5-1

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Chapter 5

Environmental Consequences, Cumulative Impacts

(2002 - 2006), and Mitigation Measures

Table of Contents

5.0 Introduction .......................................................................................................................................... 5-3

5.1 Background Information for Impact Analyses ................................................................................. 5-4

5.1.1 Proposed Action (Delineation Drilling) ................................................................................... 5-4

5.1.1.1 Impact – Producing Factors of the Proposed Action .................................................. 5-4

5.1.2 Cumulative Analyses ................................................................................................................ 5-7

5.1.2.1 Impact – Producting Factors of the Cumulative Case ................................................ 5-8

5.1.2.2 Reasonably Foreseeable Activities ............................................................................... 5-8

5.1.3 Oil Spills, Risk, Movement, and Response ............................................................................ 5-15

5.1.3.1 Oil Spill Risk Assessment .......................................................................................... 5-15

5.1.3.2 Conditional Oil Spill Risk Analysis ........................................................................... 5-19

5.1.3.3 Oil Sources, Behavior, and Spill Response ................................................................ 5-34

5.2 Environmental Impacts of Alternative 1: The Proposed Action .................................................... 5-41

5.2.1 Impacts on Air Quality ........................................................................................................... 5-41

5.2.1.2 Cumulative Impact Analysis for Air Quality ............................................................ 5-59

5.2.2 Impacts on Water Quality ...................................................................................................... 5-66

5.2.2.2 Cumulative Impact Analysis for Water Quality ........................................................ 5-76

5.2.3 Impacts on Rocky and Sandy Beach Habitats ...................................................................... 5-83

5.2.3.2 Cumulative Impact Analysis For Rocky and Sandy Beach Habitats Resources ..... 5-84

5.2.4 Impacts on Seafloor Resources .............................................................................................. 5-84

5.2.4.2 Cumulative Impact Analysis for Seafloor Resources ................................................ 5-90

5.2.5 Impacts on Kelp Beds ............................................................................................................. 5-93

5.2.5.2 Cumulative Impact Analysis for Kelp Beds ............................................................... 5-93

5.2.6 Impacts on Fish Resources .................................................................................................... 5-94

5.2.6.2 Cumulative Impact Analysis for Fish Resources ...................................................... 5-96

5.2.7 Impacts on Marine and Coastal Birds ................................................................................. 5-104

5.2.7.2 Cumulative Impact Analysis for Marine and Coastal Birds ................................... 5-106

5.2.8 Impacts on Marine Mammals .............................................................................................. 5-106

5.2.8.2 Cumulative Impact Analysis for Marine Mammals ................................................ 5-111

5.2.9 Impacts of the Proposed Action and Cumulative Impact Analysis for

Threatened and Endangered Species ................................................................................... 5-120

5.2.10 Impacts on Estuarine and Wetland Habitats ..................................................................... 5-136

5.2.10.2 Cumulative Impact Analysis for Estuaries and Wetlands .................................... 5-136

5.2.11 Impacts on Refuges, Preserves and Marine Sanctuaries .................................................. 5-137
5-2

Delineation Drilling Activities Offshore Santa Barbara County

5.2.12 Impacts on Onshore Biological Resources ......................................................................... 5-138

5.2.12.2 Cumulative Impact Analysis for Onshore Biological Resources .......................... 5-138

5.2.13 Impacts on Cultural Resources........................................................................................... 5-138

5.2.13.2 Cumulative Impact Analysis for Cultural Resources ........................................... 5-141

5.2.14 Impacts on Visual Resources .............................................................................................. 5-144

5.2.14.2 Cumulative Impacts for Visual Resources............................................................. 5-147

5.2.15 Impacts on Recreation ........................................................................................................ 5-148

5.2.15.2 Cumulative Impact Analysis for Recreation.......................................................... 5-149

5.2.16 Impacts on Community Characteristics and Tourism Resources ..................................... 5-152

5.2.16.2 Cumulative Impact Analysis for Community Resources

and Tourism ................................................................................................................. 5-153

5.2.17 Impacts on Employment and Population ........................................................................... 5-153

5.2.17.2 Cumulative Impact Analysis for Employment and Population ............................ 5-154

5.2.18 Impacts on Housing ............................................................................................................ 5-155

5.2.18.2 Cumulative Impact Analysis for Housing ............................................................. 5-155

5.2.19 Impacts on Infrastructure .................................................................................................. 5-155

5.2.19.2 Cumulative Impact Analysis for Infrastructure.................................................... 5-157

5.2.20 Impacts on Public Finance and Services............................................................................ 5-157

5.2.20.2 Cumulative Impact Analysis for Public Finance and Services ............................. 5-158

5.2.21 Impacts on Non-Residential Land Use............................................................................... 5-159

5.2.21.2 Cumulative Impact Analysis for Non-Residential Land Use ................................ 5-159

5.2.22 Impacts on Commercial Fishing and Kelp Harvest ........................................................... 5-159

5.2.22.2 Cumulative Impact Analysis for Commercial Fishing and Kelp

Harvest......................................................................................................................... 5-171

5.2.23 Impacts on Marine Recreational Fishing ........................................................................... 5-178

5.2.23.2 Cumulative Impact Analysis for Marine Recreational Fishing ............................ 5-180

5.2.24 Impacts on Military Operations ......................................................................................... 5-185

5.2.24.2 Cumulative Impact Analysis for Military Operations .......................................... 5-187

5.3 Environmental Justice ................................................................................................................... 5-191

5.4 Environmental Impacts of Alternative 2 - Onshore Disposal of Muds and Cuttings ................. 5-192

5.5 Environmental Impacts of Alternative 3 - No Action ................................................................... 5-195

5.6 Unavoidable Adverse Impacts of the Proposed Action ................................................................. 5-195

5.7 Relationship Between the Short-term Use of Man’s Environment and the

Maintenance and Enhancement of Long-term Productivity ........................................................ 5-197

5.8 Irreversible and Irretrievable Commitment of Resources............................................................. 5-198
5-3

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

5.0 INTRODUCTION

The reader is encouraged to read section 1.2,

Reader’s Guide to the use of this document, to get a

good understanding of how this EIS is organized.

Chapter 5 provides an analysis of how the Proposed Action will likely affect the environmental resources in or migrating through the study area. The

analysis is provided on a resource-by-resource basis

for the Proposed Action in isolation and with respect

to the cumulative case. Available measures to mitigate adverse effects of the Proposed Action are also

identified, with an estimate of the ameliorative effects

of these measures for specific resource categories. Finally, this chapter includes a discussion of the effects

of the two alternatives on the resources. The list of

related environmental documents is presented in appendix 7. These documents are hereby incorporated

into this EIS.

Impacts that could potentially occur as a result

of delineation drilling are highly localized (Figure 1.0-

3). However, the study area includes a considerably

larger geographic area to facilitate the analysis of both

near-term (through residual effects of the delineation

drilling) and longer-term (through potential development and decommissioning of all 36 currently undeveloped OCS leases) (Figure 4.0-1). This was discussed in Chapter 4.

This chapter builds on the description of the affected environment provided in chapter 4. The structure of the analysis of the environmental consequences

of the Proposed Action describes the impact-producing

factors and defines the criteria employed for high,

moderate, low, and negligible impacts for each resource

category. The impacts are analyzed for all the projects

combined, followed by those impacts associated with

each separate project, as appropriate.

The basis for the cumulative effects analyses considers the aggregate of all the effects of all activities

and the contribution of the Proposed Action. The effects of the other activities in the study area (past,

present, and within the foreseeable future) are evaluated, and the likely effects of the Proposed Action are

overlaid to provide a clear understanding of the contribution of the Proposed Action to the whole.

The cumulative effects of OCS activities are discussed for each resource category in two phases, or

two different “futures,” one of longer duration than

the other:

• Chapter 5 provides an analysis of the effects

over the near-term future (2002-2006). This is

the timeframe projected through the time when

no further residual effects associated from the

Proposed Action are expected to occur.

• Chapter 6 provides an analysis of the effects of

potential development of the 36 undeveloped

OCS leases over the near- and long-term future (2002-2030). This Chapter also analyzes

the cumulative effects of all existing offshore

oil and gas activities and other related activities in the study area.

This approach to analyzing the effects of the

Proposed Action as it influences other activities and

conditions that exist within these timeframes provides

the readers and decisionmakers an understanding of

the incremental effects of the Proposed Action. In both

cases, assumptions were made concerning the foreseeable future activities in and influencing the study area

(section 5.1.2.2 and 6.1.2). A limited amount of information is currently known of how and when the reasonably foreseeable activities (both those associated

with OCS development and with other influences on

the environment) may occur. To provide a long-term

analysis, the MMS developed a hypothetical development scenario for the 36 undeveloped OCS leases. This

is described in detail in section 6.1.3.

Chapter 5

Environmental Consequences, Cumulative Impacts

(2002 - 2006), and Mitigation Measures
5-4

Delineation Drilling Activities Offshore Santa Barbara County

5.1 BACKGROUND INFORMATION FOR

IMPACT ANALYSES

5.1.1 PROPOSED ACTION (DELINEATION

DRILLING)

The operators (Nuevo Energy Company, Aera

Energy LLC, and Samedan Oil Corporation) of four

OCS units (Bonito, Cavern Point, Point Sal, and Gato

Canyon), are expected to propose to drill 4-5 delineation wells on those units (figure 1.0-3; table 1.0-2).

These will be proposed in 4-5 revised Exploration Plans

EP’s).

The four proposed projects will use a semi-submersible drilling vessel, commonly referred to as a

mobile offshore drilling unit (MODU). The MODU

will move from one unit to another, sequentially drilling a total of 4-5 wells on the four separate unitized

areas (table 1.0-2). Each of the four units has been

previously-explored under EP’s approved by the MMS.

These EP’s were found consistent with the California

Coastal Management Plan by the California Coastal

Commission. The operators of these units propose to

drill delineation wells to complete their data on reservoir configuration and characteristics. It will take

68-92 days to drill and test each well. The first well

would commence drilling in May 2002 and the last

well in May 2003. The data received from these wells

will assist the operators in determining how to develop and produce the underlying oil and gas reserves.

Table 5.1.1.1-1 provides a summary of impact-producing factors associated with the Proposed Action (Delineation Drilling). Refer to section 2 for a complete

description of the proposed projects.

5.1.1.1 IMPACT-PRODUCING FACTORS FOR

THE PROPOSED ACTION

Exploring for hydrocarbon resources as a result

of the Proposed Action requires a complex and interrelated series of operations that began with pre-lease

geological and geophysical exploration under MMS

permits, continued through leasing of offshore blocks,

post-lease seismic surveying operations, exploration

drilling, and, finally, the proposed drilling of delineation wells on the four units. Transportation of the

personnel and supplies needed to maintain these operations are also part of the process. These diverse

activities have associated potential impacts to offshore

and onshore biological, physical, and socioeconomic

resources. This section describes the various kinds of

offshore activities that could affect the environmental

and socioeconomic resources in the study area. The

potential impacts associated with these activities are

described in section 5.2.1 through 5.2.24.

Tables 2.1-2.4 show the magnitudes of the impact producing factors (IPF’s) that are projected to

occur in the various units from the Proposed Action.

Also, table 5.1.1.1-1 presents a summary of these IPF’s.

PERSONNEL

It is expected that approximately 140-145 individuals will be directly involved in the proposed drilling activities at each well site. Most of the employees

will be working on the drilling rig and will stay with

the rig. The offshore personnel will typically work

shifts of 7 days on and 7 days off. Service personnel

will move to and from the rig as needed. Other than

employees of the drilling contractor, the personnel associated with these operations are generally already

living and located in Santa Barbara and Ventura Counties.

INFRASTRUCTURE AND OPERATIONS

Delineation Wells. Delineation of petroleum-bearing formations is carried out from mobile drilling rigs

or drillships. For the Proposed Action, a single semisubmersible type, or MODU, would be used (figure

2.1.3-1) to drill all the proposed delineation wells for

the proposed project to minimize potential cumulative

impacts. The analog rig to be used for the representative analysis will be the SEDCO 712. This drill rig is

similar to rigs used in previously-approved EP’s and

has been used to drill seven wells in the Pacific OCS

Table 5.1.1.1-1. Summary of impact-producing factors associated with the proposed action

(delineation drilling).

Wells Proposed to be 

Drilled on Each Unit 

Time on Location 

(days) 

Mud and Cuttings 

Volume Per Well (bbl) 

Anchor Spread 

(ft) 

Crew and Supply Boat 

Trips Per Month (Total) 

Helicopter Trips/Month 

(Total) 

Bonito – 1-2 88-90 2,957 3,000 20 (57-59) 30 (86-88) 

Point Sal – 1 68 12,250 1,100-1,900 14 (31) 20 (44) 

Purisma Point – 1 68 12,250 1,100-1,900 14 (31) 20 (44) 

Gato Canyon – 1 92 2000 to 3000 2,500-3,500 11 (33) 28 (84) 
5-5

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Region in the past. The time required to drill and test

each well is 68-92 days. One delineation well would

be drilled on the Point Sal, Gato Canyon, and Purisima

Point Units and one to two wells on the Bonito Unit.

Offshore Transport –Service Vessels. Support

vessels associated with MODU drilling operations will

operate out of Port Hueneme, with some possible crew

boat trips originating from Carpinteria Pier. Due to

the rough sea conditions north of Point Conception

and distances involved, crews will be transferred to

and from the MODU primarily by helicopter. Supply

boat trips are projected to number 8-12 per month,

which averages about 1 every 3 days. Currently, about

12-13 supply boat trips per month (1 every 2 to 3 days)

are made to the four existing OCS platforms (Irene,

Harvest, Hermosa, Hidalgo) in the Santa Maria Basin. An additional 12 supply boat trips per month (1

every 2 to 3 days) are made to existing OCS platforms

(Hondo, Heather, and Harmony) in the western Santa

Barbara Channel.

The Proposed Action includes the following list

of service-vessel activities:

• Crew boats: It is expected that one 110-foot

class crew boat will be used to support the delineation drilling operations. It is likely that

the boat will be stationed in, and operate out

of, Port Hueneme or the Carpinteria Pier and

will travel through established corridors. Although crew boats may service other area platforms on the same trip, it is assumed for this

analysis that crew boats serve the drilling rig

exclusively. Approximately 2 (Gato Canyon)

to 8 (Purisima Point, Point Sal, and Bonito)

trips per month will be required. Based on a

2- to 3-month program per well, the following

miles would be traveled to each unit: Bonito -

5,712 mi, Gato Canyon - 350 mi, Purisima Point

- 2,640, Point Sal - 3,360.

• Standby boat: A standby boat will be stationed

near the delineation rig at all times during operations. It is anticipated that this boat will

be a 110-foot class vessel with a two-man crew.

The primary purpose of this vessel is emergency response in the unlikely event of an oil

spill. This vessel will not normally leave the

drill site, except for emergency situations, and

only when another vessel can act as standby.

No trips for the standby vessel are planned

other than initial mobilization and demobilization.

• Supply boats: It is expected that one 180-foot

class supply boat will be used to support the

delineation drilling operations. It is likely that

the boat will be stationed in, and operate out

of, Port Hueneme and will travel through predetermined corridors. Approximately 12 (Bonito) to 8 (Gato Canyon) trips per month will

be required. Based on a 2- to 3-month program per well, the following miles would be

traveled to each unit assuming they will originate from Point Hueneme: Bonito - 7,344, Gato

Canyon - 2,500, Purisima Point - 3,960, Point

Sal - 5,280.

• Anchor handling boats: An anchor handling

boat will deploy the anchors. The boats run

the anchor and anchor chain out to the required length, and lower the anchor onto the

seafloor using a work wire.

Offshore Transport –Helicopters. Offshore southern California, helicopters are a primary means of

transporting crew to and from the platforms. Helicopter traffic on the OCS operates primarily out of

Santa Maria, Lompoc, and Santa Barbara airports.

Most of the traffic is to and from platforms in the western Santa Barbara Channel and Santa Maria Basin.

In addition, several international and numerous

smaller airports, along with several military airfields,

exist along the southern California coast, and air traffic is a daily occurrence in the region.

Helicopter trips in support of MODU drilling

activities are expected to average 20-30 month (up to

1 per day). In comparison, about 150 helicopter trips

(5 per day) are made monthly to the four Santa Maria

Basin platforms. The Sea King, a two-engine helicopter, is expected to best represent the type of helicopters used for this program.

Because of noise and safety concerns, the Federal Aviation Administration (FAA) regulates flight

patterns. FAA Circular 91-36C encourages pilots to

maintain higher than minimum altitudes near noisesensitive areas. Corporate policy (all helicopter companies) states that helicopters should maintain a minimum altitude of 700 ft while in transit offshore and

500 ft while working between platforms and drilling

rigs. When flying over land, the specified minimum

altitude is 1,000 ft over unpopulated areas and coastlines, and 2,000 ft over populated areas and sensitive

areas including national parks, recreational seashores,

and wildlife refuges. In addition, the guidelines and

regulations promulgated by NMFS require helicopter

pilots to maintain 1,000 ft of airspace over marine

mammals.

Offshore Disturbances –Anchoring. The emplacement and anchoring/mooring of the MODU used for

the exploration of oil and gas is known to impact the

seafloor (USDOI, MMS, 1997a). Furthermore, the use

of anchors are also known to cause seafloor disturbances within the area surrounding a given structure.

Impacts on the seafloor potentially caused by the anchoring of rigs are of concern near sensitive areas

within the Proposed Action area. Regulations and miti-
5-6

Delineation Drilling Activities Offshore Santa Barbara County

gating measures should protect the sensitive resources

occurring within the Proposed Action area from potential bottom area disturbance.

The Sedco 712 rig has a mooring system designed

for a maximum of 1,600 ft of water. The rig has eight

Nippon model 4500LP 45,000-lbs anchors. The generic rig has eight 4,300’ lengths of 3” chain on board

and has access to an additional eight 1,000’ segments

of spare chain. A 3” regular die-locked and “oil rig”

welded chain weighs 89.3 lbs./ ft in air and 77.6 lbs./ft

in water.

The semi-submersible rig has two hulls upon

which it floats while being towed to the designated

location. At the designated location, the hulls are

flooded with seawater to submerge them to a depth a

little below the water’s surface to its drilling position.

Anchors will be deployed in their predetermined locations and then tested for proper tension. Typically,

the anchor is loaded onto the boat, which then motors

away from the rig. As the boat travels toward the

anchor location, chain is released to the required

length. At a position roughly half way from the rig,

the workboat begins to lower the anchor on a work

wire while continuing towards the final anchor location. Finally, the anchor is lowered to the seafloor

and the appropriate amount of tension is placed on

the chain. Surveyors will take the final location fix.

If the anchors do not hold a pretension determined by mooring calculations, tandem or “piggyback”

anchors can be used. This is done by attaching the

pendant line to the anchor shackle of another anchor

and deploying it in a manner similar to the original

anchor.

Offshore Disturbances –Space-use Conflicts.

During OCS operations, the area occupied by the

MODU, anchor cables, and safety zones is unavailable to commercial fishermen. The exploratory drilling rig will spend approximately 68-92 days on site.

Offshore Disturbances –Aesthetic Interference.

Drilling rigs placed within sight of coastal beaches,

parks, residences, and vacation lodging could cause

some disruption of an unencumbered view of the marine seascape seaward of the coastline. Impacts to

visual resources result from the presence of the MODU

within an area that is in view of the public.

Offshore Disturbances –Abandoned Bottom Debris. Bottom debris is herein defined as material resting on the seabed (such as cable, tools, pipe, drums,

and structural parts of platforms, as well as objects

made of plastic, aluminum, wood, etc.) that is accidentally lost by workers from drillships. Varying quantities of ferromagnetic bottom debris may be lost per

operation.

OPERATIONAL DISCHARGES OFFSHORE

The major operational wastes generated during

offshore oil and gas activities include drilling fluids

and cuttings. Other major wastes generated by the

offshore oil and gas industry include the following:

from drilling - waste chemicals, fracturing and acidifying fluids, and well completion fluids; deck drainage, and miscellaneous well fluids (cement, BOP fluid);

and from other sources - sanitary and domestic wastes,

gas and oil processing wastes, ballast water, storage

displacement water, and miscellaneous minor discharges. All the effluents will be regulated by the new

General National Pollutant Discharge Elimination

System (NPDES) permit (EPA, 2000a). The limitations under this permit cover a wide range of parameters including, toxicity, metals, oil and grease, chlorine, and sheens, foam and floating solids.

Drilling Muds and Cuttings. Drilling mud is

essentially water with a few basic components added

to it to increase the fluid density. Drilling mud is used

in the well bore to move drill cuttings to the surface,

control formation pressure, maintain borehole stability, prevent formation damage, and cool and lubricate

the drill bit and drill pipe.

Generic drilling fluid composition is anticipated

to be in accordance with the NPDES General Permit

currently in preparation by the EPA. The NPDES

permit limitations do not allow for discharge of free

oil, oil-based muds, or diesel oil. At this time, it is not

possible to describe the precise characteristics of the

drilling muds to be used. However, it appears that

the drilling mud will most likely be water based. Generic drilling muds typically used to drill wells similar to those proposed here are listed in each project

description (Point Sal and Purisima Point: page 4-5;

Bonito: page 2-21; and Gato Canyon: pages 4-3

through 4-4). Drilling mud may be discharged intermittently during drilling and disposed of in bulk upon

completion of the drilling program. If oil or synthetic

based muds are used they will not be permitted to be

discharged.

Drill cuttings are fragmented rock material ranging from clay to pebbles in size and are composed of

shale, siltstone, sand, limestone/dolomite and approximately one percent drilling mud. Oil contaminated

drill cuttings are proposed be transported to shore via

supply boat for disposal at a state approved disposal

site. Oil-free and cleaned drill cuttings will be disposed of in accordance with the NPDES permit requirements. Cuttings discharge volumes will be monitored and reported to the EPA.

Air Emissions. The major impact agents for air

emissions expected from the proposed activities are

emissions from equipment associated with exploratory

drilling operations (main and crane engines) and emissions from crew/supply vessels and helicopter support

for the drilling operations.
5-7

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Emissions resulting from the proposed projects

may have a potential to increase concentrations of air

pollutants onshore. The primary regulated pollutants

of concern in Santa Barbara County are oxides of nitrogen (NOx) and reactive organic compounds (ROC).

Both NOx and ROC are considered precursors to ozone

(O3) formation, for which Santa Barbara County is

presently in nonattainment. The major pollutant of

concern associated with projects of this type and duration are NOx emissions due to the extensive use of

propulsion and stationary combustion equipment.

Noise. Noise associated with the Proposed Action could result from operations related to the offshore drilling rig and service-vessel traffic (e.g., support boats and helicopters). Noise generated from these

activities can be transmitted through both air and

water, and may be continuous or transient. Offshore

drilling involves various activities that produce a composite underwater noise field. The intensity level and

frequency of the noise emissions are highly variable,

both between and among the various sources. Noise

from the proposed OCS activities may affect resources

near the activities. The level of underwater sound

depends on receiver depth and altitude, aspect, and

strength of the noise source. The time during which a

passing airborne or surface sound source can be received underwater is increased in shallow water by

multiple reflections.

Four to five delineation wells would be drilled as

a result of the Proposed Action. Drilling operations

often produce noise that includes strong tonal components at low frequencies, including infrasonic frequencies in at least some cases. Drilling noise from conventional metal-legged structures and

semisubmersibles is not particularly intense and is

strongest at low frequencies, averaging 5 Hz and 10-

500 Hz, respectively (Richardson et al., 1995).

Drillships are apparently noisier than

semisubmersibles (Richardson et al., 1995). Sound

and vibration paths to the water are through the hull

of a drillship.

Aircraft and vessel support may further ensonify

broad areas. Noise generated from helicopter and service-vessel traffic is transient in nature and extremely

variable in intensity. Helicopter sounds contain dominant tones (resulting from rotors) generally below 500

Hz (Richardson et al., 1995). Helicopters often radiate more sound forward than backward; thus, underwater noise is generally brief in duration, compared

with the duration of audibility in the air. Water depth

and bottom conditions strongly influence propagation

and levels of underwater noise from passing aircraft.

Lateral propagation of sound is greater in shallow

than in deep water. Helicopters, while flying offshore,

generally maintain altitudes above 700 ft during transit to and from the working area. A total of 264 helicopter trips are projected to occur as a result of the

Proposed Action.

Service vessels transmit noise through both air

and water. The primary sources of vessel noise are

propeller cavitation, propeller singing, and propulsion;

other sources include auxiliaries, flow noise from water dragging along the hull, and bubbles breaking in

the wake (Richardson et al., 1995). Propeller cavitation is usually the dominant noise source. The intensity of noise from service vessels is roughly related to

ship size, laden or not, and speed. Sounds from support boats range from 400 to 7,000 Hz at 120-160 dB

(USDOC, NMFS, 1984). Large ships tend to be noisier

than small ones, and ships underway with a full load

(or towing or pushing a load) produce more noise than

unladen vessels. Noise increases with ship speed,

which would usually be greater offshore. A total of

840 (approximately 2 per day) service-vessel trips are

projected to occur as a result of the Proposed Action.

Test Fluids. Fluids from delineation well testing operations will be stored in a barge brought to the

site by tug and moored with the semi-submersible drilling unit. The objective is to transfer, safely and efficiently, the test fluids to a barge that is equipped, capable, and of the appropriate size and draft for safely

entering ports along the California coast.

A tug and barge system will be used to transport

oil produced when testing the delineation wells. Under the Oil Pollution Act of 1990 requirements, barges

are required to be double hulled. The barge design

and systems would be in compliance with Coast Guard

regulations. Test fluids will be transported by barge

to the Long Beach/Los Angeles Harbor Complex or

Point Hueneme where it will be transferred to an approved refinery, used oil-handling facility, or permitted hazardous waste handling and disposal contractor.

The offloading system would offload approximately 200 to 7,500 barrels per day (depending on the

unit) to a barge moored to the semi-submersible. The

maximum capacity of the barge would be 40,000-50,000

bbls.

5.1.2 CUMULATIVE ANALYSES

The CEQ handbook entitled “Considering Cumulative Effects under the National Environmental

Policy Act” (CEQ, 1997) provides the following guidance:

NEPA documents should only consider those

past, present, and future actions that incrementally contribute to the cumulative effects

on resources affected by the proposed action.

Actions affecting other resources, or with cumulatively insignificant effects on the target

resources, do not add to the value of the analysis.
5-8

Delineation Drilling Activities Offshore Santa Barbara County

5.1.2.1 IMPACT-PRODUCING FACTORS OF

THE CUMULATIVE CASE (2002-2006)

This section identifies impact-producing factors

(IPF’s) that are associated with the potential development of those of the 36 undeveloped leases that may

be developed from existing platforms (for example,

Cavern Point, Rocky Point, and Sword Units) and any

potential future development of existing leases during

the 2002-2006 timeframe (for example Tranquillon Ridge

Unit). As discussed in section 5.1.1.1, exploring for,

producing, and transporting hydrocarbon resources

that could be developed require a complex and interrelated series of operations. The IPF’s involving the

proposed action will not be restated here. However,

the effects from those and any cumulative activities

are considered and discussed in each resource section

(5.2.1 through 5.2.24).

Impact-producing factors for past and present activities are discussed in Section 4.0.1. Table 5.1.1.1-1

shows the IPF’s that are projected to occur due to the

proposal (Delineation Drilling). The list below gives

the projects and activities which the analysts used to

ascertain the potential for cumulative impacts over

the 2002-2006 timeframe.

• Geological and Geophysical Surveys

• Development and Production activities (includes the installation of jackets, topsides, pipelines, and drilling. Production activities include

bringing the oil and gas to the surface, handling of oil and gas on the platform and sending the oil and gas to shore).

• Vessel and Helicopter Support Activities

• Produced Water

• Site Characterization Surveys for OCS Development

• Shallow Hazards Surveys

• Subsurface Investigation and Testing

• Extended reach drilling

• Pipeline installation and abandonment

• Oil spills

• Crude Oil Tankering

• Fiber Optic Data Transmission Cables

• State Tidelands Projects

• Spill Remediation

• Point and Nonpoint Source Discharges

• Commercial Fishing Activities

• Military Operations and Commercial Space

Launches

Section 4.0.1 presents a detailed discussion of

these factors for Past and Present activities and Section 5 discusses those factors as they relate to reasonable foreseeable and future activities.

Therefore, the cumulative impact analysis for the

proposed delineation drilling will focus on those resources where the proposed action contributes to the

cumulative effects.

However, in response to concerns raised in the

initial scoping stages for this document, MMS and the

Department agreed to prepare an additional analysis

outside the traditional NEPA cumulative analysis. In

July 1999, MMS made a commitment to the Governor

of California to prepare an additional analysis. Also,

in a November 12, 1999, response to Sara J. Wan, Chair

of the California Coastal Commission, the then-Secretary of the Interior committed to providing a disclosure of the “additional exploration and development

activities that the lessees are hoping to pursue, so that

authorities and the interested public will have full disclosure of the proposed actions in question.” This is

in addition to “completion of an environmental analysis of the potential impacts associated with the proposed activity, including a cumulative analysis that

takes into account changed circumstances that have

occurred since the original plan approvals.” This is

the reason for the broader (in geographic and temporal terms), cumulative analysis included in section 6

as well as the traditional cumulative analysis of the

Proposed Action through the residual effects of the

delineation drilling activities provided in this section.

5.1.2.2 REASONABLY FORESEEABLE

ACTIVITIES

The projects described in this section include

Federal OCS oil and gas projects, State Tidelands oil

and gas projects, and other energy and non-energy

activities (Military Activities, Commercial Fishing

Activities, Crude Oil Tankering, etc.). All of the

projects described are located in the vicinity of the

Santa Barbara Channel and Santa Maria Basin offshore Santa Barbara County, Ventura County, and San

Luis Obispo County. It should be noted that information on many of these projects is limited because they

are in the preliminary stages of development.

There are two categories of Reasonably Foreseeable activities:
5-9

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Table5.1.2.2-1. Federal offshore oil and gas wells expected to be drilled from existing platforms by

field.

First are activities that are ongoing and expected

to continue through the period of delineation drilling,

2002-2006.

Second are oil and gas activities that may begin

during the period of delineation drilling, 2002-2006.

ONGOING ACTIVITIES

ANTICIPATED FUTURE ACTIVITIES ON

EXISTING LEASES

Section 4.0.1 describes past and present offshore

oil and gas activities in State and Federal waters. Original recoverable reserves and peak production from

State and Federal offshore facilities is shown in figure

4.0.1-1. Production on existing State and Federal offshore facilities peaked in approximately 1969 and 1995

respectively and we assume production will continue

to decline.

Additional production from new wells would slow

the decline of production and is expected to occur over

the life of the existing facilities. Table 5.1.2.2-1 shows

the number of wells expected to be drilled by field from

existing Federal platforms. No new production wells

are expected on State Platforms with the exception of

Platform Holly (see State Tidelands below). Discharge

volumes are expected to be at or below the levels identified in table 4.0.1-7. Helicopter and vessel support is

assumed to be at or below the levels identified in table

4.0.1-5.

Operational impacts associated with the development and production of oil and gas resources from

these existing facilities have been fully analyzed, mitigated and permitted by applicable Federal, State and

local authorities.

The risk of an oil spill from the existing OCS

facilities has previously been individually and cumulatively analyzed and reviewed (section 5.1.3). Oil spill

Platform Operator Location 1

 Field Wells drilled 

2001-2006 

Wells drilled 

2007-

Decommissioning

Edith Nuevo 

Ellen 

Elly 2

Eureka 

Aera 

Huntington 

Beach 

Beta 1 1 

Gail Venoco Port Hueneme Sockeye 2 1 

Grace Venoco 0 0 

Gilda Nuevo 

Mandalay Santa Clara 

0 0 

Gina Nuevo Port Hueneme Hueneme 1 1 

Hermosa 

Harvest 

Hildago 

Arguello, Inc. Point Arguello Pt Arguello 6 6 

Habitat Nuevo Carpinteria Pitas Point 2 2 

Hillhouse 

A 

B 

C 

Nuevo Summerland Dos Cuadras 2 1 

Henry Nuevo Carpinteria Carpinteria 0 0 

Hogan 

Houchin 

POOI Carpinteria Carpinteria 5 5 

Heritage Sacate 3 3 

Heritage Pescado 0 0 

Harmony 

Hondo 

Exxon SYU 

Hondo 3 3 

Irene Torch Point Pedernales Point Pedernales 1 1 

1

 Number refers to location on Figure POCS Region with Fields 

2

 Platform Elly is an offshore processing facility to process production from Platforms E11en, Edith, and Eureka. 
5-10

Delineation Drilling Activities Offshore Santa Barbara County

response planning as required by MMS has been implemented and is currently in place. Oil spill prevention

and response efforts offshore California are coordinated

between the MMS and the California Office of Spill

Prevention and Response. Among other measures, this

coordination provides for the sharing of technical expertise in drilling, production, pollution prevention,

and other related areas of offshore operations and

safety.

There are no scheduled or anticipated oil and

gas lease sales scheduled or anticipated in Federal or

State waters. Therefore, with no new leasing, once

the development of the 36 undeveloped leases occurs

(see section 6.1.3), no additional new production platforms would be installed.

DECOMMISSIONING

Over the next 28 years all existing oil and gas

platforms in Federal and State waters are expected to

be removed (table 4.0.1-5). Some decommissioning has

already occurred. The Offshore Storage and Treatment

Vessel and Single Anchor Leg Mooring was removed

from the Santa Ynez Unit in Federal waters in 1994

and Platforms Hazel, Heidi, Hilda, and Hope were removed from State waters in 1996. No decommissioning projects are expected to occur during delineation

drilling (2002-2003).

CRUDE OIL TANKERING

Oil spills resulting from vessel collisions and

other marine transportation-related accidents have the

potential to cause significant impacts on the marine,

coastal, and human environments, and contribute to

cumulative environmental impacts. Marine transportation of Alaskan and foreign-import oil is an activity

that occurs offshore California. Table 4.0.1-8 shows

volume and number of oil tankers offshore California

visiting Ports of San Francisco and of Los Angeles/

Long Beach and El Segundo. In 2000, 877 oil tankers

visited the ports of Los Angeles/Long Beach and El

Segundo. Of these tankers, 192 were United States

flagged oil tankers and 685 were foreign flagged oil

tankers (pers. Comm., Reed Crispino, Marine Exchange, March, 2001).

The long-term oil supply outlook for California

remains one of declining in-State and Alaska supplies

leading to increasing dependence on foreign oil sources,

according to the California Energy Commission (CEC)

(1999). Since 1989, California refineries have received

about half of Alaska’s total production. If this trend

remains unchanged into the 20-year future, then supply volumes from Alaska to California would decline

by 61 percent from current levels. Although it is possible that Alaska production could increase with the

opening of new areas for development, no decisions

have yet been made. In 1998, the foreign component of

California’s oil supply represented 16 percent of total

supply - triple the amount in 1992 (CEC, 1999).

California refineries receive about half of their

total oil supplies by marine tankers. As California petroleum product demand increases and in-State crude

oil supplies decline, marine tanker deliveries will increase. Based on the CEC estimates, the rate of import growth varies between 2 to 3 percent per year,

while the total demand increases at 1 percent per year

(CEC, 1999).

The CEC (1999) estimates that import of 168 to

257 million more bbls per year are expected by 2017

based on a very gradual decline in California in-state

supply. The volume of 168 million bbls translates into

the equivalent of about 220 more oil tanker deliveries

to California ports per year in 2017, based on the use

of medium class size tankers (about 120, 000 dead

weight tons). The 257 million barrel estimate means

337 more tanker deliveries per year, about one per day.

MILITARY OPERATIONS AND COMMERCIAL

SPACE LAUNCHES

The Point Arguello Unit and Rocky Point Unit

leases are located in the Naval Air Warfare Center

Weapons Division (NAWCWD) Point Mugu Sea Range

(PMSR). The PMSR covers a 36,000 square-mile area

offshore San Luis Obispo, Santa Barbara, Ventura,

Los Angeles, Orange, and San Diego Counties. The

PMSR currently supports test and evaluation of sea,

land, and air weapons systems as well as various categories of training activities. The NAWCWD has recently proposed to expand operations in the PMSR and

has prepared a Draft Environmental Impact Statement/

Oversea Environmental Impact Statement for the proposal (U.S. Navy, 2000), which provides a detailed discussion of the operations conducted in the PMSR. The

operations include missile testing, and training exercises including fleet, amphibious, and special warfare

training. The PMSR has been operated by the Department of the Navy for more than 50 years

The Point Sal, Purisima Point, and Bonito Units

are also in the vicinity and operational area of the

Western Space and Missile Center (WSMC) at

Vandenburg Air Force Base. Space vehicles launched

at WSMC fly over various sectors of the project area.

During such overflights, the area beneath the flight

path may be subject to hazards resulting from falling

debris and jettisoned components; but such events are

extremely rare.

To minimize potential hazards and conflicts with

military operations, the MMS has placed stipulations

on the OCS leases in the project area. The stipulations control vessel traffic in designated areas, include

“hold-harmless” requirements, and reserve the right

of the United States to suspend offshore operations
5-11

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

temporarily for national security reasons. Prior to a

vehicle launch, provisions for control of air and marine traffic, stabilization of platform operations, and

for personnel shelter and evacuation measures are

coordinated by the WSMC, U.S. Coast Guard, MMS,

and the platform operators. These measures have

proven to be effective in minimizing hazards and conflicts.

COMMERCIAL FISHING ACTIVITIES

Commercial fisheries in the Southern California

Bight (SCB) and Santa Maria Basin (SMB) date back

to the mid-nineteenth century. Commercial fishing

occurs at various locations off the coast of southern

and central California. The nearshore waters along

the coast from Los Angeles to Monterey counties and

the waters just off the Channel Islands contain giant

kelp beds that provide habitats for numerous species

of commercially important fish and shellfish species.

The majority of fish are caught within these areas.

Fishes in the SCB and SMB support important

commercial and recreational fisheries; more than 100

species appear in the catches. The commercial landings at ports within the southern and central California account for about 4 percent of the total U.S. catch

(approximately 2.7 x 109

 kg, or 6 x 109 lb). Los Angeles area ports rank among the top 10 ports in the

United States in quantity and value of commercial

catch. Recreational fishermen in the SCB and SMB

land about 60 percent of the total recreational catch

in California. Fishermen on private and commercial

passenger vessels account for more than 80 percent of

the recreational catch. Recreational landings in the

SCB and SMB account for about 5 percent of the total

recreational landings in the continental United States

About 64 commercial fish and shellfish species

are fished using up to 15 gear types, the most common

of which are trawl, drift and set nets, purse seines,

traps, and hook-and-line gear. Troll gear, harpoons,

and diving are also common in certain areas of the

SCB and SMB. Many fishers of the area do not fish for

just one species, or use only one gear-type. Most switch

fisheries during any given year depending on market

demand, prices, harvest regulations, weather conditions, and fish availability. There are twelve major

ports between San Diego and Point Sur, California

which provide over 1,500 commercial fishing berths

for the commercial fleet.

POINT SOURCE DISCHARGES

Only five Publicly-Owned Treatment Works

(POTWs), or sewage treatment plants, discharge into

either rivers or the Pacific Ocean in San Luis Obispo

County. All the dischargers are small, according to

EPA criteria (less than 25 million gallons discharged

per day [mgd]). The six POTWs that discharge treated

effluent to the Santa Barbara Channel are all small

dischargers whose effluents are at a mixed primary/

secondary level of treatment (SCCWRP, 1996).

There are no other industrial wastewater discharges north of Point Conception. However, several

power plants spaced along the coastlines of southern

Santa Barbara county, and Ventura and northern Los

Angeles Counties, do discharge heated water, and some

chlorine is used to prevent fouling of heat exchangers.

NONPOINT SOURCE DISCHARGES

Urban and storm water runoff is the largest

source of unregulated pollution to waterways and

coastal areas of the United States. Locally, urban and

storm runoff results in an increase in health risks to

swimmers near storm drains, high concentrations of

toxic metals in harbor and ocean sediments, and toxicity to aquatic life.

Storm water runoff from urban areas is a major

source of pollution in the coastal waters of the SCB.

Because runoff is an untreated pollution source, it

contains high concentrations of contaminants and is

a significant health hazard to humans. The SCB has

multiple sources of nutrients, particulates and contaminants that discharge into the coastal ocean, including submerged outfalls, rivers, creeks, storm

drains, atmospheric inputs, ocean dumping, and advection (Anderson et al., 1993).

The runoff systems in southern California are

different from those in other areas because the flow is

mostly confined to the winter months. Over the dry

months, contaminants accumulate in the flow systems

and are then released as pulses when winter storms

strike. During winter storms, these drainage systems

release most of the fresh water that flows into the

coastal ocean.

GUADALUPE DILUENT SPILL AND

REMEDIATION (1998 TO 2003)

The Guadalupe Oil Field site is located on the

central coast of California approximately 15 miles

south of San Luis Obispo. It is part of the Unocal

LeRoy Lease which covers approximately 3,000 acres

within the Nipomo Dunes system, a Secretary of the

Interior-designated National Natural Landmark. The

City of Guadalupe is located approximately three miles

east of the site. Oil exploration and production began

on the site with the Sand Dune Oil Company in October 1947. Unocal acquired the field in the early 1950s

and continued to operate it until March 1990. At its

peak, in 1988, there were 215 potential producing wells.

The crude oil produced from the site was extremely

viscous, with a density that causes the crude oil to
5-12

Delineation Drilling Activities Offshore Santa Barbara County

behave like asphalt at ambient conditions. Unocal used

several methods to enhance recovery of this heavy

crude, including diluent mixing. The term diluent is

derived from “dilute” and it refers to any additive (in

this case a refined hydrocarbon blend piped into the

field from the Santa Maria refinery) that is used to

thin the crude. Over time, leaks that developed in the

tanks and pipelines used to distribute it around the

field, have led to serious contamination of the ground

water below the site. Diluent has accumulated in 64

plumes (separate-phase) at the water table in the dune

sand aquifer (about 10 to 130 feet down), with some

plumes as much as 6 ft thick. Ground water passing

through these areas, has become contaminated because

some of the diluent dissolves (dissolved-phase) into the

water and moves downstream with the ground water

flow. This has resulted in ground water contamination beneath much of the site, with a flux towards the

Pacific Ocean (to the west) and the Santa Maria River

(to the south).

Remedial activities that have already taken place

at the Guadalupe Oil Field under emergency permits

issued by the County of San Luis Obispo or the Coastal

Commission, include installation of a bentonite wall,

beach excavation, installation of an High-density polyethylene (HDPE) wall, installation of a sheetpile wall,

breaching of the Santa Maria River, installation of a

polyvinylchloride (PVC) barrier wall, the removal of a

sump, and other work. The technologies that are proposed will be used to either remove the diluent through

excavation, bioremediation or pumping, or contain the

diluent through physical or hydraulic barriers. Unocal

has also proposed to abandon the site. This would include removal of most pipelines from the field, and all

surface facility tanks, buildings and other miscellaneous equipment.

AVILA BEACH TANK FARM SPILL AND

REMEDIATION (1997 TO 2002)

The community of Avila Beach, California is located on the northern end of San Luis Bay near Point

San Luis. The Unocal Avila Terminal facility has been

used for petroleum hydrocarbon storage and transfer

activities since 1910. Petroleum products, including

gasoline, diesel, fuel oil and crude oil, were pumped

from the tank farm located on a bluff overlooking the

town through a network of underground pipelines

beneath Front Street to Avila Beach Drive and over

the San Luis Obispo Creek bridge to the Unocal pier.

In addition, gasoline and diesel fuel were pumped from

tankers to the tank farm for distribution to county

consumers. Unocal has spilled petroleum products

including: gasoline, diesel and crude oil to soil and

ground water beneath the beach, roads, commercial

and residential properties of Avila Beach. These spills

were reportedly caused by historic leaks from Unocal’s

pipelines and possibly the tank farm. Five pipelines

are currently active, and another 5 to 10 lines are abandoned in place under Front Street. There are no known

leaks in the active pipelines at this time. Unocal has

not used these pipelines since the summer of 1996.

Unocal’s remediation efforts are divided into four

main areas of concern: the beach, which is divided into

the west and east beaches; under Front Street; north

of Front Street, and the intertidal plume. All four areas have underground gasoline-grade, diesel-grade, and

crude or residual-grade hydrocarbon contamination.

The hydrocarbons are found both above and below

ground water, are attached to the soil grains (sand

and silt) and within the soil pore spaces. Over 460 soil

borings and 70 monitoring wells were taken and analyzed by various agencies. Levels of hydrocarbon contamination exceeded those found to cause cancer, reproductive toxicity, and other acute and chronic health

problems.

Legal efforts on the part of local activist groups,

joined by the California Attorney General’s office, and

the Regional Water Quality Control Board, the County

of San Luis Obispo produced an agreement that will

require Unocal to fully remediate the contamination

and rebuild the town and economy of Avila Beach.

Unocal’s remediation project includes two general aspects: excavation of all petroleum contamination under the beach, Front Street, and all areas where contamination exceeds 100 parts per million, and excavation and removal of the petroleum, and replacement

with new, clean soil and nutrients. Monitoring and

sampling, including testing of groundwater four times

a year will help ensure the project meets State standards.

FIBER OPTIC DATA TRANSMISSION

CABLES

The timing of fiber optic cable installation is unknown, however the operations are expected to be conducted in the period 2001-2003.

Global West (Global Photon) Fiber Optic Cable

Project

Global West is a proposed fiber optic telecommunications project that would link major metropolitan

areas along the California coast using buried undersea cable. The cable would contain seven landfalls including San Francisco, Monterey Bay North,

Monterey Bay South, San Luis Obispo, Santa Barbara, Manhattan Beach and San Diego. The currently

proposed routing of this cable is through a portion of

the Sword Unit.
5-13

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

MCI Worldcom Fiber Optic Cable Project

The MCI Worldcom fiber optic cable project is

proposed to consist of five cables that will be landed at

the Montana de Oro State Park landing site. These

cables would land through new directional bore pipes

constructed adjacent to the AT&T landing. Currently

only three of the five cables would be installed, the

remaining two to be installed once demand requires.

PAC Landing Corp (Tyco/Global Crossing)

Fiber Optic Cable System

The proposed PAC Landing Corp fiber optic cable

project entails the offshore landing of three cables and

consolidation of cables into one line extending to a

telecommunications switching facility located in the

City of Grover Beach. The telecommunications facility has already been constructed. Three cables would

be installed in State waters, two of which would be

part of the Pacific Crossing Submarine Cable (PC-1)

System and the third cable would be part of the PanAmerican Crossing Submarine Cable System (PAC).

The Grover Beach landing site would provide a connection for cable originating in Japan and proceeding

to Washington State. The site would also be the Pacific origin of the PAC Cable System, which would proceed to Mexico from Grover Beach.

AT&T China-U.S. Cable E1 and China-U.S.

Cable S7 Systems

The AT&T China/U.S. fiber optic cable project

is proposed to consist of two cables that will be landed

at the Montana de Oro State Park landing site. The

two cables will be housed within the last remaining

directional bore pipe constructed by AT&T in 1992.

The China-U.S. Cable E1 cable is proposed to follow

an alignment that is located north of the AT&T TPC5 Segment T1 cable. The China-U.S. Cable S7 cable is

proposed to follow an alignment located between the

AT&T TPC-5 Segment T1 and AT&T HAW-5 cables.

Installation of this system was scheduled to begin in

2000 but it is not known when the project will take

place.

Oil And Gas Activities That May Begin During

Delineation Drilling

The following oil and gas activities may begin

during delineation drilling (2002-2003) and include

Federal Offshore OCS Projects; Cavern Point Unit Exploration, development of some of the 36 undeveloped

leases including Rocky Point Unit, Sword Unit, and

Cavern Point Unit leases, Exploration Well Abandonment, OCS-P 0320 #2, Exploration Well Abandonment,

OCS-P 0241 #2, and State Tidelands Projects; the

Tranquillon Ridge Project, the South Elwood Project,

the Cojo Point Project, and the Molino Gas Project.

FEDERAL OFFSHORE OCS PROJECTS

Cavern Point Unit Exploration: 2002-2003

Venoco Inc. (Venoco) is the current operator of

the Cavern Point Unit. The unit includes Leases OCSP 0210 and 0527 in the Santa Barbara Channel offshore Ventura County. The Cavern Point Unit is

bounded by the Channel Islands National Marine

Sanctuary on the south and the producing Santa Clara

Unit on the north and east. Up to two exploratory

wells are planned to be drilled into the unit from Platform Gail (Santa Clara Unit). Drilling, evaluating, and

(if appropriate) abandoning the first well will occur

during the third and fourth quarters of 2002 and take

approximately 100 days. No construction of either offshore or onshore facilities is proposed. If the exploratory wells find hydrocarbons in the Cavern Point

Unit, they will serve as the basis for planning and

future evaluation of potential development. According

to current scenarios, oil and gas would be transported

from Platform Gail via existing pipeline to Platform

Grace, then onshore to the Carpinteria facility. Gas

also would be transported to shore via existing pipeline.

Rocky Point Unit Development (2002-2013)

Arguello Inc. is the current operator of the Rocky

Point Unit. The Rocky Point Unit includes Leases

OCS-P 0451, 0452, and 0453 in the southern Santa

Maria Basin. Twenty development wells, 14 oil wells

and 6 service wells, would be drilled from Platforms

Harvest, Hermosa, and Hidalgo. Seven wells each

would be drilled from Platforms Harvest and Hermosa

and six from Platform Hidalgo. The wells would be

extended-reach wells with horizontal displacements of

4.6-6.4 km (2.5-3.5 miles). Drilling each well would

require 3 to 4 months beginning in 2002.

Oil would be dehydrated and stabilized on the

platforms, then sent to the Gaviota facility via the

PAPCO pipeline. At Gaviota, the oil would be metered

and heated, stored temporarily in the Gaviota Terminal Company storage tanks, then transported via the

All-American Pipeline to various refining destinations.

Rocky Point gas would be sweetened on the platforms and used 1) to generate electricity and heat for

platform operations, 2) sent to shore to fuel the Gaviota

co-generation units, and 3) injected into the Point

Arguello Field, the Rocky Point Field or both.
5-14

Delineation Drilling Activities Offshore Santa Barbara County

Sword Unit Development (2002-2014)

Samedan Oil Company (Samedan) is the current

operator of the Sword Unit. The Sword Unit includes

leases OCS-P 0319, 0320, 0323, and 0323A. A portion

of lease OCS-P 0323 has been relinquished and the

remaining lease was redesignated 0323A to reflect the

change. Eleven development wells, 10 oil wells and 1

service well would be drilled from Platform, Hermosa,

OCS-P 0316. The wells would be extended-reach wells

with horizontal displacements of 6.4-8.3 km (3.5-4.5

miles). Drilling each well would require 3 to 4 months

beginning in 2002.

Oil would be dehydrated and stabilized on the

platforms, then sent to the Gaviota facility via the

PAPCO pipeline. At Gaviota, the oil would be metered

and heated, stored temporarily in the Gaviota Terminal Company storage tanks, then transported via the

All-American Pipeline to various refining destinations.

Sword gas would be sweetened on Platform

Hermosa and used 1) to generate electricity and heat

for platform operations, 2) sent to shore to fuel the

Gaviota co-generation units, and 3) injected into the

Point Arguello Field.

Cavern Point Unit Development (2003-2015)

The Cavern Point Unit includes Leases OCS-P

0210 and 0527 north of Santa Rosa Island in the Santa

Barbara Channel. Eleven development wells, 10 oil

wells and 1 service wells, would be drilled from Platform Gail. The wells would be extended-reach wells

with horizontal displacements of 6.4-8.3 km (3.5-4.5

miles). Drilling each well would require 3 to 4 months

beginning in 2003. The service well would be drilled

into the Sockeye Field and would not be an extended

reach well.

The oil and gas would be sent to the Carpenteria

onshore processing facility via Platform Grace using

existing pipelines. The gas sent to shore would be sour

and that there would be limited processing offshore.

The oil and gas would be processed using existing capacity. Produced water is injected or disposed overboard.

EXPLORATION WELL ABANDONMENT, OCSP 0320 #2 (2003)

Well OCS-P 0320 #2 was drilled and temporarily

abandoned in 1985. Samedan proposes to permanently

abandon well OCS-P 0320 #2. The well would be abandoned using the Mobile Offshore Drilling Unit

(MODU) used for delineation drilling after the delineation drilling operations have been completed.

Sequence of activities is as follows; 1) the MODU

would anchor over the well, 2) the well would be entered and temporary plugs removed, 3) permanent cement plugs would be placed, 4) the wellhead and casing would be removed, and 5) anchors removed and

the MODU moved offsite. Samedan estimates 11 days

to conduct abandonment activities.

EXPLORATION WELL ABANDONMENT, OCSP 0241 #2 (2003)

Torch Operating Company proposes to permanently abandon well OCS-P 0241 #2. The well was

drilled and temporarily abandoned in 1968. The well

would be abandoned using a MODU after delineation

drilling have been completed.

Sequence of activities is as follows; 1) the MODU

would anchor over the well, 2) the well would be entered and temporary plugs removed, 3) permanent cement plugs would be placed, 4) the wellhead and casing would be removed, and 5) anchors removed and

the MODU moved offsite. It would likely take 11 days

to conduct abandonment activities.

STATE TIDELANDS PROJECTS

Molino Gas Project (2001 and 2005)

Molino Energy Company gained approval for the

project from the County of Santa Barbara in 1996.

The project involves use of ERD technology from an

onshore site to recover sweet gas reserves in offshore

State Tidelands. The drilling site is located just east

of the Gaviota facility. It was initially envisioned that

the project could produce up to 60 MMcfd of sales quality sweet gas and up to 1,050 BPD of natural gas liquids (NGL)s over a project life of 20-25 years. The gas

would be sold to SoCal Gas and transported directly

into the transmission line. The NGLs would initially

be trucked to the Gaviota facility and later shipped to

the facility via a new pipeline. The ERD wells that

have been drilled to date have not been successful and

exploratory drilling ceased in 1998.

Benton Oil and Gas Company assumed all project

responsibilities in 2001. Benton plans to drill 3-6 exploration wells between 2001 and 2005.

Cojo Point Project (2002-2003)

The County of Santa Barbara has received a preliminary application from Union Oil of California to

proceed with the decommissioning of the marine terminal facility and associated oil storage tanks that

are no longer in use at Cojo Point. Cojo Point is located along the northern margin of the Santa Barbara Channel, just east of Point Conception. Details

regarding the project are not available at this time.
5-15

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

TRANQUILLON RIDGE PROJECT (2003-2030)

Nuevo Energy Company (Nuevo), is seeking approval to develop the Tranquillon Ridge area offshore

Point Pedernales in the southern Santa Maria Basin

from an existing OCS platform, Platform Irene. Platform Irene is located on Lease OCS P-0441, approximately 6 miles northwest of Point Pedernales. State

and local agencies are preparing an Environmental

Impact Report (EIR) on the proposed project. The California State Lands Commission’s decision on the

project will be contingent in part upon the EIR, and

its decision to grant a State Tidelands lease for the

project.

Current operations at Platform Irene include

drilling and production of the Federal Point Pedernales

Field, transportation of production via pipeline from

offshore to onshore, and oil dehydration and gas processing at the Lompoc processing facility. One well

from Platform Irene is producing from Tranquillon

Ridge. Processed oil is transported by pipeline to refineries. Liquefied petroleum gas and NGLs are shipped

by truck. The Lompoc facility is currently permitted

to operate under a County of Santa Barbara FDP. The

permitted production and processing capacities are

36,000 BPD oil and 15 MMcfd of gas.

The proposed Tranquillon Ridge Project would

involve the drilling of up to 30 Extended Reach Drilling (ERD) wells (22 development wells and 8 utility

and re-drills) from Platform Irene into State Tidelands.

Total well drilling and completion times are anticipated

to range between 60 and 120 days per well. Oil and

gas produced by the proposed project would be transported to shore via the existing pipeline system to the

Lompoc processing facility.

The Tranquillon Ridge project would extend over

approximately 15 years. Nuevo estimates that the

project will recover 180-200 MMbbl of oil and 40 Bcf

of gas.

5.1.3. OIL SPILLS: RISK, MOVEMENT, AND

RESPONSE

The purpose of this Section is to provide the

reader with information regarding oil spill risk, movement of spilled oil on water, and the sources of petroleum hydrocarbons (PHC’s) to the sea. Other topics

discussed include, how oil changes when it is spilled

on water, responses to oil spills, and how various organizations respond to oil spills and the tools they

have available in the “response tool box”.

5.1.3.1.OIL SPILL RISK ASSESSMENT

A major environmental concern with offshore oil

and gas activities is the potential for oil spills and the

resulting effects on biological resources, such as listed

species. The largest oil spill in the Pacific OCS Region occurred in 1969, when a well blowout on Platform A off Santa Barbara spilled an estimated 80,000

bbl into the Channel (Van Horn et al., 1988). A number of preventive measures have been initiated since

that time, including stringent regulations covering

OCS operational and environmental safety, a rigorous

MMS inspection program in the Pacific Region, continuous evaluation and improvement in OCS facilities’

oil spill response, and the development of a highly organized oil spill response structure (Bornholdt and

Lear, 1997). No spill of this magnitude has occurred

anywhere on the U.S. OCS since 1969, and these measures make a reoccurrence a highly unlikely event.

Table 5.1.3.1-1 lists the hydrocarbon spills that

occurred in the Pacific OCS Region from OCS oil and

gas activities from 1969 through 1999. During that

period, 843 oil spills were recorded. The total volume

of oil spilled in the Region is dominated by the Santa

Barbara spill. Since 1969, these spills have ranged in

size from less than 1 to 163 bbl, for a total of slightly

less than 830 bbl. For comparison, natural oil seeps

at Coal Oil Point in the Santa Barbara Channel are

estimated to discharge approximately 100-170 bbl of

oil per day (Hornafius et al., 1999).

In the course of normal, day-to-day platform operations, occasional accidental discharges of hydrocarbons may occur. Such accidents are typically limited to discharges of quantities of less than 1 bbl of

crude oil. As shown in table 5.1.3.1-1, 836 spills of

less than 50 bbl (99 percent of the total) occurred on

the Pacific OCS between 1971 and 1999, resulting in

slightly less than 320 bbl of oil being discharged into

the ocean. Due to the infrequency and small volumes

of these accidental discharges, spills of less than 50

bbl are not considered to be a significant impact-producing agent for the majority of marine and coastal

resources discussed in this document.

Larger oil spills may occur from well blowouts

(if wells are free flowing), pipeline breaks, operational

errors, or vessel-platform collisions. Only 5 of the 45

total spills (since 1969) of greater than 1 bbl measured

50 bbl or more in volume (table 5.1.3.1-1); the largest

of these was the 163-bbl Platform Irene pipeline spill

in September 1997.

5.1.3.1.1. ESTIMATED SPILL RISK FOR THE

PROPOSAL

The proposal for delineation drilling of 4 to 5

wells involves minimal risks of an oil spill. Tables

5.1.3.1-2 and 5.1.3.1-3 indicate less than a 0.05 percent probability of one or more spills from delineation

drilling (the lowest value calculated by MMS spill data).

Oil spills during exploration or delineation drilling of

wells from mobile drilling platforms are very rare

events according to the MMS and Coast Guard data
5-16

Delineation Drilling Activities Offshore Santa Barbara County

base. Wells drilled during the exploration and delineation phases of oil and gas activity tend to be drilled

and plugged quickly with little exposure to the large

volume of oil or gas processed through the well bores

during production. In addition, special precautions

are taken to stop the drilling at regular intervals to

monitor well pressures at each production zone. The

exploration and delineation well is plugged according

to MMS regulations immediately after the well has

been drilled and tested. Therefore the risk of a spill is

considered to be minimal and poses almost no risk to

the marine environment. Spills during delineation

drilling for these proposed projects are not considered

further in the spill risk assessment. However, the effects of three size classes of oil spills are analyzed in

the cumulative section of this EIS and in the section

below on the possible length of shoreline that could be

oiled by each.

Barging of Well Testing Fluids. The Proposed

Action involves the transport by barge of the fluids

pumped from the four to five delineation wells to be

drilled. These fluids are generally crude oil of various

viscosities (depending upon the location and stratum

being tested) combined with water present in most oil

formations or other fluids injected into the well to allow thick crude oil to flow. The fluids are pumped

from the mobile drilling vessel at intervals to test the

flow rate of the well and then the wells are plugged

according to MMS regulations at the end of the testing. Volumes of fluids associated with well testing for

the proposed wells are less than approximately 50,000

bbl of combined oil and other fluids. Calculating the

probability of a spill from the Proposed Action (based

upon barging spill rates for coastal United States waters) yields an extremely low probability of < 0.05 percent for one or more spills. Therefore, oil spills of the

testing fluids associated with the proposal are considered an extremely low risk and are not considered in

the proposed project assessment.

5.1.3.1.2. ESTIMATED SPILL RISK FOR THE

CUMULATIVE ANALYSIS

MMS has estimated the mean number of oil spills

and probability of one or more spills for two spill size

ranges (50 to 999 bbl; and greater than or equal to

1,000 bbl) that could occur as a result of reasonably

foreseeable cumulative actions in the region of the

proposal (tables 5.1.3.1-2 and 5.1.3.1-3). Based on a

Table 5.1.3.1-1. Crude, diesel, or other hydrocarbon spills recorded in the Pacific

OCS Region, for OCS oil and gas activities, 1969 through 1999 (volumes in barrels).

 Less than or Greater than 1 bbl Equal to or More Total 

 equal to 1 bbl less than 50 bbl than 50 bbl

Year No. Volume No. Volume No. Volume No. Volume 

1969 0 0 2 80,900.0 2 80,900.0 

1970 0 0 0 0 

1971 0 0 0 0 

1972 0 0 0 0 

1973 0 0 0 0 

1974 0 0 0 0 

1975 1 0.1 0 0 1 0.1 

1976 3 1.1 1 2.0 0 4 3.1 

1977 11 2.2 1 4.0 0 12 6.2 

1978 4 1.2 0 0 4 1.2 

1979 5 1.7 1 2.0 0 6 3.7 

1980 11 4.9 2 7.0 0 13 11.9 

1981 21 6.0 10 75.0 0 31 81.0 

1982 24 3.2 1 3.0 0 25 6.2 

1983 56 7.7 3 6.0 0 59 13.7 

1984 65 4.7 3 36.0 0 68 40.7 

1985 55 9.3 3 9.0 0 58 18.3 

1986 39 5.5 3 12.0 0 42 17.5 

1987 67 7.5 2 11.0 0 69 18.5 

1988 47 3.7 1 2.0 0 48 5.7 

1989 69 4.1 3 8.0 0 72 12.1 

1990 43 3.6 0 1 100.0 44 103.6 

1991 51 5.8 1 10.0 1 50.0 53 65.8 

1992 39 1.2 0 0 39 1.2 

1993 32 0.7 0 0 32 0.7 

1994 18 0.4 2 33.0 1 50.0 21 83.4 

1995 25 0.9 1 1.4 0 26 2.3 

1996 39 0.9 1 5.0 1 150.0 41 155.9 

1997 20 2.5 0 1 163.0 21 165.5 

1998 29 1.0 0 0 29 1.0 

1999 22 0.5 1 10.0 0 23 10.5 

Totals 796 80.4 40 236.4 7 81,413.0 841 81,729.8 
5-17

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Table 5.1.3.1-2. Spill Risks 50 – 999 Barrels.

p

Estimated Mean Number 

of spills: 50 - 999 bbls 

Probability of One 

or More Spills (%) 

Proposal (4-5 Delineation Wells) (2002-2006) None Less than 0.05 

Cumulative w/o Proposed Action (2002-2006) 

Existing Federal Oil and Gas Development 

Existing State Oil and Gas Development 

Proposed Federal (Rocky Pt, Cavern Pt., 

Sword) Oil and Gas Development 

Proposed State (Tranquillon Ridge) Oil and 

Gas Development 

Total Risk (less Tankering)

Alaskan and Foreign Tankering (Crude Oil) 

0.97 

0.25 

0.12 

0.08 

1.42

NA1 

62.1 

23.2 

11.4 

 7.7 

75.9

99 

Cumulative w/o 36 undeveloped leases (2002-2030) 

Existing Federal Oil and Gas Development 

Existing State Oil and Gas Development 

Proposed State (Tranquillon Ridge) Oil and Gas 

Development 

Total Risk (less Tankering)

Alaskan and Foreign Tankering (Crude Oil)1

2.96 

0.49 

1.55 

5.0

NA 

94.9 

38.8 

78.8 

99

99 

Development of 36 leases (incl. Rocky Pt., Cavern 

Pt., Sword) 

Most likely case (0.558 Bbls) 

High Case (0.660 Bbls) 

4.35 

5.115 

98.8 

99 

1 Spills less than 1000 barrels not recorded in database. 

 Estimated Mean Number 

of spills: >1,000 bbl 

Probability of One 

or More Spills (%) 

Proposal (4-5 Delineation Wells) (2002-2006) None Less than 0.05 

Cumulative w/o Proposed Action (2002-2006) 

Existing Federal Oil and Gas Development 

Existing State Oil and Gas Development 

Proposed Federal (Rocky Pt, Cavern Pt., 

Sword)) Oil and Gas Development 

Proposed State (Tranquillon Ridge) Oil and 

Gas Development 

Total Risk (less Tankering)

Alaskan and Foreign Tankering (Crude Oil) 

0.173 

0.044 

0.021 

0.014 

0.252

0.99 

15.9 

 4.4 

 2.1 

 1.4 

23.3

63.9 

Cumulative w/o 36 undeveloped leases (2002-2030) 

Existing Federal Oil and Gas Development 

Existing State Oil and Gas Development 

Proposed State (Tranquillon Ridge) Oil and 

Gas Development 

Total Risk (less Tankering)

Alaskan and Foreign Tankering (Crude Oil) 

0.53 

0.087 

0.276 

0.893

5.742 

41.2% 

 8.4 

24.2 

59.1

99 

Development of 36 leases (incl. Rocky Pt., Cavern 

Pt., Sword) 

Most likely case (0.558 Bbls) 

High Case (0.660 Bbls) 

0.774 

0.911 

53.9 

59.8 

1

Spills of 10,000 bbl or greater are a subset of spills of 1,000 bbl or greater. 

Table 5.1.3.1-3. Spill Risks Greater than 1000 Barrels.1
5-18

Delineation Drilling Activities Offshore Santa Barbara County

larger spill data set from the U.S. OCS (MMS, unpubl.

data) and cumulative oil production figures, these estimated mean number of spills and the probability of

one or more spills were calculated using the method of

Anderson and LaBelle (1994). In addition, table 5.1-1

(appendix 5.1) lists the estimated risks of spills 50 to

999 bbls and greater than or equal to 1,000 bbls for

individual units and fields. Oil spill estimates are based

on the estimated production of oil over the life of the

proposed projects, with subsea pipeline transport of

hydrocarbons to shore.

The mean size of an oil spill from Alaskan and

foreign tankers is statistically larger than the mean

spill size from a platform or pipeline. In the discussion of spill sizes below, the largest spill size analyzed

(22,800 barrels) is from a hypothetical tanker spill and

is based upon the mean tanker spill size in the database.

Estimated Most Likely Spill Size

An effort also was made to estimate the most

likely size of a spill. The MMS’s U.S. Oil Spill Database (C. Anderson, unpubl. data) includes Pacific and

Gulf of Mexico OCS spills of greater than 1.5 bbl recorded between 1971 and 1999. The database contains

platform and pipeline spills, but no barge or tanker

spills. Of the 2,125 total spills in the database, 106

are in the range of 50-999 bbl. The mean volume of

these spills is 158.6 bbl, and 75 percent (79) are of less

than 200 bbl. More than 95 percent (101) are of less

than 500 bbl. Given these data and the experience in

the Pacific Region over the last 30 years and nationally over the past 15 years, it seems reasonable to assume that such a spill would probably be less than

200 bbl, and almost certainly less than 500 bbl in volume.

The most likely maximum size of a major oil spill

from future development – the maximum most probable discharge – 2,000 barrels, is based upon the volumes of oil in various pipelines and vessels (i.e., tanks

and other containers on platforms) as described in the

U. S. Coast Guard Area Contingency Plans for oil spill

response (e.g., USCG, 1999). This is the maximum

volume of oil calculated to be spilled from a break in

the longest Point Arguello Unit pipeline, the Hermosa

to shore pipeline (A. D. Little, 2001).

In addition to possible spills from oil and gas

platforms and pipelines, spills can originate from Alaskan and foreign tankers and other shipping activities

in the area. It is obvious from the estimated mean

number of spills and the probability of one or more

spills given in the tables above, that the greatest risk

of an oil spill in the area comes form these tanker and

shipping vessels. The mean (average) spill size derived from the U.S. Coast Guard data base for accidents in U.S. Waters is 22,800 barrels for the period

1985 – 1999 and the median spill size is 5,600 barrels.

This EIS analyzes potential environmental effects

of three sizes of spills based upon the discussion above:

200 barrels, 2,000 barrels, and 22,800 barrels. These

spill sizes correspond to the most likely spill size from

the proposed and cumulative oil and gas activities; the

maximum reasonably foreseeable spill size from the

proposed and cumulative oil and gas activities; and

the mean spill size for a tanker spill.

The level of impacts from spills will depend on

many factors, including the type, rate, and volume of

oil spilled and the weather and oceanographic conditions at the time of the spill. These parameters would

determine the quantity of oil that is dispersed into the

water column; the degree of weathering, evaporation,

and dispersion of the oil before it contacts a shoreline;

the actual amount, concentration, and composition of

the oil at the time of shoreline or habitat contact; and

a measure of the toxicity of the oil. The estimate of

the maximum reasonably foreseeable volume of an oil

spill (2,000 bbls see paragraph above) from oil and

gas operations used in this analysis suggests that oil

is unlikely to remain in the water (beyond dispersed,

weathered tar balls) in appreciable amounts for more

than ten days. Therefore, a ten-day oil-spill trajectory analysis was used to establish the primary geographic boundaries for the EIS. In addition, primary

environmental impacts are based upon an oil spill

reaching a resource within ten days after the spill.

ESTIMATED OF LENGTH OF AFFECTED

COASTLINE

Estimating the length of coastline that may be

affected by an oil spill is necessary to determine potential impacts by oil spills on resources considered in

the EIS. The following discussion provides information on the empirical methods used to determine this.

Using the multiple regression equations developed by

Glenn Ford (Ford, 1985; Ford and Bonnell, 1987), an

attempt was made to estimate the length of coastline

that might be contacted by spill sizes indicated in the

section above.

The equation used is: log (COAST) = -0.8357 +

0.4525 log (VOL) + 0.0128 (LAT) + ZS

-where COAST is the length of coastline contacted in kilometers,

-VOL is the spill volume in barrels,

-LAT is the spill latitude and

-Z is a correction factor applied to S the standard deviation of the residual variation.

This version of the equation explained 64.8 percent of the total variance. Inclusion of additional variables for wave height (WAVE), wind speed (WIND), or

sea surface temperature (TEMP) did not significantly

improve the fit of the equation. Ford (1985) felt that
5-19

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

the variable LAT obtained at least some of its predictive power from its high intercorrelation with the

WAVE, WIND, and TEMP variables. It should be noted

that this model does not account for weathering, cleanup efforts, or any other complicating factors.

Example

If VOL = 2,000 bbl and LAT = 34.5 (the approximate latitude of Point Conception), then:

log (COAST) = -0.8357 + 0.4525 log (2,000) +

0.0128 (34.5) = 1.09

Hence, COAST = 12.3 kilometers. This represents the median length of coastline that spills of this

volume would be expected to contact.

Using the same methodology, the maximum number of kilometers of coastline affected was estimated

for three spill sizes and five levels of probability (table

5..1.3.1-4):

Thus, for the 200-bbl spill, only 5 percent of the

spills would be expected to contact more than about

18 km (11.2 mi) of shoreline, 25 percent more than 8

km (5.0), and so on.

The estimates above for the length of shoreline

that may be affected by a hypothetical oil spill are based

upon a statistical analysis (multiple linear regression

of spill size, length of shore oiled, and various environmental factors) of historical spills. These estimates

are used by EIS analysts in conjunction with the results of the oil spill trajectory analyses (section 5.1.3.2,

below) and the probability of spills of three size categories to discuss the potential impacts to marine resources. In the case of the largest spill category, 22,800

bbl mean spill size from tankering, the length of coastTable 5.1.3.1-4. The probability of an oil spill

contacting the coastline for various spill sizes

and the length of coastline contacted.

line and probability of shore contact may be overestimated. This is because oil tankers have voluntarily

agreed to transit the coast at a minimum distance of

80.6 km (50 mi) for the past few years. Therefore, a

spill from a tanker would most likely begin at a point

distant from land. This is not reflected well in the

existing data base of oil spills (thus biasing the shoreline length analyses) and probability of shoreline contact (because the oil spill trajectory analyses do not

take into account oil weathering or other processes

which act to reduce the amount of oil with time.)

5.1.3.2 CONDITIONAL OIL SPILL RISK

ANALYSIS

The probabilities presented in this analysis are

in the conditional context that assumes an oil spill

has occurred for the cumulative impact analysis. As

stated above, no oil spills are assumed for the proposed delineation wells. However, for the cumulative

analysis, we assume a 200 bbl oil spill to be the most

likely case, and a 2000 bbl spill to be the maximum

most probable discharge (see section above). We then

address the issue of resources impacted if either of

these scenarios do occur. To do this we look at two oil

spill models and a surface current data set assuming a

spill did occur. The three analyses described below

provide estimates of oil spill trajectory and potential

landfall. They include MMS’s Oil Spill Risk Assessment (OSRA) Model calculation, an analysis of 306

free-floating surface drifter trajectories deployed by the

Scripps Institution of Oceanography (Scripps), and the

National Oceanic and Atmospheric Administration’s

(NOAA) “General NOAA Oil Modeling Environment”

(GNOME) oil spill model. These three analyses indicate a similar area of possible oil contact to the south.

When the winds are relaxed for an extended period of

time, the drifter data shows that oil can be transported

north along the coast. Use of these three analyses is

a conservative approach to identifying the possible area

of oil contact for the Pacific Region. The summary of

results of this composite analysis is presented in this

section. A more detailed presentation of the three separate analyses can be found in appendix 5.2 Conditional

Oil Spill Risk Analysis.

The MMS OSRA Model analysis calculates numerous trajectories from pre-designated launch points

by combining observed wind data with seasonally-averaged ocean current fields and applying a local wind

effect to estimate the movement of oil over the surface layer of the water. The seasonally averaged current fields were provided by Scripps Institution of

Oceanography (Scripps) and are based on several years

of current meter and free-floating drifter data. ShoreSpill Size 

(bbl) 

Probability of 

Contacting a Length 

of Coastline (%) 

Length of 

Coastline 

Contacted (km) 

200 95 

75 

50 

25 

5 

1.04 

2.45 

4.43 

8.01 

18.9 

2000 95 

75 

50 

25 

5 

2.84

6.76 

12.3 

22.4 

52.5 

22,800 95 

75 

50 

25 

5 

8.87 

20.89 

37.84 

68.4 

161.4 
5-20

Delineation Drilling Activities Offshore Santa Barbara County

line segments are partitioned into their USGS Quad

maps, and probabilities of oil spill landfall for each

shoreline segment are calculated. Offshore boxes giving probabilities of oil spill intrusion into their defined region are presented as part of a more comprehensive regional OSRA Model analysis contained in

OCS Report MMS2000-057. Oil spill size or weathering (evaporated or dispersed) are not modeled in the

OSRA analysis to allow for a maximum estimate of

spill travel times and extent. Results for OSRA Model

runs for the nine launch points listed in table 5.1.3.2-

1 are included as part of the composite analysis presented in subsection 5.1.3.2.2 Oil Spill Trajectory

Analyses.

The free-floating surface drifters were designed

to follow the surface current (top 1 meter of the water

column) and not to track or mimic an oil spill. However, the drifter analysis provides good information

on surface currents, which are one of the major component determining spill movement, by describing statistics on actual trajectories of free-floating surface

drifters. When the winds are relaxed, or in areas where

local winds do not dominate, drifter trajectories could

mimic the movement of an oil spill. For example, the

drifter trajectories indicate that when the winds are

relaxed, oil could be transported north along the coast.

A description of the surface drifters and their deployment strategy is found along with a more detailed presentation of comprehensive drifter analysis in appendix 5.2 Conditional Oil Spill Risk Analysis, appendix

subsection 5.2.3. Surface Drifter and GNOME Model

Data and Analysis. The drifter analyses consists of

analyses done specifically for the Lion Rock and San

Ynez Units, and drifter analyses previously written

for the Rocky Point and Cavern Point projects that

apply well to the Point Arguello and Santa Clara Units,

and Platform Hillhouse located in the northeastern

Santa Barbara Channel. These latter drifter analyses

Table 5.1.3.2-1. Launch point locations for GNOME and OSRA analyses.

are entitled: “Surface Drifter Analysis for the Rocky

Point Unit Project Oil Spill Risk Assessment” and

“Surface Drifter Analysis for the Cavern Point Unit

Project Oil Spill Risk Assessment.” The drifter analyses completed for the Lion Rock and San Ynez Units

were done for each of the three flow regimes characteristic of the Santa Barbara Channel-Santa Maria

Basin (SBC-SMB) area. The free-floating drifter

launch points are illustrated in figure 5.1.3.2-1. Examples of drifter plots for each of these three flow regimes can be found in figures 4.4-12a and b, 4.4-13a

and b, and 4.4-14a and b. The drifter analyses previously written for the Rocky Point and Cavern Point

projects were done according to seasonal months coinciding with those of the MMS OSRA Model analysis

performed for those same projects.

The GNOME analysis was run according to the

environmental forcing and criteria for winds and currents described in Section 4.4 Physical Oceanography,

subsections 4.4.4.4 to 4.4.4.7. Calculations were performed for 200 and 2000 bbl spills at each of the nine

launch points listed in table 5.1.3.2-1. Over 180

GNOME model runs were conducted. As is the case

for part of the drifter analysis, GNOME model results

were generated for the three major flow regimes described in Section 4.4: Relaxation, Convergent, and

Upwelling. Scripps provided synoptic current fields

for the GNOME model that were derived by averaging

surface current observations by dominant flow regime

rather than over time, such as the seasonal averages.

This means that the GNOME Model output for each

run gives trajectory results specific to one of the three

characteristic flow regimes that occur in the SBC-SMB

area. The synoptic current fields for these three flow

regimes were based on five years of concurrent moored

current data and free-floating drifter trajectories. Synoptic current fields, used by the GNOME model, for

the relaxation, convergent, and upwelling current flow

Lease Launch Pt. Unit Latitude N Longitude W 

0409 SMB A Lion Rock Unit 34 56’ 07.80” 120 49’ 55.60” 

0315 Harvest Point Arguello Unit 34 28 08.89 120 40 50.94 

0316 Hermosa Point Arguello Unit 34 27 19.83 120 38 47.00 

0450 Hidalgo Point Arguello Unit 34 29 42.05 120 42 08.24 

0188 Hondo Santa Ynez Unit 34 23 26.63 120 07 13.91 

0190 Harmony Santa Ynez Unit 34 22 36.03 120 10 03.09 

0182 Heritage Santa Ynez Unit 34 21 01.41 120 16 45.06 

0205 Gail Santa Clara Unit 34 07 30.29 119 24 00.78 

0240 Hillhouse Northeastern Channel 34 19 52.84 119 36 11.69 
5-21

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

regimes are illustrated in figures 5.1.3.2-2 through

5.1.3.2-4 respectively. Further description of these flow

regimes can be found in Section 4.4 Physical Oceanography. Results of GNOME model runs are given in

terms of estimated barrels of oil beached, location of

beaching, barrels floating, barrels weathered (evaporated or dispersed), or barrels moving out of the model

domain. Run scenarios are conducted for 200 and 2000

bbl spills over 3 and 10 days. For these more detailed

results, please see appendix 5.2 Conditional Oil Spill

Risk Analysis.

The OSRA Model calculations, the GNOME Model

results, and the drifter data provide important insights

concerning potential areas affected by an oil spill occurring in the area of proposed activity. The MMS

OSRA model gives us seasonal results over a large

domain covering the entire affected area. The GNOME

model provides oil spill trajectory results based on

current flow regimes strongly characteristic of the

area. One of these flow regimes is very likely to be

occurring during an actual spill event. So the GNOME

Model gives us trajectories based on calculations using mean wind and current fields established from

analyzing 6 years of data, but over a smaller model

domain. The drifter analysis is based on actual field

observations and provides information on surface current variability to be considered with the computergenerated results calculated for the SBC-SMB area by

the GNOME and OSRA Models. Where the local winds

do not dominate, the drifter data like the two models,

provide reasonably good estimates of the locations of

oil spill contacts over the entire affected area. This

composite of the three analyses present a more complete picture of what may result from an oil spill event

occurring in the area of proposed activity where the

current and wind regimes are very complex.

5.1.3.2.1 SUMMARY DISCUSSION

As stated in the introduction, there is only a remote probability that an oil spill of 200 bbl or greater

Figure 5.1.3.2-1. Launch point locations for freefloating surface drifter deployments

121 ̊W 120 ̊W

33 ̊30’N

34 ̊0’N

34 ̊30’N

35 ̊0’N

35 ̊30’N

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

Figure 5.1.3.2-2. Synoptic representation of the

relaxation current flow regime characteristic of

the Santa Barbara Channel-Santa Maria Basin

area prepared by Scripps scientists and used by

NOAA in their GNOME Model.

Figure 5.1.3.2-3. Synoptic representation of the

convergent current flow regime characteristic of

the Santa Barbara Channel-Santa Maria Basin

area prepared by Scripps scientists and used by

NOAA in their GNOME Model.
5-22

Delineation Drilling Activities Offshore Santa Barbara County

will occur for the proposed delineation well projects.

The probabilities presented in the Oil Spill Trajectory

Analysis section are in the conditional context that a

significant oil spill has occurred for the cumulative

impact analysis.

For the cumulative impact analysis, the geographical limits of the potentially affected area are

defined by the farthest locations on the California coastline that could be contacted by oil within 10 days of a

spill event occurring in the area of proposed developed activities. The drifter analysis indicates that during an extended period of relaxed winds, the extreme

northern boundary of the potentially affected area is

Pt. Lobos on the central California coast. The drifters

also indicate that during this same wind condition,

the northern limits of the area where contact with a

spill is “most likely” is Ragged Point, which is further

south on the central California coast. Both the drifter

and the OSRA Model analyses indicate that both the

extreme and “most likely” southern boundaries of the

potentially affected area coincide at Santa Catalina

Island in the Southern California Bight, and Palos

Verdes on the Southern California mainland.

The analysis indicates that spilled oil from activity as far away as the eastern-most Unit in the SBC,

the Santa Clara Unit, may contact the shoreline as

far north as Point San Luis on the central California

coast. The central California coast is found most likely

to be contacted by oil from a spill occurring during a

relaxation flow regime. The relaxation flow regime

occurs 27 percent of the time during a year (Section

4.4 Physical Oceanography).

The composite analysis indicates that oil from a

spill occurring anywhere in the SBC may contact either the SBC mainland, the Channel Islands, or both.

The Channel Islands have the highest probability of

contact, according to both models and the drifter data,

with San Miguel and Santa Rosa Islands being the

most likely islands contacted by spilled oil. The area

between Goleta Point and Gaviota seems to be the most

likely area along the SBC mainland to experience contact with spilled oil. Oil spill contact with SBC shorelines is most likely during a convergent or upwelling

flow regime. These flow regimes occur 31 and 35 percent of the time respectively during the year. This is

because there is strong re-circulation within the SBC

associated with these two flow regimes. During a convergent flow regime, a spill in the northern area of

the SBC tends to affect the western-most Islands: San

Miguel and Santa Rosa a little more than the others.

During an upwelling flow regime, a spill in the same

area will tend to affect the eastern most Islands: Santa

Cruz and Anacapa a little more than their western

neighbors. Purisima Point to Point Arguello on the

central California coast and San Miguel and Santa

Rosa Islands in the SBC are the most likely areas of

shoreline contact with oil spilled in the Lions Rock

Unit during an upwelling event.

Spills occurring in the eastern portion of the SBC

(in the Santa Clara Unit) will likely move south and

southeast out of the SBC by way of the eastern SBC

entrance, and into the area offshore of the Santa

Monica Bay-Redondo Beach coastlines in the Southern California Bight. The composite analysis indicates

that at times Santa Catalina Island, and to a lesser

extent San Nicolas Island, may be contacted by a spill

occurring in the SBC. This is largely during the spring

when the upwelling flow regime occurs most prominently. Additionally, the composite analysis indicates

that a spill in the SBC could affect the southern California shoreline as far south as Palos Verdes. The probability that spilled oil will continue south of Santa

Catalina Island within a 10 day time frame is remote.

5.1.3.2.2 OIL SPILL TRAJECTORY ANALYSES

The geographical limits of the potentially affected

area are defined by the farthest locations on the California coastline that could be contacted with oil within

10 days of a spill event occurring in the area of proposed developed activities. For cumulative impact concerns, our analysis indicates that the extreme northern boundary of the affected area is Pt. Lobos on the

central California coastline and the extreme southern

boundary is Santa Catalina Island in the Southern

California Bight, and Palos Verdes on the Southern

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

Figure 5.1.3.2-4. Synoptic representation of the

upwelling current flow regime characteristic of

the Santa Barbara Channel-Santa Maria Basin

area prepared by Scripps scientists and used by

NOAA in their GNOME Model.
5-23

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

California mainland. The limits of the area where contact with a spill is “most likely” is Ragged Point on

the central California coast to Palos Verdes and Santa

Catalina in the Southern California Bight. Figures

5.1.3.2-5 to 5.1.3.2-6 depict the potentially affected

area.

The aggregate of the three analyses provides both

time-dependent and scenario-driven results. The different analyses present results by either 3-month season or by characteristic synoptic flow regime. The frequency and relative dominance of all three flow regimes differ for each calendar month. Table 5.1.3.2-2

presents this information determined from 5 years of

continuous synoptic current data. The table shows

OSRA model seasons defined by calendar month along

with the dominant flow regime and relative frequency

of occurrence of all flow regimes for each particular

month. There is a mix of all three flow regimes for

each month, and therefore for each 3-month OSRA

season. There is no season where one flow regime is

exclusive.

The frequencies that relaxation, upwelling, or

convergent flow events occur during winter, as defined

above, are 38, 32, and 30 percent of the time respectively. Since the relaxation flow event is only slightly

more dominant than the other two, results for all three

flow regimes will be reported for the winter season.

The dominant flow regime during the spring, as

defined above, is upwelling with a 66 percent frequency

of occurrence. Results for this flow regime will be reported for the spring season.

The dominant flow regimes during the summer,

as defined above, are convergent and upwelling with a

37 and 35 percent frequency of occurrence respectively.

Results for these two flow regimes will be reported for

the summer season.

The dominant flow regimes during the fall, as

defined above, are relaxation and convergent with a

44 and 40 percent frequency of occurrence, respectively. Results for these two flow regimes will be reported for the fall season.

The Drifter, GNOME, and OSRA analyses results

are summarized in the composite analysis below for

each of the Units listed in table 5.1.3.2-1. Complete

OSRA Model results are contained in OCS Report

MMS2000-057. Examples of OSRA Model output in GIS

format for hypothetical oil spills during all 4 seasons

at Platforms Hidalgo and Gail are presented in figures 5.1.3.2-11 through figures 5.1.3.2-14 and figures

5.1.3.2-19 through 5.1.3.2-22, respectively. Detailed

tabular results of the Drifter and GNOME analyses

are contained in appendix 5.2 Conditional Oil Spill

Risk. Examples of GNOME Model output for 2000 bbl

spills during for all 3 flow regimes at platforms Hidalgo

and Gail are illustrated in figures 5.1.3.2-7 through

5.1.3.2-10 and figures 5.1.3.2-15 through 5.1.3.2-18,

respectively. Two illustrations for the relaxation flow

Figure 5.1.3.2-5. Coastal cities and areas of the

central California coastline that are part of the

affected area.

event, one during a 4 m/s NW wind and one during a

4 m/s SW wind, are included in these illustrations for

both platforms.

Results from the two models and the drifter data

present numbers that are estimates, and therefore the

reader is advised to view them as such. OCS Report

MMS 2000-057 refers to OSRA Model generated probabilities of contact from hypothetical oil spill trajectories to land segments as estimates. NOAA defines results from GNOME model runs, that lists numbers of

barrels “Evaporated and Disbursed,” “Beached,” “Off

Map”(out of the model domain), and “floating”, as a

“Best Guess.” So the GNOME Model results should

not be viewed as precise numbers. Drifter analysis

Figure 5.1.3.2-6. Coastal cities and areas of the

southern California coastline that are part of the

affected area.
5-24

Delineation Drilling Activities Offshore Santa Barbara County

results are from a relatively small data set from a statistical point of view. Therefore the reader is advised

to view the percentages attached to drifter data as estimates.

LION ROCK UNIT ANALYSES

The Lion Rock Unit is the northernmost location of the 36 undeveloped leases. Location SMB-A

(table 5.1.3.2-1) serves as the launch point for the

GNOME and OSRA Model analyses. Drifter launch

points 17, 18, 19, and 20 (figure 5.1.3.2-1), located offshore Purisima Pt. to Avila Beach in the SMB, were

selected as the launch points for the Lion Rock Unit

drifter analysis. Seventy-two trajectories for drifters

launched from these locations were analyzed to estimate the possible trajectory of oil during three different flow regimes characteristic to the SMB area. Appendix table 5.2-4 summarizes this data.

During the relaxation flow regime the composite

analysis indicates that both computed and observed

trajectories are generally directed to the north going

with the prevailing poleward current. During the upwelling and convergent flow regimes, trajectories generally head south either well offshore west of the SBC

toward the equator or through the SBC and into the

south portion of the Southern California Bight.

The information provided below list areas that

could be contacted by a spill, without consideration

for the actual chance of the spill occurring or contacting an area. If a spill were to occur the chance of

shoreline contact and volume of oil contacting shoreline will vary greatly with a number of factors including: location of spill, volume and characteristics of

spilled oil, wind and current conditions, sea conditions, and the success of the oil spill containment and

response operations.

Table 5.1.3.2-2. Comparison of seasonal months with the frequency and relative dominance of

the three characteristic flow regimes per calendar month (Section 4.4 Physical Oceanography).

OSRA 

Season 

Calendar 

Month 

Dominant 

Flow Regime 

Days of 

Continuous 

Current Data 

Upwelling 

(%) 

Convergent 

(%) 

Relaxation 

(%) 

Other 

(%) 

Winter December Relaxation 146.5 9.22 34.30 49.32 7.17 

Winter January Relaxation 155.0 30.16 26.13 37.42 6.29 

Winter February Upwelling 141.0 51.77 26.06 19.15 3.01 

Spring March Upwelling 154.5 53.07 33.98 2.43 10.52 

Spring April Upwelling 150.0 86.00 8.83 2.67 2.50 

Spring May Upwelling 155.0 47.74 32.10 14.68 5.50 

Summer June Upwelling 150.0 44.67 32.83 17.33 5.17 

Summer July Relaxation 155.0 22.42 32.10 32.90 12.58 

Summer August Convergent 155.0 28.87 35.32 27.58 8,23 

Fall September Relaxation 152.0 20.07 36.35 37.99 5.59 

Fall October Convergent 155.0 19.03 41.94 32.74 6.29 

Fall November Relaxation 135.0 5.37 33.52 53.15 7.96 
5-25

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

WINTER (DECEMBER – FEBRUARY):

The composite results of all three analyses indicates that land contact during the winter season can

occur in any of the following areas:

• The Santa Maria Basin as far south as Pt.

Arguello to as far north as Pt. Lobos, specifically: Pt. Lobos, San Simeon Pt. to Estero Bay,

Pt. Buchon, and Pismo Beach, and Pismo Beach

to Pt. Sal to Purisima Pt. to Surf and Pt

Arguello,

• The Santa Barbara Channel at Pt. Conception,

San Miguel Island and Santa Rosa Island, and

• The south Southern California Bight at Santa

Monica Bay and San Clemente Island.

SPRING (MARCH – MAY):

The composite results of all three analyses indicates that land contact during the spring season can

occur in any of the following areas:

• The Santa Maria Bight at Estero Bay, Pt.

Buchon, Pismo Beach, Pt. Sal, Purisima Pt.

to Surf and Pt. Arguello,

• The Santa Barbara Channel at Pt. Conception

and from the western end of San Miguel Island to Santa Rosa Island, and

• The south Southern California Bight at Santa

Monica Bay and San Clemente Island.

SUMMER (JUNE – AUGUST):

The composite results of all three analyses indicates that land contact during the spring season can

occur in any of the following areas:

• The Santa Maria Basin at Estero Bay, Pt.

Buchon, Pismo Beach, Pt. Sal, Purisima Pt.,

Surf, and Pt. Arguello,

• The Santa Barbara Channel at Pt. Conception

and San Miguel and Santa Rosa Islands, and

• The south Southern California Bight at Santa

Monica Bay and San Clemente Island.

FALL (SEPTEMBER – NOVEMBER):

The composite results of all three analyses indicates that land contact during the spring season can

occur in any of the following areas:

• The Santa Maria Basin as at Pt. Lobos, Pt.

Buchon, Pismo Beach, Pt. Sal, Purisima Pt.,

Surf, and Pt. Arguello, and

• The Santa Barbara Channel at Pt. Conception

and San Miguel Island.

POINT ARGUELLO UNIT ANALYSES.

The Point Arguello Unit is the general location

of Platforms Hidalgo, Harvest, and Hermosa which

serve as launch points for the GNOME and OSRA

Model analyses. Examples of GNOME Model output

for 2000 bbl spills during all 3 flow regimes at platforms Hidalgo are illustrated in figures 5.1.3.2-7

through 5.1.3.2-10. Examples of OSRA Model output

in GIS format for hypothetical oil spills during all 4

seasons at Platform Hidalgo are presented in figures

5.1.3.2-11 through 5.1.3.2-14. Drifter launch points

12, 13, 14, and 15 (figure 5.1.3.2-1), located offshore

Pt. Arguello and Pt. Conception in the transition area

between the SMB and the SBC, were selected as the

launch points for the Point Arguello Unit drifter analysis. Drifter analysis results reflect the documented

trajectories of 65 free-floating surface drifters deployed

at these launch points. This data is discussed in more

detail in the paper: “Surface Drifter Analysis for the

Rocky Point Unit Project Oil Spill Risk Assessment”

contained in appendix 5.2 Conditional Oil Spill Risk

Analysis, appendix exhibit 5.2-1.

During the relaxation flow regime the composite

analysis indicates that trajectories are generally directed to the north along the central California coat

along with the prevailing poleward current. During

the upwelling flow regime the trajectories generally

head either south-southeast through the western island passes of the SBC or south, offshore of the western SBC, toward the equator. During the convergent

flow regime, trajectories generally head west, well offshore the SBC.

The information provided below list areas that

could be contacted by a spill, without consideration

for the actual chance of the spill occurring or contacting an area. If a spill were to occur the chance of

shoreline contact and volume of oil contacting shoreline will vary greatly with a number of factors including: location of spill, volume and characteristics of

spilled oil, wind and current conditions, sea conditions, and the success of the oil spill containment and

response operations.
5-26

Delineation Drilling Activities Offshore Santa Barbara County

WINTER (DECEMBER – FEBRUARY):

The composite results of all three analyses indicates that land contact during the winter season can

occur in any of the following areas:

• The Santa Maria Basin at Ragged Pt., Pt.

Piedras Blancas, Pt. Estero, Pt. Buchon, Pt.

San Luis, Pismo Beach, Pt. Sal, Purisima Pt.,

Surf, Pt. Arguello, and Jalama.

• The Santa Barbara Channel at Pt. Conception

and San Miguel, Santa Rosa, Santa Cruz, and

Anacapa Islands.

• The south Southern California Bight at Santa

Catalina Island

SPRING (MARCH – MAY):

The composite results of all three analyses indicates that land contact during the spring season can

occur in any of the following areas:

• The Santa Maria Basin at Pt. Arguello,

• The Santa Barbara Channel at Pt. Conception and the San Miguel, Santa Rosa, Santa Cruz, and

Anacapa Islands, and South Santa Rosa Island, and

• The south Southern California Bight at PalosVerdes, and Santa Catalina and San Nicholas Islands.

SUMMER (JUNE – AUGUST):

The composite results of all three analyses indicates that land contact during the summer season can

occur in any of the following areas:

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

Figure 5.1.3.2-7. GNOME Modeled 10 day, 2000 bbl

oil spill scenario for platform Hidalgo (depicted

by “+”), located offshore of Point Arguello,

during a relaxation flow regime and a 4 m/s NW

wind. GNOME model output indicates that of

2000 bbl released: 358 bbl beach, 950 bbl evaporate

or are dispersed, 318 bbl are still floating, and 374

bbl have moved out of the model domain heading

north in the Santa Maria Basin.

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

Figure 5.1.3.2-8. GNOME Modeled 10 day, 2000 bbl

oil spill scenario for platform Hidalgo (depicted

by “+”), located offshore of Point Arguello,

during a relaxation flow regime and a 4 m/s SW

wind. GNOME model output indicates that of

2000 bbl released: 296 bbl beach, 942 bbl evaporate

or are dispersed, 220 bbl are still floating, and

542 bbl have moved out of the model domain

heading north in the Santa Maria Basin.

Figure 5.1.3.2-9. GNOME Modeled 10 day, 2000 bbl

oil spill scenario for platform Hidalgo (depicted

by “+”), located offshore of Point Arguello,

during a convergent flow regime and a 7m/s NW

wind. GNOME model output indicates that of

2000 bbl released: 2 bbl beach, 946 bbl evaporate

or are dispersed, 446 bbl are still floating, and

606 bbl have moved out of the model domain

heading west out of the Santa Maria Basin.

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N
5-27

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Figure 5.1.3.2-10. GNOME Modeled 10 day, 2000

bbl oil spill scenario for platform Hidalgo

(depicted by “+”), located offshore of Point

Arguello, during an upwelling flow regime and a

8m/s NW wind. GNOME model output indicates

that of 2000 bbl released: 596 bbl beach, 974 bbl

evaporate or are dispersed, 128 bbl are still

floating, and 302 bbl have moved out of the model

domain heading south to southeast offshore of the

Southern California Bight

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

Figure 5.1.3.2-11. MMS OSRA Model output for a

10 day event at platform Hidalgo during the

winter season. The boxes are U. S. Geological

Survey 7.5 Minute Quad series maps presenting

the calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map.

Figure 5.1.3.2-12. MMS OSRA Model output for a

10 day event at platform Hidalgo during the

spring season. The boxes are U. S. Geological

Survey 7.5 Minute Quad series maps presenting

the calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map.

Figure 5.1.3.2-13. MMS OSRA Model output for a

10 day event at platform Hidalgo during the

summer season. The boxes are U. S. Geological

Survey 7.5 Minute Quad series maps presenting

the calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map.
5-28

Delineation Drilling Activities Offshore Santa Barbara County

ses. Drifter launch points 5, 6, 7, and 8 (figure 5.1.3.2-

1), located in the northwest and north central area of

the SBC, were selected as the launch points for the

San Ynez Unit drifter analysis. Drifter analysis results reflect the documented trajectories of 104 freefloating surface drifters deployed at these launch

points. Appendix table 5.2-3 summarizes this data.

During the relaxation flow regime the composite

analysis indicates that trajectories are primarily directed to the west along the northern shoreline of the

SBC and out its western entrance where one to three

events occur: (1) they turn the corner at Point Arguello

where they proceed north along the central California

coast, (2) they continue west further offshore, and/or

(3) they turn south to southeast toward the Baja or

the San Miguel, Santa Rosa, and possibly the Santa

Cruz Islands. Other trajectories will head west, south

west, or southeast toward the western Channel Islands.

During the convergent flow regime the composite analysis indicates that primarily the trajectories

initially go west along the SBC mainland, but then

become entrained in the cyclonic gyre in the western

end of the SBC where they eventually re-enter the SBC

heading in a southwesterly direction. The few trajectories that escape the western SBC will either go north

along the central California coast, continue west toward the central Pacific, or go southwest toward the

Baja. The majority of trajectories remain in the SBC

within the cyclonic gyre or turn Southeast toward the

three western-most Channel Islands.

During the upwelling flow regime the composite

analysis indicates that most trajectories become entrained in the SBC’s western cyclonic gyre, but then

continue in a southeasterly direction heading toward

either the easternmost two Channel Islands or out of

the eastern SBC entrance along the Southern California Bight coastline.

The information provided below list areas that

could be contacted by a spill, without consideration

for the actual chance of the spill occurring or contacting an area. If a spill were to occur the chance of

shoreline contact and volume of oil contacting shoreline will vary greatly with a number of factors including: location of spill, volume and characteristics of

spilled oil, wind and current conditions, sea conditions, and the success of the oil spill containment and

response operations.

WINTER (DECEMBER – FEBRUARY):

The composite results of all three analyses indicates that during the winter season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Pt. Lobos, Lopez

Pt., Pt. Sur North, Pt. Sur, Cambria, Pt. San

Luis, Pismo Beach, Pt. Sal, Purisima Pt.,

Figure 5.1.3.2-14. MMS OSRA Model output for a

10 day event at platform Hidalgo during the fall

season. The boxes are U. S. Geological Survey 7.5

Minute Quad series maps presenting the

calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

• The Santa Maria Basin at Pt. Sal and Pt.

Arguello,

• The Santa Barbara Channel at Pt. Conception

and the San Miguel, Santa Rosa, Santa Cruz,

and Anacapa Islands, and

• The south Southern California Bight at Palos

Verdes and Santa Catalina Island.

FALL (SEPTEMBER – NOVEMBER):

The composite results of all three analyses indicates that land contact during the fall season can occur in any of the following areas:

• The Santa Maria Basin at Pt. Piedras Blancas,

Pt. Estero, Pt. Buchon, Pt. San Luis, Pismo

Beach, Pt. Sal, Purisima Pt., Surf, Pt. Arguello,

and Jalama,

• The Santa Barbara Channel at Pt.Conception,

and the San Miguel and Santa Rosa Islands,

and

• The south Southern California Bight at PalosVerdes.

SANTA YNEZ UNIT ANALYSES.

The San Ynez Unit is the general location of Platforms Heritage, Harmony, and Hondo which serve as

launch points for the GNOME and OSRA Model analy-
5-29

Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Santa Maria River mouth, Surf, and Pt.

Arguello,

• The Santa Barbara Channel at Pt. Conception,

Drake, Capitan, Gaviota, Coal Oil Pt., Santa

Barbara, Sea Cliff, Ventura, Oxnard, Pt. Mugu,

and San Miguel, Santa Rosa, Santa Cruz, and

Anacapa Islands, and

• The south Southern California Bight at Santa

Monica, Palos Verdes, and San Nicholas Island.

SPRING (MARCH – MAY):

The composite results of all three analyses indicates that during the spring season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Pismo Beach,

• The Santa Barbara Channel at Santa Barbara,

Coal Oil Pt., Ventura, Oxnard, Pt. Mugu along

the mainland, and San Miguel, Santa Rosa,

Santa Cruz, and Anacapa Islands, and

• The south Southern California Bight at Santa

Monica and Palos Verdes.

SUMMER (JUNE – AUGUST):

The composite results of all three analyses indicates that during the summer season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Pismo Beach and

Purisima Pt.,

• The Santa Barbara Channel at Drake, Capitan,

Gaviota, Coal Oil Pt., Santa Barbara, Sea Cliff,

Ventura, Oxnard, Pt. Mugu along the SBC

mainland, and San Miguel, Santa Rosa, Santa

Cruz, and Anacapa Islands, and

• The south Southern California Bight at Santa

Monica to Palos Verdes.

FALL (SEPTEMBER – NOVEMBER):

The composite results of all three analyses indicates that during the fall season land contact may occur in any of the following areas:

• The Santa Maria Basin at Pt. Lobos, Lopez

Pt., Pt. Sur north, Pt. Sur, Cambria, Pt. San

Luis, Pismo Beach, Pt. Sal, Purisima Pt.,

Santa Maria River mouth, Surf, and Pt.

Arguello,

• The Santa Barbara Channel at Pt. Conception,

Drake, Capitan, Gaviota, Coal Oil Pt., and Sea

Cliff along the SBC mainland and San Miguel,

Santa Rosa, and Santa Cruz Islands.

• The south Southern California Bight at San

Nicolas Island.

PLATFORM HILLHOUSE ANALYSES

Platform Hillhouse is located in the northeast

Santa Barbara Channel, just north of the Pitas Point

Unit. Its location serves as the launch points for the

GNOME and OSRA Model analyses. Drifter launch

points 1, 2, 3, E.CE (figure 5.1.3.2-1), located in a southwest to northeast transect from western Santa Cruz

Island to Carpenteria on the mainland and at the eastern Santa Barbara Channel entrance, were selected

as the launch points for the Platform Hillhouse drifter

analysis. Drifter analysis results reflect the documented trajectories of 85 free-floating surface drifters

deployed at these launch points. This data is discussed

in more detail in the report: “Surface Drifter Analysis

for the Cavern Point Unit Project Oil Spill Risk Assessment” contained in appendix 5.2 Conditional Oil

Spill Risk Analysis, appendix exhibit 5.2-2.

During the relaxation flow regime the composite

analysis indicates that trajectories are primarily directed to the west along the northern shoreline of the

SBC and out its western entrance where the majority

turn the corner at Point Arguello and continue north

along the central California coast. Other trajectories

will frequently continue west, but some will go southwest toward the equator, or southeast toward the western Channel Islands.

During the convergent flow regime the composite analysis indicates that the trajectories initially

travel west along the mainland shoreline but then the

majority turn south to southeast inside the western

portion of the channel toward the San Miguel and

Santa Rosa Islands. Some trajectory is directed out

the southwestern corner of the western SBC entrance.

During the upwelling flow regime the composite

analysis indicates that the trajectories, as in the convergent case, initially travel west but then turn to the

south and southeast sooner than during a convergent

flow regime. Trajectories continue south to southeast

toward the eastern-most Channel islands: Santa

Catalina and Anacapa Islands and out the eastern

entrance of the SBC to continue into the Southern

California Bight.

The information provided below list areas that

could be contacted by a spill, without consideration

for the actual chance of the spill occurring or contacting an area. If a spill were to occur the chance of

shoreline contact and volume of oil contacting shoreline will vary greatly with a number of factors including: location of spill, volume and characteristics of

spilled oil, wind and current conditions, sea conditions, and the success of the oil spill containment and

response operations.
5-30

Delineation Drilling Activities Offshore Santa Barbara County

WINTER (DECEMBER – FEBRUARY):

The composite results of all three analyses indicates that during the winter season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Estero Bay, Pt. San

Luis, San Luis Obispo Bay, Pismo Beach and

the entire area from Pt. Sal to Purisima Pt. to

Pt. Arguello,

• The Santa Barbara Channel at Jalama, Pt. Conception, Capitan, Gaviota, Coal Oil Pt., Goleta

Pt., Santa Barbara, Carpenteria, Carpenteria to

Point Hueneme, Sea Cliff to Pitas Pt., and

Ventura on the mainland and San Miguel, Santa

Rosa, Santa Cruz, and Anacapa Islands, and

• The south Southern California Bight at south

Santa Cruz Island, south Santa Rosa Island,

Pt. Dume, Santa Barbara Island, Pt. Vicente

to Redondo Beach, Santa Catalina Island, and

San Nicolas Island.

SPRING (MARCH – MAY):

The composite results of all three analyses indicates that during the spring season land contact may

occur in any of the following areas:

• The Santa Barbara Channel at Pt. Conception,

Gaviota, Coal Oil Pt., Santa Barbara, Pitas

Pt. to Punta Gorda, Ventura, Oxnard, Port

Hueneme and Pt. Dume along the mainland,

and the San Miguel, Santa Rosa, Santa Cruz,

and Anacapa Islands, and

• The south Southern California Bight at south

Santa Cruz Island, south Santa Rosa Island,

Redondo Beach, Pt. Vicente, San Nicolas Island, and San Clemente Island.

SUMMER (JUNE – AUGUST):

The composite results of all three analyses indicates that during the summer season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Pismo Beach and

Estero Bay,

• The Santa Barbara Channel at Pt. Conception,

Capitan, Goleta Pt., Gaviota, Santa Barbara,

Santa Barbara to Loon Pt., Carpenteria, Punta

Gorda to Pitas Pt. to Ventura, Port Hueneme,

Pt. Dume, and San Miguel, Santa Cruz, Santa

Rosa, and Anacapa Islands, and

• The south Southern California Bight at South

Santa Cruz Island, south Santa Rosa Island,

Redondo Beach, Pt. Vicente, and San Nicolas

Island.

FALL (SEPTEMBER – NOVEMBER):

The composite results of all three analyses indicates that during the Fall season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Estero Bay, Pt. San

Luis, San Luis Obispo Bay, and the entire area

from Pismo Beach to Pt. Sal to Purisima Pt.,

and Pt. Arguello,

• The Santa Barbara Channel at Pt. Conception,

Capitan, Gaviota, Goleta Pt., Goleta to Coal

Oil Pt., Santa Barbara, Carpenteria, and

Ventura along the mainland shoreline and San

Miguel, Santa Rosa, Santa Cruz, and Anacapa

Islands, and

• The south Southern California Bight at south

Santa Cruz Island.

SANTA CLARA UNIT (PLATFORM GAIL)

ANALYSES

The Santa Clara Unit contains Platform Gail,

which is located just north of the northbound vessel

traffic lane near the eastern SBC entrance. Its location serves as the launch points for the GNOME and

OSRA Model analyses. Examples of GNOME Model

output for 2000 bbl spills during for all 3 flow regimes

at platform Gail are illustrated in figures 5.1.3.2-15

through 5.1.3.2-18. Examples of OSRA Model output

in GIS format for hypothetical oil spills during all 4

seasons at Platform Gail are presented in figure 5.1.3.2-

19 through figure 5.1.3.2-22. Drifter launch points 1,

2, 3, E.CE (figure 5.1.3.2-1), located in a southwest to

northeast transect from western Santa Cruz Island to

Carpenteria on the mainland and at the eastern Santa

Barbara Channel entrance, were selected as the launch

points for the Santa Clara Unit drifter analysis. Drifter

analysis results reflect the documented trajectories of

85 free-floating surface drifters deployed at these

launch points. This data is discussed in more detail in

the report: “Surface Drifter Analysis for the Cavern

Point Unit Project Oil Spill Risk Assessment” contained in appendix 5.2 Conditional Oil Spill Risk Analysis, appendix exhibit 5.2-2.

During the relaxation flow regime the composite

analysis indicates that trajectories are primarily directed to the west along the northern shoreline of the

SBC and out its western entrance where the majority

turn the corner at Point Arguello and continue north

along the central California coast. Other trajectories

will frequently continue west, but some will go southwest toward the equator, or southeast toward the west-
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

ern Channel Islands. Some trajectories head north

toward the Gaviota-Capitan portion of the SBC mainland or southwest toward the western-most Channel

Islands: San Miguel and Santa Rosa.

During the convergent flow regime the composite analysis indicates that trajectories initially either

go northwest towards the Carpenteria to Ventura portion of the SBC mainland with the majority of trajectories changing course to directly west along the SBC

mainland. They then proceed to turn south to southeast, along with the western cyclonic gyre, toward the

San Miguel, Santa Rosa, and Santa Cruz Islands and

their Island passes.

During the upwelling flow regime the composite

analysis indicates that almost 100 percent of the trajectories are directed southeast out of the eastern SBC

entrance and into the Southern California Bight.

The information provided below list areas that

could be contacted by a spill, without consideration

for the actual chance of the spill occurring or contacting an area. If a spill were to occur the chance of

shoreline contact and volume of oil contacting shoreline will vary greatly with a number of factors including: location of spill, volume and characteristics of

spilled oil, wind and current conditions, sea conditions, and the success of the oil spill containment and

response operations.

WINTER (DECEMBER – FEBRUARY):

The composite results of all three analyses indicates that during the winter season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Estero Bay, Pt. San

Luis, San Luis Obispo Bay, and the area from

Pt. Sal to Purisima Pt. to Pt. Arguello,

• The Santa Barbara Channel at Jalama to Coal

Oil Pt. including: Pt. Conception, Drake,

Gaviota, Capitan, Naples, and Coal Oil Pt.;

Goleta Pt., Santa Barbara to Loon Pt.,

Carpenteria to Pt. Hueneme including:

Carpenteria, Punta Gorda to Pitas Pt.,

Ventura, and Laguna Pt. on the mainland and

San Miguel, Santa Rosa, Santa Cruz, and

Anacapa Islands.

• The south Southern California Bight at South

Santa Cruz Island, Pt. Dume, Pt. Vicente to

Redondo Beach, Santa Catalina Island, and

San Nicolas Island.

SPRING (MARCH – MAY):

The composite results of all three analyses indicates that during the spring season land contact may

occur in any of the following areas:

121 ̊W 120 ̊W

33 ̊30’N

34 ̊0’N

34 ̊30’N

35 ̊0’N

Figure 5.1.3.2-15. GNOME Modeled 10 day, 2000

bbl oil spill scenario for platform Gail (depicted

by “+”), located in the center of the Channel near

its eastern entrance, during a relaxation flow

regime and a 4 m/s NW wind. GNOME model

output indicates that of 2000 bbl released: 94 bbl

beach, 974 bbl evaporate or are dispersed, 924 bbl

are still floating, and 8 bbl have moved out of the

model domain heading west out of the Santa

Maria Basin and south to southeast offshore of

the Southern California Bight.

121 ̊W 120 ̊W

33 ̊30’N

34 ̊0’N

34 ̊30’N

35 ̊0’N

Figure 5.1.3.2-16. GNOME Modeled 10 day, 2000

bbl oil spill scenario for platform Gail (depicted

by “+”), located in the center of the Channel near

its eastern entrance, during a relaxation flow

regime and a 4 m/s SW wind. GNOME model

output indicates that of 2000 bbl released: 316 bbl

beach, 978 bbl evaporate or are dispersed, 534 bbl

are still floating, and 172 bbl have moved out of

the model domain heading north out of the Santa

Maria Basin.
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Delineation Drilling Activities Offshore Santa Barbara County

Figure 5.1.3.2-17. GNOME Modeled 10 day, 2000

bbl oil spill scenario for platform Gail (depicted

by “+”), located in the center of the Channel near

its eastern entrance, during a convergent flow

regime and a 7 m/s NW wind. GNOME model

output indicates that of 2000 bbl released: 410 bbl

beach, 964 bbl evaporate or are dispersed, 366 bbl

are still floating, and 260 bbl have moved out of

the model domain heading south to southeast

offshore of the Southern California Bight

Figure 5.1.3.2-18. GNOME Modeled 7 hour, 2000

bbl oil spill scenario for platform Gail (depicted

by “+”), located in the center of the Channel near

its eastern entrance, during an upwelling flow

regime and a 1.5 m/s NW wind. GNOME model

output indicates that of 2000 bbl released: 0 bbl

beach, 148 bbl evaporate or are dispersed, 160 bbl

are still floating, and 1692 bbl have moved out of

the model domain heading southeast out of the

eastern Santa Barbara Channel entrance and

along the southern California coastline. After 3

and 10 days, the GNOME model gives the same

output of 150 bbl of oil evaporated and dispersed

and 1850 bbl out of the model domain heading

southeast out of the Santa Barbara Channel by

way of its eastern entrance and along the southern

California coastline.

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

121 ̊W 120 ̊W

34 ̊0’N

34 ̊20’N

34 ̊40’N

35 ̊0’N

Figure 5.1.3.2-19. MMS OSRA Model output for a

10 day event at platform Gail during the winter

season. The boxes are U. S. Geological Survey 7.5

Minute Quad series maps presenting the

calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map.

Figure 5.1.3.2-20. MMS OSRA Model output for a

10 day event at platform Gail during the spring

season. The boxes are U. S. Geological Survey 7.5

Minute Quad series maps presenting the

calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

• The Santa Barbara Channel at Pt. Conception,

Santa Barbara to Loon Pt., Punta Gorda to

Pitas Pt., Carpenteria, Pitas Pt. to Ventura,

Port Hueneme, and Laguna Pt. on the mainland and San Miguel, Santa Rosa, Santa Cruz,

and Anacapa Islands, and

• The south Southern California Bight at Pt.

Dume, Redondo Beach, and Pt. Vicente on the

mainland, and South Santa Cruz, south Santa

Rosa, San Nicolas, Santa Barbara, and Santa

Catalina Islands.

SUMMER (JUNE – AUGUST):

The composite results of all three analyses indicates that during the summer season land contact may

occur in any of the following areas:

• The Santa Maria Basin at Pt. Sal to Purisima

Pt.,

• The Santa Barbara Channel at Pt. Conception,

Gaviota, Goleta, Goleta Pt. to Coal Oil Pt.,

Santa Barbara to Loon Pt., Carpenteria, Punta

Gorda to Pitas Pt. to Ventura, and Pt. Hueneme

along the mainland, and the San Miguel, Santa

Rosa, Santa Cruz, and Anacapa Islands, and

• The south Southern California Bight at Pt.

Hueneme to Pt. Dume, Laguna Pt., Redondo

Beach, Pt. Vicente along the mainland, and

south Santa Cruz, south Santa Rosa, San

Nicolas, and Santa Catalina Islands.

FALL (SEPTEMBER – NOVEMBER):

The composite results of all three analyses indicates that during the fall season land contact may occur in any of the following areas:

• The Santa Maria Basin at Estero Bay, Pt. San

Luis, San Luis Obispo Bay, and the area from

Pismo Beach to Pt. Sal to Purisima Pt. to Pt.

Arguello,

• The Santa Barbara Channel at Pt. Conception,

Capitan, Gaviota, Naples, Goleta to Coal Oil

Pt., Santa Barbara to Loon Pt., Carpenteria,

Punta Gorda, Pitas Pt., Ventura, Pt. Hueneme

along the mainland, and San Miguel, Santa

Rosa, Santa Cruz, and Anacapa Islands, and

• The south Southern California Bight at Laguna Pt., Pt. Dume, south Santa Cruz Island,

and south Santa Rosa Island.

This concludes the summary of the trajectory

analyses performed for the Lion Rock, Point Arguello,

Figure 5.1.3.2-21. MMS OSRA Model output for a

10 day event at platform Gail during the summer

season. The boxes are U. S. Geological Survey 7.5

Minute Quad series maps presenting the

calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map.

Figure 5.1.3.2-22. MMS OSRA Model output for a

10 day event at platform Gail during the fall

season. The boxes are U. S. Geological Survey 7.5

Minute Quad series maps presenting the

calculated probabilities (in percentages) of oil

contact with the shoreline contained within each

map.
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Delineation Drilling Activities Offshore Santa Barbara County

5.1.3.3 OIL SOURCES, BEHAVIOR, AND

SPILL RESPONSE

5.1.3.3.1 SOURCES OF OIL

Sources of oil that could enter the marine environment include:

• Oil and gas exploration;

• Oil and gas development and production;

• Tankers, barges, and other shipping; and

• Natural seeps.

Municipal and industrial wastes and urban runoff also contribute oil to the marine environment, likely

in amounts much greater than those contributed by

any other single source. See section 5.2.2 for further

detail on these sources of hydrocarbons. For the purposes of this discussion, we will only examine the potential for oil spills from the sources listed above.

These are summarized below with additional detail given in appendix 5.3.

OIL AND GAS EXPLORATION ACTIVITIES

Exploration activities include the mobilization

and operations on the drilling vessel as well as support vessel operations. The two general potential

sources for spills during exploration activities, include

spills during drilling operations due to loss of well control (blowout) and spills from other exploratory sources

including those related to support vessels.

Technological innovations today have greatly

lessened the risk from exploration drilling, including:

• Increased knowledge of undrilled geology from

such methods as 3-D seismic surveys and improved data processing;

• A better ability to control wells that by intensive monitoring of a plethora of downhole data

while drilling is occurring; and

• Intensive training and drills by facility workers, resulting in a readiness and an instant responsiveness to unexpected events.

Spills during drilling due to loss of well control.

A total of 38 OCS blowouts have occurred nation-wide

from 1992 to date. Of these, four separate events resulted in a total hydrocarbon spillage of 302 bbl, and

one of those accounted for the largest spillage of 150

San Ynez, and Santa Clara Units, and for Platform

Hillhouse. Please see appendix 5.2 Conditional Oil

Spill Risk Analysis for a detailed presentation of the

results of the OSRA, drifter, and GNOME analyses.

to 200 bbl of oil (as well as 806 bbl of synthetic drilling mud)1 . Twenty-six of the 38 events occurred during drilling, and 13 occurred during exploration operations. Three events occurred in the Pacific OCS

Region, both as a result of development operations;

only one of these, in November 2000, spilled approximately 1 gallon of oil (see the website: http://

www.mms.gov/stats/OCSincident.htm and appendix 5.3

for additional information).

Spills from other exploratory sources including

those related to support vessels. When only exploration activities are accessed in the MMS Pacific Region

database, of 239 exploratory wells drilled from 1970

to present (all from MODUs), a total of 78 hydrocarbon spills occurred, spilling about 50 bbl of hydrocarbons. Most of the exploration drilling occurred during the 1980s; the last Pacific Region exploratory well

was drilled in 1989.

OIL AND GAS DEVELOPMENT AND

PRODUCTION ACTIVITIES

In the Pacific OCS Region from 1970 through

2000, a total of 881 spill events resulted in 780 bbl of

oil spilled from all sources related to development and

production activities, while about 950 million bbl of

oil was produced. The largest spill from a Pacific Region facility since 1970 was 163 bbl from a pipeline

from Platform Irene in 1997. As noted earlier, the

1969 event resulted in 80,000 bbl of oil spilled.

There are four potential phases in development

and production activities during which spills could

occur:

• Platform installation;

• Development drilling;

• Production and pipelines; and

• Decommissioning

The MMS oil spill database does not contain information that allows differentiation between these

phases and the frequency of spills and the type of hydrocarbon spilled. Therefore, the following discussion

will only address generic possibilities and scenarios,

rather than statistics.

Platform installation. Spills of diesel, lube oil

and hydraulic oil are the most common types of spills

to occur during platform installation and construction activities since no wells would have been drilled

at that time. These types of spills can occur during

all phases (including exploration) of offshore oil and

gas activities. Transfer of diesel fuel between the supply vessel and the derrick barge can result in small

spills during the transfer process. Lube and hydraulic oils are stored in drums or cans. To our knowledge, no drums of these types have been dropped into
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

barge and the supply vessels.

TANKERS, BARGES AND OTHER SHIPPING

Vessels that carry hydrocarbons, either as cargo

or as fuel or both, ply the waters of the Study. The

history of spills in the west coast from vessels is brief

(USCG, 2000). Since the early 1970s, six vessels have

spilled various types of oil, totaling about 9,000 bbl,

within the study area (see appendix 5.3 for additional

detail).

NATURAL SEEPS

At least 50 oil seepage areas exist between Point

Arguello and Huntington Beach with at least 38 in

the Santa Barbara Channel. Altogether, it is estimated

that 40 to 670 bbl of oil per day seep into the sea in the

Santa Barbara Channel with the most concentrated

occurring near Coal Oil Point where about 25 to 400

bbl/day seep out (Hornafius, et al., 1999; Quigley, et

al., 1999). Seepage areas are also known to exist from

Point Arguello to Monterey.

ONSHORE SOURCES

Sources of oil that could enter rivers and, perhaps, the sea, include municipal and industrial waste

and urban runoff, refineries, oil and gas production

facilities, oil and gas processing facilities, and pipelines.

One refinery is located near the Santa Maria River

in San Luis Obispo County while several others are

located near the Los Angeles Harbor and sea shore

near Los Angeles International Airport. To our knowledge, no spills from those refineries have entered either rivers or the sea.

Two separate, but related, production spills have

occurred on the San Luis Obispo County coast. They

are the Guadeloupe Dunes diluent spill and the Avila

Beach oil spill. They are both under ground spills

formed by both the diluent (diluent is a light hydrocarbon used to thin oil in formations to ease the pumping of the oil to the surface) and the oil seeping and

contacting ground water, where it was transported

further from the original spill site. The diluent spill

was first noticed when hydrocarbons appeared in the

surf zone. The source of the “spill” was traced to

underground pools of diluent which had settled atop

of ground water, then seeped downhill to the ocean.

The Coast Guard with Unocal the State, developed a

response to the situation, which is ongoing. Further

searches revealed many such pools scattered about the

oil field. The Avila Beach spill is another that is under ground. It was the result of long-term seepage of

oil from tanks on the slopes above the town of Avila

Beach. Again, Unocal was the responsible party and

the sea that resulted in the spillage of oil. However,

lines and hoses have broken resulting in small spills

of lube and hydraulic oils into the sea.

Development drilling. During development drilling, the possibility of crude oil spills arises, only when

oil is found. Loss of well control can and has happened. Of the 881 spills events that have occurred

from 1970 to the late-1980’s, when drilling activities

was high in the Pacific Region, 1 in 25 events occurred

during drilling or while equipment was in a well during other operations.

Most platforms have diesel fuel onboard even if

they are powered from shore by electrical cable. The

diesel is used for powering some cranes and for backup

generators, especially for running fire water pumps in

case of emergencies. Diesel is commonly stored in

tanks in the pedestals that support the superstructure of the cranes. The use of hydraulic and lube oils

continues in this phase since various pumps, compressors and other machinery require one or both of these.

Production and pipelines. Hydrocarbon spills

may occur during production of oil and gas and while

the oil and gas is treated and pumped through pipelines to shore (all oil and gas is piped to shore in the

Pacific OCS Region). By far, the most spills occur

during this phase, as this phase lasts the longest, over

30 years in some cases. The largest spills that occurred on a facility during this phase were two-17 bbl

spills. Otherwise, the 1997 Platform Irene pipeline

spill of 163 bbl has been the largest in this phase (and

largest overall since 1969).

Produced water discharges also contribute oil

into the sea. This effluent is regulated under the National Pollutant Discharge Elimination System

(NPDES) regulations under the Environmental Protection Agency purview. The effluent is treated prior

to discharge by various means. The most common

treatment system used involves a combination of heat,

chemicals (for example, emulsion breakers) and the

use of mechanical forces (such as corrugated plates,

bubbling air, etc.). Under normal operating and treatment circumstances, no slick will form on the ocean

surface as from an oil spill. However, since NPDES

permits allow some dissolved components of oil to remain in the effluent (currently ranging in the POCSR

from 29 to 72 ppm) some amount of oil is discharged

into the sea from this effluent. See section 6.2.2 for

more detailed information on oil and grease in produced water discharges.

Decommissioning. The potential for oil spill from

decommissioning activities is similar to those from

platform installation. Since platform operations will

cease, there is no chance for spills from oil wells. Thus,

the greatest chance of spills from this phase would be

due to the attendant vessels, including the derrick

1 This occurred during deep-water drilling in the Gulf

of Mexico when a riser accidentally disconnected.
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Delineation Drilling Activities Offshore Santa Barbara County

sedimentation/sinking, and biodegradation. The processes of spreading, evaporation, dispersion, emulsification and dissolution are most important during the

early stages of a spill whilst oxidation, sedimentation

and biodegradation are more important later on and

determine the ultimate fate of the oil (ITOPF, 2001;

Fingas, 2000).

Tar Balls and Mats. Heavy oil residues, or tar

balls, often remain after all the short-term weathering processes have occurred. These residues are normally made up of the least volatile components of the

oil (MMS, 1996). Tarballs, which are often found on

shorelines, and have a solid outer crust surrounding

a softer, less weathered interior, are a typical example

of this process. The process forms an outer protective

coating of heavy compounds that results in the increased persistence of the oil as a whole (ITOPF, 2001).

The oil may come from spills, but may also arise from

natural seeps or from deliberate (but illegal) operational releases from ships during bilge-cleaning operations (Fingas, 2000). For additional information on

sources of oil and weathering processes, sea NRC,

(1985).

5.1.3.3.3. OIL SPILL RESPONSE

This very broad topic is summarized here and

expanded in appendix 5.3. A typical response potentially involves many Federal, State, and local agencies, as well as the spiller of the oil (known as the

Responsible Party – RP) and various oil spill clean-up

entities in the form of cooperatives and contractors.

The volume of the oil normally determines the identity and number of entities involved in the response.

As discussed above, the EIS examines three different

oil spill scenarios. They are:

• 50 to 1,000-bbl spill with a most-likely volume

of 200 bbl or less;

• 2,000 bbl, assumed to occur from a pipeline;

and

• A 22,800 bbl tanker spill.

The agencies that would always be involved in

an oil spill response are the U. S. Coast Guard and

the State of California’s Office of Oil Spill Prevention

and Response (OSPR, contained, administratively,

within the Department of Fish and Game). The Coast

Guard, the State and the RP all constitute the Unified

Command (UC), where all information and all decisions are made regarding spill response strategy and

day-to-day planning. MMS’s responsibilities are summarized below and given in more detail in appendix

5.3.

has undertaken the entire cost of the clean up action.

Oil and gas processing facilities are located

mostly near the shore and some are located in canyons that also contain small seasonal streams. In

some cases, much effort has been expended to prevent

any spilled oil from reaching the sea where there is a

potential for oil to spill into a small stream and hence

into the sea.

Processing facilities range in oil-handling capability from large (for example, Exxon’s Los Flores

Canyon), to medium (Nuevo’s Mandalay Beach) to

small (Pacific Offshore Operators’, Rincon plant). All

of these examples take wet oil from offshore, separate

the water and dewater the gas, send the treated water

back offshore for disposal, and ship the oil and gas

into the local pipeline infrastructure. All are located

on or near the shore, or in a canyon (in the Las Flores

Canyon case). No oil spills from these facilities have

been known to reach the sea or any nearby local stream

which runs to the sea.

Pipelines are the primary way that oil is shipped

both from offshore to onshore and from one place to

another onshore. Since pipelines that run along the

shore often cross small streams and some major rivers, the potential for a breakage and subsequent leakage into the stream or river exists. Examples are the

1997 Northridge earthquake which caused an ARCO

pipeline to brake in six places; a Unocal pipeline running from a tank farm in Avila Beach which broke

and spilled oil which ran down a cliff into the shallow

tidal waters; a Berry Petroleum pipeline break with

oil flowing into a nearby agricultural drainage pond

near McGrath State Beach.

5.1.3.3.2. BEHAVIOR AND WEATHERING

PROCESSES: HOW OIL CHANGES

WHEN SPILLED AT SEA

When oil is spilled at sea it will normally break

up and be dissipated and dispersed into the marine

environment over time. This dissipation is a result of

a number of chemical and physical processes and are

collectively known as weathering. Some of the processes, like dispersion of the oil into the water, cause

part of the oil to leave the sea surface, while others,

like evaporation or the formation of water in oil emulsions, cause the oil that remains on the surface to

become more persistent. The time dissipation takes

depends on a series of factors, including the amount

and type of oil spilled, the weather conditions and

whether the oil stays at sea or is washed ashore. Physical properties such as the density, viscosity and pour

point of the oil also affect the speed and the resulting

form of the oil during these weathering processes.

There are eight main processes that cause oil to

weather (ITOPF, 2001). They are: spreading, evaporation, dispersion, emulsion, dissolution, oxidation,
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Other agencies and private organizations that

might participate in a response (depending on size and

location) could include the local county’s Office of

Emergency Services, Fire Department, Harbor Patrol,

Department of Transportation’s Office of Pipeline

Safety, U. S. Park Service, Federal Emergency Management Agency, U. S. Fish and Wildlife, California

Department of Fish and Game (the wildlife part), and

various contractors that would provide personnel,

equipment, food and housing services, disposal of oily

debris and hazardous materials, and other services.

PLANS

Planning for an oil spill response is essential to

insure an effective, efficient and organized response.

Oil Spill Response Planning is conducted at four distinct levels: the National, Regional, Area, and the Facility/Vessel. The first three levels of response planning are conducted by government agencies charged

with protecting the environment under the National

Response System. The Area level of response planning includes input from both state and local government, as well as industry and other interested parties, while the facility response planning is conducted

by the owner or operator of the oil and gas facility

from which a spill could impact navigable waters (see

appendix 5.3 for additional detail on these levels of oil

spill response planning).

For a good example of a generic, recently-written OSRP, see the main text and the key appendices A,

C, D, E and F of Padre and Associates (2001). This

plan covers oil spill response in the eastern Santa

Barbara Channel and Santa Maria Basin area. The

plan was written in accordance with MMS regulation

found at 30 CFR 254. The main text of the plan describes the typical response organization and actions

to be taken by an oil and gas operator. Appendix A

discusses the spill response equipment available in this

area and its maintenance and inspection. Appendix C

describes a worst case discharge scenario for this area,

where the discharged oil may occur, the resources at

risk and the response for this spill. Appendices D and

E are plans for the use of dispersants and in-situ burning, respectively. These spill response technologies

could be used if their used demonstrated that a net

environmental benefit would result. This section also

includes the approval process for use of these technologies and procedures for their use. Appendix F

discusses the spill response training and drills offshore

personnel will undergo to prepare for a spill response.

Operator Response. Any operator’s strategy for

dealing with oil spills is to prevent their occurrence.

Well-engineered facilities, good housekeeping practices,

adequate equipment maintenance and adherence to

proper operational procedures are diligently employed

to reduce the likelihood of an oil spill to the lowest

possible level. In the unlikely event that an oil spill

occurs, response operations would be initiated immediately. Throughout all response operations, the highest priority would be placed upon personnel safety, in

addition, environmental resource considerations would

be taken into account in the selection of response techniques and equipment and in the conduct of response

operations.

The initial response to a spill at a site of delineation activities will be from onsite equipment stationed

on dedicated spill response vessels at the drill site.

Additional response resources for spills beyond the

capabilities of the onsite equipment will be provided

by the oil spill cooperative.

Notifications. Upon the spillage of oil, the

operator’s first concern is always the safety of the

personnel at the site. Next, the RP begins to discern

the cause of the spill and attempts to abate (shut off)

the source. MMS personnel, when notified, would

assist in this endeavor. While these initial actions are

occurring, notifications to the U. S. Coast Guard’s

National Response Center, and the State of California’s

Office of Emergency Services are made2 , along with

several other agencies, including the State Lands Commission, the Coast Guard at Long Beach and Santa

Barbara, OSPR and the Oiled Wildlife Care Network.

Several other agencies would be notified ,when time

and if circumstances warrant (see appendix 5.3). If

the spill is from a platform or pipeline under MMS’s

jurisdiction, MMS would be included in the initial

notification as noted above, and be on-scene as rapidly as possible. If the spill were from a tanker as

described in the scenario, above, the notifications

would be substantially be the same, except for MMS

and other agencies with no direct jurisdiction.

The second type of entity to be commonly notified would be the local oil spill cooperative. For the

Santa Barbara Channel and Santa Maria Basin that

would be Clean Seas, and for offshore Los Angeles,

Clean Coastal Waters. These two co-ops have response

equipment and contractors (including a fishing vessel-based organization, the Fisherman Oilspill Response Team). Other co-op type organizations that

could contribute personnel and equipment include the

Coast Guard’s Pacific Strike Team, the oil industry’s

Marine Spill Response Corporation, and the National

Response Corporation, another major independent

contractor.

Equipment and Personnel Deployment. Once oil

is in the water from either a platform or pipeline, equipment is deployed either directly from the spilling facility, or a co-op, or both. On-scene oversight is usually

provided by a local co-op representative who, with the

use of helicopter overflights, properly positions booms

and vessels to most efficiently attack the thickest part

of the oil slick.
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Delineation Drilling Activities Offshore Santa Barbara County

Beach debris removal, wildlife capture and rehabilitation, and public concerns all are concerns the

UC must address for any spill. A spill from a tanker,

in addition to being very large, as compared to one

from a platform or pipeline, would generally entail the

mobilization of nearly all the resources discussed above

and, potentially, others from other states and even

countries. The Exxon Valdez spill was just such an

event, and equipment from all over the world was eventually mobilized to Prince William Sound, Alaska.

Day-to-Day Spill Response. The emergency phase

of a spill lasts until the major assets are in-place and

working. The UC is formed and four sub-units are

set-up: Finance, Logistics, Operations, and Planning.

The general philosophy is to initially overreact to any

incident, so depending on the size of the spill, more or

less equipment and personnel would be added or released from the spill scene. Night-time and foggy operations can continue, but often on a more limited

basis.

As a spill response continues, various auxiliary

issued must be addressed. These include disposal of

oily debris, recycling, disposal at sea of water separated from recovered oil, contaminated debris, sorbent

use/reuse, petroleum-contaminated soil recycling and

reuse, temporary storage, treatment of oily wastes,

characterization of recovered material, transportation,

hazardous waste, and nonhazardous wastes. All of

these topics have their individual considerations that

must be accounted for in any oil spill response. Additional information is given in appendix 5.3.

EQUIPMENT

Operators in the Pacific Region are required to

keep sufficient equipment on or near the platform to

enable them to initiate immediate containment activities. For a secondary level response, equipment at the

platform is supplemented by equipment kept onshore

and operated by oil spill cooperatives formed by the

lessees and operators. For example, Clean Seas has

pre-staged equipment located at Morro Bay, Avila Bay,

Santa Barbara Harbor, the Carpinteria Yard, in the

Ventura/Port Hueneme area, and at Point Mugu Navy

Base. Various types of response equipment are stored

at these locations. The three major cooperatives also

have at least six dedicated ocean-going vessels with

containment and recovery equipment for oil spill response.

If the Federal OSC so requests, the Navy and

the USCG can provide additional oil spill response

equipment and personnel located at Stockton and at

Hamilton Air Force Base in northern California. Also,

the Marine Spill Response Corporation has established

a Southwest Region Response Center at Port Hueneme

on the Santa Barbara Channel. Equipment from this

center may be used for response to a spill from OCS

exploration and production operations if so directed

by the Federal OSC.

The three oil spill response cooperatives on the

California coast—Clean Bay, Clean Seas, and Clean

Coastal Waters—have formally agreed to provide each

other response assistance within the boundaries established by State and Federal regulatory authorities.

These cooperatives have also been acquiring new equipment to supplement their existing inventories. See

appendix 5.3 for details on the sources, amounts, and

types of mechanical equipment available for oil spills

within the study area.

MMS RESPONSIBILITIES

MMS’s primary responsibilities, by law, are abatement of the initial spill and investigation of the cause.

However, MMS believes that prevention of oil spills is

much preferable to cleaning up spilled oil. This prevention strategy includes a regulatory scheme that

requires the use of the best available and safest technologies at any facility, training standards for the

operator’s personnel and a rigorous inspection program. This strategy ensures that industry operates

well-engineered facilities, with good housekeeping

practices, adequate equipment maintenance, and adherence to proper operational procedures to reduce the

likelihood of an oil spill. For additional information

on MMS’s responsibilities, see appendix 5.3.

To insure that a facility is prepared in the unlikely event that oil is spilled, the MMS has a comprehensive oil spill response exercise program in place.

The program tests a facility operator’s response, as

well as their knowledge and understanding of their

individual OSRP. For planning purposes, the MMS

adheres to the requirements of the USCG’s National

Preparedness for Response Exercises Program

(PREP)3 . Facility operators must exercise their entire response plan at least once every 3 years (triennial exercise). To satisfy the triennial exercise requirement an owner or operator must conduct the following aspects of their response capability:

• Annual spill management tabletop exercise;

• Annual deployment exercise of spill response

equipment staged at onshore locations;

• Annual notification exercise; and

• Semiannual deployment exercise of any response equipment which the owner or operator must maintain at the facility of on dedi2 Both of these notifications go to entities who disseminate the information to many other agencies, usually

by fax. In some cases, multiple notifications are made to the

same agency by this methods, via the NRC or State OES, as

well as directly by phone from the RP.
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

cated vessels (MMS-initiated or actual spill responses can be used for credit for one of these

exercises).

ALTERNATIVE RESPONSE TECHNOLOGIES

– OFFSHORE

Dispersants. Dispersants are a class of spilltreating agents that, when applied to oil on water, form

the oil into droplets which are driven into the top layer

of water column (Fingas, 2001). Surface active agents

(surfactants) are the key components of a chemical

dispersant. These compounds contain both a water

compatible and an oil compatible group. Because of

this molecular structure, the surfactant locates at the

oil-water interface, reduces the interfacial tension, and

enabling the oil slick to break up into small oil droplets. Once the droplets are dispersed into the water

column, they are subjected to natural processes such

as spreading by currents and biodegradation (National

Research Council (NRC), 1989; SL Ross, 2000) A

number of papers have been written explaining how

dispersants work (Fingas 1988 and Fingas et al., 1997;

1995; 1993) and summarized in American Petroleum

Institute (1999; 1997). Appendix 5.3 contains more

information on the NRC (1989) study which asked two

questions:

• Do dispersants do any good? (that is, are they

effective?); and

• Do dispersants do any harm (that is, are they

toxic?).

Effectiveness. “Dispersant effectiveness” is

defined as a measure of how effective the application

of dispersant might be on a targeted part of a slick. It

is not to be confused with dispersant “operational efficiency” which relates to operational factors such as

having sufficient stockpiles of chemicals, application

platforms, and fast response capabilities. Also, “dispersant effectiveness” means the effectiveness of the

dispersant under field conditions, rather than laboratory conditions. Unfortunately, there is little quantitative information on the effectiveness of dispersants

when used in the field. This is because (1) there have

been only a handful of open-ocean trials; and (2) there

are no acceptable surface-sampling or remote sensing

methods available for measuring the overall thickness

or volume of a spill on the sea surface, and no acceptable methods for determining total volume of dispersed

oil in the water column. Most quantitative information comes from a number of laboratory tests, which

are poor simulators of dispersant-use in the field. The

five most popular laboratory tests today (Swirling

Flask, Labofina, IFP, MNS and Exdet; see Nordvik et

al. 1993) have different designs and produce different

results for identical dispersant/oil combinations. Although the results from any laboratory test can be

useful in providing relative values of dispersant effectiveness between dispersant/oil combinations, they

should not be trusted to predict absolute dispersant

effectiveness values in the field.

A critical factor in the strategy of dispersant

application is that the viscosity of the oil increases

rapidly with weathering, which is a function of evaporation and emulsification (see appendix 5.3 for additional information). When an oil is highly viscous

the applied chemical may simply “roll off” the oil or

does not penetrate and mix with the mass of oil. Because more viscous oil is more difficult to disperse,

response within a few hours is generally essential to

high effectiveness.

Two other critical factors to consider when applying dispersants are the type of oil and sea energies

available. Both of these factors, in turn, affect how

much dispersant is needed for any specific application.

For example, assuming the same amount of dispersant is used in both low and high sea energy conditions, diesel and light crude oils will be dispersed at

rates greater than 50 percent under any conditions.

Medium crude oils, those that would disperse only

under ideal conditions, need a greater amount of sea

energy in order to show any significant dispersibility.

Heavy oils, such as Intermediate Fuel Oil and Bunker

C, do not disperse at a rate of greater than 10 percent

under any circumstances (Fingas, 2001).

A study conducted by McAuliffe, et al. (1981) offshore southern California gives some “rules of thumb”

regarding dispersant effectiveness. While some of these

may appear to be obvious conclusions, they are nevertheless, important considerations when deciding how

to attack an oil spill:

• Chemical dispersion is more effective than

natural dispersion in relatively calm seas;

• Dispersant treatment by air is superior, in most

cases, to dispersant treatment by boat;

• Weathered oil is not dispersed as effectively as

fresh oil; and

3

 U. S. Coast Guard’s PREP was developed to meet

the intent of section 4202 (a) of OPA90. PREP plays a key

role in assuring that to successful responds to major oil and

hazardous chemical incidents occurs. PREP incorporates

the exercise requirements of the U. S. Coast Guard, the

EPA, the Research and Special Programs Administration

(RSPA) [Office of Pipeline Safety] and the MMS. Using

PREP guidelines and participating in PREP exercises will

satisfy all OPA90-mandated federal pollution response exercise requirements. For more information on the PREP

program, see the website at: http://www.uscg.mil/hq/nsfcc/

nsfweb/nsfcc/prep/prephome.html.
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Delineation Drilling Activities Offshore Santa Barbara County

• A dispersant that performed poorly in the laboratory also performed poorly in the field.

Toxicity. The toxicity of dispersants is the other

issue of concern. The wreck of the Torrey Canyon,

offshore England in 1967, was the first occasion where

dispersants, or dispersant-like substances were used

to address oil spills. Unfortunately, the materials used

in that event were extremely toxic and affected the

shoreline organisms and habitats more severely than

did the oil alone. That experience gave the concept of

using dispersants a somewhat undeserved reputation

since the substances used during the Torrey Canyon

incident were of the first generation toxic-type (NRC,

1989). Other early dispersants exhibited toxicities in

the 5 to 50 mg/l LC50 range. Since then, the formulation of dispersants has evolved into carefully controlled

combinations of lower-toxicity solvents with surfactants with LC50s ranging from 200 to 500 mg/l (Fingas,

2001).

Once an oil slick is dispersed, then what? In

most places, oil slicks are subjected to surface currents, winds, and waves. If the oil is all or paritally

removed from the water surface, these factors that directly affect the movement and weathering of the oil,

become detached from any changes in the characteristics of the oil. Subsurface currents then predominate.

If the dispersed droplets are small enough they will

have little buoyancy and will be carried away and diluted by normal ocean current and movement. One of

the inputs to a decision regarding tradeoffs (discussed

below) is where the oil might go if subsurface currents become the predominant influence on the plume

of dispersed oil.

As with other Alternative Response Technologies

(for example, in-situ burning) the decision to apply

dispersants is a balancing of tradeoffs. Since dispersants are never 100 percent effective, any responder

would have to ask if the process of apply dispersants

is worth the costs (both environmental and economic)

of attacking the spill by only mechanical means. A

succinct summary of biological tradeoffs is from NRC

(1989):

• In open waters, organisms on the surface will

be less affected by dispersed oil than by an oil

slick;

• Organisms in the water column, particularly

the upper layers, could experience greater exposure to oil components if the oil was dispersed;

• In shallow water habitats with poor circulation, benthic organisms could be more immediately exposed to dispersed oil;

• Although some immediate biological effects of

dispersed oil may be greater than for untreated

oil, long-term effects on most habitats, such

as mangroves, are less and the habitat recovers more quickly if the oil is dispersed before it

reaches that area;

• Studies have shown that dispersed oil does not

adhere as much as untreated oil to some organisms or habitats; and

• The application of dispersants after oil contacts

some habitats, such as salt marshes, rocky

shorelines and, sand and mud flats, is generally not effective and could do more harm than

good.

A comprehensive discussion on the logistics of

dispersant planning and application is beyond the scope

of this discussion. However, some key factors that

members of the Unified Command must consider in

their decision-making process are:

• availability of dispersant product;

• characteristics of platforms (payload, pump

rate, speed);

• spill conditions (e.g., type of spill, behavior of

the oil, distance offshore);

• ability to identify thick oil areas and position

spray equipment accordingly;

• availability of effectiveness monitoring; and

• weather and daylight hours.

In-situ burning. While mechanical removal is

the preferred method, it is recognized that in-situ burning can be a viable option in conjunction with, or in

lieu of, mechanical or other types of recovery. In-situ

burning has been demonstrated to be a very useful

response tool in open water conditions when used in

conjunction with a fire resistant boom. In-situ burning greatly reduces the need for recovery, storage,

transportation, and disposal of a large percentage of

the spilled oil. Numerous burn tests have been done

in the lab, in test tanks, and in the field (including

one during the second day of the Exxon Valdez spill

cleanup operation), which demonstrate the feasibility

and effectiveness of this technique.

Currently, California does not permit the burning of oil within the State or on State waters. In-situ

burning can be used in the State of California and its

waters by Federal preemption of this Code, which is

only possible under specific circumstances. In-situ

burning may be considered in waters beyond three

miles of the shore, which are under Federal jurisdiction. The Federal On-Site Coordinator (FOSC) would

need to obtain approval from the Environmental Protection Agency (EPA) representative to the Regional

Response Team (RRT). In all cases, the State of Cali-
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

fornia will be notified of the use of in-situ burning.

Preliminary laboratory testing has been conducted on the crude oil currently being produced from

the Santa Barbara Channel and Santa Maria Basin

Areas. The results of these tests indicate that the crude

oil has a low percentage of volatile components that

would cause difficulty to ignite the oil. Therefore, insitu burning of discharged oil may not be an appropriate mitigation measure. Information on the equipment needed and the procedures that would be followed

in preparation for in-situ burning are contained in

appendix 5.3.

Other issues that must be included in any discussion on in-situ burning are efficiency and environmental effects. Burning efficiency is calculated as the

difference between the percentage of residue left and

the initial amount of oil and is largely a function of oil

thickness within the fireproof boom. During the Exxon

Valdez spill, a test burn using the 3M fire resistant

boom was conducted 2 days following the spill. In

this test, an estimated 357 to 714 bbl of North Slope

crude oil were burned in approximately 75 minutes

with an estimated efficiency of 98 percent. The volume elimination rate for this test using a single

500-foot boom was estimated to be between eight to 16

bbl per minute (Allen, 1990).

The primary objective of oil spill abatement and

cleanup is to reduce the effect of spilled oil on the environment. The use of in-situ burning may be considered when the preferred techniques are judged to be

inadequate and the environmental benefit of in-situ

burning outweighs its adverse effects. Some critics of

in-situ burning have raised questions about the effects

of air pollution resulting from the process. Tests conducted by MMS, Environment Canada, and the American Petroleum Institute, to better quantify air quality

data related to in-situ burn processes indicated that

burn products reach safe levels within several kilometers of the burn site and that the eventual concentrations of particulates and associated pollutants are several orders of magnitude below acutely toxic levels.

Additional research is needed to fully document these

hazards and to develop methods to minimize these

hazards.

In August 12, 1993, MMS, USCG, Canadian

Coast Guard, and Environment Canada also co-sponsored a large-scale in-situ test burn off the coast of

Newfoundland, Canada. Environment Canada published a preliminary report that included the following findings:

• Burning at sea is feasible and practical.

• The fireproof boom stood up throughout the

tests, but more work is necessary for it to last

longer. Sea motion combined with heat appears to have reduced the life of the boom (48

hours in test tanks). The total burn during

the tests lasted 4 hours.

• Some observations from the burns did not correspond to previous test tank data. First, several effects, such as the rapid sea burns noted

in test tanks, did not occur at sea. Second,

burn rate calculations must more accurately

account for the effects of wind. Even a small

amount of wind (8-11 km/hr during the second burn) drove the oil far into the apex of the

boom and thereby reduced the burning rate to

about two-thirds of previous calculations.

• Burning outside of the fire-resistant boom occurred on about three occasions as a result of

too much oil in the boom, but did not result in

sheening. Either some form of containment

occurred naturally, or the overflow was very

viscous.

ALTERNATIVE RESPONSE TECHNOLOGIES–

ONSHORE

Shoreline cleaning agents, bioremediation and

no action are other options for oil spill responders.

Each of these involve tradeoffs, have their own

strengths and weaknesses, and have their particular

roles during the response to an oil spill. Appendix 5.3

contains additional detail on these tools.

5.2 ENVIRONMENTAL IMPACTS OF

ALTERNATIVE 1: THE PROPOSED

ACTION

5.2.1 IMPACTS ON AIR QUALITY

The following significance criteria levels were

used in the impact analysis for air quality to determine whether the proposed delineation projects emissions could result in air quality impacts.

High - Project may cause or contribute to a violation of Federal or State ambient air quality

standards, and exceed threshold emission levels that have been determined to result in significant impacts to air quality. Impacts deemed

to be high are considered to be significant.

Moderate - Project does not result in any violations of Federal or State ambient air standards,

but does exceed threshold emission levels that

have been determined to result in significant

impacts to air quality. Impacts deemed to be

moderate are considered significant, but are

mitigable to an insignificant level.