7

10.2 Issue Fuel to Fuel Tanker/Barge ....................................................................10-10 x Revision No. 05 September 2009

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10.2.1 Process and Responsibilities..............................................................10-10

10.2.2 Safety and Environmental Protection .................................................10-13

10.2.3 Quality During Transfer.......................................................................10-14

10.2.4 Procedure ...........................................................................................10-14

10.3 Receive Fuel from Commercial Pipeline ........................................................10-17

10.3.1 Process and Responsibilities..............................................................10-17

10.3.2 Safety and Environmental Protection .................................................10-18

10.3.3 Quality During Transfer.......................................................................10-18

10.3.4 Procedure ...........................................................................................10-18

10.4 Tank-to-Tank Transfers..................................................................................10-20

10.4.1 Process and Responsibilities..............................................................10-20

10.4.2 Safety and Environmental Protection .................................................10-20

10.4.3 Quality During Transfer.......................................................................10-21

10.4.4 Procedure ...........................................................................................10-21

10.5 Issue Fuel to Tank Truck(s)............................................................................10-21

10.5.1 Process and Responsibilities..............................................................10-22

10.5.2 Safety and Environmental Protection .................................................10-22

10.5.3 Quality During Transfer.......................................................................10-22

10.5.4 Procedure ...........................................................................................10-23

10.6 Pipeline Shipment to Kinder Morgan or Carson Station .................................10-24

10.6.1 Process and Responsibilities..............................................................10-24

10.6.2 Safety and Environmental Protection .................................................10-24

10.6.3 Quality During Transfer.......................................................................10-25

10.6.4 Procedure ...........................................................................................10-25

10.7 Recordkeeping ...............................................................................................10-26

10.7.1 Construction Records .........................................................................10-27

10.7.1.1 Terminal and Pier ..............................................................10-27

10.7.1.2 Pipeline ..............................................................................10-27

10.7.2 Inspection/Test Records.....................................................................10-28

10.7.2.1 Terminal and Pier ..............................................................10-28

10.7.2.2 Pipeline ..............................................................................10-28

10.7.3 Operating Records..............................................................................10-30

10.7.3.1 Terminal.............................................................................10-30

10.7.3.2 Pipeline ..............................................................................10-31

10.7.3.3 Pier ....................................................................................10-31

11 Abnormal Operations.....................................................................11-1

11.1 Loss of Commercial Power...............................................................................11-1

11.1.1 Operations ............................................................................................11-1

11.1.2 Communications...................................................................................11-1

11.2 Transfer Process ..............................................................................................11-2

11.2.1 Insufficient Pump Suction Head............................................................11-2

11.2.2 No or Low Discharge Flow from Fuel Pump .........................................11-3

11.2.3 High Pressure in Pipeline .....................................................................11-4

11.2.4 Material not Meeting Specifications ......................................................11-5

11.2.5 Component Failure ...............................................................................11-5

11.2.6 Pipeline System Damage .....................................................................11-5

11.2.7 Corrosion ..............................................................................................11-6

11.2.8 Activation of a Safety Device................................................................11-6

11.3 Tanks................................................................................................................11-7

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11.3.1 Tank Damage .......................................................................................11-7

11.3.2 Overfilling a Tank..................................................................................11-7

11.3.3 Contaminated Fuel in Tank...................................................................11-8

11.3.4 High Water Content in a Fuel Transfer Operation ................................11-9

11.4 Emergency Equipment Operating Procedures .................................................11-9

11.4.1 Emergency Generator ..........................................................................11-9

11.4.2 Power Transfer Guidelines .................................................................11-11

12 Quality Surveillance .......................................................................12-1

12.1 Procedures for Preventing and Controlling Contamination ..............................12-2

12.2 Sampling Procedure.........................................................................................12-2

12.3 Sampling Requirements ...................................................................................12-3

12.3.1 Receipt from Tanker/Barge...................................................................12-3

12.3.2 Receipt from Commercial Pipeline .......................................................12-4

12.3.3 Tank-to-Tank Transfer ..........................................................................12-5

12.3.4 Issue to Marine Vessel .........................................................................12-5

12.3.5 Issue to Truck .......................................................................................12-6

12.3.6 Issue to Kinder Morgan Pipeline...........................................................12-7

12.3.7 Inactive Tanks.......................................................................................12-7

12.4 Standard Laboratory Procedures .....................................................................12-8

12.4.1 Sample Shipping Procedure .................................................................12-8

12.4.2 Tests Required .....................................................................................12-9

12.4.3 Test Significance ..................................................................................12-9

12.5 Calibration Program .......................................................................................12-11

13 Maintenance ..................................................................................13-1

13.1 Equipment Descriptions ...................................................................................13-1

13.1.1 DFSP San Pedro Equipment Numbering Scheme ...............................13-1

13.1.2 Tanks....................................................................................................13-2

13.1.3 Valves...................................................................................................13-3

13.1.4 Pumps ..................................................................................................13-3

13.1.5 Other Mechanical Equipment ...............................................................13-3

13.2 Preventative Maintenance System...................................................................13-3

13.2.1 Responsibility........................................................................................13-3

13.2.2 General Maintenance Requirements ....................................................13-4

13.2.3 Inspections Before Use.........................................................................13-4

13.2.4 Daily Maintenance Requirements.........................................................13-5

13.2.5 Weekly Maintenance Requirements .....................................................13-6

13.2.6 Monthly Maintenance Requirements ....................................................13-6

13.2.7 Quarterly Maintenance Requirements ..................................................13-7

13.2.8 Semiannual Maintenance Requirements..............................................13-8

13.2.9 Annual Maintenance Requirements......................................................13-8

13.3 Piping Testing/Inspection Requirements..........................................................13-9

13.3.1 Responsibility......................................................................................13-10

13.3.2 Maintenance Safety and Environmental Protection............................13-10

13.3.3 Required Materials..............................................................................13-10

13.3.4 Hydrostatic Testing.............................................................................13-11

13.3.5 Leak Testing .......................................................................................13-12

13.3.6 Cathodic Protection System ...............................................................13-12

13.3.7 API 570 Inspections............................................................................13-13 xii Revision No. 05 September 2009

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13.3.8 Inspections of Exposed Piping............................................................13-13

13.4 Storage Tank Cleaning and Inspections ........................................................13-14

13.4.1 Aboveground Storage Tanks..............................................................13-14

13.4.2 Underground Storage Tanks ..............................................................13-14

13.5 Repair and Replacement Procedures ............................................................13-15

13.6 Pipeline Abandonment ...................................................................................13-15

13.6.1 Quality Control ....................................................................................13-16

13.6.2 Procedure ...........................................................................................13-16

13.7 Pipeline Movement .........................................................................................13-17

Tables Table 1-1. Applicable Federal/State/Local Environmental and Safety Directives .....................1-3 Table 1-2. Applicable Petroleum Operation and Maintenance Directives.................................1-3 Table 1-3. Supporting Documents ............................................................................................1-6 Table 2-1. Pipeline Details ........................................................................................................2-3 Table 2-2. Description of Products Handled .............................................................................2-5 Table 2-3. Communication Requirements and Compliance Methods.......................................2-7 Table 4-1. Personal Protective Equipment ...............................................................................4-8 Table 5-1. Fire Fighting Media, Instructions, and Precautions for Fuels and Fuel Additives ....5-7 Table 5-2. Local Fire Stations .................................................................................................5-11 Table 6-1. Pier Containment .....................................................................................................6-4 Table 6-2. Examples of Facilities Management Operations and Related Concerns.................6-8 Table 6-3. Regulatory Citations for Facilities Management Operations....................................6-8 Table 6-4. OMES Documents Generated by DFSP San Pedro..............................................6-12 Table 7-1. Oil Spill Response Equipment at Main Tank Farm ..................................................7-7 Table 7-2. Oil Spill Response Equipment at Fuel Pier 12.........................................................7-8 Table 9-1. Pier Area Tank Capacities and Alarms....................................................................9-1 Table 9-2. Main Tank Farm Tank Capacities and Alarms.........................................................9-2 Table 9-3. MOP and NOP for Active Pipelines at DFSP San Pedro.........................................9-4 Table 9-4. Required Temperature Readings ............................................................................9-7 Table 9-5. Open Valves for Water Draw-off Tanks 42 - 47 to Tank 51.....................................9-8 Table 11-1. Switch Settings for Generator Operation ...........................................................11-11 Table 12-1. Samples Collected for Receiving from Tanker/Barge..........................................12-3 Table 12-2. Samples Collected for Receiving from Commercial Pipeline...............................12-4 Table 12-3. Samples Collected for Transferring from Tank to Tank .......................................12-5 Table 12-4. Samples Collected for Issuing to Marine Vessel .................................................12-5 Table 12-5. Samples Collected for Issuing to Tank Truck ......................................................12-7 Table 12-6. Samples Collected for Pipeline Transfer .............................................................12-7 Table 12-7. Samples Collected for Inactive Tanks .................................................................12-8 Table 12-8. Tests Required for Aviation Turbine Fuels ..........................................................12-9 Table 13-1. Area Designation Key ..........................................................................................13-1 Table 13-2. Equipment Designation Key ................................................................................13-2 Table 13-3. Piping Testing Frequency ..................................................................................13-10

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PART 3

OPERATIONS AND MAINTENANCE

September 2009 Revision No. 05

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9 OPERATIONAL PROCEDURES AND GUIDELINES

9.1 Operating Parameters

9.1.1 Operating Tank Capacities and Alarms

Table 9-1. Pier Area Tank Capacities and Alarms

Tank Product Shell

Capacity (gallons)

Notes

Tank 200 Fuel System Icing Inhibitor

(FSII)

10,000 Aboveground steel single-walled

Tank 201 Slop 84,462 Aboveground steel single-walled, high and low level alarms.

Tank 251 Out of Service 113,358 Aboveground steel single-walled, high and low level alarms.

Tank 252 Out of Service 113,358 Aboveground steel single-walled, high and low level alarms.

Tank 253 Out of Service 113,358 Aboveground steel single-walled, high and low level alarms.

Tank 254 Out of Service 113,358 Aboveground steel single-walled, high and low level alarms.

Tank 301 Fire Water 135,030 Aboveground steel single-walled. Fire system also includes a 500-gallon AFFF tank. High and low level alarms.

Tank 501 Slop 217,770 Aboveground steel single-walled, high and low level alarms.

Tank 502 Slop 217,770 Aboveground steel single-walled, high and low level alarms.

Tank 503 Out of Service 217,896 Aboveground steel single-walled, high and low level alarms.

Tank

JP-5 (Vessel issue, if needed)

872,718 Aboveground steel single-walled, high and low level alarms.

Tank

Out of Service (Proposed JP-

5 Pressure Relief)

873,642 Aboveground steel single-walled, high and low level alarms.

Tank

Out of Service (Proposed JP-

5 Pressure Relief)

873,558 Aboveground steel single-walled, high and low level alarms.

Tank F001 Diesel 500 Underground, coated steel, single wall, low level alarm. (Used for generator supply)

Tank 1 AFFF 500 Aboveground, single-walled steel, no alarms

September 2009 Revision No. 05 9-1

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Table 9-2. Main Tank Farm Tank Capacities and Alarms

Tank Product Shell

Capacity (gallons)

Notes

Tank 1 JP-5 2,100,000 Underground, pre-stressed concrete with steel liner. High and low level alarms.

Tank 2 JP-8 2,100,000 Underground, pre-stressed concrete. High and low level alarms.

Tank 3 JP-5 2,100,000 Underground, pre-stressed concrete with steel liner. High and low level alarms.

Tank 4 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 5 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 6 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 7 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 8 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 9 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 10 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 11 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 12 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 13 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 14 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 15 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 16 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 17 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 18 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 19 JP-5 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 20 JP-8 2,100,000 Underground pre-stressed concrete, high and low level alarms.

Tank 42 JP-5 2,100,000 Underground single-walled coated steel, high and low level alarms.

Tank 43 JP-5 2,100,000 Underground single-walled coated steel, high and low level alarms.

Tank 44 JP-5 2,100,000 Underground single-walled coated steel, high and low level alarms.

Tank 45 JP-8 2,100,000 Underground single-walled coated steel, high and low level alarms.

Tank 46 JP-8 2,100,000 Underground single-walled coated steel, high and low level alarms.

(Continued)

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Table 9-2. Main Tank Farm Tank Capacities and Alarms (Cont’d)

Tank Product Shell

Capacity (gallons)

Notes

Tank 47 JP-8 2,100,000 Underground single-walled coated steel, high and low level alarms.

Tank 48 F-76 2,310,000 Aboveground single-walled steel with floating roof, high and low level alarms.

Tank 49 F-76 2,310,000 Aboveground single-walled steel with floating roof, high and low level alarms.

Tank 50 F-76 2,310,000 Aboveground single-walled steel with floating roof, high and low level alarms.

Tank 51 Slop 13,000 Underground pre-stressed concrete, high and low level alarms.

Tank 52 Slop 5,000 Underground double-walled fiberglass

Tank 53 Slop 12,000 Aboveground double-walled steel

Tank 54 Slop 12,100 Aboveground steel, double-walled, local high level alarm

Tank 56-A FSII 12,000 Aboveground steel, double-walled

Tank 68 FSII 10,423 Aboveground steel, double-walled

Tank 72 Slop 2,500 Underground double-walled fiberglass

Tank 80 AFFF 300 Aboveground steel, single-walled

Tank 81 AFFF 150 Aboveground steel, single-walled

Tank 82 AFFF 150 Aboveground steel, single-walled

Tank 2 Stadis 450 100 Aboveground steel, single-walled

9.1.2 Maximum Operating Pressures218

9.1.2.1 Definitions

To establish operating pressures, definitions must first be clearly understood. Normal operating range is the target range for adequate performance. The classification of the system is an absolute limit and it is defined as a maximum pressure the system can withstand. The fuel system will have parameters in place to ensure the system does not experience pressures higher than its rating. However, it is possible to be outside of the normal operating range but still within the system classification. If this occurs, it is the operator’s responsibility to ensure that protective measures are taken to relieve this additional pressure that is above the normal operating pressure range. Procedures for these operations are included in Chapter 11, Abnormal Operations.

218 49 CFR §195.406

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Maximum Operating Pressure/Maximum Allowable Operating Pressure (MOP/MAOP): 49 CFR Part 195 states the highest pressure at which the pipeline can safely operate for extended periods of time is the definition of MOP.219 This is sometimes referred to as the MAOP, but could be different than MOP under certain conditions. MOP/MAOP can be determined in the following manners:

• A hydrotest at 125% of the value set as the MOP;

• Calculate MOP/MAOP based on internal design pressure of the pipe or the design pressure of the pipeline components, whichever is lowest. Calculations are based on 49 CFR §195.106220; or

• A specified MOP/MAOP based on 80% of the highest operating pressure recorded for a continuous period of 4 hours or more without incident.

MAWP: Maximum Allowable Working Pressure (MAWP) takes into account the operational constraints of the fuel system. For example, a pipeline has a MOP of 125 pounds per square inch (psi). Pressure due to the hydraulic grade line states that the pressure inside a pipeline at the bottom of the hill is greater than the pressure at the top of the hill for a packed line. Since the MOP is 125 psi, the MAWP at the bottom of the hill is 125 psi and the MAWP at the top of the hill is less than 125 psi. This has to be true or the pressure at the bottom of the hill will be in excess of the established MOP. Thus, the MAWP varies for the pipeline while the MOP is constant.

NOP: Normal Operating Pressure (NOP) is the target range for adequate system performance.

9.1.2.2 DFSP San Pedro MOP/NOP

The pressure in a pipeline may not exceed 110 percent of the operating pressure limit during surges or other variations from normal operations.221 Table 9-3 identifies the NOP and the MOP for the active pipelines at DFSP San Pedro. The DFSP San Pedro must provide adequate controls and protective equipment to control the pressure within this limit.222

Table 9-3. MOP and NOP for Active Pipelines at DFSP San Pedro

System MOP NOP

10-inch Government Line (0660-0065) 505 pounds per square inch, gauge (psig) 450 psig

Truck loading system 100 psig 50 to 60 psig

Terminal and Pier tank farm piping 210 psig 150 psig

(Continued)

219 49 CFR §195.406

220 49 CFR §195.406(a)(1) 221 49 CFR §195.406(b) 222 49 CFR §195.406(b)

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Table 9-3. MOP and NOP for Active Pipelines at DFSP San Pedro (Cont’d)

System MOP NOP

JP-5/F-76 and JP-8 14-inch and 18-inch lines (0660-00711, 0660-00712, 0660-00701, 0660-00702)

200 psig 150 psig

Surge Line (0660-0911) 200 psig 150 psig

Multi-product Line (12-inch) 200 psig 150 psig

9.2 Standard Operating Procedures

Forms to be completed by fuels personnel are italicized. Copies of all forms listed are included in Appendix E of this Plan.

Operational schematics are included as Appendix G. Operational schematics show all fuel tanks, lines, operational valves appropriate for a specific procedure.

9.2.1 Tank Gauging

Normally, gauging frequencies are determined by DoD Management of Bulk Petroleum Products, Natural Gas, and Coal (DOD 4140.25-M) or as stipulated in the operating contract.

An active fuel storage tank requires gauging daily and before and after any fuel transfer activity (receipt, issue, tank to tank transfer). Inactive storage tanks must be gauged weekly. Facility inventories are completed the first day of each week, and also the first day of each month, and recorded on DD Form 1348-8 (Inventory Accounting Document). This form is also used to record known inventory discrepancies due to spills, contaminated fuel, samples, and other losses greater than 5 gallons. For inventory discrepancies that are unexplained or show evidence of misconduct or negligence, DD Form 200 (Financial Liability Investigation of Property Loss).

Tank inventory is normally obtained from the automatic tank gauging (ATG) system, but may need to be obtained manually. This procedure covers the proper steps for manual fuel storage tank gauging as well as adjusting the reading for temperature compensation.

Responsibility

The FDSO is responsible for all fuel storage tank gauging activities.

Safety and Environmental Protection

No fuel operations (including gauging) should occur during electrical storms. Also, gauging should not be done during high winds. While gauging, the FDSO must follow all standard safety and environmental protection rules as contained in OSHA 29 CFR Part 1910 and 49 CFR Part 195, respectively (and applicable California regulations).

Required Materials

• Tape and bob

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• Fuel gauging and water finding paste

• Thermometer

• Sampling cup

• Clean rags

• American Society for Testing and Materials (ASTM) tables

• Personal protective equipment

Procedure for Gauging

1. The FDSO will gather required materials.

2. Inspect the tape to ensure it is in good condition (i.e., no kinks or splices in the tape). Check that the bob is not deteriorated beyond 1/16 of an inch.

3. Check the local tank gauge to determine the fuel reference point. Confirm the water level reference point from the most recent gauging.

4. The FDSO must ground himself by grasping the tank handrail. This will equalize static electricity potential between the FDSO’s body and the tank.

5. Coat the bob or tape with a thin coat of water-finding paste above and below the water level reference point.

6. Coat the gauging tape with a thin coat of fuel-gauging paste on the area that extends above and below the fuel level reference point.

7. Lower the tape into the tank’s manual gauging well, maintaining contact between the tape and gauge hatch.

8. The tape must remain in the tank for 10 seconds for an accurate reading. In conditions when the fuel is cold, a longer period of time may be required.

9. Raise the tape and bob. First read the fuel level, then read the water level. Fuel and water levels must be read to the nearest 1/8-inch increment.

10. Repeat the gauging procedures with a clean tape until two comparable readings are obtained. Record the tank gauging results in the Gauger’s Record and on the Daily Stock Sheet for tanks that are off-line from the automated system.

11. Allow the tape and bob, as well as any rags used to clean gauging equipment, to air dry.

Procedure for Temperature Measurement

1. Use a thermometer that has been calibrated within the last 12 months. The most common thermometers use range 0 to 180 degrees Fahrenheit (ºF) marked in 1-degree increments.

2. Inspect the thermometer to ensure the column is not broken and there are no separations in the mercury.

3. Remove the bob from the gauging tape and attach the thermometer. Lower the tape into the tank’s manual gauging well, maintaining contact between the tape and gauge hatch.

4. If tank construction allows, take the temperature 1/3 of the radius from the edge of the tank for the most accurate reading.

5. Allow the thermometer at least 5 minutes to reach equilibrium.

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6. Perform the reading as quickly as possible after the thermometer is removed from the liquid to minimize atmospheric temperature influence.

7. Record the temperature in the Gauger’s Record.

8. Clean the tape.

The following table presents the location of necessary readings for various depth tanks.

Table 9-4. Required Temperature Readings

Depth of Product Number of Required Readings Location of Readings

Less than 10 feet 1 1. Midpoint

10-14 feet 2 1. 3 feet from bottom

2. 3 feet below surface

15-19 feet 3

1. 3 feet from bottom

2. Midpoint

3. 3 feet below surface

20 feet or more 3

1. 4 feet from bottom

2. Midpoint

3. 5 feet below surface

Volume Calculations and Corrections

Calculations for volume corrections to net gallons are performed as follows:

1. Utilizing the observed API gravity and temperature, use ASTM Table 5b and establish the API gravity at 60 ºF.

2. Calculate volume using gauge readings and tank conversion tables to obtain gross gallons.

3. If the storage tank contains water bottom and the measurement is intended for tank contents, the volume of water is read directly as net and subtracted from the gross gauge before calculating net volume.

4. Using ASTM Table 6b, obtain the correction factor and correct the volume from gross to net.

9.2.2 Water Draw-off and Disposal

Water is routinely drawn off from the bottom of the fuel storage tanks. Tanks are checked daily for water as part of normal inspection procedures. If water is found, the Terminal Superintendent will authorize the water to be drained using the procedures described in the following subsections.

9.2.2.1 Drain Water from Underground Storage Tanks 42 – 47

1. Determine the operating tank for water bottom removal. Gauge the operating tank for fuel, water, and temperature using the procedures in Tank Gauging, Section 9.2.1 of this Plan, and record on the Gauger’s Record.

2. Gauge Slop Tank 51 to verify that there is sufficient ullage to accept the tank bottom water and record in the Gauger’s Record.

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3. Align valves according to Table 9-5 at the operating tank, slop tank, and appropriate visual tub. Schematics showing the slop tank and valves are located in Appendix G.

4. The last valve to be opened is the visual tub inlet valve. Open this valve slowly and observe the visual tub to prevent fuel from draining into the slop tank. Close the visual tub inlet valve at the first sign of fuel.

5. Allow the visual tub to empty.

6. Close and lock the appropriate valves.

7. Gauge both the operating tank and Tank 51 and record the levels on the Gauger’s Record.

Table 9-5. Open Valves for Water Draw-off Tanks 42 - 47 to Tank 51

Operating Tank Operating Tank Valves Visual Tub Valves Slop Tank Valves

42 V-527, V-641

43 V-530, V-645

44 V-533, V-649

TK-4V-860

TK-6V-653

45 V-537, V-656

46 V-540, V-660

47 V-543, V-664

TK-4V-861

TK-6V-668

TK-8V-753

Note: Raise plug stem at tank top

9.2.2.2 Drain Water from Tanks 11, 14, and 17 to Tank 54

1. Determine the operating tank for water bottom removal. Gauge the operating tank for fuel, water and temperature using the procedures in Tank Gauging, Section 9.2.1 of this Plan, and record the levels on the Gauger’s Record.

2. Gauge Slop Tank 54 to verify that there is sufficient ullage to accept the tank bottom water and record in the Gauger’s Record.

3. Align valves, opening the tank water drain valves, water draw-off pump suction and discharge valves.

4. Start the water draw-off pump for the selected tank.

5. Continuously observe the sight glass in the water draw-off line. Stop the pump at the first sign of fuel or if the in-line fuel sensor is activated.

6. Close and lock the appropriate valves.

7. Gauge both the operating tank and Tank 54 and record the tank levels on the Gauger’s Record.

9.2.2.3 Manually Drain Water from Tanks 2, 4, 6, 8, 9, 10, 12, 13, 15, 16, 18, 19, and 20

1. Determine the operating tank for water bottom removal. Gauge the operating tank for fuel, water and temperature using the procedures in Section 9.2.1, Tank Gauging, of this Plan and record the levels on the Gauger’s Record.

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2. Align the valves on the tank. Attach the vacuum truck to the tank water draw-off connection via cam-lock.

3. Open the water draw-off valve for the selected tank.

4. Close the valve when the in-line fuel sensor is activated or at the first sign of fuel, whichever occurs first.

5. Lock the appropriate valves.

6. Gauge the operating tank and the tank level on the Gauger’s Record.

7. Normally, the bowser will be emptied into Tank 51. Gauge Slop Tank 51 to verify that there is sufficient ullage to accept the tank bottom water and record in the Gauger’s Record.

8. Connect the bowser hose to the Slop Tank 51 cam-lock connection. Open the valve on the tank and the bowser and allow the bowser to gravity flow into Slop Tank 51.

9. Gauge Slop Tank 51 and record the tank level on the Gauger’s Record.

9.2.2.4 Transfer Slop Tank Contents to Waste Removal Truck

Gauge the slop tank and record the tank level on the Gauger’s Record.

1. Direct the waste disposal truck to the slop tank issue point.

2. Follow safety precautions applicable to all fuel transfer activities including but not limited to:

Ground the waste disposal truck by attaching a grounding clamp.

The FDSO must ground himself by grasping a ground wire or metal rail.

The waste disposal truck driver must shut off the vehicle and all other potential spark sources.

Place a grounded catch pan under the connection point.

The vehicle driver must remain near waste truck, but not in the truck.

3. Open the slop tank issue valves and transfer the specified amount of waste to the waste disposal truck.

4. When the specified amount has been transferred, close and lock the issue valves.

5. Gauge the slop tank and record the tank level on the Gauger’s Record. Also record the amount transferred on the Waste Manifest.

6. The Waste Manifest must be signed by the TOCCO.

7. Obtain a copy of the Waste Manifest from the driver and forward it to the QAR. Copies of the Waste Manifests are also maintained in the office of the TOCCO (Building 113).

8. The driver will disconnect the truck loading arm and grounding connection. The FDSO remove the catch pan and drain any caught liquid into the slop tank.

9.2.3 Automatic Control System

The majority of the operations at DFSP San Pedro main tank farm are completely automated and controlled from the control room (Building 113) located on the southern part of the Main Terminal near the entrance on Gaffey Street. The control room is manned 24 hours a day, 7 days a week.

All of the tanks, pumps, and valves in the system are numbered and identified on the computer which monitors all operations and the status (open or closed) of all motor operated valves

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(MOVs). Status lights on the computer screen illuminate green when a valve is closed and magenta when the valve is open. Similarly for pumps, a light illuminates green when a pump is stopped and magenta when the pump is started. The valves or pump will indicate red if a valve or pump has a problem.

An alarm on the computer alerts the operators when an alarm condition exists anywhere in the fueling system.

When authorized or directed by the Terminal Superintendent, the TOCCO will direct the FDSO to open and close block valves, gauge tanks, and line up pipelines, pumps, and tanks for receiving and issuing products. The TOCCO is able to operate (open or close) the motor operated valves (MOVs) in the pipeline system at the terminal and is able to start and stop transfer pumps from the terminal control panel located in the Control Room.

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10 NORMAL OPERATIONS

Operational schematics that show only the portions of the system relevant to the operation are included in Appendix G and are referenced as appropriate throughout this section. Appendix G also contains the valve alignment charts corresponding to the specific operations.

10.1 Receive Fuel from Fuel Tanker/Barge

Receipt from fuel tanker or barge occurs at Pier 12 where JP-5, JP-8, and F-76 are received from barges with capacities as small as 400,000 gallons and tankers with capacities as large as 10,000,000 gallons. All vessels must have an under keel clearance of at least 6 feet from the sea floor. JP-5 can be received into one active storage tank at the fuel pier (Tank 2001), but this is not the normal receipt operation. Fuel is normally received directly into the Main Terminal storage tanks via the 14-inch and 18-inch JP-5 and JP-8 pipelines.

10.1.1 Process and Responsibilities

A minimum of six people (the TOCCO, the terminal FDSO, the FPOCCO/TPIC, the pier FDSO, the VPIC, and the pier Security Guard) must be on duty during the transfer:223

• The TOCCO is in charge of all automated pump and valve controls and directs terminal FDSOs throughout the operation.

• The terminal FDSO pulls fuel samples, manually gauges tanks when required, operates manual valves, and monitors operations in and around the Main Terminal.

• The FPOCCO/TPIC works closely with the VPIC during transfers. The FPOCCO/TPIC directs pier FDSOs throughout the operation.224

• The pier FDSO pulls fuel samples, manually gauges tanks when required, operates manual valves, and monitors operations in and around the pier. The Pier FDSO must also fill out the Pier 12 Operations Pre-Load/Off-Load Checklist and the Pier 12 Operations Post- Load/Off-Load Checklist.

• The VPIC is the person in charge of the vessel’s marine oil transfer operations and works closely with the FPOCCO/TPIC and TOCCO during transfers. The VPIC is a vessel employee and is not under the control of the DFSP San Pedro.225

• The Security Guard at the Pier performs routine security during the fuel transfer as described in Security, Section 3.1 of this Plan.

Vessel arrivals are typically scheduled several weeks in advance. DESC Americas West notifies the QAR of a delivery. The QAR verifies the marine vessel receipt with the Terminal Superintendent. The Terminal Superintendent notifies the TOCCO/TPIC through the Bulk Fuel Operations Order.

223 33 CFR §154.310 (a)(6); 2 CCR §2385(d)(1)(B); 2 CCR §2385(d)(2)(F)

224 33 CFR §154.310

225 33 CFR §154.310

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Prior to the vessel’s arrival, the Terminal Superintendent will acquire the following information from the…