5-11 Fire Protection

5.11 Fire Protection and Emergency Response

October 2006 5.11-1 Draft EIR

5.11 Fire Protection and Emergency Response This section addresses the fire protection and emergency response resources related to the proposed project. These resources include the existing services and capabilities of nearby fire departments and neighboring oil and gas facilities, the internal fire protection plans, and the systems and design of the facilities and their associated pipelines. The emergencies that would require summoning these available resources include fire, oil spill, hazardous substance release, or another event that could lead to these emergency situations, such as an earthquake, traffic accident, pipeline rupture, etc. This section also evaluates the impacts of the proposed project and alternatives on these services and capabilities and presents criteria used to determine significant impacts of the project.

5.11.1 Environmental Setting

5.11.1.1 Fire Fighting Capabilities in the Project Area

Santa Barbara County (SBC) operates many fire stations within County borders, and the cities of Lompoc and Santa Maria operate their own fire stations near the project area. The City of Lompoc and SBC have a mutual aid agreement that allows city and county fire departments to cooperate with one another. Therefore, the Lompoc City Fire Stations could also respond during an emergency along the pipeline route or at the LOGP. The closest fire stations to the LOGP and the route of the pipelines evaluated in this EIR are listed in Table 5.11.1 with street address, equipment, number of personnel, and proximity to the projects. Figure 5.11-1 presents the location of each of the fire stations in relation to the project area (locations are numbered as in Table 5.11.1).

SBC Fire Station Number (No.) 51 near Lompoc is the closest to the LOGP and would be first to respond to the LOGP in the event of a fire. The fire station is located within 10 miles (within 15 minutes response time) from most of the pipeline routes addressed in this document. The next nearest fire stations to the LOGP are located in the City of Lompoc, including Lompoc Fire Station No. 51 (5.3 miles from LOGP) and Lompoc City Fire Station No. 2 (7.5 miles from LOGP). Furthermore, as presented in Table 5.11.1, Vandenberg Air Force Base (VAFB) Fire Department also has emergency response capabilities. SBC Fire Station No. 31 in Buellton could also be alerted to respond to any emergency at the LOGP.

In addition to the county and city emergency response equipment, oil facilities are required by Federal, State, and local regulations to maintain onsite fire fighting equipment as well as materials to control oil spills or other hazardous materials releases. PXP has fire fighting and emergency response capabilities at the LOGP in accordance with these regulations.

Other facilities in the vicinity that also have fire fighting and emergency response capabilities include the Orcutt Pump Station and the Santa Maria Pump Station. These capabilities are also listed in Table 5.11.1. Fire fighting capabilities at the Santa Maria and Sisquoc Pump Stations are described in the Tosco Sisquoc Pipeline EIR (91-FDP-03, 2/1992) and the Tosco Sisquoc Pipeline Public Draft SEIR (00-EIR-09, 12/2000).



Table 5.11.1 Facilities in the Area with Fire Fighting and Emergency Response Capabilities

Fire Station/ Facility Address

DistanceMiles1 Fire-fighting Equipment/Personnel Emergency or Spill Response Capabilities

1. Lompoc, Fire Station No. 51 (SBC)

749 Burton Mesa Rd., Lompoc

5.3 1 engine, 1 reserve engine, 1 Captain, 2 engineers and 2 firefighter/paramedics

Paramedic unit

2. Buellton, Fire Station No. 31 (SBC)

168 W. Highway 246, Buellton

20 Engine/brush-fire engine (1250 gpm), reserve engine, reserve personnel (10-15 people), 1 Captain, 1 engineer, 1 firefighter and 1 firefighter/paramedic

HazMat response truck3 HazMat team3

3. SM Airport, Fire Station No. 21 (SBC)

3339 Terminal Dr., Santa Maria

18 Engine (1500 gpm), crash rescue truck, 1 Captain, 1 engineer, and 1 firefighter

4. Santa Maria, Fire Station No. 22 (SBC)

1596 Tiffany Park Ct., Santa Maria

17 Engine (1500gpm), brush fire engine, 1 Captain, 1 engineer, 1 firefighter, and 1 firefighter/paramedic

5. Sisquoc, Fire Station No. 23 (SBC)

5003 Depot Ave., Sisquoc

28 Engine (1250 gpm), fire/foam tender (2800 gallons of water or 6,000 gallons of AFFF foam), 2 1 Captain, 1 engineer, and 1 firefighter

6. Los Alamos, Fire Station No. 24 (SBC)

99 Centennial, Los Alamos

16 Engine (1500 gpm), brush fire engine, 1 Captain, 1 engineer, and 1 firefighter

Paramedic engine

7. Nipomo (SLO County)

450 Pioneer St. Nipomo

31 Type A pumper with foam capability, 2 Minimum of 2 personnel per 24-hour shift

8. Lompoc City Station No.1

115 South “G” St., Lompoc

8 1 Engine, aerial ladder truck in reserve, 3 personnel, reserve personnel

9. Lompoc City Station No. 2

1100 North “D” St., Lompoc

7.5 1 Engine, , reserve personnel

10. City of Santa Maria, Fire Station No. 1

206 E. Cook St., Santa Maria

21 Engine (1500 gpm) with three personnel, Reserve engine (1500 gpm) unstaffed, Wildland engine (5 gpm, 4-wd) cross-staffed with the 3 personnel from the engine

11. Lompoc Oil and Gas Plant

3602 Harris Grade Road, Lompoc

0 Fire water system including water tank, fire hydrants and pumps, foam concentrate tank, foam discharge system, fire detection system, flammable gases detectors

Sorbent boom; sorbent pads, empty sand bags, rakes, shovels, pitch forks, 6 SCBAs; fire fighting turnouts, tri-monitors, fire extinguishers, portable tanks, gas or diesel trash pumps; emergency response (ER) trailer; ER suitcase; pickup truck, foreman’s vehicle, cell phones, radio base station

12. Lompoc Field

Mobile 0-10 Fire extinguishers Radio base station; half-ton truck w/radio; two ¾ ton trucks w/radio & cell phone 15 ton stinger w/radio; 15 ton stage-crane truck, utility truck; two half-ton trucks; three ¾-ton trucks, two-wheel gas trailer; two-wheel grease trailer



Table 5.11.1 Facilities in the Area with Fire Fighting and Emergency Response Capabilities

Fire Station/ Facility Address

DistanceMiles1 Fire-fighting Equipment/Personnel Emergency or Spill Response Capabilities

plastic trash bags, excelsior, solvent, brooms, bales, various hand tools; assorted pipe plugs, clamps, fittings; pipe cutters, pipe tape, primer, coat line pipe; 3-in-1 gas analyzer, H2S analyzers; air compressors; two-wheel air compressor trailer

13. Orcutt Pump Station and field

201 South Broadway, Orcutt

16 Sieve nets, plastic buckets with lids, aquarium-type air pumps with associated plastic tubing, gang valves, air stones, and batteries; fiberglass/plywood storage box; three 1-ton trucks; three ¾-ton trucks; two 2.5-ton A-frames; hydro crane; two 2-wheel air compressors; half-ton truck

14. Santa Maria Pump Station

1580 Battles Rd. Santa Maria

23 400 gallon foam system 2

200 gallons of foam in storage 2 Fire water tank, 364,000 gal Fire detection system with audio alarm Fire hydrants Manually activated foam discharge outlets

Response Trailer4: 23 lengths boom; 6 bundles sorbent pads; 1 roll excelsior with net; dip nets with handles, 7 metal stakes; 2 steel culverts, 10 pairs waders, wader suspenders, 1 portable tank (600 gallon), shovels, rakes, gloves; 4 trailer-mounted portable lights, 6 respirators; 4 radios and radio base station Storage Container4: Rubber boots, Tyvec Suits, XC rain suits, flotation vests, work vests, garbage cans, utility brushes, fence posts, rakes, shovels, brooms, tarps, fencing, plastic swimming pools, spool 1” rope, waders, wheelbarrows; can liners, Sol-vex and examination gloves, protective goggles roll sorbent pad SPC 150, 500 ft. Minimax 17 boom

15. Vandenberg Air Force Base Fire Department

Multiple locations 4-10 5 Type 1 engines and 1 truck company at 3 locations 1 Hazmat squad 5 Airport crash/fire/rescue companies 3 Water Tenders 1 hand crew and 1 truck company (6 locations)

Source: PXP, 2005a; Santa Barbara County Fire Department; City of Lompoc Fire Department; City of Santa Maria Fire Department; Unocap Emergency Response Plan, May 2000.

gpm – gallons per minute 1. The distance shown is from a fire station/response facility to the LOGP facility. 2. Specialized Oil Fire Fighting Equipment. 3. Denotes the equipment that might be on a delayed response. 4. The full list of contents can be found in UNOCAP Sisquoc to Santa Maria Station & Point Pedernales LOGP to Orcutt Pump Station Emergency Response Plan, Revised

May 1, 2000.



5.11.1.2 Fire Protection Capabilities at the LOGP

The LOGP has a Fire Protection Plan approved by the Santa Barbara County Fire Department (SBCFD). The LOGP is designed with fire prevention as a prime concern using concepts such as early ignition detection and fire spread prevention at the basis of the design. The Fire Protection System is shown in Figure 5.11-2 on the plant plot plan. Sources of open flame are grouped together and segregated from areas with potentially flammable materials. The electrical installation was designed to conform to the National Electric Code (NEC) and National Fire Protection Agency (NFPA) requirements. Potential ignition sources include the heater treaters, thermal oxidizer, reclaim heater, glycol heater, flare, and occasional vehicles traveling through the facility. A network of fire and flammable gas detectors located throughout the plant enhances early fire detection.

Spills and leaks of chemicals, oil and other hydrocarbon materials are cleaned up as soon as reasonably possible after they are detected. Almost all of the LOGP facility is subject to the SBC Air Pollution Control District Fugitive Hydrocarbon Inspection and Maintenance Program, which requires the timely repair of leaking components. Oil and chemical soaked rags are kept in suitable containers in the facility prior to disposal. Grass and brush within 100 feet of the facility perimeter is mowed to a height of 6 inches or less.

There is a road immediately adjacent to the LOGP that surrounds the entire facility. Additionally, there is a road within 1,000 feet of the LOGP that also surrounds the entire facility. Both roadways are maintained at a minimum of 20-feet wide with paved or all weather surfaces able to support 20-ton County fire apparatus.

Water is supplied to the LOGP from the existing PXP water system in the Lompoc Field. Firewater at the LOGP is stored in two water tanks with respective capacities of 210,000 and 420,000 gallons. The tanks are kept full by an automatic level control system. The 210,000-gallon tank has a 4-inch National Standard male thread outlet for fire department engine use with the outlet within 10 feet of the fire engine parking area. The mobile fire equipment includes twenty-four 20-pound dry chemical extinguishers, seven 10-pound dry chemical extinguishers, two 5-pound dry chemical extinguishers, one 14-pound Halon extinguisher and one 17-pound Halon extinguisher, and two portable 150-pound dry chemical extinguishers.

The fire water system includes the water tanks, foam system, pumps, valving, fire monitors and detectors, hose reels, and fire hydrants and is shown in Figure 5.11-2. Two fire pumps with diesel engines are designed to deliver 2500 gallons per minute (gpm) each at 150 Pounds per square inch (psi). The fire pumps and pump controllers comply with all requirements of NFPA Standard 20. The fire system water mains comply with all requirements of NFPA Standard 24. All the valves meet NFPA Standards 22 and 24 requirements and are UL listed. The fire hydrants are UL listed and installed in accordance with NFPA Standard 24. All of the fire monitors have approved adjustable fog nozzles attached. All of the monitors and hose reels have foam capability.

The control room is part of the main office structure. A loss of power to the control room results in the automatic shutdown of the entire facility. The control room is equipped with a smoke detection system that will initiate facility shutdown. Facility shutdown can also be initiated by



flame or gas detection. Windows and frames on the plant side of the control building are explosion-resistant.

All of the bermed or diked areas hold at least 1 1/2 times the volume of the largest vessel or tank within the dike/berm. To prevent fire from spreading, the areas are sloped to prevent spills from pooling around or under any vessel or tank. All onsite drainage is collected in either the berm around the 100,000 barrels (bbl) oil surge tank or the retention basin, which is located away from the process equipment to the south of the facility.

The fire protection system is designed for a worst-case release from the largest vessel, which is the oil surge tank with 100,000 bbls capacity and 134 feet in diameter, and subsequent fire. The oil surge tank is protected by a fixed foam system as shown on Figure 5.11-2. There are three foam chambers mounted on the tank. A header is installed outside the bermed area to control the foam application. There is a 3,000-gallon atmospheric foam concentrate tank that is kept 1/3 full of foam concentrate. The concentrate is pumped into a distribution loop, which parallels the water mains. There is a “light water” pressure control valve and proportioner at each monitor, hose reel and the surge tank foam system. The concentrate pumps are run by an electric motor. Both pumps are a part of the emergency power system. The foam system, including foam pumps, tank, piping, proportioners, and applicators comply with NFPA Standard 11. An additional 1,200 gallons of foam concentrate is stored in 55-gallon drums.

The incoming and outgoing oil and gas pipelines are equipped with automatic shutdown valves. These valves will close in the event of high vessel pressure or high levels. The valves also can be closed by activating the emergency shutdown system in the control room or in the plant. The incoming oil line automatic valve is located downstream of the first oil/water separator. Each vessel, tank, and pump is equipped with manual valves, which will isolate individual pieces of equipment.

The emergency power generator is equipped with both manual and automatic startup, synchronizing, and shutdown. These functions are provided by a switchgear, which feeds the essential loads of the facility including flammable gas detectors, the H2S detectors, and the flame detectors. Essential loads also include the facility’s leak detection August Control System, power to the control building, power to the instrument air, and the electrical panel for the diesel firewater pumps.

PXP holds monthly safety meetings at each work site that include fire prevention. The LOGP also has periodic unannounced fire drills to ensure that the employees know their area of responsibility in the event of a fire. In the event of a small fire, employees will attempt to extinguish it using fire extinguishers and/or hose reels. In the event of a major fire, employees will activate the emergency system shutdown, with subsequent initiation of the ERP. It should be noted that since 19921 there has not been a fire event at the LOGP that was connected to the equipment failure or leaks. The only one recorded fire event at the LOGP was a grass brush fire outside the facility fence.

The LOGP facility is required to operate according to the safety rules contained in the PXP Safety Inspection, Maintenance and Quality Assurance Program (SIMQAP), as defined by the

1 The SBCFD database goes back only to 1992.



Point Pedernales Project Final Development Plan (FDP) Conditions. This program covers the LOGP, the three pipelines connecting the LOGP to Platform Irene, and the sales gas pipeline, and is required to be implemented during construction and operations.

The program is a dynamic document that is required to be regularly updated for new procedures, safety and maintenance technologies and processes, and then reviewed and approved by the County’s Systems Safety and Reliability Review Committee (SSRRC), which includes the SBCFD.

5.11.1.3 Fire Protection at Platform Irene

Figures 5.11-3a and 5.11-3b show the main fire protection equipment on both decks of the platform. This equipment includes fire and smoke/heat detectors, fire monitors, combustible gas detectors, fire alarms and alarm pulls, fire extinguishers, hose reels, and breathing apparatus systems. Foam concentrate is stored in a 300-gallon tank. Foam can be delivered to hose reels, spraying systems, and to sprinklers, which are strategically located throughout the platform. Water to the foam system can be supplied by two electrical firewater pumps or by a new vertical turbine pump with a diesel engine. All three pumps use seawater. In addition, the two electrical firewater pumps can also utilize water from the 8-inch produced water return pipeline.

Because of the specifics of the offshore location, personnel are instructed to evacuate in case of any major emergency including a large fire. Survival capsules are provided for these types of emergencies.

5.11.1.4 Fire Protection at Orcutt Pump Station

The entire Orcutt Pump Station, including all pumps, sumps, equipment and aboveground piping, is curbed, guttered, and sloped so that any oil spilled will drain into a large pit. The magnitude of a spill that could occur from a leak at the pump station is approximately 160 bbls (UNOCAP ERP, 2000), given the pump station flowrate, oil volumes contained in station piping, leak detection system recognition and response times, and valve closure time (approximately 50 seconds).

Fire water for the pump station is supplied by the water district. The fire system includes 250-gallons of fire foam, a foam proportionator, a 1,000-gpm fire pump, a diesel emergency power generator, and several strategically located foam monitors, fire hoses and hydrants. The single oil storage tank (23,000 bbls) located at the pump station has sufficient secondary containment and is equipped with three foam injectors, each with a foam maker.

Risk analysis of the pump station has concluded (UNOCAP ERP, 2000) that the impacts from accidents such as a fire or oil spill would be limited to the facility itself. The pump station safe operation is maintained through ConocoPhillips SIMQAP that is updated on a regular basis in the same fashion as the LOGP SIMQAP.

5.11.1.5 Emergency Response

PXP and ConocoPhillips have implemented a three-tier emergency response organization following the Incident Command approach (see Table 5.11.2). PXP’s Incident Commander (IC) will be the first PXP employee at the scene of an emergency incident and will take command



until relieved by a more senior company employee. After conducting preliminary reconnaissance and reporting the situation to the IC, the first level of response will be mobilized by activating the Immediate Response Team. The team made up of PXP employees will be the first to respond to any incident, regardless of size. For minor incidents, this Level One response will likely be sufficient. The Point Pedernales onshore pipeline and facility personnel can field two shifts of the Immediate Response Team with the assistance of the District personnel. In the event of any emergency, including an oil spill at Platform Irene, the Clean Seas organization will also be among the first responders. ConocoPhillips would follow the same approach at its facilities. This approach is detailed in the UNOCAP Sisquoc Pipeline and Point Pedernales Pipeline Project Emergency Response Plan (PXP ERP 2004, with minor updates in May and August 2005).

The second level of response would be used when the magnitude of the incident or its impacts indicate the need for additional personnel. In a Level Two response, the District Sustained Response Team will augment the response with members drawn from the PXP or Conoco Phillips Santa Maria District employees.

The third level of response is initiated when the size of the incident dictates the need for a major sustained response effort. In a Level Three response, the Unified Command would be mobilized. This team is made up of specialists and specifically trained employees from various State and County agencies and contract companies.

The organization and resources available for each level of response are described in detail in the Lompoc Oil and Gas Plant Emergency Response Plan (LOGP ERP) revised by PXP in December, 2004 with minor updates in May and August of 2005, and in the UNOCAP ERP. The Oil Spill Response Plan developed for Platform Irene (November 2004) details the oil spill response at the platform and includes available company and outside resources. In the event that emergency assistance is needed, PXP has formal relationships with other firms and organizations in the local petroleum industry.

The SBC Area Oil and Gas Industry Emergency Response Plan (P-4 Plan) may be activated during an emergency that involves more than one onshore facility or involves offsite impacts to or threatens the public, livestock, property, or the environment. The P-4 Plan would be activated when the required response to an emergency incident is beyond the capabilities of the responsible company to mitigate effectively. The P-4 Plan may also be activated at any time that industry-mutual assistance is required. Mutual aid would be requested via the agreed upon P-4 mutual aid agreement.

The P-4 Plan is to be used by industry in coordinating its response, sharing resources, and functioning within the governmental command system present at an incident. It is activated at the discretion of the company or Agency Unified Command in command of emergency response activities. PXP and ConocoPhillips are members of Clean Seas and can call upon that organization’s resources to assist in the clean up of a spill. If an oil spill were to occur at Platform Irene or offshore pipelines or at the Santa Ynez River at a time when there is enough flow to carry oil toward the ocean, assistance would be sought from Clean Seas for containment and cleanup operations. Other petroleum companies with emergency response capabilities operating in the Santa Maria Basin can also be called upon if assistance is needed.



Table 5.11.2 Level of Emergency Classification

Level of Emergency Criteria Incident Commander (IC)

Typical Fire Dept Response Notification

1. Initial Response Minor On-Site Incident

1. Oil spill or produced water spill >1 bbl outside secondary containment designated for that vessel, system or pipeline, or >5 bbl inside secondary containment designated for that vessel, system or pipeline, unless it impacts or potentially impacts state or marine waters, in which case go to level 3.

2. Two combustible gas or fire eye alarms. 3. Verified high level combustible gas (50% LEL) alarm. 4. Single held detector with a LEL reading >50%. 5. Smoke investigation. 6. Fire reported out. 7. Hazardous material release outside secondary containment designed

for that vessel, system or pipeline. 8. Bomb or extortion threat.

Highest ranking on-duty operations person until relieved by Fire Department

One Engine Code 2

9-1-1 and the facility notification

2. Sustained Response On-Site Incident

1. Oil or produced water spill >5 bbls, unless it impacts or potentially impacts state or marine waters, in which case go to level 3.

2. Any toxic gas release >10 ppm by fixed or hand-held monitor. 3. More than two combustible gas or fire eye alarms. 4. Fire. 5. Hazardous materials release requiring hazardous materials emergency

response from emergency rescue personnel or contractors. 6. Sour gas in sales line. 7. Earthquake or flooding damages. 8. Activation of Emergency Shutdown for plant and/or pipeline.

Highest ranking on-duty operations person until relieved by Fire Department

1st alarm 3 engines, Chief Officer Code 3

9-1-1; Off duty

personnel; Community

notification; Agency

notification as required

3. Major Incident with Public Exposure Potential (off site impacts)

1. Oil spill or produced water spill impacting or potentially impacting State or marine waters, or threatened release of oil or produced water impacting or potentially impacting state or marine waters.

2. Fire with potential for spreading. 3. Explosion. 4. Hazardous materials release or gas leak with off-site potential. 5. Civil disturbance. 6. State of War. 7. Highway 101 closure or impact on other significant access routes or

roads.

Highest ranking on-duty operations person until relieved by Fire Department and potentially: Responsible party Sheriff’s Department CHP Federal On-Scene CoordinatorState On-Scene Coordinator

2nd alarm or greater, additional engines and/or specialized equipment/ resources 2 Chief Officers

9-1-1; Off duty

personnel; Community

notification; Agency

notification as required

Source: PXP, 2005b. See Guidance Matrix below for terms definitions.



Table 5.11.2 Level of Emergency Classification Guidance Matrix for Emergency Incident Transition – Definition of Terms

These definitions are provided to define terminology in the guidance matrix for emergency Incident Transition (“matrix”).

Combustible gas. A gas that burns, including the fuel gases, hydrogen, hydrocarbon, carbon monoxide, or a mixture of these.

Emergency rescue personnel. Any public employee, including but not limited to any fireman, firefighter, or emergency rescue personnel, or personnel of a local EMS agency or poison control center, who responds to any condition caused, in whole or in part, by a hazardous material that jeopardizes, or could jeopardize public health or safety or the environment.

Hazardous material. Any material that, because of its quantity, concentration, or physical or chemical characteristics poses a significant present or potential hazard to human health and safety or to the environment if released into the workplace or the environment. Hazardous materials include, but are not limited to, hazardous substances, hazardous waste, and any material which a handler or the administering agency has a reasonable basis for believing that it would be injurious to the health and safety of persons or harmful to the environment if released into the workplace or the environment.

Hazardous material emergency response. Includes, but not limited to, assessment, isolation, stabilization, containment, removal, evacuation, neutralization, transportation, rescue procedures, or other activities necessary to ensure the public safety during a hazardous materials emergency.

Marine waters. Those waters subject to tidal influence.

Oil. Any kind of petroleum, liquid hydrocarbons, or petroleum products or any fraction or residues therefrom, including but not limited to, crude oil, bunker fuel, gasoline, diesel fuel, aviation fuel, oil sludge, oil refuse, oil mixed with waste, and liquid distillates from unprocessed natural gas.

Oil spill. Any release of oil or produced water.

Potential release. “Threatened release”.

Produced water. The water remaining after being separated through oil and gas processing.

Release. Any spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, or disposing into the environment.

Secondary containment. Containment designated for that vessel, system, or pipeline.

Sour gas. Natural gas that contains corrosive, sulfur bearing compounds, such as hydrogen sulfide (H2S) and mercaptans.

Threatened release. A condition creating a probability of harm, when the probability and potential extent of harm make it reasonably necessary to take immediate action to prevent, reduce, or mitigate damages to persons, property, or the environment.

Toxic gas. Gases which are extremely hazardous and may be fatal if inhaled or absorbed through skin.

Waters of the state. Any surface water or groundwater, including saline waters, within the boundaries of the state.



5.11.2 Regulatory Setting There are numerous codes and standards that apply to fire protection and emergency response for facilities such as the ones affected by the proposed projects. The applicable rules and regulations are listed in Table 5.11.3. Fire protection systems associated with the project must be detailed in the fire protection plan and include systems and design that ensures compliance to a range of codes and standards. These are specified by the NFPA, American National Standards Institute (ANSI), Industrial Risk Insurers (IRI), American Petroleum Institute (API), SBCFD Criteria and Guidelines, and the Uniform Fire Code (UFC). Table 5.11.3 Project Applicable Standards and Codes

Code/Standard Description ANSI B31.4 Liquid Petroleum Transportation Piping Systems API RP 500 Classification of Hazardous Areas in Petroleum Pipeline Facilities API Pub 2004 Inspection for Fire Protection API Pub 2510 Design and Construction of LPG Installations API Pub 2510A Fire-Protection Considerations for the Design and Operation of LPG Storage

Facilities IRI IM.2.5.2 Plant Layout and Spacing for Oil and Chemical Plants NFPA Standard 11 Low Expansion Foam and Combined Agent Systems NFPA Standard 15 Water Spray Fixed Systems NFPA Standard 22 Water Tanks for Private Fire Protection NFPA Standard 24 Installation of Private Fire Service Mains and Their Appurtenances NFPA Standard 25 Inspection, Testing and Maintenance of Water-Based Fire Protection Systems NFPA Standard 30 Flammable and Combustible Liquids Code NFPA Standard 58 Standard for the Storage and Handling of Liquefied Petroleum Gases NFPA Standard 70 National Electric Code SBC Code Chapter 15 Amendments to the UFC SBC Permit Conditions Various SBC Public Works Engineering Design Standards

Roadways

SBCFD Standard 2A Fire Protection Water Regulations Flows and Hydrant Spacing SBCFD Standard 3 Fire Protection Hazard Area Requirements SBCFD Standard 6 Hazardous Materials Conditions SBCFD Standard 7 Alarms & Signaling Systems SBCFD Evacuation Near Flammable or Combustible Pipeline UFC Article 02, Division II Special Procedures UFC Article 04 Permitting UFC Article 09 Definitions and Abbreviations UFC Article 10 Fire Protection UFC Article 11 General Precautions Against Fire UFC Article 12 Maintenance of Exits and Occupant Load Control UFC Article 13 Smoking UFC Article 14 Fire Alarm Systems UFC Article 49 Welding and Cutting UFC Article 79 Flammable and Combustible Liquids UFC Article 80 Hazardous Materials UFC Article 85 Electrical Systems



IRI Guideline 17 indicates that fire water supplies should be capable of supplying at least 500 gallons per minute for 4 hours for pumping stations (IRI 17.3.3) and 3,000 gallons per minute for 4 hours to all areas of an oil storage terminal (IRI 17.3.4). These total a supply of 120,000 to 720,000 gallons of water.

Foam is frequently used in combination with the cooling water to extinguish fires associated with crude oil storage tanks. Foam can be applied to a liquid spill to suffocate a fire or prevent ignition of the flammable material spill. NFPA Standard 11 is applicable to foam application for protection of outdoor vertical atmospheric storage tanks containing flammable and combustible liquids by means of fixed foam discharge outlets. It specifies that application rates of foam should be at least 0.1 gpm/ft2 of liquid surface area of the fixed-roof tank to be protected. NFPA 11 also states that for extinguishing crude petroleum fixed-roof storage tank fires, the adequate foam supply should last 30 to 55 minutes, depending on the type of foam outlet (NFPA 11, 3-3). For floating roof storage tanks, the adequate foam supply should last for at least 20 minutes with an application rate of 0.3 gpm. For dike fires, NFPA requires a foam supply with a minimum discharge rate of 0.16 gpm/ft2 (for foam monitors) and minimum discharge time of 30 minutes for Class I hydrocarbons fires (NFPA 11, 3-7). Minimum foam application rate and discharge time for non-diked spill for adequate fire protection are 0.10 gpm/ft2 and 15 minutes, respectively.

Safe equipment spacing requirements for petrochemical plants are given in IRI Guidelines IM2.5.2, NFPA Fire Protection Handbook, and Standard 30. Specific requirements for spacing of the vessels containing pressurized LPG are given in the API standard 2510. The applicable requirements to the proposed project spacing are summarized in Table 5.11.4.

IRI IM2.5.2 also gives guidelines for the overall oil and chemical plants layout. The most important of these include the following:

• There should be at least two entrances to the plant;

• The overall site should be subdivided into general areas (blocks) with a maximum size of 300 feet x 600 feet;

Table 5.11.4 a-e Applicable NFPA, API and IRI Equipment Spacing Requirements a. Inter-Unit Spacing Requirements (feet)

Flar

es

Flares - Loa

ding

R

acks

Loading Racks 300 50 Serv

ice

Bui

ldin

gs

Service Buildings 300 200 - Con

trol

R

oom

s

Control Rooms 300 200 - - Fire

Wat

er

Pum

ps

Fire Water Pumps 300 200 50 50 - Proc

ess U

nits

Hig

h H

azar

d

Process Units High Hazard 300 200 400 300 300 200 Pres

sure

Sto

rage

T

anks

Pressure Storage Tanks 400 350 350 350 350 350 * Atm

osph

eric

Sto

rage

T

anks

Atmospheric Storage Tanks 300 250 250 250 350 350 * * - = there is no spacing requirement

* = see table C (Storage Tanks Spacing Requirements)



b. Intra-Unit Spacing Requirements (feet)

Com

pres

sors

Compressors 30 Pipe

rac

ks

Pipe racks 50 - Fire

d H

eate

rs

Fired Heaters 50 50 25 Hea

t Exc

hang

es

Heat Exchanges 30 10 50 5 Hig

h H

azar

d Pu

mps

High Hazard Pumps 30 15 50 15 5 Em

erge

ncy

cont

rols

Emergency controls 50 50 50 50 50 - Ana

lyze

r ro

oms

Analyzer rooms 50 50 50 50 50 - - c. Storage Tanks Spacing Requirements (feet)

Floa

ting

Roo

f T

anks

3,

000<

C<1

0,00

0 bb

ls

Floating Roof Tanks 3,000<C<10,000 bbls 0.5 D

Floa

ting

Roo

f T

anks

10

,000

<C<3

00,0

00 b

bls

Floating Roof Tanks 10,000<C<300,000 bbls D D Pr

essu

re S

tora

ge v

esse

ls –

D

rum

s and

Bul

lets

Pressure Storage vessels – Drums and Bullets

1.5 D 100’ min.

1.5 D 100’ min. D

Source: IRI, 1993 to 1995, IM2.5.2. C = tank capacity; D = tank diameter

d. Atmospheric Storage Tanks Spacing Requirements

Required Distance (feet) Between Adjacent Tanks (Shell-to-Shell) 1/6 sum of adjacent tank

diameters but not less than 3 feet From Property Line that Is or Can be Built Upon, Including the Opposite Side of a Public Way – With Protection for Exposures

½ times diameter of tank or 175 feet for tanks over 3,000,000 gal (72,000 bbls) capacity

From Property Line that Is or Can be Built Upon, Including the Opposite Side of a Public Way – No Protection for Exposures

Diameter of tank but need not to exceed 175 feet but no less than 5 feet

From Nearest Side of any Public Way or from Nearest Important Building on the Same Property

1/6 times diameter of tank but no less than 5 feet or 60 feet for tanks over 3,000,000 gal capacity

Source: NFPA, 2000.



e. Pressurized LPG Tanks Spacing Requirements

Required Distance (feet) Between Adjacent Tanks (Shell-to-Shell) 5 feet or ¾ of larger tank diameter Adjoining Property Line 75 feet (for 30,000-70,000 gallon tanks) Control buildings 50 feet Other buildings 100 feet Process vessels 50 feet Flares and other equipment with open flames 100 feet Fired equipment including process furnaces 50 feet Rotating equipment, except pumps taking suction from LPG tanks

50 feet 10 feet

Loading facilities 50 feet Source: API, 1995.

• Access roadways should be provided between the blocks to allow access to each block from at least two directions; and

• Road widths and clearances should be sized to handle large moving equipment and emergency vehicles.

5.11.3 Significance Criteria The SBC’s Environmental Thresholds and Guidelines Manual (as updated through October 2006) does not contain any significance criteria for fire protection or emergency response as a separate issue area. Therefore, a set of criteria has been developed, with input from the SBCFD, against which the significance of the proposed project impacts to fire or other emergency protection can be judged. This document evaluates fire protection impacts for two general major areas: the general adequacy and design of onsite fire protection systems and the general adequacy of emergency response capabilities. By examining these two areas, the following significance criteria were developed. The proposed project would be considered to have a significant impact in the fire protection and emergency response area if:

• The project site does not contain adequate fire water and/or fire foam supplies to meet the recommended NFPA Standards and the IRI guidelines.

• The project equipment layout does not meet the API, NFPA, and IRI recommendations for equipment spacing (see Table 5.11.4).

• The project facilities do not have sufficient capabilities in early fire detection and fire spread prevention as per the NFPA requirements.

• The project site is located more than 10 miles (15 minutes) from an emergency response location with both hazmat (spill response) or fire fighting capabilities (i.e., a fire station or facility with fire fighting and emergency response capabilities), accessibility to the site is difficult or limited, and the site does not have an adequately developed emergency response plan.

5.11.4 Impact Analysis for the Proposed Project This section characterizes the fire protection and emergency response impacts generated by the proposed project. Modifications of equipment and operations at Orcutt, Santa Maria, and Sisquoc



Pump Stations are minor and could be handled within the requirements of the ConocoPhillips SIMQAP, therefore these changes are not expected to have any impact on the fire protection or emergency response.

Impact # Impact Description Phase Residual Impact

Fire.1 Due to equipment modifications at Valve Site #2 the increased potential for upset conditions at the site could create impacts to fire protection and emergency response resources.

Operations Class III

Installation of three new pumps on the emulsion pipeline at Valve Site #2 is not expected to significantly increase the risk of fire or oil spills. All appropriate fire and oil spill prevention measures would be undertaken by PXP during the installation as well as during the new operations, as required in the LOGP SIMQAP, which covers Valve Site #2 and the pipelines from Platform Irene.

Valve Site #2 can be accessed by emergency personnel and equipment within 15 minutes. Operation of the new pumps at Valve Site #2 would increase the probability of an oil spill at this location (see Section 5.1, Risk of Upset/Hazardous Materials). This increase in the probability of an oil spill would represent an increase in the demands on emergency response services. PXP is required by the Point Pedernales Final Development Plan (FDP) and LOGP Safety Inspection, Maintenance and Quality Assurance Program (SIMQAP) to follow a number of measures that would serve to reduce the impacts of the proposed projects, and therefore decrease the demands on the emergency response services. These measures include remote controls for the pumps to allow for automatic shutdown in response to various malfunctions (e.g., high vibration, low suction pressure, high and low discharge pressure, high bearing and case temperatures, low and high voltage, and overload). Given the high water content of the produced oil in the emulsion pipeline, fire is not expected to be an issue in the event of an oil spill.

Because there are sufficient resources to respond to an upset condition and these resources are located within 15 minutes response time from the valve site, and the likelihood of a fire is low; the impacts to fire protection and emergency response from the installation of the new pumps at Valve Site #2 are considered adverse but not significant.

Mitigation Measure

As with any major equipment and operation changes at oil and gas facilities, it is necessary to alter the fire protection, oil spill, and emergency response plans if the changes affect the contents of the plans. Therefore the following mitigation measure is required to mitigate the impact to the maximum extent feasible in accordance with Santa Barbara County (SBC) policies:

Fire-1 PXP shall review and revise the Fire Protection Plan, Emergency Response Plan, and Oil Spill Response Plan that apply to all the facilities which will have equipment or operations modifications due to the proposed project. The plans shall be submitted to the SBC Fire Department and P&D for review and approval prior to land use clearance.



Residual Impact Impact Fire.1 is considered adverse but not significant (Class III).


Fire.2 Operation of the new power line to Valve Site #2 could result in impacts to fire protection and emergency response resources due to addition of an ignition source into a high fire hazard area.

Operations

Class III

Overhead power lines always pose a fire risk when, during severe wind conditions, a line could break, fall, and cause a brush fire. The Harris Grade fire that burned 9,700 acres in 2000 was caused by a spark from a Torch power pole line in the Lompoc Field, which ignited brush under the pole. Probability of this type of fire could be minimized by clearing vegetation in the vicinity of the power lines.

Another possible fire from a power line could occur when a pole is impacted by a vehicle, causing a line break that causes a fire. All of the power poles would be cemented in the ground and would meet all the design requirements of PG&E regarding exposure to wind. The location of the power poles would be in a remote area on VAFB that is not subject to high levels of traffic, which minimizes the likelihood of a vehicle impacting a power pole.

Because of the low likelihood of fire, adequate response capabilities, and adequate response time, the impacts to fire protection and emergency response resources are considered to be adverse but not significant.

Mitigation Measure As with Impact Fire.1, the existing LOGP Fire Protection Plan must be revised to reflect changes in the project operations. Therefore, the following measure is recommended to mitigate this impact to the maximum extent feasible in accordance with SBC policies.

Fire-2 The applicant shall update the LOGP Fire Protection Plan to include the power line, in particular, the Flammable Vegetation Management part of the plan, to minimize possibility of a brush fire. The applicant shall submit the updated Fire Protection Plan to SBC Fire Department for review and approval prior to land use clearance.



Fire.3 Increased risk of upset due to increased oil flow rates through the project pipelines and pipeline facilities could create impacts to fire protection and emergency response resources.

Increased Throughput Extension of Life

Class III

Increased flow rates would increase spill volumes by 114 barrels (bbls). In the worst-case scenario, rates would increase by 688 bbls, if the SCADA system is not operational (see Section 5.1, Risk of Upset/Hazardous Materials) over current operations, which could result in a larger



area being impacted as a result of a spill. This rate increase could increase the size of the area that the emergency responders would have to manage. However, the change in spill volumes is relatively small (3.6 to 10.9 percent), and response capabilities are currently available for spill volumes that could occur with the proposed project. The increase in spill volume above baseline volumes would not necessitate increasing the response capabilities in the region. Given the nature of the crude oil (high water content), it is highly unlikely that a fire would result in the event of a spill (see Section 5.1, Risk of Upset/Hazardous Materials). The Point Pedernales Project facilities originally have been designed to handle flowrates higher than expected with the proposed project’s flowrates. The existing facilities’ Fire Protection and Emergency Response Plans have been developed for flowrates up to 36,000 barrels per day (bpd) of dry oil; therefore these plans would be applicable for the expected increase in flow rates. However, the Orcutt Pump Station is limited by the SBCAPCD PTO 7511 to a throughput of 9,125,000 bbls per year (which averages 25,000 bpd). If the crude oil flow rate through the pump station is increased, ConocoPhillips’ SIMQAP would have to be updated as required to reflect the operation, maintenance, or safety changes.

With the proposed project, the expected life of the Point Pedernales facilities would be extended, thereby extending the need to maintain the required fire protection and emergency response capabilities for these facilities; however, the pipeline facilities represent only a very small portion of the local response services scope of work. The response services are funded by PXP to provide the services, and this funding would continue if the facilities’ life term is extended. Extension of life of the PXP pipelines is therefore viewed as not significant. Because of the low likelihood of fire, adequate response capabilities and response time, the impacts associated with the increased throughput and extension of life are considered to be adverse but not significant.

Mitigation Measures No mitigation measure has been identified.



Fire.4 Increased likelihood of upset conditions due to equipment modifications at the LOGP and potential increase of wet oil and sour gas quantities processed at the facility could create impacts to fire protection and emergency response.

Operations Increased Throughput

Extension of Life

Class III

The LOGP facility has a fire detection system that is designed to detect flame sources early. The major vessels and equipment spacing satisfies the applicable requirements.

The grading under the LPG/NGL vessels is sufficiently sloped towards the retention basin outside the southern boundary of the facility to prevent liquid pooling under the vessels. Other storage tanks, vessels, and equipment are provided with secondary containment dikes to prevent fire spreading to other areas of the facility.

The LOGP facility is within the required response time (less than 15 minutes) from several fire stations: Lompoc Station No. 51 (SBC) and City of Lompoc Stations No.1 and No.2. Combined



with the resources onsite, these fire stations have sufficient fire fighting and emergency response capabilities. The facility has an emergency response plan that is approved by and coordinated with the SBCFD. The site has good access for the fire and other emergency vehicles.

The LOGP facility has a sufficient supply of water and foam for fire fighting purposes, which was determined in the Torch Fire Protection Plan for LOGP (May 1998 revision) and updated by PXP in March 2005.

Equipment spacing at the LOGP facility satisfies the American Petroleum Institute (API), National Fire Protection Agency (NFPA), and Industrial Risk Insurers (IRI) recommendations. The most important or hazardous equipment and the applicable distances are listed in Table 5.11.5. This table shows that the facility satisfies the applicable spacing requirements.

Table 5.11.5 Equipment Spacing at the LOGP

Equipment or Vessel

Distance from Other Equipment, feet

Minimum Required Distance, feet

Requirement Satisfied?

Oil Storage Tank 100,000 bbls b, c

200 – facility fence-line and any vessels or equipment

175 Yes

>200 – flare, 150 – heater treaters

100 – any open flame source

Yes

95 – LPG loading racks 50 - loading racks Yes >300 – any buildings at facility

50 – control building 100 – other buildings

Yes Yes

LPG Storage Tanks d

>150 – gas processing equipment 50 – process equipment Yes Flare a >300 – LPG loading racks 300 Yes Firewater Pumps a >300 – any equipment 300 – flare

200 - loading racks Yes Yes

Notes: a, b, c, d letters correspond to the specific tables in Table 5.11.4.

The LOGP facility would continue to require response services for a longer period of time than projected in the approved Point Pedernales Project. This constitutes an extension of life impact. However, the response services are funded by PXP to provide response services to the LOGP and other related facilities. This funding would continue to be provided if the life of the facilities is extended.

Equipment changes that are connected with the increased oil and gas throughput are minor and would not have significant impact to the fire protection or emergency response. The LOGP facility along with its fire protection system was designed to process a maximum of 36,000 bpd of dry oil, therefore operation at higher oil and gas processing rates would not have a significant impact on fire protection or emergency response. Also, the facility’s Fire Protection and Emergency Response Plans were developed for maximum flowrates of 36,000 bpd of dry oil, therefore these plans would be applicable for the expected increase in oil flow rates. Because of adequate facility design, sufficient response capabilities and response time the impacts on the fire protection and emergency response resources for the LOGP facility are considered adverse, but not significant.

Mitigation Measures No mitigation measures have been identified.



Residual Impact Impact Fire.4 is adverse but not significant (Class III).

5.11.5 Impact Analysis for the Alternatives Detailed descriptions of the various alternatives have been provided in Chapter 3.0. This section provides a discussion of the fire protection and emergency response impacts of the various alternatives.

5.11.5.1 No Project Alternative With the No Project Alternative, Impacts Fire.1 through Fire.4 would not occur because there would not be changes at Valve Site #2, including installation of a new power line, and no changes in oil flow rates over current conditions (i.e., baseline).

5.11.5.2 VAFB Onshore Alternative The VAFB Onshore Alternative would require the construction and operation of a drilling and production facility on southern VAFB. The onshore drilling and production site would be located directly west of Space Launch Complex 5 (SLC-5) on southern VAFB. SLC-6 is located south of Honda Canyon, south of the alternative drilling and production site. The alternative drilling/ production site could impose severe safety considerations on some VAFB operations, especially during launch windows (see Risk of Upset/Hazardous Materials Section 5.1.5.2). The fire protection and emergency services impacts are as follows:

Impact Fire.1, Valve Site #2 upset conditions, would not apply to the VAFB Onshore Alternative. Impact Fire.4, LOGP risk of upset, would be the same as for the proposed project.

Impact Fire.2 - Power Line Operations would introduce risks similar to the proposed project due to the new power line route from the new substation to the VAFB onshore site. Possible fire from a power line could occur when a pole is impacted by a vehicle or blown down by high winds, causing a line break that causes a fire. Such was the case for the December 22, 1977 Honda Canyon fire. This fire, which eventually burned approximately 9,000 acres, injured 65 people and took 4 lives, started when hurricane-force winds blew a power pole and transformer down in a dry brushy draw on south VAFB near Honda Ridge Road (http://lompoconline.com/ Ron_Fink/fire.html). As a result of this tragedy, significant changes were made in the wild fire management program at VAFB. In addition to the Santa Barbara County Fire Department, there are ten other fire agencies providing fire protection within the County of Santa Barbara: Of the eleven fire protection agencies, only the USDA Forest Service, Santa Barbara County Fire Department and the VAFB Fire Department have wildland fire protection as part of their primary mission. Both the USDA Forest Service – Los Padres National Forest and the DOD VAFB Fire Department staff 20-person inter-regional “Hotshot” handcrews. Hotshot crews are highly trained and organized wildland firefighting crews that are extremely versatile. Currently, VAFB Fire Department response capabilities include 5 Type 1 engines and 1 truck company at 3 locations, 1 Hazmat squad, 5 Airport crash/fire/rescue companies, 3 Water Tenders, 1 hand crew and 1 truck company (6 locations). VAFB also participates with the City of Lompoc in a Mutual Aid agreement.

As discussed for the proposed project, the risk of fire from overhead power lines could be minimized by clearing vegetation in the vicinity of the new power lines. All of the power poles



would be secured to cement foundations and would meet all the design requirements of PG&E regarding exposure to wind. The location of the power poles would be in a remote area on VAFB that is not subject to high levels of traffic, which minimizes the likelihood of a vehicle impacting a power pole.

Because of the low likelihood of fire, adequate response capabilities, and adequate response time, the impacts to fire protection and emergency response resources are considered to be adverse but not significant (Class III). Mitigation Measures Fire-1 and Fire-2 would apply to mitigate this impact to the maximum extent feasible in accordance with SBC policies.

Impact Fire.3 - Pipeline Risk of Upset would not occur offshore but would increase onshore. The new pipelines and drilling/production site associated with this alternative would generate risks to public safety and Base personnel (see Section 5.1.5.2, Risk of Upset/Hazardous Materials). In the event of an oil spill, there would need to be emergency response capabilities similar to what is required for the proposed project. Catchment basins would need to be included in the pipeline design in accordance with Mitigation Measures OWR-5 and OWR-12. Impact Fire.3 would stay the same as for the proposed project, adverse but not significant (Class III).


Fire.5 Pipeline construction could create short-term impacts to fire protection and emergency response.

Construction

Class II

Construction of the new onshore pipeline and power line would be short-term and is not expected to have significant impacts on emergency response resources. The Applicant would be required to follow all fire and oil spill prevention measures, and other safety precautions required by regulations for excavation.

The construction of the pipeline would require hot work for welding, which has the potential to start fires. In addition, movement of the construction equipment could result in sparks that have the potential to start fires. Although the pipeline construction would occur within high fire hazard areas, it would be near existing roadways and UPRR right-of-way, reducing the likelihood of a spark-generated fire and providing adequate emergency response accessibility. Further, a VAFB fire station is located on Coast Road, in close proximity to alternative facilities.

Mitigation Measures

Fire-3 All construction equipment shall be equipped with the appropriate spark arrestors and functioning mufflers. PXP shall submit the pipeline construction procedures to the SBC Fire Department for review and approval prior to land use clearance.

Fire-4 A fire watch with appropriate fire fighting equipment (i.e., hydrants, water truck, etc.) shall be available at the project site at all times when welding or grinding activities are taking place. Further, welding or grinding shall not occur when sustained winds exceed 15-20 mph, as determined by SBC Fire Department, unless an SBC Fire Department approved wind shield is on site. PXP shall submit the pipeline construction procedures to the SBC Fire Department for review and approval prior to land use clearance.



Fire-5 All rubber-tired construction vehicles shall be equipped with appropriate fire fighting equipment, such as shovels and axes or pulaskis, to aid in the prevention or containment of fires. PXP shall submit the pipeline construction procedures to the SBC Fire Department for review and approval prior to land use clearance.

Residual Impact The residual impact for Impact Fire.5 is considered significant but mitigable (Class II).

5.11.5.3 Casmalia East Oil Field Processing Location

Impacts Fire.1 to Fire.3 would be the same as for the proposed project.

Impact Fire.4 – LOGP Upset: The part of Impact Fire.4 that is related to increased throughput would be eliminated because the processing facilities that pose the greatest risk of upset and demand for emergency resources would be moved to Casmalia. Because there still would be pumps and compressors at the LOGP site beyond the currently projected life of the Point Pedernales facilities, and these remaining facilities would have fire protection and emergency response requirements, the part of Impact Fire.4 related to extension of life would remain, though greatly reduced in magnitude.

Impact Fire.5 – Construction Risk of Upset: Construction of the Casmalia Alternative pipeline would be short-term and is not expected to have significant impacts on emergency response resources. The construction of the pipeline would require hot work for welding, which has the potential to start fires. In addition, movement of the construction equipment could result in sparks that have the potential to start fires. Since the pipeline construction would occur within high fire hazard areas, the impact due to construction is considered significant but mitigable (Class II) with the implementation of Mitigation Measure Fire-3, Fire-4, and Fire-5.


Fire.6 Construction of Casmalia site facilities and dismantling of the LOGP could create short-term impacts to fire protection and emergency response.

Construction

Class III

Increased truck traffic involved in materials and equipment deliveries and the removal of refuse from dismantling of the LOGP could increase the likelihood of road accidents. During the LOGP dismantling, open-flame cutting (if used) of equipment and piping that were used for oil processing would increase the likelihood of fire. Open flame work (e.g., welding) at the new facility site that is located in a high fire hazard area could also increase the likelihood of fire. Trenching to install new pipelines would increase risk of damaging other hazardous pipelines or power cables and could result in a fire or explosion. The California Fire Marshal Report on hazardous liquids pipelines states that third-party damage is one of the leading causes of pipeline failure (see Section 5.1, Risk of Upset/Hazardous Materials). However, PXP is required to follow California Code of Regulations, Title 1, Division 5, §§4215-4217, regarding notifications of the Underground Service Alert (USA) prior to beginning excavations, markings of the existing pipelines in the vicinity of the project site, and other safety measures during excavations. Dismantling the old facilities is expected to have similar impacts as constructing the new facilities at Casmalia site. Both constructing and dismantling would be short-term, however. Any



adverse impacts would be mitigated by appropriate construction techniques and safety measures; therefore, the impact would be adverse but not significant.

Mitigation Measures

Fire-6 For the new facilities, PXP shall follow all appropriate fire protection and safety measures outlined in the Point Pedernales Project Final Development Plan (FDP), Systems Safety and Reliability, Part P. PXP shall submit the construction procedures to the SBC Systems Safety Reliability Review Committee (SSRRC) for review and approval prior to land use clearance.

Residual Impact Impact Fire.6 is adverse but not significant (Class III).


Fire.7 Operation of the new oil and gas facility at Casmalia East site could create long-term impacts to fire protection and emergency response.

Operations Extension of Life

Class II

Operating the new oil and gas facility at Casmalia site could create significant impacts to the fire protection or emergency response resources due to the increased demand that an oil and gas processing facility would have on fire protection services in the southern Orcutt/Santa Maria area. The facility would generate potential fire hazards due to releases of crude oil, produced gas and natural gas liquids. The facility would also generate toxic gas hazards due to a potential release of produced gas or acid gas, which could be generated as part of the produced gas treatment process.

Under this alternative, the majority of the LOGP facility would be dismantled. However, crude oil shipping pumps and produced gas compressors would still remain at the site. Therefore, fire protection and emergency response requirements would still remain at the LOGP site, but they would be substantially reduced. A new processing facility at Casmalia would shift the primary emergency response capabilities from the Lompoc area to the Santa Maria area. The new site is within 8 to 10 miles from the fire stations in Santa Maria, which can provide response to the Casmalia site within 15 minutes. Fire stations located in Lompoc (17 to 18 miles from the new site) would serve as secondary response services. The Orcutt/Santa Maria fire stations currently do not have resources to be the primary responder to an oil and gas processing facility emergency situation other than fire (e.g., HazMat teams, spill response capabilities).

The new facility would also extend the life of the remaining Point Pedernales facilities. Because the existing response resources could not provide adequate emergency response to the Casmalia area, impacts to fire protection and emergency response resources are considered to be significant.

Mitigation Measures Mitigation Measure Fire-6 is applicable to operations of the new facilities as well as for construction. In addition, the following mitigation measures are required.



Fire-7 The new facility shall be designed in accordance with all applicable fire protection and emergency response standards. The new facility should be designed with all early fire detection and prevention of fire spread as the basis of the fire safety design. The facility should have adequate supply of water and oil fire fighting foam as per the National Fire Protection Agency (NFPA) requirements (i.e., Standards 11, 15, 22, 24, 25). The facility layout should provide sufficient access for emergency response vehicles and provide adequate equipment spacing as per the American Petroleum Institute (API) and Industrial Risk Insurers (IRI) guidelines (IRI IM 2.5.2). The new facility should have fire detection monitors positioned in the locations most likely to be affected by fire. All appropriate equipment such as crude oil storage tanks should have sufficient secondary containment. Grading under liquefied petroleum gas (LPG) storage vessels should be sloped to allow any spilled flammable liquids to flow outward from the vessel and into an impoundment area. The applicant shall submit all appropriate documentation for the new facility to the SSRRC for review and approval prior to land use clearance

Fire-8 Fire protection, oil spill, and emergency response plans of the new facility shall be developed or adjusted using the similar LOGP plans and coordinated with the SBC Fire Department. These plans shall address the fire prevention measures at the facility, the fire suppression systems, the specific hazards at the facility, and fire and emergency response training and planning. The Fire Protection, Oil Spill Response, and Emergency Response Plans shall be submitted to the SBC Fire Department for review and approval prior to land use clearance.

Fire-9 The facility operators/owners shall provide funding to the SBC Fire Department to provide adequate staffing and equipment for the Santa Maria Fire Station to address the emergency response requirements of the Casmalia oil and gas processing facility. The facility operators/owners shall enter into an agreement with the SBC to provide the reasonable share of funds for fire protection and emergency response. The operators/owners shall provide documentation of the monetary deposits into the appropriate funds prior to land use clearance.

Residual Impact With incorporation of the measures listed above and Mitigation Measure Fire-3, Impact Fire.7 would be reduced to a less than significant level (Class II).


Fire.8 Operation of the sour gas pipeline to the new plant at Casmalia East site could create long-term impacts to fire protection and emergency response.

Operations

Class II

This alternative would require that a new sour gas pipeline be built from the LOGP to the Casmalia oil and gas processing facility. This pipeline would have similar hazard zones to the sour gas pipeline from Platform Irene to the LOGP. However, the risk to public safety that is associated with this pipeline would be greater (see Section 5.1, Risk of Upset/Hazardous Materials). The pipeline would be in close proximity to a number of residences in southern Orcutt. The pipeline would present both fire and toxic hazards that would place additional



requirements on fire protection and emergency response. For a major portion of this pipeline, the Santa Maria Fire Station No. 22 would be the primary responder. The Santa Maria fire stations do not currently have resources to be the primary responder to an oil and gas processing facility emergency situation (e.g., HazMat teams, oil spill response capabilities) (see Table 5.11.1). Because the adequate response resources are not available, this impact is considered to be significant.

Mitigation Measures Mitigation Measure Fire-9 would apply, along with these additional measures.

Fire-10 The sour gas pipeline shall be equipped with a leak detection system that is capable of detecting leaks as small as ¼ inch. The pipeline shall be equipped with remotely operated block valves to limit the volume of material release in the event of a leak or rupture. The applicant shall submit documentation for the pipeline controls design to the SBC SSRRC for review and approval prior to land use clearance.

Fire-11 The pipeline shall be constructed following all applicable standards for sour gas pipeline service. The applicant shall submit all pipeline documentation (e.g. route, materials of construction, operation procedures) to the SBC SSRRC for review and approval prior to land use clearance.

Mitigation Measure Risk-3 (see Section 5.1, Risk of Upset/Hazardous Materials) requires that the route of the LOGP-Casmalia pipeline to be not closer than 2,500 feet from southern Orcutt.

Residual Impact With incorporation of the mitigation measures listed above and Mitigation Measure Risk-3, the residual impact would be considered less than significant (Class II).

5.11.5.4 Alternative Power Line Routes to Valve Site #2 Impacts Fire.1, Fire.3, and Fire.4 would stay the same as for the proposed project. The magnitude of Impact Fire.2 would greatly decrease as installation of a portion of the power line below ground, as opposed to above ground, would eliminate addition of a new ignition source to a portion of the power line route, which is located in high fire hazard area.

5.11.5.5 Replacement of Oil Emulsion Pipeline from Platform Irene to LOGP Impacts Fire.1 and Fire.2 would not occur because Valve Site #2 modifications would not be needed. Impact Fire.4 would be the same as for the proposed project. Impacts Fire.6, Fire.7, and Fire.8 (Casmalia construction and operations) would not apply to this alternative.

Impact Fire.3 – Pipeline Risk of Upset would stay the same as for the proposed project as discussed below. The replacement pipeline would be designed, maintained and operated using the LOGP SIMQAP. Since the replacement pipeline would follow the same right-of-way as the existing pipeline, the same catchment basins would be available to contain spills in the vicinity of Santa Ynez River. The pipeline valves would use the same valve sites, and the same control and leak detection system would be in place. The existing pipeline operation has a risk of fire or oil spill. However, these risks are a part of the baseline for this analysis. The replacement pipeline would have greater wall thickness and fewer anomalies due to corrosion and erosion, therefore, the replacement pipeline is expected to have a decreased spill probability (~10



percent). However, the potential spill volume would be the same and in the event of an oil spill there would still need to be emergency response capabilities similar to what is required for the proposed project. Therefore, Impact Fire.3 would stay the same as for the proposed project, adverse but not significant (Class III).

Impact Fire.5 – Construction Risk of Upset: Construction of the replacement emulsion pipeline would be short-term and is not expected to have significant impacts on emergency response resources. There is a potential of encountering and damaging the existing Point Pedernales pipelines during excavation; however, the pipelines would not be in operation during construction. The applicant would be required to follow all fire and oil spill prevention measures and other safety precautions required by regulations for excavation. This would include draining the existing pipelines prior to beginning the excavation work for the new pipeline.

The construction of the pipeline would require hot work for welding, which has the potential to start fires. In addition, movement of the construction equipment could result in sparks that have the potential to start fires. Since the pipeline construction would occur within high fire hazard areas, the impact due to construction is considered significant but mitigable (Class II) with the implementation of Mitigation Measure Fire-3, Fire-4, and Fire-5.

5.11.565 Alternative Drill Muds and Cuttings Disposal Onshore activities under these alternatives are the same as for the proposed project. Therefore, Impacts Fire.1 through Fire.4 would be the same as for the proposed project.

5.11.6 Cumulative Impacts

5.11.6.1 Offshore Oil and Gas Projects

Potential offshore oil and gas development projects within the proposed project area could include the Rocky Point, Lion Rock, Point Sal, Santa Maria, Purisima Point, Bonito and Sword Units, and Lease OCS-P 0409. The hazardous nature of these facilities would require well-developed fire protection and emergency response services. These new oil and gas facilities could require significant additions to existing response services in the VAFB and Lompoc area; however, with project-specific requirements such as expanded or new fire protection and emergency response facilities, services and personnel, cumulative impacts would not be considered significant. Although the proposed project would prolong the life of the Point Pedernales Project, and thus its need for such services, with project-specific mitigation measures for the other potential offshore oil and gas-related projects in the area, its incremental contribution to cumulative impacts would not be considered significant. The other offshore and onshore oil and gas development projects discussed in Sections 4.3 and 4.4, respectively, are a substantial distance away from the proposed project; consequently, no overlap with their related fire protection and emergency response services would be anticipated to occur.

5.11.6.2 Onshore Projects

The potential onshore development projects discussed in Section 4.4 would put additional strains on existing fire protection and emergency response services; however, the proposed project’s contribution to this impact is not expected to be significant. The fire protection services in Lompoc and Santa Maria are adequate to service the onshore developments. In addition, as



presented in Section 4.4, a new County fire station and sheriff substation, to be located near the intersection of Burton Mesa Boulevard and Harris Grade Road, are currently under review. This would provide sufficient fire protection capabilities to service the additional onshore developments in the proposed project area. Therefore, the cumulative impacts on fire protection and emergency responses resources from the future onshore development would not be expected to be significant.

5.11.7 Mitigation Monitoring Plan

Mitigation Measure Mitigation Requirements and Timing

Method of Verification

Timing of Verification

Party Responsible

For Verification

Fire-1 PXP shall review and revise the Fire Protection Plan, Emergency Response Plan and Oil Spill Response Plan that apply to all the facilities which will have equipment or operations modifications due to the proposed project. The plans shall be submitted to the SBC Fire Department and P&D for review and approval prior to land use clearance.

The plans shall be reviewed prior to Land

Use clearance.

Compliance with the plans

shall be verified by annual drill and audit.

SBCFD

Fire-2 The applicant shall update the LOGP Fire Protection Plan to include the power line, in particular, the Flammable Vegetation Management, part of the plan to minimize possibility of a brush fire. The applicant shall submit the updated Fire Protection Plan to SBC Fire Department for review and approval prior to land use clearance.

Prior to Land Use clearance.

Compliance with the Fire

Protection Plan shall be verified

through regular drills.

SBCFD

Fire-3 (VAFB

Onshore, Casmalia,

and Emulsion Pipeline

Replacement Alternatives

only)

All construction equipment shall be equipped with the appropriate spark arrestors and functioning mufflers. PXP shall submit the pipeline construction procedures to the SBC Fire Department for review and approval prior to land use clearance.


Review during construction

SBCFD and EQAP monitor

Fire-4 (VAFB

Onshore, Casmalia,



only)

A fire watch with appropriate fire fighting equipment (i.e., hydrants, water truck, etc.) shall be available at the project site at all times when welding or grinding activities are taking place. Further, welding or grinding shall not occur when sustained winds exceed 15-20 mph, as determined by SBC Fire Department, unless an SBC Fire Department approved wind shield is on site. PXP shall submit the pipeline construction procedures to the SBC Fire Department for review and approval prior to land use clearance.









Party Responsible

For Verification

Fire-5 (VAFB

Onshore, Casmalia,



only)

All rubber-tired construction vehicles shall be equipped with appropriate fire fighting equipment, such as shovels and axes or pulaskis, to aid in the prevention or containment of fires. PXP shall submit the pipeline construction procedures to the SBC Fire Department for review and approval prior to land use clearance.




Fire-6 (Casmalia Alternative

only)

For the new facilities, PXP shall follow all appropriate fire protection and safety measures outlined in the Point Pedernales Project Final Development Plan (FDP), Systems Safety and Reliability, Part P. PXP shall submit the construction procedures to the SBC Systems Safety Reliability Review Committee (SSRRC) for review and approval prior to land use clearance.

Prior to Land Use clearance, and regularly

during operations.

Compliance with the new FDP shall be

verified through regular facility audits.

SSRRC (includes SBCFD)


only)

The new facility shall be designed in accordance with all applicable fire protection and emergency response standards. The new facility should be designed with all early fire detection and prevention of fire spread as the basis of the fire safety design. The facility should have adequate supply of water and oil fire fighting foam as per the National Fire Protection Agency (NFPA) requirements (i.e., Standards 11, 15, 22, 24, 25). The facility layout should provide sufficient access for emergency response vehicles and provide adequate equipment spacing as per the American Petroleum Institute (API) and Industrial Risk Insurers (IRI) guidelines (IRI IM 2.5.2). The new facility should have fire detection monitors positioned in the locations most likely to be affected by fire. All appropriate equipment such as crude oil storage tanks should have sufficient secondary containment. Grading under liquefied petroleum gas (LPG) storage vessels should be sloped to allow any spilled flammable liquids to flow outward from the vessel and into an impoundment area. The applicant shall submit all appropriate documentation for the new facility to the SSRRC for review and approval prior to land use clearance


Through review of the

facility documentation, such as facility

plot plans, P&IDs, etc.

SSRRC






Party Responsible

For Verification


only)

Fire protection, oil spill, and emergency response plans of the new facility shall be developed or adjusted using the similar LOGP plans and coordinated with the SBC Fire Department. These plans shall address the fire prevention measures at the facility, the fire suppression systems, the specific hazards at the facility, and fire and emergency response training and planning. The Fire Protection, Oil Spill Response, and Emergency Response Plans shall be submitted to the SBC Fire Department for review and approval prior to land use clearance.


Compliance with the plans

is verified through regular

drills.

SBCFD


only)

The facility operators/owners shall provide funding to the SBC Fire Department to provide adequate staffing and equipment for the Santa Maria Fire Station to address the emergency response requirements of the Casmalia oil and gas processing facility. The facility operators/owners shall enter into an agreement with the SBC to provide the reasonable share of funds for fire protection and emergency response. The operators/owners shall provide documentation of the monetary deposits into the appropriate funds prior to land use clearance.

Prior to issuance of the

FDP.

Review of monetary

deposits into the appropriate

accounts.

SBCFD


only)

The sour gas pipeline shall be equipped with a leak detection system that is capable of detecting leaks as small as ¼ inch. The pipeline shall be equipped with remotely operated block valves to limit the volume of material release in the event of a leak or rupture. The applicant shall submit documentation for the pipeline controls design to the SBC SSRRC for review and approval prior to land use clearance.


Review prior to construction and operation

SSRRC


only)

The pipeline shall be constructed following all applicable standards for sour gas pipeline service. The applicant shall submit all pipeline documentation (e.g., route, materials of construction, operation procedures) to the SBC SSRRC for review and approval prior to land use clearance.


Review prior to and during construction

SSRRC

5.11.8 References API. 1998. Recommended Practice 14C, Recommended Practice for Analysis, Design,

Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms. March

____. 1995. Standard 2510, Design and Construction of LPG Installations. 1995 Edition.

____. 1989. Publication 2510A, Fire-Protection Considerations for the design and Operation of Liquefied Petroleum Gas (LPG) Storage Facilities. April



____. 1994. Design, Construction, Operation, Inspection and Maintenance of Tank and Terminal Facilities, API Standard 2610.

____. 1999. Tank Inspection, Repair, Alteration, and Reconstruction, API Standard 653. California Code of Regulations. Title 1, Division 5.

City of Lompoc Fire Department; City of Santa Maria Fire Department. 2000. Unocap Emergency Response Plan, May.

http://lompoconline.com/Ron_Fink/fire.html, A Burning Memory: The Darkest Day in the History of the Vandenberg AFB Fire Department and the Birth of the Vandenberg AFB Hot Shots.

IRI. 1993 to1995. Guidelines for Loss Prevention and Control.

National Fire Protection Association (NFPA). 2000. National Fire Codes, 2000 Edition.

____. 1997. Fire Protection Handbook, 18th edition.

Nuevo Energy Company. 1999. Lompoc Oil and Gas Plant Safety Inspection, Maintenance, and Quality Assurance Program (revised January 2002).

____. 1999. Safety Inspection, Maintenance, and Quality Assurance Program. Lompoc Oil and Gas Plant (revised January 2002).

PXP. 2005a. LOGP Fire Protection Plan. March.

____. 2005b. Emergency Response Plan. Platform Irene Production Pipeline from Beach to Lompoc OGP and LOGP. August.

____. 2004. Oil Spill Response Plan. Platform Irene and Point Pedernales 20-inch Wet Oil Pipeline. November.

____. 2004 (updated May and August 2005). Emergency Response Plan. December

Santa Barbara County, Planning and Development Department. 1995. Environmental Thresholds and Guidelines Manual.

Tosco Refining Company. May 2000. Unocal Sisquoc Pipeline Project: Fire Protection Plan.

____. 2001. Safety Inspection, Maintenance, and Quality Assurance Program. March 28.

UNOCAP. 2000. UNOCAP Sisquoc to Santa Maria Station & Point Pedernales Lompoc Oil and Gas Plant to Orcutt Pump Station Emergency Response Plan. May.



Figure 5.11-1 Fire Station Locations and Emergency Response Facilities Figure 5.11-2 Fire Protection Equipment - Lompoc Oil and Gas Plant Figure 5.11-3a Fire Protection Equipment - Platform Irene Production Deck Figure 5.11-3b Fire Protection Equipment - Platform Irene Drill Deck

Documents

5-11 Fire Protection