6-1

Description of the Affected Environment: Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

Chapter 6

Cumulative Impact Analysis For The

36 Undeveloped Leases (2002 - 2030)

Table of Contents

6.0 Introduction ................................................................................................................................. 6-3

6.1 Background Information for Impact Analysis .................................................................. 6-3

6.1.1 Impact Causing Agents of The Cumulative Case (2002-2030) ............................... 6-3

6.1.2 Reasonably Foreseeable Activities (2002-2030)....................................................... 6-4

6.1.3 Hypothetical Development Scenario for the 36 Undeveloped Leases ...................6-10

6.2 Environmental Impacts of Development of the 36 Undeveloped Leases ........................6-17

6.2.1 Cumulative Air Quality Impacts (2002-2030) ........................................................6-17

6.2.2 Cumulative Water Quality Impacts (2002-2030) ....................................................6-24

6.2.3 Cumulative Rocky and Sandy Beach Habitat Impacts (2002-2030) .....................6-31

6.2.4 Cumulative Seafloor Resources Impacts (2002-2030) ............................................6-36

6.2.5 Cumulative Kelp Bed Impacts (2002-2030) ............................................................6-38

6.2.6 Cumulative Fish Resources Impacts (2002-2030) ..................................................6-40

6.2.7 Cumulative Marine and Coastal Birds Impacts (2002-2030) ................................6-43

6.2.8 Cumulative Marine Mammals Impacts (2002-2030) ..............................................6-46

6.2.9 Cumulative Threatened and Endangered Species Impacts (2002-2030) ...............6-50

6.2.10 Cumulative Estuarine and Wetland Habitats Impacts (2002-2030).....................6-64

6.2.11 Cumulative Refuges, Preserves and Marine Sanctuaries Impacts (2002-2030) ....6-68

6.2.12 Cumulative Onshore Biological Resources Impacts (2002-2030) .........................6-69

6.2.13 Cumulative Cultural Resources Impacts (2002-2030) ..........................................6-70

6.2.14 Cumulative Visual Resources Impacts (2002-2030) ..............................................6-73

6.2.15 Cumulative Recreation Impacts (2002-2030) ........................................................6-76

6.2.16 Cumulative Community Characteristics and Tourism Resources

 Impacts (2002-2030) ...............................................................................................6-78

6.2.17 Cumulative Employment and Population Impacts (2002-2030) ...........................6-80

6.2.18 Cumulative Housing Impacts (2002-2030)............................................................6-82

6.2.19 Cumulative Infrastructure Impacts (2002-2030) ..................................................6-82

6.2.20 Cumulative Public Finance and Services Impacts (2002-2030) ...........................6-83

6.2.21 Cumulative Non-Residential Land Use Impacts (2002-2030) ..............................6-84

6.2.22 Cumulative Commercial Fishing and Kelp Harvest Impacts (2002-2030) ..........6-85

6.2.23 Cumulative Marine Recreational Fishing Impacts (2002-2030) ..........................6-87

6.2.24 Cumulative Military Operations Impacts (2002-2030) .........................................6-90

6.3 Environmental Impacts of the High Case Scenario ........................................................6-92
6-2

Delineation Drilling Activities Offshore Santa Barbara County
6-3

Description of the Affected Environment: Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

Chapter 6

Cumulative Impact Analysis For The

36 Undeveloped Leases (2002 - 2030)

6 CUMULATIVE IMPACT ANALYSIS

FOR THE 36 UNDEVELOPED LEASES

(2002-2030)

6.0 INTRODUCTION

As discussed earlier, section 5 provides an analysis of how the Proposed Action will likely affect the

resources in or migrating through the study area. The

likely effects of the Proposed Action over the nearterm future (2002-2006) provide a clear understanding of the contribution of the Proposed Action to the

effects of other ongoing activities during this time

period. After 2006 no further residual effects associated from the Proposed Action are expected to occur.

This section (section 6) provides an analysis of the

effects over the near- and long-term future (2002-

2030). This timeframe includes the contribution of

potential activities on all 36 currently undeveloped

leases, through decommissioning.

The assumptions made concerning the nearterm foreseeable future activities in and influencing

the study area are in sections 5.1.2.1, and 5.1.2.2. The

long-term future is based on the MMS developed hypothetical development scenario for the 36 undeveloped leases. This is described in detail in sections

6.1.2, and 6.1.3. Environmental effects on each of the

resources are presented in section 6.2.1-6.2.24.

6.1 BACKGROUND INFORMATION FOR

IMPACT ANALYSIS

6.1.1 IMPACT CAUSING AGENTS OF THE

CUMULATIVE CASE

This section identifies additional impact producing factors (IPF) that are associated with the potential development of the 36 undeveloped leases and any

potential future development of existing leases. 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

delineation drilling activities will not be restated here.

However, the effects from those activites and the cumulative activities are considered and discussed in each

resource section for the near-term (2002-2006) in section 5.2.1, through 5.2.24, and the long-term (2002-

2030) in section 6.2.1 through 6.2.24.

Impact producing factors including past and

present activities were already discussed in Section

4.0.1. Tables in Section 6.1.2 and 6.1.3 show the magnitudes of the impact-producing factors that are projected to occur in the various offshore/onshore areas

from the potential development of the 36 undeveloped

leases in the study area. These quantities are expressed as the total amount generated over the life

for the development of the undeveloped leases (2002-

2030).

• Geological and Geophysical Surveys

• Development and Production activities (Development activities include 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

• Decommissioning

• Site Characterization Surveys for OCS Development

• Shallow Hazards Surveys

• Subsurface Investigation and Testing

• Extended Reach Drilling

• Pipeline Installation and Abandonment

• Crude Oil Tankering
6-4

Delineation Drilling Activities Offshore Santa Barbara County

• Oil Spills

• Fiber Optic Data Tranmission Cables

• State Tidelands Projects

• Spill Remediation

• Point and Nonpoint Source Discharges

• Commercial Fishing Activities

• Military Operations and Commercial Space

Launches

Table 6.1.1-1 provides a summary of activities

projected for existing and future OCS and State leases

(2002-2030). 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 (2002-

6.1.2 REASONABLY FORESEEABLE

ACTIVITIES (2002-2030)

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.

Two categories of Reasonably Foreseeable activities are examined:

First are activities that are ongoing and expected

to continue during the period 2002-2030. Non-point

source discharges are included in the category.

Second are oil and gas activities that could occur in the period 2002-2030.

Many of the activities described in this section

are the same as in section 5.1.2.2 Reasonably Foreseeable Activities. This section differs from section 5

in that it considers the delineation drilling and additional reasonably foreseeable activities for the period

2002-2006 in addition to all activities that could occur

during the 2002-2030 timeframe including: 1) delineation drilling, 2) decommissioning and removal of

existing production facilities, and 3) development of

the 36 undeveloped leases (see section 6.1.3 Hypothetical Development Scenario For The 36 Undeveloped

Leases). Delineation drilling would occur during the

2002-2003 timeframe and was considered in the analysis in chapter 5. However, potential future exploratory and development activities that could occur after all residual effects from the proposed action are

gone are considered in this section.

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 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 identifed in table 4.0.1-7. Helicopter and vessel

support is assoumed 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.

Table 6.1.1-1. Summary of activities projected for existing and future OCS and state leases ( 2002-2030). y pj g ( )

Activity Future Activity on 

Existing OCS Facilities 

Future Activity on State 

Existing Facility1 Activity on 36 Undeveloped Leases 

Total 

Wells Drilled 50 0 50 50+? 

Platforms Installed 0 0 5 5 

Miles of Pipelines Installed 0 0 130 130 

Platforms Removed 23 9 5 37 

Crew and Supply Boat Trips 122,416 105,542 42122 232,170 

Helicopter Trips 50,264 13,260 412452 104,769 1

 Assumes THUMS platforms are removed in 2010 

2

 Gato Canyon Platform would be served at same time as SYU until 2025 and Bonito Platform would be served at same time as Platform Irene through 

decommissioning. 
6-5

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

Table 6.1.2-1. Platform decommissioning project scenarios.

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

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 (OSPR). 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,

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. For example, 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.

For purposes of analysis in this EIS, we make

the following assumptions:

• Platforms will be decommissioned in groups

of 3-9 based on age, size, geographic location,

and heavy lift vessel (HLV) lifting capability.

• Pipelines will be abandoned in place.

• Platform decommissioning projects will be

phased and occur in the following chronological sequence: (1) South Coast (2) Eastern

Santa Barbara Channel, (3) Western Santa

Barbara Channel and Southern Santa Maria

Basin (4) Western Santa Barbara Channel, (5)

Southern Santa Maria Basin (6) Northern/

Southem Santa Maria Basin and Gato Canyon

(see table 6.1.2-1).

• HLV’s spreads (see table 6.1.2-2) will be mobilized from the GOM, North Sea, or Asia. No

more than one HLV will be operating at a time.

Decommissioning of platforms will be phased

to minimize environmental impacts. Associated onshore processing facilities will be decommissioned immediately after the offshore

component of the project has been completed.

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

Project I - South Coast (Los Angeles/Orange County) 

4 OCS Platforms: Eureka, 

Ellen, Elly, Edith 

3 State Tidelands Platforms: 

Emmy, Eva, Esther 

Time-period: 

Decommissioning could 

occur between 2010-2015 

Project Duration/Scheduling230 days Vessel Spread B Disposal Site: Long Beach, 

CA 

Project II - Eastern Santa Barbara Channel (Ventura and Santa Barbara County) 

9 OCS Platforms: Hogan, 

Houchin, A, B, C, Gina, 

Gilda, Henry, Hillhouse 

Time-period: 

Decommissioning could 

occur between 2012-2017 

Project Duration/Scheduling - 

200 days 

Vessel Spread A Disposal Site: Long Beach, 

CA 

Project III - Santa Barbara Channel and Southern Santa Maria Basin (Santa Barbara County) 

7 OCS Platforms: Gail, 

Grace, Hermosa, Harvest, 

Hidalgo, Irene, Habitat 

1 State Tidelands Platform: 

Holly 

Time-period: 

Decommissioning could 

occur between 2015-2020 

Project Duration/Scheduling - 

400 days 

Vessel Spread B Disposal Site: Portland, OR 

Project IV - Western Santa Barbara Channel (Santa Barbara County) 

3 OCS Platforms: Hondo, 

Harmony, Heritage 

Time-period: 

Decommissioning could 

occur between 2020-2025 

Project Duration/Scheduling - 

270 days 

Vessel Spread C Disposal Site: Portland, OR 

Project V - Northern/Southern Santa Maria Basin and Gato Canyon (Santa Barbara County) 

5 OCS Platforms (to be 

constructed) 

Time-period: 

Decommissioning could 

occur between 2040-2050 

Project Duration - 250 days Vessel Spread B Disposal Site: Portland, OR 
6-6

Delineation Drilling Activities Offshore Santa Barbara County

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

(California Energy Commission, 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 Arguello and Rocky Point Units are

also in the vicinity and operational area of the Western Space and Missile Center (WSMC) at Vandenberg

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

Table 6.1.2-2. Conventional decommissioning vessel spreads. g p

Derrick Barge Anchor Handling Support Vessel Cargo Barges Tug Boat(s) Support Craft 

Spread A (for platforms in 50 - 200 foot water depths) 

1 HLV (Derrick Barge 

Valhalla - 400 ton lift 

capability) 

1 anchor handling tug 1 support vessel 3 cargo barges 2 tugboats crew boats (use current 

level) 

supply boats (use 

current level) 

helicopters (use current 

level) 

Spread B (for platforms in 200 - 700 foot water depths) 

1 HLV (Derrick Barge 

Balder or DB 50 - 4000 

ton lift capability) 

1 anchor handling tug 1 support vessel 6 cargo barges 4 tugboats crew boats (use current 

level) 

supply boats (use 

current level) 

helicopters (use current 

level) 

Spread C (for platforms in 700+ feet of water) 

1 HLV (Derrick Barge 

Thialf or Saipem 7000: 

6600 - 7000 ton lift 

capability) 

1 anchor handling tug 1 support vessel 10 cargo barges 10 tugboats crew boats (use current 

level) 

supply boats (use 

current level) 

helicopters (use current 

level) 
6-7

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

of the United States to suspend offshore operations

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 Southern California Bight (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 ex-
6-8

Delineation Drilling Activities Offshore Santa Barbara County

tremely viscous, with a density that causes the crude

oil to 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 3 to 40 m(10 to 130 feet) down,

with some plumes as much as 1.8 m (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

standard.

FIBER OPTIC DATA TRANMISSION 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.
6-9

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

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.

OIL AND GAS ACTIVITIES THAT MAY

OCCUR IN THE PERIOD 2002-2030

The following oil and gas activities could occur

the period (2002-2030) and include Federal Offshore

OCS Projects; Cavern Point Unit Exploration, development of some of the 36 undeveloped leases, Exploration Well OCS-P 0320 #2 Abandonment, Exploration Well OCS-P 0241 #2 Abandonment, 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

DELINEATION DRILLING (2002-2003)

Delineation drilling activities are described in

chapter 2.

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.

DEVELOPMENT OF THE 36 UNDEVELOPED

LEASES

A hypothetical development scenario for the 36

undeveloped leases is presented in section 6.1.3.

EXPLORATION WELL ABANDONMENT,

OCS-P 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.
6-10

Delineation Drilling Activities Offshore Santa Barbara County

EXPLORATION WELL ABANDONMENT, OCSP 0241 #2 (2003)

Torch Operating Company (Torch) 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 when delineation drilling is 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.

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.

6.1.3 HYPOTHETICAL DEVELOPMENT

SCENARIO FOR THE 36

UNDEVELOPED LEASES

This scenario was developed for the purpose of

cumulative analysis for this EIS and provides assumptions for the analysis of development of the 36 undeveloped leases. The scenario is based on:

• Project Descriptions (PD’s) provided by Unit

Operators(Aera, 2000a, Aera, 2000b, Nuevo,

2000, and Samedan 2000) indicating: 1) where

a production platform might be located and,

2) production destinations.

• Operator submitted Rocky Point PD and Revised Development and Production Plans

(DPP’s) for Platforms Hermosa, Harvest, and

Hidalgo.

• MMS resource estimates.
6-11

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

SITE CHARACTERIZATION SURVEYS FOR

OCS DEVELOPMENT

A Development and Production Plan for a platform must include a complete site investigation program. The site investigation program generally consists of three major phases (30 CFR 250.909):

• Shallow hazards survey to obtain data needed

to analyze seafloor and subsurface geologic and

manmade hazards

• Geological survey to obtain data of a regional

nature concerning the site

• Subsurface investigation and testing to obtain

the necessary geotechnical data.

SHALLOW HAZARDS SURVEY

A high-resolution or acoustic-profiling survey is

required to obtain information on the conditions existing at and near the surface of the seafloor. A survey

is required for proposed production platform sites and

proposed pipeline routes. The Pacific OCS Region issues guidance in regional Notice to Lessees and Operators for developing survey strategies capable of

detecting and evaluating hazardous conditions that

might be in the vicinity of the proposed development

site(s).

Table 6.1.3-1 Shallow Hazards Surveys for Development, summarizes the number and timing of

shallow hazards surveys by three development areas.

GEOLOGICAL SURVEY

Background geological data is required to provide regional information that can affect the design

and siting of a platform or route of a pipeline.

• Based on those resource estimates, MMS estimates of platforms, piplines, power cables, onshore facilities characteristics, and other information.

• MMS requirements for site investigation prior

to installation of platforms and pipelines.

• MMS requirements for periodic inspections

after installation of platforms and pipelines.

Resources from eight leases are planned to be

produced from existing POCSR platforms:

• Rocky Point, OCS-P 0452, 0453, Plaforms

Harvest, Hermosa, and Hidalgo.

• Sword Unit, OCS-P 0319, 0320, 0322, and

0323A, Hermosa.

• Cavern Point, OCS-P 0210 and 0527, Plaform

Gail.

Resources from 28 leases are planned to be produced from five new POCSR platforms:

• Lease OCS-P 0409.

• Lion Rock Unit, OCS-P 0396, 0397, 0402, 0403,

0408, and 0414.

• Point Sal Unit, OCS-P 0415, 0416, 0421, and

0422.

• Purisima Point Unit, OCS-P 0426, 0427, 0432,

and 0435.

• Santa Maria Unit, OCS-P 0425, 0430, 0431,

0433, and 0434.

• Bonito Unit Unit,, OCS-P 0443, 0445, 0446,

0449, 0499, and 0500.

• Gato Canyon Unit, OCS-P 0460 and 0464.

Table 6.1.3-1. Shallow hazards surveys, hypothetical development of the 36 undeveloped leases.

Area Survey Platforms Pipelines 

Plans Number Survey Area per 

Platform (mi2

) 

Length of 

Pipeline Corridor 

(mi) 

Area of Pipeline 

Corridor (mi2

) 

Timeframes 

NSMB 1 3 1.2 25 19 2003 

Bonito Unit 1 1 1.2 4 1/2 3.4 2004 

Gato Canyon 

Unit 

1 1 1.2 5 1/3 4.3 2003 
6-12

Delineation Drilling Activities Offshore Santa Barbara County

SUBSURFACE INVESTIGATION AND

TESTING

A detailed geotechnical evaluation of the

platform’s foundation is required. For pile supported

platforms, such as those likely to be installed in the

Pacific OCS Region, this will entail at least one borehole having a minimum depth of the anticipated length

of the pile plus a zone of influence to be drilled at the

proposed installation site. The regulations at 30 CFR

250.909 provide specific requirements for subsurface

investigation and testing for platforms.

In addition, the operator will be required to perform sufficient geological/geotechnical sampling and

testing of foundation soils within a proposed pipeline

corridor to thoroughly categorize foundation-engineering conditions.

The MMS will review the results of the site investigation program prior to approving a proposed

platform site or pipeline route. Based on the review,

the operator may be required to verify hazards, archaeological resources or sensitive habitats to ensure

safety of personnel and equipment and protection (or

avoidance) of archaeological resources, etc. This may

require the use of equipment and techniques such as

underwater video/photography, hydrocarbon sniffer

surveys, diver inspection, current velocity measurements, additional seafloor sampling and/or geologic

age dating.

PERIODIC INSPECTIONS

All platforms and pipelines installed in the Pacific OCS Region will be inspected periodically in accordance with applicable regulations and regional

Notice to Lessees and Operators. Inspections for platforms could include, but is not limited to, visual, cathodic protection, magnetic particle, or ultrasonic testing.

Routine inspections on pipelines include visual

(diver and/or remotely operated vehicle), side scan

sonar (SSS), and high resolution internal surveys.

Pipeline SSS surveys must be conducted at least once

every six years.

Figure 6.1.3-1. Potential platform, pipeline, and

power cable locations, northern Santa Maria Basin

units.

Figure 6.1.3-2. Potential platform, pipeline, and

power cable locations, Bonit Unit.
6-13

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

Figure 6.1.3-3. Potential platform, pipeline, and

power cable locations, Gato Canyon Unit.

Table 6.1.3-2. Surface structures, pipelines and power cables, and production offshore Southern

California, hypothetical development of the 36 undeveloped leases.

HYPOTHETICAL DEVELOPMENT SCENARIO

The hypothetical development scenario includes

development 1) from existing platforms and 2) development that requires new platforms. The Rocky Point

Unit would be developed from Platforms Hermosa,

Harvest, and Hidalgo. The Sword Unit would be developed from Platform Hermosa. The Cavern Point

Unit would be developed from Platform Gail. Five new

platforms are estimated to develop most of the remaining 36 undeveloped leases. Three platforms would

develop the northern Santa Maria Basin area (figure

6.1.3-1, one would develop the Bonito Unit (figure

6.1.3-2), and one would develop the Gato Canyon Unit

(figure 6.1.3-3). Tables 6.1.3-2 and 6.1.3-3 provide scenario estimates of 1) reserves, platforms, pipelines,

power cables, and production, 2) dates and length of

time for installation, 3) dates for production and decommissioning, 4) pipeline destination, and 5) support

activities.

Extended reach drilling technologies would be

used to produce the fields efficiently with the minimum number of new facilities. MMS has assumed in

this scenario that all new platforms would be conventional fixed platforms similar to existing Pacific OCS

facilities and that development activities, processing,

and other operations both offshore and onshore would

Platforms Pipelines and Power Cables Production 

Peak Production: Oil 

and Gas 

Platform Operator Location Well Slots 

Production Wells 

Service Wells 

Remaining Well Slots 

Year To 

Be 

Installed 

Size, Type, and 

Number 

Year 

Installed 

Onshore 

Facility 

(pipeline 

destination) 

Field Date 1st

Production 

Volume 

(bbls/day) 

(MCF/day) 

Year 

Reserves 

Expected To 

Be Developed 

by Field: oil 

(MMbbl) gas 

(Bcf) 

SMB 

“A” 

60 

45 

6 

9 

2008 16” oil/water 

8”gas 

10” water return 

8” service 

2 power cables 

To SMB 

Central 

Lease 

OCS-P 

0409, Lion 

Rock, and 

Point Sal 

2009 35,000 

10,500 

2016 115 

47 

SMB 

“B” 

60 

49 

6 

5 

2007 24” oil/water 

10”gas 

12” water return 

8” service 

3 power cables 

Casmalia Point Sal 

and 

Purisima 

Point 

2009 32,000 

6,400 

2017 118 

24 

SMB 

“C” 

AERA Point Sal 

60 

46 

6 

8 

2008 16” oil/water 

8”gas 

10” water return 

8” service 

2 power cables 

3/2008 – 

1/2009 

To SMB 

Central 

Santa 

Maria, and 

Purisima 

Point 

2009 25,000 

5,000 

2017 90 

18 

Bonito Nuevo Point 

Arguello 

36 

21 

6 

9 

2008 14” oil/water 

8”gas 

10” water return 

2 power cables 

4/2009 – 

9/2009 

To 

Platform 

Irene to 

Lompoc 

Bonito and 

Electra 

2010 26,000 

13,000 

2015 68 

34 

Rocky 

Point 

Arguello 

Inc. 

Point 

Arguello 

N/A 

14 

6 

N/A 

Existing 

Plaforms 

Harvest, 

Hermosa, 

and 

Hidalgo 

See Table 4.0.1-4 See 

Table 

4.0.1-4 

Gaviota Rocky 

Point 

2002 18,500 

5,550 

2006 39 

11.7 

Sword 

Uses 

Existing 

Plaform 

Hermosa 

Samedan Point 

Arguello 

N/A 

10 

1 

N/A 

Existing 

Plaform 

Hermosa 

See Table 4.0.1-4 See 

Table 

4.0.1-4 

Gaviota Sword 2003 12,500 

3,125 

2007 29 

7.3 

Gato 

Canyon 

Samedan Naples 

Beach 

28 

20 

4 

4 

2007 14” oil/water 

8”gas 

8” water return 

2 power cables 

11/2007 

– 2/2008 

Corral 

Canyon 

Gato 

Canyon 

2008 22,500 

13,500 

2013 77 

46 

Cavern 

Point 

Uses 

Existing 

Plaform 

Venoco Anacapa 

Island 

N/A 

10 

1 

N/A 

Existing 

Plaform 

Gail 

N/A N/A Carpenteria 

via 

Platform 

Grance 

Cavern 

Point 

2003 9,600 

8,640 

2006 22 

20 
6-14

Delineation Drilling Activities Offshore Santa Barbara County

be very similar to the existing facilities and operations.

These platforms are assumed to have a number of

curved conductors to allow for reaching remote targets using extended reach drilling technology. MMS

has assumed that gas and oil production would be sour

with limited offshore processing. All jackets would

most likely be fabricated overseas and require 12-14

months to fabricate and 3 months to loadout and transport to the hypothetical platform location. Topside

modules would most likely be fabricated in the Gulf

of Mexico. Table 6.1.3-4 provides estimates of the number of days required for the phases of construction for

each platform.

All crew and supply boat operations would originate from Port Hueneme or Carpinteria pier. All helicopter operations would originate from either the Santa

Maria or the Santa Barbara airports.

Peak production for new facilities may be lower

than that attained by existing platforms in the Pacific

Region. The new platforms would contain extended

reach wells, which, based on industry’s current experience, take longer to drill. This fact causes the peak

production to occur later in the life of the field, and

Table 6.1.3-4. Estimates of the number of days required for the phases of construction,

hypothetical development of the 36 undeveloped leases.

Table 6.1.3-3. Surface structures offshore Southern California, construction timing, production support

activities, and decommissioning timing, hypothetical development of the 36 undeveloped leases.

stretches the peak out so that the actual peak production is lower.

With proper planning, the 5 potential platforms

could be installed in a sequential order over a 2-3 year

period using a single derrick barge (also called a Heavy

Lift Vessel or Crane Vessel) rather than 5 separate

derrick barges required if the platforms were installed

independently. A derrick barge with a 2999-metric ton

(3000-ton) capacity should be adequate to install all

the platforms in the scenario described below. The timing of the operation including first production for each

facility would have to allow for a coordinated effort

for this to be possible. Using the information from

the operators’ PD’s and development and production

activity timelines, a coordinated effort of sharing a

derrick barge appears possible. We assume all the 5

new platforms would be electrified due to Santa Barbara Air Pollution Control District requirements. We

also assume pipelines would be installed using a pipeline lay barge and the power cables would be installed

using a power cable vessel. With proper planning it

may also be possible for the pipelines and power cables

to be installed in a sequential manner sharing the

needed pipeline and power cable lay vessels.

Platforms Construction Production and Support Activities Decommissioning 

Platform 

Water Depth 

Operator Location Of 

Nearest Land 

Year Installed Field Date 1st Production Helicopter Trips 

per week with 

Yearly Total4

Crew and Supply 

Boat Trips with 

Yearly Total4

Estimated 

Removal Date 

SMB North 

450 ft. 

2008 Lion Rock and 

Point Sal 

2009 

SMB Central 

300 ft. 

2007 Point Sal, Santa 

Maria, and 

Purisima Point 

2009 

SMB South 

300 ft. 

AERA Point Sal 

2008 Santa Maria, and 

Purisima Point 

2009 

5/day - 1825/yr 3/wk – 156/yr 2024 – 2029 

Bonito 

700 ft. 

Nuevo Point Arguello 2008 Bonito and Electra 2010 Existing rates for 

Arguello Platforms 

and Irene 

Existing rates for 

Arguello Platforms 

and Irene 

2015-2020 (w/o 

Tranquillion Ridge 

Development) 

2030-2035 (with 

Tranquillion Ridge 

Development)

Rocky Point 

Existing Plaform 

Hermosa , Harvest, 

and Hidalgo 

Arguello Inc. Point Arguello Existing Plaform 

Hermosa , Harvest, 

and Hidalgo 

Rocky Point 2002 Existing rates for 

Arguello Platforms 

and Irene 

Existing rates for 

Arguello Platforms 

and Irene 

2015-2020

Sword 

Existing Plaform 

Hermosa 

Samedan Point Arguello Existing Plaform 

Hermosa 

Sword 2003 Existing rates for 

Arguello Platforms 

and Irene 

Existing rates for 

Arguello Platforms 

and Irene 

2015-2020

Gato Canyon 

560 ft. 

Samedan Naples Beach 2007 Gato Canyon 2008 1/day 2-3/ week 2023 - 2028 

Cavern Point 

Existing Plaform 

Gail 

Venoco Anacapa Island Existing Plaform 

Gail 

Cavern Point 2003 Existing rates for 

Platforms Gail 

Existiing rates for 

Platforms Gail 

2015-2020

Platform Launch Jacket Drive Piles/ Set 

Topsides 

Install Pipelines Install Power 

Cables 

Comissioning 

Gato 1 153 93 63 214 

SMB “B” 1 93 456 

SMB “A” 1 121 335 

SMB “C” 1 92 

276 123 

243 

Bonito 1 183 92 63 304 
6-15

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

SANTA MARIA BASIN DEVELOPMENT

Three platforms would be located in the northern Santa Maria Basin (NSMB) area and would be

used to recover reserves in the Lion Rock Unit,

Purisima Point Unit, Point Sal Unit, and Santa Maria

Unit and Lease OCS-P 0409, see figure 6.1.3-1 Platforms names are used as follows:

SMB “A” is the northern Santa Maria Basin platform located on Lease OCS-P 0409.

SMB “B” is the central Santa Maria Basin platform located on Lease OCS-P 0422.

SMB “C” is the southern Santa Maria Basin platform located on Lease OCS-P 0431.

SMB “A”

Reservoirs up to 6.44 km (4 mi) horizontally

away could be reached from this platform using current drilling technology. The production from this platform would go by pipelines to SMB “B”.

SMB “B”

Reservoirs up to 4.83 km (3 mi) to 6.44 km (4

mi) horizontally away could be reached from this platform using current drilling technology. The production from SMB “A” and SMB “C” would go by pipelines to this central platform and then on to shore.

SMB “C”

Reservoirs up to 4.83 km (3 mi) to 6.44 km (4

mi) horizontally away could be reached from this platform using current drilling technology. The production from this platform would go by pipelines to SMB

“B”.

The oil emulsion and gas would go to shore in

separate pipelines for processing. The processing of

the production would be mainly accomplished at the

onshore facility. Because of the nature of the crude oil

and its high viscosity, pipeline transport of the oil

emulsion is predicated on having water content of at

least 50% in the pipeline (known as “wet-flow” transport). We estimate that a 61-cm (24-inch oil) emulsion and a 25-cm (10-inch) gas pipeline to the onshore

processing facility should be adequate for this purpose.

The OSMB crude is highly viscous, API Gravity

5-15, by industry standards and requires special consideration to optimize transportation and refining. The

optimum product of the OSMB crude has not been

decided on; refining options continue to be studied

and evaluated. At this time, it cannot be definitively

said what transportation method(s); pipelines, rail,

truck, or a combination of all three, would be used for

the OSMB crude from the hypothetical processing facility. As stated in the COOGER study, rail and truck

transportation, may be required due to viscosity and

delivery limitations of pipelines.

The oil emulsion and gas would be sent to a hypothetical processing facility located in the Casmalia

area, similar to the Lompoc Oil and Gas Processing

facility, where the oil and gas would be processed for

further distribution through local pipelines. There is

also the potential for a co-located asphalt facility. All

oil would be sold. Some of the gas may be used as fuel

on the platform for production operations. Gas may

be 1) re-injected at one or more of the NSMB platforms or 2) used at a hypothetical co-located onshore

co-generation facility and be returned to the platforms

as electrical power, or 3) sold to the gas utility. A combined processing, asphalt, and co-generation facility

would be roughly twice the size of the of the Lompoc

Oil and Gas Processing facility. Pipelines from the

hypothetical processing facility would probably tie into

the All American Pipeline system at an existing pump

station.

The North County Siting Study (Santa Barbara

County, 2000) identifies constraints to the siting of

new oil and gas processing facilities. The study identifies a number of potential sites and identifies two

sites as a prefered location; Casmalia East or West.

For purposes of this analysis the Casmailia East site

was chosen as the location of the onshore oil and gas

processing facility.

The pipelines from SMB “B” would come onshore through the sandy shoreline associated with the

Pt. Sal and Lion Rock area, south of the area with

surface outcrops of the Monterey formation and north

of the mouth of Shuman Creek. The pipeline would

be placed in a 1⁄2 mile-wide corridor from the landfall

to the Casmalia East site. The northern boundary runs

due east to the Casmalia site. The southern boundary

of the corridor runs along Pt. Sal Road and maintains

a separation from the town of Casmalia, slopes prone

to landslides, and Shuman Creek.

Produced water would be treated at the hypothetical oil and gas processing facility and then transported offshore by a 30-cm (12-inch) water return line

to the OCS-P 0422 platform for offshore disposal or

down-hole injection there or at one of the interconnected platforms. There would also be 25.4 cm (10-

inch) produced water pipelines between the platforms.

Included are 20.3 cm (8-inch) service/utility pipelines

between the platforms and between the OCS-P 0422

platform and shore for additional options and operational flexibility due to the nature of the heavy oil. A

40 by 0.8 km (25 by 1⁄2 mile) corridor (4 pipelines for a

total of 161 km (100 miles)) of new pipelines that would

be needed to complete the offshore portion of the

NSMB project (see figure 6.1.3-1).

The three platforms are assumed to be electrified and there would be three power cables from shore

to the central platform (SMB “B”), one power cable
6-16

Delineation Drilling Activities Offshore Santa Barbara County

each from shore to the SMB “A” and SMB “C”, and

one power cable each between SMB “B” and SMB “A”

and SMB “B” and SMB “C”.

BONITO UNIT DEVELOPMENT

One platform located on OCS-P 0443 (Platform

Bonito) would be used to develop the Bonito Unit area.

Reservoirs up to 6.44 km (4 mi) horizontally away

could be reached from this platform using current

drilling technology. API Gravity of Bonito crude oil is

estimated at 11-22. The production from Platform

Bonito would go by new pipelines to Platform Irene

on Lease OCS-P 0441 where existing J-tubes have

previously been installed to accommodate future pipelines. A new 35.5 cm (14-inch) oil pipeline, a new 20.3

cm (8-inch) gas pipeline and a new 25.4 cm (10-inch)

water return line between the platforms would be adequate for this purpose. The 3 pipelines would be placed

in a 7.2 km by 0.8 km (4 1⁄2 by 1⁄2 mile) corridor, with a

total of approximately 22.5 km (14 miles) of new pipelines (see figure 6.1.3-2).

At Platform Irene, the Bonito production would

be commingled with the Point Pedernales and

Tranquillon Ridge production before being sent to

shore via Platform Irene’s existing pipeline system to

the Lompoc Oil and Gas Processing facility. The oil

and gas would be dehydrated at the facility using existing capacity. The excess water would either be injected onshore, sent back to Irene for ocean disposal

or formation injection at Irene or transported via pipeline to the Bonito Unit for ocean disposal or formation injection. From the Lompoc Oil and Gas Processing facility, the dehydrated oil would be sold to Tosco.

The dehydrated gas would go to the Southern California Gas pipeline system. Electric power to the platform would most likely be supplied from an existing

substation located onshore approximately 19.3 km (12

miles) northeast of the Bonito Unit. One power cable

would be run from Platform Irene to the platform and

another power cable would go to the Bonito Unit Platform from the substation.

ROCKY POINT UNIT DEVELOPMENT

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.

SWORD UNIT DEVELOPMENT

The Sword Unit includes leases OCS-P 0319,

0320, 0323, and 0323A. Samedan Oil Company is the

Unit operator. 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.

GATO CANYON DEVELOPMENT

One platform located on Lease OCS-P 0460

(Platform Gato) would be used to develop the Gato

Canyon Unit area. Reservoirs up to 4.8 km (3 miles)

horizontally away could be reached from this platform

using current drilling technology. API Gravity of Gato

Canyon crude oil is estimated at 10-26. The jacket be

installed starting in 2007. First oil and gas production would be in 2008. Oil production would peak at

22,500 bopd in 2013. Gas production would peak at

13,500 MCFD in 2013. The production from Platform

Gato would be sent to shore via 3 new pipelines. A

35.5 cm (14-inch) oil pipeline, an 5.5 cm (8-inch) gas

pipeline and an 5.5 cm (8-inch) return pipeline would

be adequate. The 3 pipelines would be placed in a 8.8

by 0.8 km (5 1

/

3

 by 1⁄2 mile) corridor, a total of approximately 25.7 km (16 miles) of new pipelines for the

offshore portion of this project (see figure 6.1.3-3).

The oil and gas would be sent to shore to the

ExxonMobil operated facilities at Las Flores Canyon.

The gas sent to shore would be sour and that there

would be limited processing offshore. The pipelines
6-17

Cumulative Impact Analysis for the 36 Undeveloped Leases (2002-2030)

would run from the platform and transverse State

Lease PRC 2991.1 to and landfall through the the existing Exxon SYU pipeline crossings and corridor. New

pipelines would be run to Las Flores Canyon. Production from the platform would be processed at Las

Flores Canyon using existing capacity and the oil

shipped in the All American Pipeline, now owned by

Plains All American Pipeline, L.P. The gas would be

processed at the Exxon Gas Plant using existing capacity and sold to the Gas Company. The produced

water would be treated at the existing water treatment plant at Las Flores Canyon, transported offshore

by pipeline and disposed of at the Gato Canyon Unit

Platform. The platform is assumed to be electrified

and two power cables would be run to the platform

from the existing co-generation facility located in Las

Flores Canyon.

PIPELINE AND POWER CABLE

INSTALLATION

We assume that the pipelines between platforms

and platforms to the landfalls (Gato Canyon Unit and

Northern Santa Maria Basin) are accomplished with

a pipeline lay barge with one pass per pipeline. The

number of passes with the lay barge is dependent on

the number of pipelines between the inter-connecting

platforms and the platform to shore pipelines. The

number of pipelines between the platforms is three

for Bonito Unit to Irene, three for Gato Canyon Unit

to shore and four for NSMB development, both between the platforms and between SMB “B” and shore.

Installation of power cables would be completed by

reeling the power cable off a power cable vessel into

the same corridors as the pipelines. The power cables

are connected to the platforms by pulling them

through J-tubes at the platform.

CAVERN POINT UNIT DEVELOPMENT

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 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.

6.2 ENVIRONMENTAL IMPACTS OF

DEVELOPMENT OF THE 36

UNDEVELOPED LEASES

6.2.1 CUMULATIVE AIR QUALITY

IMPACTS (2002-2030)

Section 6.1 describes the assumptions and lists

the projects considered in the cumulative air quality

analysis. Cumulative air emission data and assumptions are further documented in Appendix 5.4. The

EIS analyzes cumulative impacts in two different time

periods: 2002-2006 and 2002-2030. All of the cumulative projects and activities occur in the South Central

Coast Air Basin composed of San Luis Obispo, Santa

Barbara and Ventura Counties. For this analysis, it is

assumed that due to the prevailing onshore wind conditions, the geographic scope for cumulative air quality impacts will be those projects or actions that exist

or are pending or approved in the Santa Maria Basin

and central Santa Barbara Channel and Southern

Santa Barbara County. Major sources of cumulative

air quality impacts include emissions from on-going

oil and gas activities in Federal and State waters, proposed oil and gas activities, natural petroleum seeps,

and offshore shipping and tankering operations.

Section 5.2.1 discuss the major impacting agents

associated with past, present and foreseeable activities, including the proposed activities, that result in

cumulative contributions to regional air quality during the expected duration of the proposed delineation

activities (2002-2006). These include emissions from

proposed oil and gas projects, existing oil and gas activities, natural petroleum seeps, and marine shipping

and tankering.

The projects discussed in this section include

past, present and reasonably foreseeable actions that

may produce impacts during the period that the development of the 36 undeveloped leases would likely

occur. The temporal period used for this analysis is

the years 2002-2030. Two separate scenarios will be

evaluated for potential cumulative effects on regional

air quality. The first analysis will discuss the cumulative air impacts expected without the development of

the 36 undeveloped leases. The second analysis will

evaluate the incremental contribution to cumulative

air quality impacts associated with the expected development of the leases.

CUMULATIVE AIR QUALITY IMPACTS

WITHOUT DEVELOPMENT OF THE 36

UNDEVELOPED LEASES

It is assumed that without development of the

36 undeveloped leases, no new production platforms