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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.
5-42

Delineation Drilling Activities Offshore Santa Barbara County

Low - Project does not result in any violations of

Federal or State ambient air standards, and

does not exceed threshold emission levels that

have been determined to result in significant

impacts to air quality. Impacts deemed to be

low are considered to be insignificant.

The primary impact-producing activities associated with the proposed project include exploratory

drilling operations with associated support activities.

The major impact agents expected from the proposed

activity 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.

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.

Table 5.2.1-1 provides a summation of SBCAPCD

threshold requirements as provided in Regulation VIII:

New Source Review, relating to the application of Best

Available Control Technology (BACT), air quality impact analysis (AQIA), and emission offsets.

The following NEPA documents provide discussions of air quality impacts associated with the Santa

Barbara County offshore activities. The references are

organized in chronological order and may be referenced

for additional information. Various Authority To Construct (ATC) permits and Permits to Operate (PTO)

have been issued by the SBCAPCD regarding modifications and operations to OCS projects located adjacent to Santa Barbara County. As these permits are

regulatory authorizations and do not contain discussions of air quality impacts, they have not been incorporated in this chronology and may be further referenced by contacting the SBCAPCD offices.

• 1976 - Final Environmental Impact Statement

for Oil and Gas Development in the Santa Barbara Channel, Outer Continental Shelf Off

California, United States Geological Survey

(USGS).

• 1981 - Final EA/EIR for Natural Gas Platform

Habitat and Pipeline, Pitas Point Unit, Santa

Barbara Channel, Proposed by Texaco, Inc.,

Chambers Consultants and Planners.

• 1984 - Point Arguello Field and Processing Facility Area Study and Chevron/Texaco Development Plans EIR/EIS, Arthur D. Little.

• 1984 - Environmental Impact Statement /Report for Santa Ynez Unit/Los Flores Canyon

Development and Production Plan, Science Applications, Inc.

• 1985 - Union Oil Project/Exxon project Shamrock and Central Santa Maria Basin Area

Study EIS/EIR, Arthur D. Little.

• 1986 - Cities Service Oil and Gas Corporation

and Chevron Pipeline Company San Miguel

Project and Northern Santa Maria Basin Area

Study EIS/EIR, URS Corporation.

• 1988 - OCS Environmental Assessment for the

Santa Ynez Unit Development Project modifications, MMS Pacific OCS Region.

• 1991 - OCS Environmental Assessment for the

Santa Ynez Unit Pipeline/Power Cable Construction Project, MMS Pacific OCS Region.

• 1994 - OCS Environmental Assessment, OS&T

Abandonment Plan, Santa Ynez Unit, Exxon

Company U.S.A., MMS Pacific OCS Region.

• 1995 - OCS Environmental Assessment, A proposed 3-Dimensional Seismic Survey, Santa

Ynez Unit, Exxon Company, U.S.A., MMS Pacific OCS Region.

• 1997 - OCS Environmental Assessment, Platform Heritage to Platform Harmony Gas Pipeline, Santa Ynez Unit, Exxon Company U.S.A.,

MMS Pacific OCS Region.

5.2.1.1 IMPACTS OF THE PROPOSED

ACTION

IMPACTS COMMON TO ALL UNITS

A single, semi-submersible type, Mobile Offshore

Drilling Unit (MODU), has been proposed to drill all

the proposed delineation wells for the projects to mini-
5-43

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

performed by SBCAPCD on crew and supply boats

(SBCAPCD, 1987).

Operating equipment/machinery on the SEDCO

712 rig is electrically driven with primary power supplied by diesel-fired engines. Main power is supplied

by three EMD 16-645E9 diesels driving three 2400kW

generators. Average daily rig fuel usage is estimated

at 2,860 gallons per day. The fuel capacity of the

SEDCO 712 rig is 277,914 gallons. The fuel used will

be approved low sulfur diesel fuel (0.05wt.%S). It is

proposed that the fuel will be transported from shore

by boat and transferred to the lower hulls and deck

tanks of the rig. Table 5.2.1-2 summarizes the estimated fuel usage per well for each of the proposed

exploratory projects.

Air emissions expected from the proposed projects

result primarily from the main engines and cranes on

the MODU, crew and supply boats, and helicopters.

The analysis assumes that the MODU will utilize

BACT to reduce emission below normal operating levels in compliance with Santa Barbara APCD requirements. Air emission data and assumptions are further documented in Apendix 5.4.

Drill Rig Main Engines: Emission estimates for

the SEDCO 712 are based on data supplied from a 1990

source test performed for Texaco in 1990 (Texaco,

1990). The SEDCO 712 utilizes three prime mover

(GM EMD Model 1 6-645E9) diesel engines. The engines power three 2,200 KW/3, 125 KVA generators to

produce the main power to drilling operations. The

source test analyzed emissions from the main engines

for the air pollutants NOx, CO, and VOC. The main

engines tested were equipped with the following emission controls:

• 4 degree injection timing retard

• Turbo-charging

• Enhanced inter-cooling with seawater

• Low sulfur diesel fuel (≤ 0.05 wt.%S)

Results of the source test demonstrates that NOx

emissions will be reduced approximately 40% from

uncontrolled levels, while CO emissions will increase

mize potential cumulative impacts. Using one dedicated MODU will minimize the short-term cumulative

impacts to air quality that would be produced by having multiple drill rigs operating simultaneously in the

Santa Barbara Channel. For this analysis, air emissions will be estimated for a typical semi-submersible

drilling unit that is representative of the actual drilling unit that is anticipated for the proposed projects.

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 Exploration Plans

and has been used to drill seven wells in the Pacific

OCS Region in the past.

Santa Barbara APCD Rule 202 F.6 (Drill Rig

Engine Exemption) provides a permit exemption for

drilling equipment provided that emissions from the

equipment are less than 25 tons per year. Exceeding

the drill rig engine exemption threshold simply requires

a permit from the applicant for those pollutant sources

and does infer an air quality significance threshold.

This exemption would include the MODU’s main engines used to power the equipment used during the

drilling phase. The remaining equipment that is not

part of the drilling phase will be subject to permit including marine vessel emissions and various ROC

sources. Thus, all of these projects will require a Permit to Operate from SBCAPCD and will be in accordance with BACT and emission offset provisions to

ensure a net air quality benefit.

The operator submitted project descriptions contained equipment, proposed emission control technology and proposed activities information used in this

analysis to determine if significant impacts to air quality could occur. Additionally, this information was

used to evaluate compliance with emission limitations

imposed upon this project pursuant to SBCAPCD

Rules and Regulations. Emissions of air pollutants

during exploratory and support activities were calculated using the methodology and emission factors contained in the EPA publication AP-42 (EPA, 1990), and

recent emissions source tests for the representative

semi-submersible drilling vessel (Texaco, 1990). Additional emission factor and emission control measure

information were obtained from the results of a study

Table 5.2.1-1. Santa Barbara County APCD New Source Review requirements. y q

BACT Requirements > 25 lbs/day for any non-attainment pollutant (except CO) 

> 150 lbs/day for CO 

AQIA Requirements > 120 lbs/day for any non-attainment pollutant (except CO and PM10) 

> 550 lbs/day for CO; > 80 lbs/day for PM10

Emission Offset 

Requirements 

> 55 lbs/day or >10 tons/yr for any non-attainment pollutant (except CO and PM10) 

> 150 lbs/day or >25 tons/yr for CO; > 80 lbs/day or >10 tons/yr for PM10
5-44

Delineation Drilling Activities Offshore Santa Barbara County

approximately the same 40 % due to lower combustion chamber temperatures. VOC emissions source

tested approximately 80% lower than those estimated

by the manufacturer for the uncontrolled VOC level.

Total main engine emissions for the drilling program are assumed to be approximately proportional

to electromotive requirements. Determination of electromotive requirements requires an estimation of engine load during various drilling program phases and

the duration of time in each phase. A 1982 study by

Radian (Radian, 1982) documented total electromotive requirements and number of days for each of 10

representative activities associated with drilling programs. Engine load (horsepower) requirements were

then calculated for each of these phases utilizing the

data points. Although engine loads were identical for

the various well depths calculated, the length of time

in each mode may vary according to well depth.

Drill Rig Crane Engines: The SEDCO 712 has

two separate 50 ton cranes, each powered by a Detroit

Diesel 8V-171 diesel engine rated at 300hp. Emission

control technology proposed for the cranes will be 4-

degree injection timing retard.

Crane use was monitored on the SEDCO 712 for

the 1989 drilling program by Texaco of the Proteus

Prospect off Point Conception. Drilling duration for

the program lasted 60 days and crane use and emissions were documented in a report to MMS (Texaco,

1990a). As the cranes that were monitored for this

project did not exercise emission control technology,

emission estimates will need to be adjusted to reflect

the proposed injection timing retard.

Crew and Supply Boats: At a minimum, the following vessels have been proposes to be used directly

or in connection with the drilling operations:

• One 110-foot class crew boat

• One standby vessel (most likely a 110-foot class

vessel)

• One 180-foot class supply boat to transport

supplies, equipment, and materials to the drilling rig and to carry garbage, oil contaminated

drill cuttings and formation water back to

shore.

• Anchor handling boat

• Tow Vessels

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.

Based on a two to three month program, the following

mileage assumptions used to calculate crew boat emissions are summarized in Table 5.2.1-3.

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 pre-determined corridors. Based

on a two to three month program, the following supply boat mileage assumptions originating from Point

Hueneme to each unit are summarized in Table 5.2.1-

4.

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.

Tow Vessels and Anchor Handling Boats. Tow

vessels will be used to tow the MODU to the individual

lease locations and position the rig prior to drilling.

It is anticipated that there will be (2) - 5000 hp tugboats utilized for towing and positioning the MODU.

Vessel usage assumptions are based on the estimated

duration projected by the applicant for the movement

and positioning phases of the drilling operation. It is

anticipated that there will be (2) 3000 hp tugboats

utilized for anchor handling. The work boats are required to run the anchor and anchor chain out to the

required length, and lower the anchor onto the seafloor using a work wire.

Table 5.2.1-2. Estimated fuel usage by project.

Unit Total (days) Estimated Fuel Usage (gal.) 

Point Sal 68 194,480 

Purisima Point 68 194,480 

Bonito/well 88-90 257,400 

Gato Canyon 92 260,120 
5-45

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

Helicopters: Helicopter trips originating from

the Santa Barbara Airport will be used as required

(Santa Maria airport for Point Sal and Purisima

Point). No modifications are proposed for the helicopters. The Sea King, a two-engine helicopter, is expected to best represent the type of helicopters used

for this program. Total flying time assumptions used

to determine helicopter emissions for the MODU

project is summarized in Table 5.2.1-5 using emission

factors from AP-42 (EPA, 1990).

Accidents/Upsets: As discussed in the oil spill

Section, no oil spills are expected to occur from the

proposed exploratory drilling activities. Thus no impacts to air quality from accidental oil spills are expected from the proposed exploratory drilling activities.

For this analysis, it is assumed that there is no

impact to regional air quality expected from a hydrogen sulfide release into the atmosphere as a result of

the exploratory activities. If such a release were to

occur, it would be localized to the vicinity of the semisubmersible and the MMS approved H2

S Contingency

Plan for the exploratory operations would dictate the

emergency requirements to be implemented.

AIR QUALITY MODELING ANALYSIS

The MMS studied the impacts of the projected

offshore, non-reactive, or inert, emissions from the

MODU activities using the Offshore and Coastal Dispersion (OCD) Model. The model was used to predict

the ambient concentrations of nitrogen dioxide (NO2),

sulfur dioxide (SO2), and fine particulates (PM10) that

could result from the proposed projects. Meteorological inputs to the model consist of source parameters

and emissions, along with source and receptor coordinates.

The OCD model computes both short-term (24

hours or less) and annual averaged pollutant concentrations. The OCD model requires separate data sets

for characterizing the dispersion meteorology occurring offshore and onshore. Offshore meteorological

data utilized for the model runs were compiled for 1990

- 1992 using offshore moored buoys located in the Santa

Maria Basin (Buoy 46011) and Point Arguello (Buoy

46023). Onshore meteorological data was obtained from

the Santa Maria NWS meteorological site and monthly

average morning and afternoon mixing heights were

based on 1990 - 1992 averages from the Vandenberg

upper air monitoring site. The Gato Canyon Unit

model run utilized Buoy 46053 and 1994 onshore meteorological data from the Santa Barbara surface station.

Peak hour emissions were determined for each

proposed project and used to determine the onshore

impacts to air quality. All the proposed projects have

committed to using the same MODU for drilling operations. As the same equipment is proposed for all

projects, the peak hour emissions are expected to be

the same for each project. The duration of the delineation drilling at each site is the project variable that

results in different total emission estimates for each

project.

Peak hour emissions were estimated to occur

during operational phases utilizing tugboats. Thus,

the peak emissions are expected to occur during the

movement and site preparation stages of the projects

which are the only drilling stages using tugboats. Peak

hour emissions were determined to occur during the

site preparation phase of the proposed projects. The

site preparation stage was used for this analysis as it

was determined that this phase had a much greater

localized concentration of pollutants that would not

Table 5.2.1-3. Estimated miles traveled for crew boats.

Table 5.2.1-4. Estimated miles traveled for supply boats.

Unit Number of Trips/ Month Total Miles 

Bonito 8 5,712 

Gato Canyon 2 350 

Purisima Point 6 2,640 

Point Sal 6 3,360 

Unit Number of Trips/ Month Total Miles 

Bonito 12 7,344 

Gato Canyon 8 2,500 

Purisima Point 9 3,960 

Point Sal 9 5,280 
5-46

Delineation Drilling Activities Offshore Santa Barbara County

Table 5.2.1-6. Peak hour emissions estimates.

be as readily dispersed over distance as would be the

case with the towing of the semi-submersible to the

drill site. While the site preparation phase is generally of short duration (1-3 days), the engine load to

the main drilling engines, coupled with emissions from

the tugs and anchor handling vessels resulted in the

maximum hourly emissions.

The proposed delineation projects are all within

the modeling domain of the OCD, however individual

modeling runs were performed per project location to

estimate the potential for incremental emission contributions to onshore receptors from the individual

projects. One-hour, 3-hour, 8-hour and 24 hour average concentrations were modeled with expected peakhour NOx emissions for the Bonito Unit, Purisima

Point, and Gato Canyon. A conservative estimate of a

90 day project duration was used for all projects.

Using the peak hour emissions from a small increment of the overall project is expected to result in

an overly conservative estimate of ambient air concentrations expected from the project. The OCD model

predicts the highest concentrations from the peak hour

emissions using an entire year of meteorological data.

Therefore, it is highly unlikely that the worst case

meteorology will occur during the exact day of the site

preparation. Peak hour emissions estimates occurring during the drilling phase of the project are considered to be more indicative of the air quality impacts

expected of the project due to the large duration for

this phase (21-29 days). Drilling phase peak hour

emissions were additionally modeled to demonstrate

more representative peak concentrations predicted

during drilling operations. The peak hour emissions

are provided in Table 5.2.1-6 for the site preparation

and drilling phases of the project and were used to

model potential impacts to air quality resulting from

the proposed projects.

Onshore incremental concentrations from the

proposed projects are compared to PSD allowable increments (40 CFR 51.166(c), SBCAPCD Rule 803 ) to

determine the potential for significant impacts. In

addition, the incremental concentrations will be added

to existing background pollutant levels provided by

the SBCAPCD and then compared to applicable Federal and State ambient air quality standards to determine potential violations. Baseline air quality utilized

in the analysis reflects the most recent ambient concentration levels and Santa Barbara monitoring stations. When NOx is emitted from a combustion source,

the majority of the emissions are in the form of NO

and a much smaller percentage is emitted in the form

of NO2

. The NO is gradually converted in the atmosphere to NO2. As the ambient standards apply only

to NO2, a conversion factor of NO to NO2 must be

applied. The EPA screening approach of using the

national default of a NO2/NOx ratio of 0.75 was applied to the predicted concentrations. Results of the

individual project contributions to onshore pollutant

concentrations are presented under the respective Unit

analyses.

CLEAN AIR ACT CONFORMITY

The EPA instituted final rules for determining

general conformity of federal actions with federal and

state air quality implementation plans (SIP). Section

176(c) of the CAA, the General Conformity Rule, reTable 5.2.1-5. Estimated helicopter trips.

1

LTO cycles during the program. Half are at the rig and half at the airport.

Unit Trips/Month Trips per 

Drilling 

Program 

 LandingTakeoff Cycles 

(LTO)1

Roundtrip 

Flying Time 

 (hour) 

Total Flying 

Time (hour) 

Bonito* 30 90(180) 180 (360) 1 90 (180) 

Point Sal 20 50 100 1 50 

Purisima Pt. 20 40 80 1 40 

Gato Canyon 28 84 168 .5 21 

Total: 98 264 (354) 528 (708) 3.5 201 (291) 

* Bonito Unit numbers are given per 1 well and (2 wells) 

Delineation Peak Hour Emission Estimates (lbs) 

Drilling Phase NOx CO VOC SO2 PM10

Site 

Preparation 

189.45 47.95 13.44 3.92 16.24 

Drilling 43.16 9.93 2.35 0.93 2.96 
5-47

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

quires federal agencies to ensure that actions undertaken in nonattainment or maintenance areas are consistent with the applicable implementation plan. The

provisions for demonstrating conformity of a federal

action are that the project does not:

• cause or contribute to any new violation of any

standard;

• interfere with provisions in the applicable SIP;

• increase the frequency or severity of any existing violation of any standard; or

• delay timely attainment of any standard, any

required interim emission reductions, or other

milestones in any area.

The Proposed Actions were evaluated to determine whether the proposed activities are applicable

for a general conformity determination and to identify

any conformity requirements. General Conformity Rule

applicability for a federal action is determined by

whether the emissions associated with the action are

below de minimus levels for the region in which the

action is proposed. Santa Barbara County is presently classified as a serious non-attainment area for

ozone. The de minimus level for a serious

nonattainment area is 50 tons/year of NOx or VOC;

or, 10% or more of the emission inventory (regionally

significant). Conformity determinations are not required when the federal action:

• requires a permit under New Source Review

(NSR);

• the total of direct and indirect emissions is

below 50 tons/year for O3 precursors; and,

• actions where emissions are not reasonably

foreseeable (OCS Lease Sales).

A Federal agency must make a determination that

a federal action conforms to the applicable implementation plan before the action is taken. A federal action is defined as any activity in which the federal

government issues a permit or approval. The proposed projects each require a separate approval decision for the individual Exploration Plan per MMS regulations. Under the definition of a federal action in the

General Conformity Rule, the proposed projects constitute four separate federal actions. Santa Barbara

County APCD has indicated that per their Rules and

Regulations, each of the Proposed Actions will require

a separate permit under NSR and those emissions will

be considered exempt under general conformity.

Emission estimates were developed for the representative projects to determine whether each of the

Proposed Actions were below the 50 ton de minimus

levels for NOx and VOC and the emissions are not

considered to be regionally significant. Emission estimates for the individual projects demonstrate that the

total project emissions for each project are well within

the 50 ton de minimus threshold for both NOx and

VOC. Accounting for the portion of the total project

emissions subject to an NSR permit further reduces

the emission potential subject to conformity. A comparison of the regional significance of the federal action demonstrates that each Proposed Action emissions are less than 1% of Santa Barbara County’s OCS

emission budget and a fraction of the onshore emission inventory. Thus, each of the Proposed Actions

are well below the de minimus levels for both the 50

tons/yr of O3 precursors and 10% of the Santa

Barbara’s emission budget and would be exempt from

a full conformity determination under the General

Conformity Rule.

IMPACTS UNIQUE TO EACH UNIT

Bonito Unit. One to two delineation wells are

being proposed on the Bonito Unit. The operator has

identified 15 potential sites where the well(s) could be

drilled. Nine of the 15 proposed sites have been previously approved with the original Exploration Plans.

Drilling on the Bonito Unit is anticipated to commence

in the second or third quarter of 2002. Air emissions

expected from the proposed delineation project result

primarily from the main engines and cranes, crew and

supply boats, and helicopters.

Drill Rig Emissions. The project description

provided by Nuevo estimated the duration for each

phase of the estimated 90 day drilling operation. The

estimated drilling phase estimates were then combined

with the engine loads as determined in the Radian report (Radian, 1982) to determine individual drilling

phase electromotive requirements. Based on these

calculations, it was estimated that the total electromotive requirements for the main engines were

2,291,236 horsepower hours for drilling 1 well. Emission estimates were then determined by applying the

1990 SEDCO 712 Source Test emission factors to the

electromotive requirements. Drilling engine emission

estimates per well are provided in the Table 5.2.1-7.

Drill Rig Crane Emissions. Crane emissions

were calculated using the crane usage and monitored

emissions from the Proteus Prospect report by Texaco

(Texaco, 1990a) and then applying a NOx control factor of 20% for the 4 degree injection timing retard.

CO estimates were conversely adjusted to reflect the

increase in these emissions due to the selective NOx

control technology. Drilling rig crane emissions per

well are provided in the Table 5.2.1-8.

Crew and Supply Boats. A contracted crew boat

will be used to transport personnel to and from the

drilling site. Crew boats will originate out of either
5-48

Delineation Drilling Activities Offshore Santa Barbara County

Port Hueneme or the Carpinteria Pier. It is estimated

that the Bonito drilling operations will involve approximately 7 round trips per month. Each round trip is

assumed to be 204 miles assuming Port Hueneme as

the base port. Approximately 9 round trips of 204

miles for supply boats will be assumed.

The crew and supply boat will utilize the same

control measures as are planned for the drilling rig.

Additionally, the support vessels will limit their cruising speed to 80 percent of full power. Santa Barbara

County APCD performed a study titled Crew and Supply Boat NOx Control Development Program

(SBCAPCD, 1987) to determine crew and supply boat

fuel usage rates and control measures. Assumptions

provided in this analysis include an estimated fuel use

of 2.97 gal/mi. for crew boats and 8.24 gal/mi. for the

supply boats. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990).

Tug and Work Boats. Additional support vessel

assumptions used in this analysis include (2) - 5000

hp tugboats utilized for towing and positioning the

MODU and (2) 3000 hp tugboats utilized for anchor

handling. Vessel usage assumptions are based on the

estimated duration projected by the applicant for the

movement and positioning phases of the drilling operation. Assumptions provided in this analysis include

an estimated fuel use of 140.5 gal/hr (maneuver) and

56.2 gal/hr (idle) for the large tugboats, and 84.3 gal/

hr (maneuver) and 33.7 gal/hr (idle) for the smaller

tugs. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990). Table 5.2.1-9

provides the crew and supply boat and work boat emissions per well.

Helicopters. Approximately 30 helicopter trips

per month will originate from Santa Barbara Airport

for a total of 90 trips during the entire drill program.

Each round trip required approximately 1 hour of flight

time and 2 landing/takeoff cycles. Table 5.2.1-10 provides the helicopter emission estimates per well.

Flare. Well testing is an integral component

during delineation activities to determine the quality

of the natural gas produced and the formation pressure. This short term duration NOx source occurs

upon well completion. Typically, this phase is offset

by the reduced power needs for drilling operations as

the drilling mode has been completed prior to well testing. Estimated flare emissions have been included in

the total emissions summary.

Total Drilling Emissions. Nuevo is proposing to

drill 1 to 2 wells on the Bonito Unit. Assuming a

conservative case of 2 wells ultimately being drilled,

the per-well and total drilling emissions expected by

major emissions source are provided in Table 5.2.1-11

below.

An evaluation of the total drilling emissions demonstrate the majority of the NOx emissions are associated with the main drilling engines and the support

vessels. Associated support vessels are responsible for

the majority of the CO, VOC, and SO2 emissions from

the project with PM10 being the least emitted pollutant.

Santa Barbara APCD Rule 202 F.6 (Drill Rig

Engine Exemption) provides a permit exemption for

drilling equipment provided that emissions from the

equipment are less than 25 tons per year. This exemption would include the MODU’s main engines used to

power the equipment used during the Bonito drilling

phase. However, if 2 wells are drilled in the Bonito

Unit as has been proposed, the threshold limit of 25

tons per year may be exceeded if the second well occurs within the same 12 month period as the initial

well. The remainder of the drilling emissions over the

threshold for that 12 month period would be subject

to SBCAPCD permit. Other equipment that is not

part of the drilling phase will be subject to permit including marine vessel emissions and various ROC

sources. Thus, this proposed project will require a

Permit to Operate from SBCAPCD and emission

sources subject to the permit will be in accordance

with BACT and emission offset provisions to ensure a

net air quality benefit. Table 5.2.1-12 presents the

total project estimated emissions in different configurations used for regulatory overview. A comparison

of the New Source Review requirements demonstrates

Table 5.2.1-7. Bonito drill rig emissions.

Table 5.2.1-8. Bonito crane engine emissions.

Bonito Drilling Engine Emission Estimate (tons) 

NOx CO VOC SO2 PM10

22.78 3.05 0.13 0.51 0.99 

Bonito Drilling Rig Crane Emission Estimate (tons) 

NOx CO VOC SO2 PM10

0.71 0.28 0.06 0.02 0.08 
5-49

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

the Bonito project will be above levels requiring application of BACT and emission offsets to those sources

subject to permit. The proposed project is additionally expected to result in a net emissions increase

greater than levels which require an air quality impact analysis (modeling) to ensure the project will not

cause a violation or interfere with expeditious attainment of any air quality standard.

Air Quality Modeling Analysis. The MMS studied the impacts of the projected offshore emissions from

the Bonito Unit using the Offshore and Coastal Dispersion (OCD) Model. Peak hour NOx emissions were

determined to occur during the site preparation phase

of the drilling operation. Utilizing the site preparation phase allowed for the addition of the crane engines to emissions from the drilling main engines and

support vessels. Table 5.2.1-13 lists the highest predicted concentrations to onshore pollutant concentrations from the proposed project for both the site preparation and drilling phases and compares them with

the maximum allowable increases over the baseline

concentration established by SBCAPCD. The concentrations demonstrate that the proposed Bonito Unit

emissions are well within the maximum NO2, SO2 and

PM10 allowable limits for a Class II area. Therefore, it

is expected that increases in the onshore average concentrations of NO2, SO2

 and PM10 are estimated to be

well within the maximum increases allowed under both

the Federal and Santa Barbara APCD standards.

Conclusion: In summary, activities associated

with the proposed Bonito Unit delineation activities

are expected to result in low impacts to air quality.

For a 1 or 2 well scenario, impacts are considered low

(insignificant) based on the significance criteria used

for this analysis. The project is not expected to result

in any violations of Federal and State ambient air standards. The project is below drilling equipment permit

exemption emission levels (25 tons/year) for the 1 well

scenario as determined by SBCAPCD Rules and Regulations. The 2 well scenario may exceed the permit

threshold if it occurs in the same 12 month period as

the initial well. NSR thresholds will be exceeded by

the project regardless of a 1 or 2 well scenario and

will require BACT and emission offsets. Thus, the

Table 5.2.1-9. Bonito support vessel emissions.

Table 5.2.1-10. Bonito helicopter emissions.

Table 5.2.1-11. Bonito total drilling emissions.

Bonito Support Vessel Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

Crew Boat 1.43 0.68 0.90 0.04 0.18 

Supply Boat 5.07 2.40 3.22 0.13 0.64 

Work Boats 4.38 1.31 0.43 0.09 0.42 

Total 10.87 4.38 4.56 0.26 1.24 

p

Bonito Helicopter Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

LTO 0.27 1.22 0.61 0.04 0.04 

In-Flight 0.29 0.22 0.02 0.04 0.04 

Total 0.56 1.44 0.64 0.08 0.07 

Bonito Total Drilling Emission Estimate (tons) 

NOx CO VOC SO2 PM10

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

Main Engines 22.78 45.56 3.05 6.10 0.13 0.26 0.51 1.02 0.99 1.98 

Crane Engines 0.71 1.42 0.28 0.56 0.01 0.01 0.01 0.04 0.08 0.16 

Flare 0.14 0.28 0.05 0.10 0.01 0.01 0.01 0.02 0.01 0.02 

Vessels 10.87 21.74 4.38 8.76 4.56 9.12 0.26 0.52 1.24 2.48 

Helicopters 0.56 1.12 1.44 2.88 0.64 1.28 0.08 0.16 0.07 0.14 

Total 35.07 70.14 9.20 18.40 5.34 10.68 0.87 1.74 2.39 4.78 
5-50

Delineation Drilling Activities Offshore Santa Barbara County

project will be subject to SBCAPCD permit requirements and New Source Review requirements that emissions be fully offset to ensure a net air quality benefit

for the project. Emission control technology proposed

with the project descriptions will additionally reduce

projected air quality impacts. No impacts are expected

from accidents or upsets.

Point Sal Unit. One-delineation well is being

proposed on the Point Sal Unit. The operator has

identified 3 potential sites where the well could be

drilled. All of the proposed sites have been previously

approved with the original Exploration Plans. Drilling on the Point Sal Unit is anticipated to commence

in the fourth quarter of 2002. Air emissions expected

from the proposed delineation project result primarily

from the main engines and cranes, crew and supply

boats, and helicopters.

Drill Rig Emissions. The project description

provided by Aera estimated the duration for each phase

of the estimated 74 day drilling operation. The estimated drilling phase estimates were then combined

with the engine loads as determined in the Radian report (Radian, 1982) to determine individual phase electromotive requirements. Based on these calculations,

it was estimated that the electromotive requirements

for the main engines are 2,553,000 horsepower hours.

Emission estimates were then determined by applying

the 1990 SEDCO 712 Source Test emission factors to

the electromotive requirements. Drilling engine emission estimates per well are provided in Table 5.2.1-14.

Drill Rig Crane Emissions. Crane emissions were

calculated using the crane usage and monitored emissions from the Proteus Prospect report by Texaco

(Texaco, 1990a) and then applying a NOx control factor of 20% for the 4 degree injection timing retard.

CO estimates were conversely adjusted to reflect the

increase in these emissions due to the selective NOx

control technology. Drilling rig crane emissions per

well are provided in Table 5.2.1-15.

Crew and Supply Boats. A contracted crew boat

will be used to transport personnel to and from the

drilling site. Crew boats will originate out of either

Port Hueneme or the Carpinteria Pier. It is estimated

that the Bonito drilling operations will involve approxiTable 5.2.1-13. Bonito Unit modeling results and corresponding maximum allowable increases.

 (micrograms per cubic meter (μg/m3))

Table 5.2.1-12. Bonito Unit total drilling emissions. g

Bonito Total Drilling Emission Estimate 

NOx CO VOC SO2 PM10

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

One 

Well 

Two 

Wells 

Lbs/hr 32.47 32.47 8.52 8.52 4.95 4.95 0.80 0.80 2.21 2.21 

Lbs/day 779.3 779.3 204.4 204.4 118.7 118.7 19.3 19.3 53.1 53.1 

Tons/qtr. 35.07 35.07 9.20 9.20 5.34 5.34 0.87 0.87 2.39 2.39 

Tons/year 35.07 70.14 9.20 18.40 5.34 10.68 0.87 1.74 2.39 4.78 

(gp ( g ))

Pollutant Averaging Period Class II Maximum 

Allowable Increase 

National/State 

Ambient Air 

Quality 

Standard 

Site Prep 

Modeled 

Impact 

Drilling 

Phase 

Modeled 

Impact 

NO2 1-hour 100-4701

 4702 61.1 17.7 

Annual Average 25.0 100 0.00 0.00 

PM10 24-hour Average 12-30 150 0.44 0.06 

Annual Average 17.0 50 0.00 0.00 

SO2 1-hour NS 6553

 1.7 0.51 

3-hour Average 512.0 1300 0.56 0.15 

24-hour Average 91.0 365 0.11 0.03 

Annual Average 20.0 80 0.00 0.00 

1. Santa Barbara APCD incremental limit. 

2. State of California ambient standard. 

3. State Standard. No National Standard. 
5-51

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

mately 6 round trips per month. Each round trip is

assumed to be 240 miles assuming Port Hueneme as

the base port. Total crew boat miles are expected to

be approximately 3,360 miles. Approximately 9 round

trips of 240 miles for supply boats will be assumed for

a total of 5,280 miles.

The crew and supply boat will utilize the same

control measures as are planned for the drilling rig.

Additionally, the support vessels will limit their cruising speed to 80 percent of full power. Santa Barbara

County APCD performed a study titled Crew and Supply Boat NOx Control Development Program

(SBCAPCD, 1987) to determine crew and supply boat

fuel usage rates and control measures. Assumptions

provided in this analysis include an estimated fuel use

of 2.97 gal/mi. for crew boats and 8.24 gal/mi. for the

supply boats. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990).

Tug and Work Boats. Additional support vessel

assumptions used in this analysis include (2) - 5000

hp tugboats utilized for towing and positioning the

MODU and (2) 3000 hp tugboats utilized for anchor

handling. Vessel usage assumptions are based on the

estimated duration projected by the applicant for the

movement and positioning phases of the drilling operation. Assumptions provided in this analysis include

an estimated fuel use of 140.5 gal/hr (maneuver) and

56.2 gal/hr (idle) for the large tugboats, and 84.3 gal/

hr (maneuver) and 33.7 gal/hr (idle) for the smaller

tugs. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990). Table 5.2.1-16

provides the crew and supply boat and work boat emissions per well.

Helicopters. Approximately 20 helicopter trips

per month will originate from Santa Barbara Airport

for a total of 50 trips during the entire drill program.

Each round trip required approximately 1 hour of flight

time and 2 landing/takeoff cycles. Table 5.2.1-17 provides the helicopter emission estimates per well.

Flare. Well testing is an integral component

during delineation activities to determine the quality

of the natural gas produced and the formation pressure. This short-term duration NOx source occurs

upon well completion. Typically, this phase is offset

by the reduced power needs for drilling operations as

the drilling mode has been completed prior to well testing. Estimated flare emissions have been included in

the total emissions summary.

Total Drilling Emissions. Total drilling emissions expected of the Point Sal drilling operation

Samedan are provided in Table 5.2.1-18.

An evaluation of the total drilling emissions demonstrate the majority of the NOx emissions are associated with the main drilling engines and the crew and

supply vessels. Associated support vessels are responsible for the majority of the CO, VOC, and SO2 emissions from the project with PM10 being the least emitted pollutant.

Santa Barbara APCD Rule 202 F.6 (Drill Rig

Engine Exemption) provides a permit exemption for

drilling equipment provided that emissions from the

Table 5.2.1-14. Point Sal drill rig emissions.

Table 5.2.1-15. Point Sal crane emissions.

Table 5.2.1-16. Point Sal support vessel emissions.

Point Sal Drilling Engine Emission Estimate (tons) 

NOx CO VOC SO2 PM10

19.98 2.67 0.10 0.45 0.87 

Point Sal Drilling Rig Crane Emission Estimate (tons) 

NOx CO VOC SO2 PM10

0.71 0.28 0.01 0.01 0.08 

Point Sal Support Vessel Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

Crew Boat 1.34 0.64 0.86 0.04 0.17 

Supply Boat 5.82 2.76 3.71 0.15 0.73 

Work Boats 2.62 0.79 0.26 0.05 0.25 

Total 9.79 4.18 4.83 0.24 1.15 
5-52

Delineation Drilling Activities Offshore Santa Barbara County

equipment are less than 25 tons per year. This exemption would include the MODU’s main engines used to

power the equipment used during the Pt. Sal drilling

phase. Other equipment that is not part of the drilling phase will be subject to permit including marine

vessel emissions and various ROC sources. Thus, this

proposed project will require a Permit to Operate from

SBCAPCD and emission sources subject to the permit

will be in accordance with BACT and emission offset

provisions to ensure a net air quality benefit. Table

5.2.1-19 presents the total project estimated emissions

in different configurations used for regulatory overview. A comparison of the New Source Review requirements demonstrates the Point Sal Unit project will be

above levels requiring application of BACT and emission offsets to those sources subject to permit. The

proposed project is additionally expected to result in a

net emissions increase greater than levels which require a an air quality impact analysis (modeling) to

ensure the project will not cause a violation or interfere with expeditious attainment of any air quality standard.

Air Quality Modeling Analysis. The MMS studied the impacts of the projected offshore emissions from

the Point Sal Unit using the Offshore and Coastal

Dispersion (OCD) Model. Peak hour emissions were

determined to occur during the site preparation phase

of the drilling operation. Utilizing the site preparation phase allowed for the addition of the crane engines to emissions from the drilling main engines and

support vessels. Table 5.2.1-20 lists the highest predicted concentrations to onshore pollutant concentrations from the proposed project for both the site preparation and drilling phases and compares them with

the maximum allowable increases over the baseline

concentration established by SBCAPCD. The concentrations demonstrate that the proposed Pt. Sal Unit

emissions are well within the maximum NO2, SO2 and

PM10 allowable limits for a Class II area. Therefore, it

is expected that increases in the onshore average concentrations of NO2, SO2

 and PM10 are estimated to be

well within the maximum increases allowed under both

the Federal and Santa Barbara APCD standards.

Table 5.2.1-17. Point Sal helicopter emissions.

Table 5.2.1-18. Point Sal total drilling emissions.

Table 5.2.1-19. Point Sal Unit total drilling emissions.

Point Sal Helicopter Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

LTO 0.15 0.68 0.34 0.02 0.02 

In-Flight 0.16 0.13 0.02 0.02 0.02 

Total 0.31 0.81 0.36 0.04 0.04 

Point Sal Total Drilling Emission Estimate (tons) 

NOx CO VOC SO2 PM10

Main Engines 19.98 2.67 0.11 0.45 0.87 

Crane Engines 0.71 0.27 0.01 0.01 0.07 

Flare 0.14 0.05 0.01 0.01 0.01 

Vessels 9.79 4.18 4.83 0.24 1.15 

Helicopters 0.31 0.81 0.36 0.04 0.04 

Total 30.93 7.98 5.31 0.76 2.15 

Point Sal Unit Total Drilling Emission Estimate 

NOx CO VOC SO2 PM10

 

Lbs/hr 34.83 8.99 5.98 0.86 2.42 

Lbs/day 835.9 215.7 143.5 20.5 58.1 

Tons/qtr. 30.93 7.98 5.31 0.76 2.15 

Tons/year 30.93 7.98 5.31 0.76 2.15 
5-53

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

Pollutant Averaging Period Class II Maximum 

Allowable Increase 

National/State 

Ambient Air 

Quality 

Standard 

Site Prep 

Modeled 

Impact 

Drilling 

Phase 

Modeled 

Impact 

NO2 1-hour 100-4701

 4702 82.1 24.2 

Annual Average 25.0 100 0.03 0.03 

PM10 24-hour Average 12-30 150 0.43 0.06 

Annual Average 17.0 50 0.00 0.00 

SO2 1-hour NS 6553

 2.3 0.62 

3-hour Average 512.0 1300 0.84 0.21 

24-hour Average 91.0 365 0.11 0.03 

Annual Average 20.0 80 0.00 0.00 

1. Santa Barbara APCD incremental limit. 

2. State of California ambient standard. 

3. State Standard. No National Standard. 

Conclusion: In summary, activities associated

with the proposed Point Sal Unit delineation activities are expected to result in low impacts to regional

air quality. For the drilling of the proposed well, impacts are considered low (insignificant) based on the

significance criteria used for this analysis. The project

is not expected to result in any violations of Federal

and State ambient air standards. The project is below

drilling equipment permit exemption emission levels

(25 tons/year) as determined by SBCAPCD Rules and

Regulations. NSR thresholds will be exceeded by the

project and will require BACT and emission offsets.

Thus, the project will be subject to SBCAPCD permit

requirements and will be subject to New Source Review requirements that emissions be fully offset to

ensure a net air quality benefit for the project. Emission control technology proposed with the project descriptions will additionally reduce projected air quality impacts. No impacts are expected from accidents

or upsets.

Purisima Point Unit. One delineation well is

being proposed on the Purisima Point Unit. The operator has identified 4 potential sites where the well

could be drilled. All of the proposed sites have been

previously approved with the original Exploration

Plans. Drilling on the Purisima Point Unit is anticipated to commence in the first quarter of 2003. Air

emissions expected from the proposed delineation

project result primarily from the main engines and

cranes, crew and supply boats, and helicopters.

Drill Rig Emissions. The project description

provided by Aera estimated the duration for each phase

of the estimated 68 day drilling operation. The estimated drilling phase estimates were then combined

with the engine loads as determined in the Radian report (Radian, 1982) to determine individual phase electromotive requirements. Based on these calculations,

it was estimated that the electromotive requirements

for the main engines are 2,295,960 horsepower hours.

Emission estimates were then determined by applying

the 1990 SEDCO 712 Source Test emission factors to

the electromotive requirements. Drilling engine emission estimates per well are provided in Table 5.2.1-21

below.

Drill Rig Crane Emissions. Crane emissions were

calculated using the crane usage and monitored emissions from the Proteus Prospect report by Texaco

(Texaco,1990a) and then applying a NOx control factor of 20% for the 4 degree injection timing retard.

CO estimates were conversely adjusted to reflect the

increase in these emissions due to the selective NOx

control technology. Drilling rig crane emissions per

well are provided in Table 5.2.1-22 below.

Crew and Supply Boats. A contracted crew boat

will be used to transport personnel to and from the

drilling site. Crew boats will originate out of either

Table 5.2.1-20. Point Sal Unit modeling results and corresponding maximum allowable increases.

(micrograms per cubic meter (μg/m3))

Table 5.2.1-21. Purisima Point drill rig emissions.

Purisima Point Drilling Engine Emission Estimate (tons) 

NOx CO VOC SO2 PM10

17.97 2.41 0.10 0.41 0.78 
5-54

Delineation Drilling Activities Offshore Santa Barbara County

Purisima Point Helicopter Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

LTO 0.12 0.54 0.27 0.02 0.02 

In-Flight 0.13 0.10 0.01 0.02 0.02 

Total 0.25 0.64 0.28 0.03 0.03 

Purisima Point Drilling Rig Crane Emission Estimate (tons) 

NOx CO VOC SO2 PM10

0.71 0.28 0.01 0.01 0.08 

Table 5.2.1-24. Purisima helicopter emissions.

Table 5.2.1-23. Purisima Point support vessel emissions.

Port Hueneme or the Carpinteria Pier. It is estimated

that the Bonito drilling operations will involve approximately 6 round trips per month. Each round trip is

assumed to be 220 miles assuming Port Hueneme as

the base port for a total of 2,640 miles. Approximately

9 round trips of 220 miles for supply boats will be assumed for a total of 3,960 miles.

The crew and supply boat will utilize the same

control measures as are planned for the drilling rig.

Additionally, the support vessels will limit their cruising speed to 80 percent of full power. Santa Barbara

County APCD performed a study titled Crew and Supply Boat NOx Control Development Program

(SBCAPCD, 1987) to determine crew and supply boat

fuel usage rates and control measures. Assumptions

provided in this analysis include an estimated fuel use

of 2.97 gal/mi. for crew boats and 8.24 gal/mi. for the

supply boats. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990).

Tug and Work Boats. Additional support vessel

assumptions used in this analysis include (2) - 5000

hp tugboats utilized for towing and positioning the

MODU and (2) 3000 hp tugboats utilized for anchor

handling. Vessel usage assumptions are based on the

estimated duration projected by the applicant for the

movement and positioning phases of the drilling operation. Assumptions provided in this analysis include

an estimated fuel use of 140.5 gal/hr (maneuver) and

56.2 gal/hr (idle) for the large tugboats, and 84.3 gal/

hr (maneuver) and 33.7 gal/hr (idle) for the smaller

tugs. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990). Table 5.2.1-23

provides crew and supply boat and work boat emissions per well.

Helicopters. Approximately 20 helicopter trips

per month will originate from Santa Barbara Airport

for a total of 40 trips during the entire drill program.

Each round trip required approximately 1 hour of flight

time and 2 landing/takeoff cycles. Table 5.2.1-24 below provides the helicopter emission estimates per well.

Flare. Well testing is an integral component

during delineation activities to determine the quality

of the natural gas produced and the formation pressure. This short term duration NOx source occurs

upon well completion. Typically, this phase is offset

by the reduced power needs for drilling operations as

the frilling mode has been completed prior to well testing. Estimated flare emissions have been included in

the total emissions summary.

Total Drilling Emissions. Total drilling emission

expected of the Point Sal drilling operation Samedan

are provided in Table 5.2.1-25 below.

An evaluation of the total drilling emissions demonstrate the majority of the NOx emissions are associated with the main drilling engines and the crew and

supply vessels. Associated support vessels are responsible for the majority of the CO, VOC, and SO2 emissions from the project with PM10 being the least emitted pollutant.

Table 5.2.1-22. Purisima Point crane emissions.

Purisima Point Support Vessel Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

Crew Boat 1.06 0.50 0.67 0.03 0.13 

Supply Boat 4.38 2.07 2.79 0.12 0.55 

Work Boats 2.61 0.79 0.26 0.05 0.25 

Total 8.05 3.36 3.72 0.20 0.94 
5-55

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

Purisima Point Total Drilling Emission Estimate (tons) 

NOx CO VOC SO2 PM10

Main Engines 17.97 2.41 0.10 0.41 0.78 

Crane Engines 0.71 0.28 0.01 0.01 0.08 

Flare 0.14 0.05 0.01 0.01 0.01 

Vessels 8.05 3.36 3.72 0.20 0.94 

Helicopters 0.25 0.64 0.29 0.03 0.03 

Total 27.12 6.73 4.12 0.66 1.84 

Santa Barbara APCD Rule 202 F.6 (Drill Rig

Engine Exemption) provides a permit exemption for

drilling equipment provided that emissions from the

equipment are less than 25 tons per year. This exemption would include the MODU’s main engines used to

power the equipment used during the Purisima Point

Unit drilling phase. Other equipment that is not part

of the drilling phase will be subject to permit including marine vessel emissions and various ROC sources.

Thus, this proposed project will require a Permit to

Operate from SBCAPCD and emission sources subject

to the permit will be in accordance with BACT and

emission offset provisions to ensure a net air quality

benefit. Table 5.2.1-26 presents the total project estimated emissions in different configurations used for

regulatory overview. A comparison of the New Source

Review requirements demonstrates the Purisima Point

Unit project will be above levels requiring application

of BACT and emission offsets to those sources subject

to permit. The proposed project is additionally expected to result in a net emissions increase greater

than levels which require a an air quality impact analysis (modeling) to ensure the project will not cause a

violation or interfere with expeditious attainment of

any air quality standard.

Air Quality Modeling Analysis. The MMS studied the impacts of the projected offshore emissions from

the Point Purisima Unit using the Offshore and Coastal

Dispersion (OCD) Model. Peak hour NOx emissions

were determined to occur during the site preparation

phase of the drilling operation. Utilizing the site preparation phase allowed for the addition of the crane engines to emissions from the drilling main engines and

support vessels. Table 5.2.1-27 lists the highest predicted concentrations to onshore pollutant concentrations from the proposed project for both the site preparation and drilling phases and compares them with

the maximum allowable increases over the baseline

concentration established by SBCAPCD. The concentrations demonstrate that the proposed Point Purisima

Unit emissions are well within the maximum NO2 allowable limits for a Class II area. Therefore, it is expected that increases in the onshore average concentrations of NO2, SO2

 and PM10 are estimated to be well

within the maximum increases allowed under both the

Federal and Santa Barbara APCD standards.

Conclusion: In summary, activities associated

with the proposed Point Purisima Unit delineation

activities are expected to result in low impacts to regional air quality. For the drilling of the proposed

well, impacts are considered low (insignificant) based

on the significance criteria used for this analysis. The

project is not expected to result in any violations of

Federal and State ambient air standards. The project

is below drilling equipment permit exemption emission

levels (25 tons/year) as determined by SBCAPCD Rules

and Regulations. NSR thresholds will be exceeded by

the project and will require BACT and emission offsets. Thus, the project will be subject to SBCAPCD

permit requirements and will be subject to NSR requirements that emissions be fully offset to ensure a

net air quality benefit for the project. Emission control technology proposed with the project descriptions

will additionally reduce projected air quality impacts.

No impacts are expected from accidents or upsets.

Gato Canyon Unit. One delineation well is being proposed on the Gato Canyon Unit. The well site

identified by the operator is in close proximity to the

well site in the original Exploration Plan. Drilling on

the Gato Canyon Unit is anticipated to commence in

the second quarter of 2002. Air emissions expected from

the proposed delineation project result primarily from

the main engines and cranes, crew and supply boats,

and helicopters.

Drill Rig Emissions. The project description

provided by Aera estimated the duration for each phase

of the estimated 95 day drilling operation. The estimated drilling phase estimates were then combined

with the engine loads as determined in the Radian report (Radian, 1982) to determine individual phase electromotive requirements. Based on these calculations,

it was estimated that the electromotive requirements

for the main engines are 3,047,628 horsepower hours.

Emission estimates were then determined by applying

the 1990 SEDCO 712 Source Test emission factors to

Table 5.2.1-25. Purisima Point drill rig emissions.
5-56

Delineation Drilling Activities Offshore Santa Barbara County

Pollutant Averaging Period Class II Maximum 

Allowable Increase 

National/State 

Ambient Air 

Quality 

Standard 

Site Prep 

Modeled 

Impact 

Drilling 

Phase 

Modeled 

Impact 

NO2 1-hour 100-4701 4702 75.8 16.6 

Annual Average 25.0 100 0.03 0.03 

PM10 24-hour Average 12-30 150 0.62 0.05 

Annual Average 17.0 50 0.00 0.00 

SO2 1-hour NS 6553 2.1 0.62 

3-hour Average 512.0 1300 0.82 0.21 

24-hour Average 91.0 365 0.13 0.03 

Annual Average 20.0 80 0.00 0.00 

1. Santa Barbara APCD incremental limit. 

2. State of California ambient standard. 

3. State Standard. No National Standard. 

the electromotive requirements. Drilling engine emission estimates per well are provided in Table 5.2.1-28

below.

Drill Rig Crane Emissions. Crane emissions were

calculated using the crane usage and monitored emissions from the Proteus Prospect report by Texaco

(Texaco, 1990a) and then applying a NOx control factor of 20% for the 4 degree injection timing retard.

CO estimates were conversely adjusted to reflect the

increase in these emissions due to the selective NOx

control technology. Drilling rig crane emissions per

well are provided in Table 5.2.1-29 below.

Crew and Supply Boats. A contracted crew boat

will be used to transport personnel to and from the

drilling site. Crew boats will originate out of either

Port Hueneme or the Carpinteria Pier. It is estimated

that the Bonito drilling operations will involve approximately 7 round trips per month. Each round trip is

assumed to be 204 miles assuming Port Hueneme as

the base port. Approximately 9 round trips of 204

miles for supply boats will be assumed.

The crew and supply boat will utilize the same

control measures as are planned for the drilling rig.

Additionally, the support vessels will limit their cruising speed to 80 percent of full power. Santa Barbara

County APCD performed a study titled Crew and Supply Boat NOx Control Development Program

(SBCAPCD, 1987) to determine crew and supply boat

fuel usage rates and control measures. Assumptions

provided in this analysis include an estimated fuel use

of 2.97 gal/mi. for crew boats and 8.24 gal/mi. for the

supply boats. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990).

Tug and Work Boats. Additional support vessel

assumptions used in this analysis include (2) - 5000

hp tugboats utilized for towing and positioning the

MODU and (2) - 3000 hp tugboats utilized for anchor

handling. Vessel usage assumptions are based on the

estimated duration projected by the applicant for the

movement and positioning phases of the drilling operation. Assumptions provided in this analysis include

an estimated fuel use of 140.5 gal/hr (maneuver) and

56.2 gal/hr (idle) for the large tugboats, and 84.3 gal/

hr (maneuver) and 33.7 gal/hr (idle) for the smaller

tugs. Emissions were calculated using emission factors contained in AP-42 (EPA, 1990). Table 5.2.1-30

provides the crew and supply boat and work boat emissions per well.

Helicopters. Approximately 28 helicopter trips

per month will originate from Santa Barbara Airport

for a total of 84 trips during the entire drill program.

Each round trip required approximately 25 minutes of

flight time and 2 landing/takeoff cycles. Table 5.2.1-

31 provides the helicopter emission estimates per well.

Flare. Well testing is an integral component

Table 5.2.1-27. Point Purisima modeling results and corresponding maximum allowable increases.

(micrograms per cubic meter (μg/m3

))

Table 5.2.1-26. Purisima Point Unit total drilling emissions.

Purisima Point Total Drilling Emission Estimate (tons) 

NOx CO VOC SO2 PM10

Lbs/hr 33.24 8.25 5.05 0.81 2.25 

Lbs/day 797.6 197.9 121.2 19.4 54.1 

Tons/qtr. 27.12 6.73 4.12 0.66 1.84 

Tons/year 27.12 6.73 4.12 0.66 1.84 
5-57

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

Gato Canyon Drilling Engine Emission Estimate (tons) 

NOx CO VOC SO2 PM10

23.85 3.19 0.13 0.54 1.04 

Gato Canyon Support Vessel Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

Crew Boat 0.15 0.07 0.10 0.01 0.02 

Supply Boat 2.77 1.31 1.77 0.07 0.35 

Work Boats 4.42 1.31 0.43 0.09 0.43 

Total 7.34 2.70 2.29 0.17 0.79 

during delineation activities to determine the quality

of the natural gas produced and the formation pressure. This short-term duration NOx source occurs

upon well completion. Typically, this phase is offset

by the reduced power needs for drilling operations as

the frilling mode has been completed prior to well testing. Estimated flare emissions have been included in

the total emissions summary.

Total Drilling Emissions. Total drilling emission

expected of the Point Sal drilling operation Samedan

are provided in Table 5.2.1-32.

An evaluation of the total drilling emissions demonstrate the majority of the NOx emissions are associated with the main drilling engines and the crew and

supply vessels. Associated support vessels are responsible for the majority of the CO, VOC, and SO2 emissions from the project with PM10 being the least emitted pollutant.

Santa Barbara APCD Rule 202 F.6 (Drill Rig

Engine Exemption) provides a permit exemption for

drilling equipment provided that emissions from the

equipment are less than 25 tons per year. This exemption would include the MODU’s main engines used to

power the equipment used during the Gato Canyon

Unit drilling phase. Other equipment that is not part

of the drilling phase will be subject to permit including marine vessel emissions and various ROC sources.

Thus, this proposed project will require a Permit to

Operate from SBCAPCD and emission sources subject

to the permit will be in accordance with BACT and

emission offset provisions to ensure a net air quality

benefit. Table 5.2.1-33 presents the total project estimated emissions in different configurations used for

regulatory overview. A comparison of the New Source

Review requirements demonstrates the Gato Canyon

Unit project will be above levels requiring application

of BACT and emission offsets to those sources subject

to permit. The proposed project is additionally expected to result in a net emissions increase greater

than levels which require a an air quality impact analysis (modeling) to ensure the project will not cause a

violation or interfere with expeditious attainment of

any air quality standard.

Air Quality Modeling Analysis. The MMS studied the impacts of the projected offshore emissions from

the Gato Canyon Unit using the Offshore and Coastal

Dispersion (OCD) Model. Peak hour emissions were

determined to occur during the site preparation phase

of the drilling operation. Utilizing the site preparation phase allowed for the addition of the crane engines to emissions from the drilling main engines and

support vessels. Table 5.2.1-34 lists the highest predicted concentrations to onshore pollutant concentrations from the proposed project for both the site preparation and drilling phases and compares them with

the maximum allowable increases over the baseline

concentration established by SBCAPCD. The modeled concentrations demonstrate that the proposed

Gato Canyon Unit site preparation NO2

 emissions

exceed the lower level of the 1 hour maximum increment range established by the SBCAPCD for NOx allowable limits for a Class II area. The increment range

has been established by SBCAPCD to represent consumption of the increment and does not constitute a

state or federal standard. The lower level of the increment range represents approximately 20% of the federal standard. Concentrations for SO2

 and PM10 were

additionally modeled for Gato Canyon to demonstrate

Table 5.2.1-28. Gato Canyon drill rig emissions.

Table 5.2.1-29. Gato Canyon crane emissions.

Table 5.2.1-30. Gato Canyon support vessel emissions.

Gato Canyon Drilling Rig Crane Emission Estimate (tons) 

NOx CO VOC SO2 PM10

0.71 0.28 0.01 0.01 0.08 
5-58

Delineation Drilling Activities Offshore Santa Barbara County

Gato Canyon Total Drilling Emission Estimate (tons) 

NOx CO VOC SO2 PM10

Main Engines 23.85 3.19 0.13 0.54 1.04 

Crane Engines 0.71 0.28 0.01 0.01 0.08 

Flare 0.14 0.05 0.01 0.01 0.01 

Vessels 7.34 2.70 2.29 0.17 0.79 

Helicopters 0.32 1.19 0.58 0.04 0.04 

Total 32.37 7.40 3.01 0.77 1.96 

Gato Canyon Total Drilling Emission Estimate (tons) 

NOx CO VOC SO2 PM10

 

Lbs/hr 28.39 6.49 2.64 0.68 1.72 

Lbs/day 681.5 155.8 63.37 16.2 41.26 

Tons/qtr. 32.37 7.40 3.01 0.77 1.96 

Tons/year 32.37 7.40 3.01 0.77 1.96 

maximum predicted concentrations for those pollutants. Concentrations of SO2

 and PM10 are well below

allowable increases.

The most recent validated ambient air concentrations were obtained from the SBCAPCD and added

to the incremental concentrations predicted by the OCD

model for a comparison against Federal and State

ambient air quality standards. The comparison indicates that increases in the onshore average concentrations of NO2

, SO2, and PM10 from the proposed

projects are estimated to be less than the maximum

increases allowed under the Federal, State and Santa

Barbara APCD standards.

Conclusion: In summary, activities associated

with the proposed Gato Canyon Unit delineation activities are expected to result in low impacts to regional air quality. For the drilling of the proposed

well, impacts are considered moderate to low (significant, but mitigable to insignificant) based on the significance criteria used for this analysis. Based on

modeling results, the project is not expected to result

in any violations of Federal and State ambient air standards, however NO2

 emissions may exceed the lower

level of the 1 hour maximum increment range established by the SBCAPCD for NOx allowable limits for a

Class II area. The project is below drilling equipment

permit exemption emission levels (25 tons/year) as

determined by SBCAPCD Rules and Regulations. NSR

thresholds will be exceeded by the project and will require BACT and emission offsets. Thus, the project

will be subject to SBCAPCD permit requirements and

will be subject to NSR requirements that emissions be

fully offset to ensure a net air quality benefit for the

project. Emission control technology proposed with

the project descriptions will additionally reduce projected air quality impacts. No impacts are expected

from accidents or upsets.

5.2.1.1.1 SUMMARY AND CONCLUSION

The potential impacts to onshore air quality resulting from the proposed delineation projects are considered low based on the significance criteria levels

utilized in this analysis. Increased NOx and SO2

 emissions from exploratory drilling operations on the

MODU will be minimized through the application of

the following project proposed emission control measures on the main engines, 4 degree injection timing

retard, turbo-charging, enhanced inter-cooling with

seawater, and low sulfur diesel fuel (≤ 0.05 wt.%S).

Table 5.2.1-33. Gato Canyon Unit total drilling emissions.

Table 5.2.1-32. Gato Canyon total drilling emissions.

Table 5.2.1-31. Gato Canyon helicopter emissions.

Gato Canyon Helicopter Emission Estimate (tons) 

 NOx CO VOC SO2 PM10

LTO 0.25 1.14 0.57 0.03 0.03 

In-Flight 0.07 0.05 0.01 0.01 0.01 

Total 0.32 1.19 0.58 0.04 0.04 
5-59

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

Pollutant Averaging Period Class II Maximum 

Allowable Increase 

National/State 

Ambient Air 

Quality 

Standard 

Site Prep 

Modeled 

Impact 

Drilling 

Phase 

Modeled 

Impact 

NO2 1-hour 100-4701 4702 200 32.8 

Annual Average 25.0 100 0.03 0.03 

PM10 24-hour Average 12-30 150 0.89 0.08 

Annual Average 17.0 50 0.00 0.00 

SO2 1-hour NS 6553 5.4 0.94 

3-hour Average 512.0 1300 1.8 0.28 

24-hour Average 91.0 365 0.2 0.04 

Annual Average 20.0 80 0.00 0.00 

1. Santa Barbara APCD incremental limit. 

2. State of California ambient standard. 

3. State Standard. No National Standard. 

The crew and supply boats supporting the exploratory

drilling activities will utilize the same control measures as are planned for the drilling rig. Additionally,

the support vessels will limit their cruising speed to

80 percent of full power.

The potential for a drilling equipment permit

exemption threshold level to be exceeded (Rule 202.

F.6; 25 tons/yr) has only been determined for the Bonito Unit project, and only if a 2 well scenario is realized over the same 12 month period. All the proposed

projects are above NSR threshold emission levels for

BACT, emission offsets and air quality impact analysis and will be required to comply with those provisions in SBCAPCD Rules and Regulations. Additional

equipment and emissions not related to drilling operations will require a Permit to Operate from SBCAPCD

and emission sources subject to the permit will be in

accordance with NSR provisions to ensure a net air

quality benefit.

The potential for violations of the ambient air

standards are considered negligible due to the short

duration of the projects and the implementation of

project proposed emission control measures to minimize impacts from the drilling equipment and support

vessels. Table 5.2.1-35 displays the OCD model results of the maximum predicted onshore pollutant concentrations expected for both the site preparation and

drilling phases of all the proposed projects. The maximum 1-hour NO2 concentrations are projected to occur during the positioning phase of the Gato Canyon

Unit proposed project, with the other proposed

projects’ onshore concentrations estimated to be below the Gato Canyon Unit levels. The modeled concentrations demonstrate that only the proposed Gato

Canyon Unit NO2 emissions may exceed the lower level

of the 1 hour maximum increment range established

by the SBCAPCD for NOx allowable limits for a Class

II area. The increment range has been established by

SBCAPCD to represent consumption of the increment

and does not constitute a state or federal standard.

According to SBCAPCD regulations, the applicant may

consume the full increment range given they provide

for an alternative fee based mitigation to the District.

Concentrations of SO2

 and PM10 are additionally well

below the allowable increases for those pollutants.

The table further demonstrates that based on the

modeled emission estimates, the onshore impacts on

air quality from the projects are estimated to be well

below federally allowable increases in NO2, SO2, and

PM10 emissions as regulated by 40 CFR 51.166(c) and

further reflected in SBCAPCD Rule 803. Any project

eventually determined to be subject to SBCAPCD permit requirements will be subject to BACT and be fully

offset at a greater than a 1:1 ratio to result in a net

air quality benefit to Santa Barbara County in accordance with SBCAPCD Rules and Regulations.

5.2.1.2 CUMULATIVE AIR QUALITY IMPACTS

(2002-2006)

CUMULATIVE IMPACTS WITHOUT THE

PROPOSED ACTION

Proposed Federal and State Oil and Gas Activities. Proposed Federal and State oil and gas activities

considered in this analysis include Arguello Inc.’s

Rocky Point Unit, Samedan’s Sword Unit, and Nuevo’s

Tranquillon Ridge Unit.

Rocky Point Unit: Arguello, Inc. is proposing to

develop the Rocky Point Unit by drilling up to 20 extended reach wells from three existing platforms, Harvest, Hidalgo and Hermosa, in the adjacent Point

Arguello Unit. Based on the project description submitted to date, drilling is expected to commence durTable 5.2.1-34. Gato Canyon modeling results and corresponding maximum allowable increases.

(micrograms per cubic meter (μg/m3))
5-60

Delineation Drilling Activities Offshore Santa Barbara County

Maximum Predicted Onshore Pollutant Concentrations From Proposed Actions 

(micrograms per cubic meter ( g/m3

) 

Pollutant Averaging 

Period 

Class II 

Maximum 

Allowable 

Increase 

Ambient Air 

Quality 

Standard 

Santa Barbara 

Maximum 

Background 

Concentration3

Site 

Prep. 

Phase 

Drill 

Phase5

Total 

Site 

Prep. 

Total 

Drill 

Phase 

NO2 1-hour 100-4701 4702 58 200 32.8 258 90.8 

Annual 

Average 

25.0 100 26 0.03 0.03 26.03 26.03 

PM10 24-hour 

Average 

12-30 150 45.2 0.89 0.08 46.09 45.28 

Annual 

Average 

17.0 50 30.9 0.00 0.00 30.9 30.9 

SO2 1-hour NS 6554 10.4 5.4 0.94 15.8 11.34 

3-hour 

Average 

512.0 1300 7.8 1.8 0.28 8.6 8.08 

24-hour 

Average 

91.0 365 2.6 0.2 0.04 2.8 2.64 

Annual 

Average 

20.0 80 5 0.00 0.00 5.00 5.00 

1. Santa Barbara APCD incremental limit. 

2. State of California ambient standard. 

3. Vandenberg (south) 1999 ambient data (Provided by SBCAPCD) 

4. State Standard. No National Standard. 

5. Maximum predicted concentration for longest project phase. 

ing the fourth quarter of 2001. No new production

equipment other than measurement and allocation

equipment will be required on the platforms. The produced oil will be transported in existing pipelines to

the Gaviota onshore facility. The oil will be heated

using existing equipment at Gaviota and transported

by pipeline to refineries. All of the wells will be

directionally drilled using existing well slots on the

platforms. The drilling program is projected to take 4

years to complete. Production is projected to last 10

years. Based on these projections, production from

the Rocky Point Unit will take place within the remaining productive life (2015) of the Point Arguello

platforms.

As the Rocky Point Unit is projected to be drilled

from the adjacent Point Arguello Unit platforms, projected emission increases must be compared to permitted emission limits for the Point Arguello Project. The

preliminary emission increases projected in the project

description for the Rocky Point Unit are expected to

be within existing allowable permitted emission limits

for the Point Arguello Project and those emissions have

been fully offset per SBCAPCD Rules and Regulations.

Any additional equipment or emissions not contained

within the Point Arguello Project emission limits will

be subject to SBCAPCD permit and shall be in full

compliance prior to commencement of the project.

Sword Unit: Samedan Oil Corporation

(Samedan), is proposing to develop the Sword Unit by

drilling an extended reach well from Platform Hermosa

located on the adjacent Pt. Arguello Unit. The new

well will be tested for productivity and the oil properties analyzed to make a final determination of the capability to commingle the Sword oil with the Point

Arguello oil in the Platform Hermosa facilities. Depending upon the success of the test well, the Sword

Unit will be developed from additional extended reach

wells from Platform Hermosa. The milestone date for

drilling the initial Sword well is August 1, 2003. The

feasibility of this project is still being investigated by

Samedan and emission estimates are not available at

this time.

Tranquillon Ridge Project: 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. The Tranquillon Ridge Unit

is located in State waters and is estimated to begin

drilling in late 2001. State and local agencies are preparing an Environmental Impact Report (EIR) on the

proposed project.

The proposed Tranquillon Ridge Project would

involve the drilling of up to 30 extended reach wells

(22 development wells and 8 utility and re-drills) from

Table 5.2.1-35. Maximum predicted onshore pollutant concentrations.
5-61

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

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

take approximately 15 years.

The proposed project will be subject to SBCAPCD

permitting requirements and NSR provisions ensuring that the project will result in no net increase in

emissions and be fully offset to have an air quality

benefit. Emission estimates for the Tranquillon Ridge

project have not been developed at this time.

On-going Oil and Gas Activities. There are presently a total of 19 platforms located in the South Central Coast Air Basin with 15 platforms located in the

OCS offshore of Santa Barbara County and 4 Platforms in federal waters offshore of Ventura County.

The existing platforms are within the jurisdiction of

the adjacent onshore air agencies and all have current Permits to Operate. The emission sources from

those facilities have been controlled and fully offset

and are in full compliance with SBCAPCD and

VCAPCD Rules and Regulations. The platforms located

in Ventura County waters are considered outside of

the geographical scope of this analysis and are not

considered to cumulatively interact with the proposed

projects.

The 1996 annual emission inventory for the OCS

contained in the 1998 Santa Barbara Clean Air Plan

(SBCAPCD, 1998) estimates that fuel combustion and

petroleum production NOx emissions from OCS oil and

gas production facilities contribute less than 4% of

the total NOx emissions. Emissions attributable to

offshore oil production crew and supply boats represent approximately 2.7% of the total marine vessel

emissions in the OCS. Therefore, total NOx emissions

attributable to OCS oil and gas activities represent

approximately 6.4% of the annual OCS emission inventory.

Oil and gas activities represent approximately

24% of the reactive organic gas (ROG) inventory with

natural petroleum seeps accounting for the largest

contribution to the ROG inventory at 45%. Thus,

natural sources of hydrocarbon emissions contribute

approximately 40% more emissions than all OCS oil

and gas activities combined. Marine vessels contribute the remaining 31% of ROG emissions.

The approximate emission contributions from ongoing oil and gas activities in the OCS are conservatively expected to remain at present levels and are considered to be indicative of the proportional contribution to cumulative air quality during the period 2002 -

2006. Table 5.2.1-36 lists the major source groupings

for the 1996 OCS annual emission inventory.

Marine Shipping and Tankering. Other offshore

emission sources considered in this analysis are marine shipping and tankering operations. Emissions

from marine vessels traversing the Santa Barbara

Channel are not regulated by federal, state or local

air authorities and are the major offshore contributor

to regional air quality. Approximately 80 percent of

the vessels calling on the Ports of Los Angeles and

Long Beach are of foreign registry and most use engines produced outside the United States (ARB, 2000).

The 1996 OCS emission inventory for Santa Barbara County estimates that emissions from ships and

commercial boats account for approximately 1 ton per

day of ROG, or about 24 percent of the total OCS ROG

inventory. The most recent Santa Barbara CAP estimates that approximately 96% of the OCS NOx emissions inventory is attributable to shipping and commercial vessels and 97% of the particulate matter emissions. Therefore, it is expected that the cumulative

air quality impact of marine shipping and tankering

will continue to be the most significant contributor to

cumulative air quality in the OCS. Table 5.2.1-37 lists

the major source groupings for the 1996 OCS annual

emission inventory.

INCREMENTAL IMPACTS OF THE

PROPOSED ACTIONS

For this analysis, each of the proposed projects

has been analyzed as to their incremental contribution to cumulative air quality. Potential sources of

cumulative air quality impacts in the project area

which overlap both spatially and temporally include

emissions from on-going and proposed oil and gas activities in Federal and State waters, natural petroleum

seeps, and marine shipping and tankering operations

and have been discussed above. See Section 5.2.1 for

the discussion of the impacts associated with the proposed delineation activities for the period 2002-2006.

Bonito Unit. A single drill rig has been proposed

by the applicants to drill all the proposed delineation

wells. Section 5.2.1 discusses the expected air quality

impacts from each of the Proposed Actions. The OCD

model predicted emission concentrations for the projected Bonito Unit to be within the maximum allowable limits for a Class II area. The predicted concentrations were added to existing ambient background

levels for NO2 and demonstrate that the proposed Bonito Unit emissions are estimated to be less than the

maximum increases allowed under both the Federal

and state ambient air standards (Table 5.2.1-13). Non

drilling equipment will require a Permit to Operate

from SBCAPCD and will be in accordance with BACT

and emission offset provisions to ensure a net air quality benefit.

Proposed Federal and State Oil and Gas Activities. Federal and state oil and gas activities considered

in the Bonito Unit cumulative analysis include the

Tranquillon Ridge Unit, the proposed Aera projects

(Purisima Point Unit, Point Sal Unit), and Samedan’s
5-62

Delineation Drilling Activities Offshore Santa Barbara County

Category ROG NOx CO SOx PM 

Stationary Sources 

 Fuel Combustion 12.46 307.07 177.36 13.72 15.36 

 Petroleum Production 354.56 9.21 50.14 77.52 2.72 

 Surface Coatings 15.46 - - - - 

 Total Stationary 382.48 316.28 227.50 91.24 18.95 

Mobile Sources 

 Ships/Comm. Boats 363.31 8,114.75 976.06 5,273.69 641.23 

 (crew/supply)* (19.75) (222.07) (55.95) (13.62) (22.20) 

 Recreational Boats 97.93 20.42 303.05 2.31 5.50 

 Aircraft 6.78 6.22 5.40 0.32 0.32 

 Total Mobile 468.02 8,141.39 1,284.51 5,276.32 647.05 

Petroleum Seeps 684.83 - - - - 

 Santa Barbara County Total 1,535.33 8,457.67 1,512.01 5,367.56 666.00 

* subset of shipping category 

Total Emission Contribution to Existing Santa Barbara OCS Emissions 

(tons) 

NOx CO VOC SO2 PM10

Bonito 35.07 9.20 5.34 0.87 2.39 

Point Sal 30.93 7.98 5.31 0.76 2.15 

Purisima Point 27.12 6.73 4.12 0.66 1.84 

Gato Canyon 32.37 7.40 3.01 0.77 1.96 

 Total 125.49 31.31 17.78 3.06 8.34 

1996 OCS Inventory 8,457.67 1,512.01 1,535.33 5,367.56 666.00 

Sword Unit and Gato Canyon Unit. Air emission impacts would be associated with delineation drilling

from the MODU and extended reach drilling from adjacent OCS platforms. The delineation drilling projects

will not run concurrently due to utilizing a single drill

rig and any short-term emission impacts from the individual activities are not expected to overlap. Emission potentials are unavailable at this time for the

Tranquillon Ridge and Sword Unit projects. All of

the proposed Federal and state oil and gas projects

will be subject to SBCAPCD permit requirements, including NSR provisions which require the implementation of BACT and emissions offsets to result in a net

air quality benefit for the projects. Therefore, the proposed projects will be permitted and analyzed by the

SBCAPCD to ensure that emissions from the proposed

projects will be below levels deemed significant to regional air quality.

On-going Oil and Gas Activities. The existing

energy related projects considered in Federal and state

waters to cumulatively contribute with the proposed

Bonito Unit project include air emissions from Platform Irene, the Point Arguello Unit and the Santa Ynez

Unit. The existing platforms identified within the vicinity of the proposed project are within the jurisdiction of the SBCAPCD and have current Permits to

Operate. Ambient air monitoring levels from the nearest monitoring station were combined with the predicted OCD modeled concentrations from the Bonito

Unit and no violation of the ambient air standards is

expected. It is assumed that the monitoring data represents ambient concentrations from the existing OCS

oil and gas facilities in the project area. The emission

sources from those facilities have been controlled and

fully offset and are in full compliance with SBCAPCD

Rules and Regulations and ambient air pollutant concentrations from these facilities are reflected in monitored data. Thus, the additional incremental emissions

levels expected with the proposed project will have been

fully offset and is not expected to have a cumulative

air quality impact with existing controlled and fully

offset Federal oil and gas activities.

Table 5.2.1-36. 1996 Santa Barbara County OCS emission inventory - (tons/year).

Table 5.2.1-37. Total emission contribution from proposed projects.
5-63

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

Marine Shipping and Tankering. Other offshore

emission sources considered in this analysis are marine shipping and tankering operations. Emissions

from marine vessels traversing the Santa Barbara

Channel are not regulated by federal, state or local

air authorities and may combine with emissions from

the proposed project to affect onshore air quality. However, emissions from the proposed project will be permitted and offset per Santa Barbara APCD Rules and

Regulations and is not expected to incrementally add

to the cumulative air quality impact of marine shipping and tankering.

Onshore Projects. No major onshore projects are

pending or approved in the vicinity of the Bonito Unit

project which have the potential of cumulatively impacting regional air quality.

Conclusions. The potential for the incremental

emissions increase associated with the Bonito Unit

delineation project to cumulatively impact regional air

quality are considered to be low. Emission increases

associated with the proposed project will be fully offset and permitted by SBCAPCD and are not expected

to contribute significantly to the potential impact to

regional air quality that may be expected from existing offshore oil and gas activities and marine shipping and tankering emissions. Emission modeling of

the project demonstrates a negligible short-term impact to overall regional air quality and is not expected

result in any violation of Federal or State ambient air

quality standards for the period 2002-2006.

Point Sal Unit. A single drill rig has been proposed by the applicants to drill all the proposed delineation wells. Section 5.2.1 discusses the expected air

quality impacts from each of the Proposed Actions.

Projected emissions from the Point Sal Unit exhibit

the highest NO2 concentrations of all the proposed

projects modeled. The modeled concentrations demonstrate that the proposed Point Sal Unit NO2

 emissions marginally exceed the lower level of the 1 hour

maximum increment range established by the

SBCAPCD for NOx allowable limits for a Class II area.

This lower limit has been established by SBCAPCD

and does not constitute a state or federal increment

and represents approximately 20% of the federal standard. The predicted concentrations were added to existing ambient background levels for NO2

, SO2, and

PM10 and demonstrate that the proposed Point Sal Unit

emissions are estimated to be less than the maximum

increases allowed under both the Federal and state

ambient air standards (Table 5.2.1-20). Non drilling

equipment will require a Permit to Operate from

SBCAPCD and will be in accordance with BACT and

emission offset provisions to ensure a net air quality

benefit.

Proposed Federal and State Oil and Gas Activities. Federal and state oil and gas activities considered

in the Point Sal Unit cumulative analysis include the

Tranquillon Ridge Unit, the proposed Aera’s Purisima

Point Unit, Nuevo’s Bonito Unit, and Samedan’s

Sword Unit and Gato Canyon Unit. Air emission impacts would be associated with delineation drilling

from the MODU and extended reach drilling from adjacent OCS platforms. The delineation drilling projects

will not run concurrently due to utilizing a single drill

rig and any short-term emission impacts from the individual activities are not expected to overlap. Emission potentials are unavailable at this time for the

Tranquillon Ridge and Sword Unit projects. All of

the proposed Federal and state oil and gas projects

will be subject to SBCAPCD permit requirements, including NSR provisions which require the implementation of BACT and emissions offsets to result in a net

air quality benefit for the projects. Therefore, the proposed projects will be permitted and analyzed by the

SBCAPCD to ensure that emissions from the proposed

projects will be below levels deemed significant to regional air quality.

On-going Oil and Gas Activities. The existing

energy related projects considered in Federal and State

waters to cumulatively contribute with the proposed

Point Sal Unit project include air emissions from Platform Irene, the Point Arguello Unit and the Santa Ynez

Unit. The existing platforms identified within the vicinity of the proposed project are within the jurisdiction of the SBCAPCD and have current Permits to

Operate. Ambient air monitoring levels form the nearest monitoring station were combined with the predicted OCD modeled concentrations from the Point Sal

Unit and no violation of the ambient air standards is

expected. It is assumed that the monitoring data represents ambient concentrations from the existing OCS

oil and gas facilities in the project area. The emission

sources from those facilities have been controlled and

fully offset and are in full compliance with SBCAPCD

Rules and Regulations and ambient air pollutant concentrations from these facilities are reflected in monitored data. Thus, the additional incremental emissions

levels expected with the proposed project will have been

fully offset and is not expected to have a cumulative

air quality impact with existing controlled and fully

offset Federal oil and gas activities.

Marine Shipping and Tankering. Other offshore emission sources considered in this analysis are

marine shipping and tankering operations. Emissions

from marine vessels traversing the Santa Barbara

Channel are not regulated by federal, state or local

air authorities and may combine with emissions from

the proposed project to affect onshore air quality. Emissions from the proposed project will be permitted and

offset per Santa Barbara APCD Rules and Regulations

and are not expected to incrementally add to the cumulative air quality impact of marine shipping and

tankering.
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Delineation Drilling Activities Offshore Santa Barbara County

Onshore Projects. No major onshore projects are

pending or approved in the vicinity of the Pt. Sal Unit

project which have the potential of cumulatively impacting regional air quality.

Conclusions. The potential for the incremental

emissions increase associated with the Point Sal Unit

delineation project to cumulatively impact regional air

quality is considered to be low. Emission increases

associated with the proposed project will be fully offset and permitted by SBCAPCD and are not expected

to contribute significantly to the potential impact to

regional air quality that may be expected from existing offshore oil and gas activities and marine shipping and tankering emissions. Emission modeling of

the project demonstrates a negligible short-term impact to overall regional air quality and is not expected

result in any violation of Federal or State ambient air

quality standards.

Purisima Point Unit. A single drill rig has been

proposed by the applicants to drill all the proposed

delineation wells. Section 5.2.1 discusses the expected

air quality impacts from each of the Proposed Actions.

The OCD model predicted emission concentrations for

the projected Purisima Point Unit to be within the

maximum allowable limits for a Class II area. The

predicted concentrations were added to existing ambient background levels for NO2

 and demonstrate that

the proposed Purisima Point Unit emissions are estimated to be less than the maximum increases allowed

under both the Federal and state ambient air standards (Table 5.2.1-26). Non drilling equipment will

require a Permit to Operate from SBCAPCD and will

be in accordance with BACT and emission offset provisions to ensure a net air quality benefit.

Proposed Federal and State Oil and Gas Activities. Federal and state oil and gas activities considered

in the Purisima Point cumulative analysis include the

Tranquillon Ridge Unit, the proposed Aera’s Point Sal

Unit, Nuevo’s Bonito Unit, and Samedan’s Sword Unit

and Gato Canyon Unit. Air emission impacts would

be associated with delineation drilling from the MODU

and extended reach drilling from adjacent OCS platforms. The delineation drilling projects will not run

concurrently due to utilizing a single drill rig and any

short-term emission impacts from the individual activities are not expected to overlap. Emission potentials are unavailable at this time for the Tranquillon

Ridge and Sword Unit projects. All of the proposed

Federal and state oil and gas projects will be subject

to SBCAPCD permit requirements, including NSR

provisions which require the implementation of BACT

and emissions offsets to result in a net air quality benefit for the projects. Therefore, the proposed projects

will be permitted and analyzed by the SBCAPCD to ensure that emissions from the proposed projects will be

below levels deemed significant to regional air quality.

On-going Oil and Gas Activities. The existing

energy related projects considered in Federal and State

waters to cumulatively contribute with the proposed

Purisima Point Unit project include air emissions from

Platform Irene, the Point Arguello Unit and the Santa

Ynez Unit. The existing platforms identified within

the vicinity of the proposed project are within the jurisdiction of the SBCAPCD and have current Permits

to Operate. Ambient air monitoring levels form the

nearest monitoring station were combined with the

predicted OCD modeled concentrations from the

Purisima Point Unit and no violation of the ambient

air standards is expected. It is assumed that the monitoring data represents ambient concentrations from

the existing OCS oil and gas facilities in the project

area. The emission sources from those facilities have

been controlled and fully offset and are in full compliance with SBCAPCD Rules and Regulations and ambient air pollutant concentrations from these facilities are reflected in monitored data. Thus, the additional incremental emissions levels expected with the

proposed project will have been fully offset and is not

expected to have a cumulative air quality impact with

existing controlled and fully offset Federal oil and gas

activities.

Marine Shipping and Tankering. Other offshore

emission sources considered in this analysis are marine shipping and tankering operations. Emissions

from marine vessels traversing the Santa Barbara

Channel are not regulated by federal, state or local

air authorities and may combine with emissions from

the proposed project to affect onshore air quality. Emissions from the proposed project will be permitted and

offset per Santa Barbara APCD Rules and Regulations

and are not expected to incrementally add to the cumulative air quality impact of marine shipping and

tankering.

Onshore Projects. No major onshore projects are

pending or approved in the vicinity of the Purisima

Point Unit project which have the potential of cumulatively impacting regional air quality.

Conclusions. The potential for the incremental

emissions increase associated with the Point Purisima

Unit delineation project to cumulatively impact regional air quality is considered to be low. Emission

increases associated with the proposed project will be

fully offset and permitted by SBCAPCD and are not

expected to contribute significantly to the potential

impact to regional air quality that may be expected

from existing offshore oil and gas activities and marine shipping and tankering emissions. Emission

modeling of the project demonstrates a negligible shortterm impact to overall regional air quality and is not

expected result in any violation of Federal or State

ambient air quality standards.

Gato Canyon Unit. A single drill rig has been

proposed by the applicants to drill all the proposed

delineation wells. Section 5.2.1 discusses the expected

air quality impacts from each of the Proposed Actions.

The OCD model predicted emission concentrations for
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

the projected Gato Canyon Unit to be within the maximum allowable limits for a Class II area. The predicted concentrations were added to existing ambient

background levels for NO2 and demonstrate that the

proposed Gato Canyon Unit emissions are estimated

to be less than the maximum increases allowed under

both the Federal and state ambient air standards (Table

5.2.1-34). Non drilling equipment will require a Permit to Operate from SBCAPCD and will be in accordance with BACT and emission offset provisions to

ensure a net air quality benefit.

Proposed Federal and State Oil and Gas Activities. Federal and state oil and gas activities considered

in the Gato Canyon Unit cumulative analysis include

the Tranquillon Ridge Unit, the proposed Aera projects

(Purisima Point Unit, Point Sal Unit), Nuevo’s Bonito Unit, and Samedan’s Sword Unit. Air emission

impacts would be associated with delineation drilling

from the MODU and extended reach drilling from adjacent OCS platforms. The delineation drilling projects

will not run concurrently due to utilizing a single drill

rig and any short-term emission impacts from the individual activities are not expected to overlap. Emission potentials are unavailable at this time for the

Tranquillon Ridge and Sword Unit projects. All of

the proposed Federal and state oil and gas projects

will be subject to SBCAPCD permit requirements, including NSR provisions which require the implementation of BACT and emissions offsets to result in a net

air quality benefit for the projects. Therefore, the proposed projects will be permitted and analyzed by the

SBCAPCD to ensure that emissions from the proposed

projects will be below levels deemed significant to regional air quality.

On-going Oil and Gas Activities. The existing

energy related projects considered in Federal and State

waters to cumulatively contribute with the proposed

Gato Canyon Unit project include air emissions from

Platform Irene, the Point Arguello Unit and the Santa

Ynez Unit. Additional southern Santa Barbara County

OCS and state facilities have also been considered for

their cumulative contributions with the proposed

project. The existing platforms identified within the

vicinity of the proposed project are within the jurisdiction of the SBCAPCD and have current Permits to

Operate. Ambient air monitoring levels form the nearest monitoring station were combined with the predicted OCD modeled concentrations from the Gato

Canyon Unit and no violation of the ambient air standards is expected. It is assumed that the monitoring

data represents ambient concentrations from the existing OCS oil and gas facilities in the project area.

The emission sources from those facilities have been

controlled and fully offset and are in full compliance

with SBCAPCD Rules and Regulations and ambient

air pollutant concentrations from these facilities are

reflected in monitored data. Thus, the additional incremental emissions levels expected with the proposed

project will have been fully offset and is not expected

to have a cumulative air quality impact with existing

controlled and fully offset Federal oil and gas activities.

Marine Shipping and Tankering. Other offshore

emission sources considered in this analysis are shipping and tankering operations. Emissions from marine vessels traversing the Santa Barbara Channel are

not regulated by federal, state or local air authorities

and may combine with emissions from the proposed

project to affect onshore air quality. Emissions from

the proposed project will be permitted and offset per

Santa Barbara APCD Rules and Regulations and are

not expected to incrementally add to the cumulative

air quality impact of marine shipping and tankering.

Onshore Projects. No major onshore projects are

pending or approved in the vicinity of the Gato Canyon Unit project which have the potential of cumulatively impacting regional air quality.

Conclusions. The potential for the incremental

emissions increase associated with the Gato Canyon

Unit delineation project to cumulatively impact regional air quality is considered to be low. Emission

increases associated with the proposed project will be

fully offset and permitted by SBCAPCD and are not

expected to contribute significantly to the potential

impact to regional air quality that may be expected

from existing offshore oil and gas activities and marine shipping and tankering emissions. Emission

modeling of the project demonstrates a negligible shortterm impact to overall regional air quality and is not

expected result in any violation of Federal or State

ambient air quality standards.

Summary and Conclusions (2002 – 2006):

The potential for the incremental emissions associated

with the Proposed Actions to add to cumulative impacts to air quality in the central Santa Barbara Channel and southern Santa Barbara County is considered

to be low. There is no temporal overlap expected of

the proposed delineation projects for the period 2002-

2006 due to the utilization of a single drilling rig that

would add to the expected peak hour emission estimates. Geographical overlap is limited presently to

the air pollutant contributions of existing OCS oil and

gas activities and ongoing marine shipping and

tankering operations. All proposed projects will be

subject to Santa Barbara APCD permit and NSR requirements to ensure individual projects do not result

in regional air quality impacts. The total emissions

for each Proposed Action are compared to the most

recently published 1996 OCS emission inventory for

Santa Barbara County in Table 5.2.1-37 and result in

less than 1.5% of that emission budget. A smaller

percentage contribution is expected to the onshore

emission budget. Therefore, no impacts to cumulative air quality are expected from the incremental

project contribution.
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Delineation Drilling Activities Offshore Santa Barbara County

5.2.2 WATER QUALITY

As noted in section 4.5, water quality in the Study

Area (Point Lobos to Point Fermin) Bight is quite good.

The following sections describe the potential for impacts to that water quality, first, from the proposal

(section 5.2.2.1). Section 5.2.2.2 then considers potential impacts to water quality cumulatively by considering all other relevant inputs to the ocean that

could also affect water quality. Section 6.2.2 then considers the potential cumulative impacts to water quality, over the timeframe of 2002 to 2030, if development

of the oil and gas resources that are proposed to be

drilled occurs.

5.2.2.1 IMPACTS OF THE PROPOSED

ACTION

IMPACT LEVEL DEFINITIONS FOR WATER

QUALITY

The following significance criteria were used in

the following analysis to determine whether the Proposed Action would result in significant impacts to

water quality.

High (Significant): Project may cause or contribute to changes in standard, measurable water quality

parameters resulting in unreasonable degradation1 to

the water quality over an area, defined as greater than

10,000 m (32,000 ft) from the discharge point.

Moderate (Significant): Project may cause or contribute to changes in standard, measurable water quality parameters resulting in unreasonable degradation

to the water quality over an area, defined as from 5,000

m to 10,000 m (16,000 to 32,0000 ft) from the discharge

point.

Low (Insignificant): Project does not cause or

contribute to changes in standard, measurable water

quality parameters resulting in unreasonable degradation to the water quality over an area defined as

from 100 m to 5,000 m (320 to 16,000 ft) from the

discharge point.

Negligible: A negligible impact to water quality

may cause changes in water quality parameters for a

short period, within 100 m (320 ft), but might still be

worthy of an enforcement action by the Environmental Protection Agency (EPA) or the U. S. Coast Guard

(USCG). This might take the form of a violation of a

National Pollutant Discharge Elimination System

(NPDES) permit, either by exceeding a limit or by creating an oil sheen (also a violation of USCG regulations). However, the act of violation, under this scenario, would not constitute an unreasonable degradation to water quality. Marine oil spills are not regulated under NPDES regulations or permits.

MITIGATION THAT IS PART OF THE

PROPOSED ACTION

National Pollutant Discharge Elimination System permits. A mitigation that will be part of the Proposed Action, via EPA regulation, is the NPDES permit in-place at the time of the proposed drilling

projects. Historically, mobile offshore drilling units

(MODUs) have acquired Individual NPDES permits

in order to operate offshore California. If the new

General permit is in-place by the time these proposed

operations occur, the MODU will operate under that

General permit. In any case, either an Individual or

the new General permit will be required by EPA for

any of the delineation drilling operations to commence.

Two sources of pollution that could affect water

quality during the operations of the delineation activities are turbidity raised from the sea floor during

the placement and recovery of the drilling vessel anchors and from as many as 17 discharges emanating

from the drilling vessel (table 5.2.2.1-1). No oil spills

are expected from these delineation drilling projects.

RESUSPENSION AND TRANSPORT

PROCESSES

Resuspension of sediments, whether from anthropogenic or natural sources, occurs in the bottom portion of the water column and can result in short-term

changes in various sediment characteristics, including grain size and chemistry, and water quality parameters. Resuspension processes can play a role in

certain offshore oil and gas activities such as anchoring and drilling mud fates. For example, sediment

stirred up during anchoring activities would drift

down-current for some distance, eventually resettling.

Also, drilling mud that settled close to the discharge

point could also be resuspended by bottom currents

and dispersed down-current. Both of these aspects

are discussed below. Finally, changes in sediment characteristics can affect the infauna communities living

within the sediments. This is discussed in the section

on sea floor resources (section 5.2.4).

Turbidity currents or flows (sediment-laden, density-driven currents that “avalanche” downslope, along

the sea floor) bring large pulses of sediment from the

1

 EPA’s regulations at 40 CFR 125.121(e)(1-3) state that

unreasonable degradation of the marine environment means:

(1) Significant adverse changes in ecosystem diversity, productivity and stability of the biological community within

the area of discharge and surrounding biological communities; (2) Threat to human health through direct exposure to

pollutants or through consumption of exposed aquatic organisms; (3) Loss of esthetic, recreational, scientific or economic values which is unreasonable in relation to the benefit derived from the discharge.
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Impacting agent Pollutant(s) Affected Water Quality 

Parameter(s) 

Estimated Distance of 

Effect (meters)* 

Anchoring activities Particulate material Turbidity 100 to 500 

Particulate material Turbidity 7,000 

Barium, chromium, cadmium, 

mercury, iron, zinc, and other 

metals 

Increased metal levels 1,000 

Drilling muds 

Additives including: sodium 

bicarbonate, ground nut shells, 

mica, cellophane, cellulose 

polymers, starch, aluminum 

stearate, alcohols, bactericides 

General pollution** 1,000 

Drilled cuttings Particulate material Turbidity 1,000 

Well completion fluids Oil and grease Increased hydrocarbons 100 

Deck drainage Oil and grease Increased hydrocarbons 100 

Chlorine Increases in chlorine 100 

Fecal coliform bacteria Bacterial contamination 100 

Treated sewage 

Floating solids and foam General pollution At the point of discharge 

Domestic wastes Floating solids and foam General pollution At the point of discharge 

Particulate material Increases in turbidity 100 Excess cement slurry 

Carbonates and other chemicals General pollution 100 

Oil and grease Increases in 

hydrocarbons 100 Blowout preventer 

fluid 

Floating solids and foam General pollution At the point of discharge 

Desalination unit 

discharge Floating solids and foam General pollution At the point of discharge 

Floating solids and foam General pollution At the point of discharge 

Chlorine (for antifouling) Increase in chlorine 100 

Fire control system 

test water 

Chemical inventory (if 

chemicals are used in the 

effluent) 

General pollution 100 

Floating solids and foam General pollution At the point of discharge 

Chlorine (for antifouling) Increase in chlorine 100 

Noncontact cooling 

water 

Chemical inventory (if 

chemicals are used in the 

effluent) 

General pollution 100 

Ballast storage and 

displacement water Oil and grease Increases in 

hydrocarbons 100 

Table 5.2.2.1-1. Potential impacting agents and the associated specific pollutants, potential water

quality parameters affected, and the estimated distance from the point of discharge the parameter

could be affected.
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Delineation Drilling Activities Offshore Santa Barbara County

Impacting agent Pollutant(s) Affected Water Quality 

Parameter(s) 

Estimated Distance of 

Effect (meters)* 

Floating solids and foam General pollution At the point of discharge 

Oil and grease Increases in 

hydrocarbons 100 Bilge water 

Floating solids and foam General pollution At the point of discharge 

Boiler blowdown Floating solids and foam General pollution At the point of discharge 

Floating solids and foam General pollution At the point of discharge 

Chlorine (for antifouling) Increase in chlorine 100 

Test fluids 

Chemical inventory (if 

chemicals are used in the 

effluent) 

General pollution 100 

Uncontaminated water Floating solids and foam General pollution At the point of discharge 

Oil and grease Increases in 

hydrocarbons 100 Laboratory wastes 

Floating solids and foam General pollution At the point of discharge 

Oil and grease Increases in 

hydrocarbons 100 Muds, cuttings and 

cement at the sea floor 

Floating solids and foam General pollution At the point of discharge 

*In most cases this distance may equal background levels or concentrations of the pollutant. 

**EPA defines a pollutant as a material that does not occur naturally at the levels input into the receiving waters. 

Not all pollutants are specifically regulated via limitations or other monitoring tools. 

continental shelf toward deep water. Often, these

pulses are associated with the large sediment input

from rivers, for example, during the 1969 winter storm

flood conditions (Drake et al., 1972). About 60 to 70

percent of the sediment input consists of silts and clays

with sand and some gravel making up the rest (Gorsline

et al. 1984). Since the heavier sand and gravel particles drop out of turbidity flows sooner, only finer,

silt and clay-sized particulate material arrives in deeper

water, further from the source. Once these pulses of

sediments settle, they also become subjected to the

resuspension processes described above. If a turbidity current passed over an area where drilling discharges had settled, they too could be rapidly redistributed and mixed with the sediment contained within

the flow.

Nephaloid layers have been examined by various researchers including Kolpack et al. (1972) and

Gorsline et al. (1984). These sediment-laden, bottomfounded, isothermal layers of water can range from 5

to 35 m (16 to 112 ft) in thickness above the sea floor.

Tidally-associated currents and input from up-shelf

turbidity flows contribute to this phenomenon.

While the Kolpack and Gorsline studies examined sediment processes in the Santa Barbara Channel, there have been only the MMS-sponsored California Monitoring Program (CaMP) studies in the western Channel and Santa Maria Basin. For example,

Steinhauer and Imamura (1990 in EPA, 2000c) found

that sediments in the vicinity of the Point Arguello

Unit platforms consisted of approximately 35-85 percent fines (silts and clays) and 15-65 percent sands

with no predominant trends with depth or distance

offshore. Unit-specific information is given below in

the discussion on anchoring activities.

DRILLING DISCHARGES

The following discussion addresses the various

effluents that can emanate from exploratory, operations on the OCS. All the effluents are regulated by

the new General 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. Potential water quality impacts regarding these effluents

will be the same for all the units.

The permit covers 22 possible effluents. Not all

of these will emanate from delineation operations; this

is noted where necessary. For example, of the first

Table 5.2.2.1-1. Potential impacting agents and the associated specific pollutants, potential water

quality parameters affected, and the estimated distance from the point of discharge the parameter

could be affected (continued).
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

five effluents discussed below (drilling muds and cuttings, produced water, well treatment completion and

workover fluids, deck drainage and domestic and sanitary wastes), produced water and well treatment and

workover fluids will not be discharged from the proposed operations; thus, they are not discussed below.

However, discussions in other parts of this EIS will

include assessments for potential impacts to the water quality from existing and future development and

production operations.

The principal impact-producing activities associated with drilling of the proposed wells that could

affect water quality are discharges of drilling muds

and cuttings. The parameters that could affect water

quality due to this discharge are turbidity, hydrocarbons, metals, and additives used in the drilling-mud

systems (table 5.2.2.1-1).

Drilling Muds. Drilling mud is discharged under two general conditions. First, during drilling,

some mud adheres to the drilled cuttings and is discharged in small quantities with the cuttings. Second, when the driller needs to change the mud system

or comes to the end of the well, much of the mud system is discharged (some small amount may remain in

the well, and some may be lost to the formation). The

following paragraphs discuss the processes by which

drilling mud is moved from the point of discharge,

through the water column and to sea floor and beyond to eventual mixing with existing sediments. This

discussion of the fate will include how studies have

traced drilling discharges, how currents move the

material and the role of resuspension.

The most comprehensive study done on drilling

discharge fates and effects is the CaMP. The purpose

of this 8-year, three-phase project, was to examine the

effects of drilling discharges on nearby deep-water

rocky reef habitats. In the process, an immense

amount of auxiliary data was collected and analyzed.

Much of the information presented below comes from

these studies. Monitoring of Platforms Hermosa,

Harvest and Hidalgo during CaMP was conducted from

1986 to 1994. During this time 44 wells were drilled.

Drilling muds were discharged at 34 m (109 ft) below

the surface at Hidalgo and Hermosa and 91 m (291 ft)

at Harvest and were highly variable, ranging from zero

to 1,300 bbl per day with typical discharges of 100 to

200 bbl/day.

Fate of Drilling Muds. The fate of drilling discharges is important because the amount that remains

in the water column, and eventually settles to the sea

floor, can help to determine the extent of any environmental impact. To determine the fate of drilling muds,

barium has often been used as a tracer. It is used as a

weighting agent (materials used to increase the weight

of the column of drilling mud – enabling better well

control – without overly increasing the volume) and

is the single most common metal used in drilling mud

formulations (SAIC and MEC, 1995). For example,

Jenkins et al. (1988) traced barium in sediments which

was discharged with drilling muds during the drilling

of an exploratory well in State waters near Gaviota.

About 866,000 kg (1,905,200 lb.) of barite (BaSO4

) was

used in the drilling of the well. The currents in the

area caused the drilling mud plume to deposit the barite and other associated solids in a fairly narrow pattern to the west of the drilling site. The authors found

that barium levels reached background with 1, 500 m

(4,800 ft) of the well site.

Coats (1991) used the deposition of barium to

study the lighter fractions of drilling muds that were

initially deposited at mid- and far-field locations

(greater than 0.5 and 1.0 km (0.31 to .62 mi) from the

discharge point, respectively). Barium in the drilling

fluids used was 150 times more concentrated than that

in natural sediments, allowing detection of relatively

small fractions of drilling particulates in samples at

distances up to 6,800 m (21,760 ft) from the discharge

point. From 1986 to 1989, the three Point Arguello

platforms, Hermosa, Hidalgo and Harvest, released

an estimated 5,120,000 kg (11,264,000 lb) of barite,

with an annual average of 1,280,000 kg (2,816,000 lb)

(Steinhauer, et al., 1991 – Chapter 2). Furthermore,

other metals, including iron, lead, zinc, mercury, arsenic, chromium, cadmium, nickel and copper had concentrations closer to local ambient levels (Steinhauer

et al., 1991 – Chapter 6).

Coats (1991) suggested that discharged drilling

muds accounted for 1.97 percent of the suspended sediment flux (direct impingement out of the water column) at one of the near-field stations in CaMP, indicating that this factor could be used to determine

barium enrichment. Further, due to this small fraction of total suspended material derived from drilling

material, compared to natural sources, any increase

in other inorganic contaminants would also be small

and be below statistical power to detect changes.

Steinhauer, et, al. (1991 – Chapter 2) noted that

after drilling ceased at Platform Hidalgo in 1989,

barium levels gradually declined to near-background

by October 1989 (between 749 and 959 μg/g). Overall,

within 1.5 years after drilling ceased in the Arguello

Field, barium collected in sediment traps had dropped

to background. Since barium can be reliably used to

trace fates of drilling mud discharges, it can be reasonably concluded that the drilling discharges from

the Hidalgo drilling activity were also dispersed to

background.

Dispersion of discharged drilling muds occurs

upon initial discharge by local mid-depth and nearbottom currents, and later by bottom currents resuspending the material. A good example of the type of

mid-depth and near-bottom currents that disperse drilling mud discharges was noted during the CaMP studies (Coats, 1991; Savoie, et, al., 1991). To a large extent, fluctuations in mid-depth current flow dictated

trajectories and depositional patterns of drilling muds,
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Delineation Drilling Activities Offshore Santa Barbara County

while near-bottom currents played a major role in

resuspension and further dispersion of this effluent

(surface waves – even during storm conditions – did

not influence resuspension dynamics due to the water

depth). At the Point Arguello area, where this study

was conducted, mid-depth and near-bottom currents

followed isobaths to the extent that drilling discharges

were deposited parallel to shore in a fairly narrow

band. Currents in this area were poleward at middepth (54 m (173 ft)) and near-bottom (126 m(403 ft))

and did not exhibit a seasonal reversal, as did surface

currents, although they did weaken around the same

time.

Once a drilling fluid plume has passed through

the influence of the initial gravity-driven phase of the

discharge (labeled as dynamic collapse in figure 5.2.2.1-

1), it begins to disperse by passive diffusion. The fine

clay particulate material, commonly used in drilling

fluids, tend to flocculate (clump together) when they

contact seawater. This electrostatically-driven process results in much of the particulate settling to the

sea floor sooner than if flocculation did not occur.

Some of the clay particles, do not flocculate. These

may remain in the water column indefinitely, eventually diffusing to background levels. These lighter,

smaller particles have been calculated to dilute to

greater than 1,500 to 1 beyond a distance of 32 to 96

m (100-300 ft) from the point of discharge (ADL,

1984a). Between 70 and 80 percent of the drilling mud

volume was water (sea or fresh) while fractions of

coarse sand, coarse silt and slit/clay ranged (in percent) from 0.77-1.55 ; 9.91-12.28; and 7.27-17.87, respectively.

Modeled seafloor deposition of solids, based on

discharges and oceanographic conditions at Platform

Hidalgo, showed that only 17-20 percent of the solids

settled out within a 16.6 hour period (Coats, 1991).

The remaining 80 percent of the solids would be distributed over an increasingly large volume of water

and area of seafloor resulting in very small, and probably undetectable, additions to the ambient levels of

particulate material. Similarly, sediment traps and

subsequent modeling at Platform Hermosa showed

that heavier particles fell close to the platform and

covered about 2.75 km2

 (679.5 acres) while silts and

clays were widely dispersed (greater than 16 km (9.9

mi) in some cases). Measured current speeds of 7 cm/

s (0.14 kts) were strong enough to transport material

about 6 km/day (3.7 mi/day).

Given a discharge depth of 34 m (111 ft), a water

depth of 183 m (603 ft), an average current speed of 7

cm/s (0.15 kts), and the following sinking rates per

100 m (310 ft): (sand/and other coarse materials, .32

hours; coarse silt, 20 hours, light slit/clay, 56 hours),

it can be seen that the lighter particles would be very

widely dispersed in a large volume of water. While the

concentration of mud particulates could exceed the ambient concentration by about 500 times during a mud

dump at 100 m (320 ft) from the discharge point (according to a generalized model), this condition is temporary due to dispersion of the particulate material

over a wide area and throughout the water column.

Modeling at the end of the CaMP studies confirmed this assumption of wide dispersion, giving an

average bottom accumulation of drilling particulate

Figure 5.2.2.1-1. Idealized view of drilling mud discharge – not to scale (from Battelle, 1991).
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

material of 1.5 to 7.5 microns (1 micron equal 1 millionth of a meter), corresponding to a very large footprint of 100 to 550 km2

 (24,710 to 135,905 acres) depending on particle size, as well as the dispersion of

40 to 80 percent of the finest-grained material beyond

the study region (SAIC, and MEC, 1995). One source

of information that explains why so much of the finer

particulate material remains in the water column comes

from Kolpack et al. (1972). In this paper, the authors

noted that flood-associated sediments from rivers

formed several mid-water sediment layers associated

with thermal stratification. These mid-water density

strata prevented some fine particulate matter from settling to the sea floor and were, instead, advected with

mid-water column currents. If a drilling mud outfall

was above a sufficiently strong thermocline, then much

of the fine particulate material could be advected within

the mid-water column currents in much the same way

as the documented river sediments.

Resuspension of drilling muds. Boundary layer

(near-bottom) currents cause resuspension of drilling

muds, as well as natural sediments, and is the other

primary factor in the dissipation of drilling discharge

particulates (Parr et al., 1991). In nondepositional

environments with relatively strong currents, the mud

solids may be resuspended from their original site of

deposition and be moved to lower energy areas.

Resuspension of surficial sediment in the Point

Arguello area averaged over 25 g/m2/day, and was the

most likely source for much of the material captured

by sediment traps since the ambient fallout of detrital

and terrigenous material ranged from 0.6 to 2.5 g/m2/

day (Steinhauer et al., 1991 – Chapter 6). However,

resuspension of drilling muds is not considered a water quality issue for two reasons: (1) no resuspension

process will raise sedimentary material greater than

one or two meters above the sea floor and (2) the same

resuspension process that moves drilling mud material will also raise natural sediments, further mixing

the two together and dispersing the drilling mud component.

As noted above, several aspects of drilling muds

can affect water quality. These include, turbidity, hydrocarbons, metals, and additives and are discussed

briefly below.

Turbidity. Increases in turbidity would arise

from the discharge of drilling muds and cuttings. The

new General NPDES Permit does not directly regulate this parameter. While it is apparent from the discussion above that much of the drilling mud fraction

remains in the water column for extended distances

and periods of time, dispersion processes continue to

work on the particulate, spreading it in three dimensions. This process will eventually reduce the particulate loading to background. A conservative estimate for drilling-related particulate to reach background is 7,000 m (22,960 ft). However, natural variations in particulate range widely throughout the water column, up to several orders of magnitude greater

than measured background levels (SAIC and MEC,

1995). Thus, any increase in particulate material due

to drilling activities, even over a wide area, will not

cause an impact to water quality since it will be temporary and transient, be within natural variability and

be dispersed to background.

Metals. Barium, chromium, cadmium, mercury,

iron, zinc, lead, arsenic, nickel and copper can all be

found in drilling muds. However, only barium, in the

form of barite (barium sulfate - BaSO4 - the form of

barium that is added to drilling muds) is added to mud

formulations. Iron is generally not present while many

of the others, including silver, vanadium, cadmium,

mercury, arsenic, nickel and copper, are contaminants

in barite. Lead and zinc were detected during the

CaMP studies and were traced back to the use of pipe

dope, a material used to lubricate the threads on drilling pipe when building or taking apart drill pipe strings

(SAIC and MEC, 1995).

Sea water background concentrations of metals

are (in μg/l): arsenic, 3; copper, 2; mercury, 0.0005;

silver, 0.16; and zinc, 8 (EPA, 2000a). All other metals are presumed not to occur in sea water at detectable levels. By comparison these metals were found in

drilling mud samples taken from the mud pits on the

platform, before discharge, to be (in μg/g dry weight2

):

arsenic, 0.28; copper, 30; mercury, 0.13; silver, 0.28;

and zinc, 290 (Steinhauer et al. (1991 – Chapter 6).

As can be seen, some metals are higher, some lower

and some about the same as in natural sea water. All

the metals in drilling fluids, except barium, are found

in the less than 1 part per million (ppm) range. Additionally, once the effluent is discharged and becomes

dispersed, as discussed above, levels of the metals in

the effluent will decrease to background.

Further, Steinhauer et al. (1991 – Chapter 6)

found that zinc and barium were the only metals analyzed from drilling mud samples at Platform Hidalgo

found to be significantly higher than those found in

the surface sediments. Similarly, only concentrations

of lead, zinc and barium were significantly elevated in

drill cuttings relative to concentrations in marine sediments. The presence of lead and zinc in the CaMP

study, while unexpected but detectable, was judged to

not have any impact on the benthic environment by

SAIC and MEC (1995).

Neither barium nor iron (as an alternative to

barite) have been monitored in the old General or Individual NPDES Permits, nor will they be monitored

in the new General Permit. Only mercury and cadmium are monitored in the barite. EPA’s justification

for this is that, so called “clean” barite will exhibit

low levels of contamination of, not only mercury and

cadmium, but of the other metals, as well (EPA, 2000b).

The use of chromlignosulfonate is specifically prohib-
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Delineation Drilling Activities Offshore Santa Barbara County

ited due to the potential presence of hexavalent chromium, a toxic form of chromium. As a result, EPA

has not and will not require a full metals analysis of

drilling fluid formulations in the new General NPDES

Permit. None of the metals used or contained in the

drilling muds for these projects will cause impacts to

water quality.

Additives. The new (and old) General NPDES

permit allow the use of eight generic mud types. These

eight types were determined by EPA to be of low toxicity. The additives listed in table 5.2.2.1-1 are all commonly used in one or more of the eight generic drilling fluids. Therefore, EPA determined that these eight

types will not cause harm to the water quality or the

organisms in the water as long as the operator stays

within the permissible contents of the various additives (EPA 1984).

Drilled Cuttings. Drilled cuttings are produced

as a result of the drill bit pulverizing the penetrated

formations. Sizes of cuttings range from pebble (about

0.6 cm (0.25 in)) to fine sand (less than 0.25 cm (1/10

in)). Cuttings also vary in terms of specific gravity, of

density, which, along with the size determines how

fast they sink in water. More dense and larger particles will sink faster than, for example particles of

the same size but are less dense. Because of their large

size and weight (relative to drilling mud particulates,

which are clay-sized and of nearly the same density),

drilled cuttings fall more quickly through the water

column than drilling muds. The references to “coarse

material” in the above discussion on drilling muds

refer to cuttings. While the fall is not vertical, no

cuttings are expected to remain in the water column

more than an hour after they leave the end of the disposal caisson (de Margerie, 1989), which will be between 30 and 40 m (100 and 130 ft) below the sea surface.

Little research has been conducted on drilled

cuttings due to this tendency to fall more directly to

the sea floor and contact a limited area of the sea floor

near the discharge point. However, an estimated maximum of 33 percent of the cuttings volume could be

drilling muds adhering to the cuttings (de Margerie,

1989). Consequently, while there will be a continuous

plume of muds that come loose from the cuttings during their fall through the water column, some proportion of the cuttings pile near the base of the drilling

vessel will consist of muds.

Steinhauer et al. (1991 – Chapter 6) conducted

an analysis of drilled cuttings discharged from Platform Hidalgo during the CaMP studies. Similarly to

the analysis of metals in drilling muds, only lead zinc

and barium were significantly elevated above the background levels found in the natural sediments. The

authors surmised that barium was elevated due, in

part, to drilling through barium-enhanced sediments,

as well as from the remainder of drilling muds that

adhered to the cuttings. The source of the lead and

zinc was from the pipe dope as noted above.

Since the cuttings will not remain in the water

column for very long and fall relatively close to the

discharge point, there will be no impacts to the water

quality.

OTHER DISCHARGES

Well Treatment, Completion and Workover Fluids. Only well completion fluids will be used during

the proposed exploratory operations. Well completion

fluids are salt solutions, weighted brines, polymers,

and various additives used to prevent damage to the

well bore during operations which prepare the drilled

well for hydrocarbon production (EPA, 2000b). The

General permit will require volume monitoring, no

discharge of free oil monitored by using a static sheen

test and a once per job oil and grease samples with

limits set at 29 mg/l monthly average or 42 mg/l daily

maximum (EPA, 2000a).

Deck Drainage. Deck drainage is mostly water

that contains materials that is washed from the decks

into drains and thence into the sea. Materials on the

deck of the drilling vessel may range from small spills

of hydrocarbons, drilling-related material, and cleaning solutions. The decks made be washed down, testing of fire systems may wash these material down the

drains, or rain may fall. The drains lead to a tank

where solids fall to the bottom and any hydrocarbons

float to the surface. In some cases, hydrocarbons are

removed by treatment in an oil-water separator of some

type. The solids would eventually be removed, containerized, and sent to shore for disposal while the

hydrocarbons would be collected and stored until they

can added to the test barge. The new General permit

will require volume monitoring and no discharge of

free oil, monitored by visual observations.

Sanitary and Domestic Wastes. Sanitary wastes

are human body wastes from toilets and urinals. These

wastes are treated by treatment machines onboard the

platforms and include maceration and the addition of

chlorine to kill fecal coliform bacteria. Chlorine is

limited to less than 10 mg/l but greater than, and as

close as possible, to 1 mg/l. Domestic wastes are materials from sinks, showers, laundries, safety showers, eyewash stations, and galleys. No treatment of

these materials is necessary. However, if foam appears

on the sea surface, then domestic wastes must be

2

 The terms μg/l and μg/g dry weight , both represent parts

per billion (ppb), and are only loosely comparable since they

are determined using different methods. However, this

analysis is given to show differences and trends, rather than

absolute comparisons, since the effluent undergoes high dilution upon discharge.
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

checked to ascertain if the foam is coming from there.

The above requirements apply only for facilities manned

by more than 10 persons.

The remaining potential effluents that could

emanate from the proposed exploratory operations and

a short description of the effluent (EPA, 2000a) and

NPDES permit limitations and monitoring (L&M) are

given below (EPA, 2000b).

• Blowout preventer fluid: fluids used to actuate

the hydraulic equipment on blowout preventers.

During testing or use, they could be spilled.

L&M: no discharge of free oil, floating solids

or foam.

• Desalination unit wastes (brines): Wastewater

associated with the process of creating fresh

water from sea water. It is in the form of concentrated sea water, usually around 40 parts

per thousand (ppt). L&M: no floating solids

or foam.

• Fire control system test water: Sea water used

during the training of personnel in fire protects and the testing and maintenance of fire

protection equipment. These water may be

treated with chlorine or other biocide to control fouling of the piping. L&M: monthly

chemical inventory, monitoring of chlorine

used, no floating solids or foam.

• Non-contact cooling water: sea water used to

cool machinery via heat exchangers. The water does not contact the machinery itself, it

merely removes heat and is discharged directly

into the sea. L&M: flow rate, chemical inventory, chlorine monitoring and no floating solids or foam.

• Ballast and storage displacement water: sea

water used to stabilize a drilling vessels draft

and trim. L&M: flow rate, no discharge of free

oil, no floating solids or foam.

• Bilge water: sea water which collects in the

lower internal areas of a drilling vessel’s hull

and may be contaminated with oil and grease

or rust. Bilge water is directed to an oil/water

separator before discharge, which occurs intermittently. L&M: flow rate, chemical inventory, chlorine monitoring and no floating solids or foam.

• Boiler blowdown: This is the discharge of circulation water and minerals from boilers necessary to minimize solids build-up in the boilers (if any – at this time, it is unknown if boilers will be aboard the drilling vessel). This is

an intermittent discharge. L&M: no floating

solids or foam.

• Test fluids: these are discharges that could occur if hydrocarbons are located during exploratory drilling and tested for formation pressure and content. It is unknown at this time

what the exact character of these test fluid are,

or if they will actually be discharged during

testing procedures. As noted above, no produced water will be discharged. What other

fluids are possible is unknown. L&M: flow

rate, no discharge of free oil, chemical inventory, no discharge of floating solids or foam.

• Bulk transfer material overflow: This refers

to bulk materials, such as barite, bentonite,

or cement which may be discharged during

transfer operations from supply ships to the

drilling vessel. This often takes the form of

dust in the form of small particles of the material being blown through the loading system

below the sea surface. L&M: no discharge of

floating solids or foam.

• Uncontaminated freshwater: This effluent

could come from such sources as air conditioning condensate or potable water transfer operation spills. L&M: no discharge of floating

solids or foam.

• Laboratory wastes: this discharge includes

small volumes of discharges associated with

laboratory testing occurring on the drilling

vessel. Given the small volume of this waste,

it is not expected to pose an environmental risk.

L&M: no discharge of free oil, no discharge of

floating solids or foam.

• Excess cement slurry, and drilling muds, cuttings, and cement at the seafloor: these wastes

result from marine riser disconnect and well

abandonment and plugging. L&M: no discharge of free oil, no discharge of floating solids or foam.

None of the discharges, described above, except

for muds and cuttings, will affect the water quality

within the Study Area.

ANCHORING ACTIVITIES

A total of eight anchors will be set and raised for

each wellsite. These anchors impact the sea floor and

raise clouds of sediment a few meters into the water

column. This particulate material is then redistributed by the bottom currents until it settles some distance away. This distance is dependant primarily on

grain size and bottom current speed. Unit-specific

descriptions of grain size is given below. No site-specific grain size data is available, but the CaMP conducted sediment grain size studies (SAIC, 1986) in the
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Delineation Drilling Activities Offshore Santa Barbara County

Santa Maria Basin and western Santa Barbara Channel. For all Units, bottom current speeds ranged between 5 and 50 cm/s (0.1 to 1 kt) (SAIC, 1986).

Gato Canyon Unit. The proposed wellsite is located on a fairly steep slope, indicating that grain size

is probably poorly sorted. Although no site-specific

data is known to exist for this wellsite, since the

wellsite is within 5 miles of shore, it is likely that the

area would be dominated by nearly equal measures of

silt and sand.

Bonito Unit. Potential well locations are located

between 200 and 500 m (640 and 1,600 ft) of water in

a complex canyon topography. The grain size in the

Bonito Unit area is dominated by silts; in places more

than 90 percent of the sediments were classified as

silt. Clay averaged between 5 and 25 percent and sand

between 10 and 60 percent. These areas were classified as poorly sorted, in large part due to the complex

canyon topography.

Point Sal and Purisima Point Units. These units

are located on a broad, flat shelf offshore Purisima

Point and Point Sal and are both less than 200 m (620

ft) of water. They are dominated by silty sediments,

ranging between 50 and 80 percent. Clay sediments

ranged between 15 and 30 percent while sand was usually less than 10 percent. These areas were classified

as well-sorted.

Conclusion (Anchoring Activities). For all four

units, the presence of large percentages of silt will cause

clouds of sediment to rise into the water column, as

discussed above. Only transient impacts to the water

quality will occur, either vertically or horizontally,

since these silty sediments will likely settle to background within 500 m (1,600 ft; table 5.2.2.1-1) and

will not rise vertically within the water column in such

a fashion to affect background sediment levels (normally 1-5 mg/l) over a large area (SAIC, 1986; 1995).

IMPACTS COMMON TO ALL UNITS

None of the discharges discussed above, except

drilling discharges, will cause any water-quality impacts due to the small volume of the discharge, the

treatment systems required, and the short-term nature of the drilling activities at each unit. Each of the

discharges will dilute quickly to background levels.

Impacts arising from drilling discharges are discussed below. While the physical characteristics for

each unit might vary (for example, water depth, current speed, etc.) the impacts to water quality are likely

to be the same. Therefore, for clarification, some unitspecific information is included below, but the conclusion applies to all units. Also, no produced water is

expected to be discharged during any of the proposed

drilling or well testing activities. Produced water, as

an effluent from other existing and future OCS activities, is discussed in the cumulative analysis (sections

5.2.2.2.1 and 2).

Because the primary impact from drilling muds

is the dispersion of the muds into the water column,

local mid-depth and bottom currents at each well site

are the most important information. These give an

indication of the direction and extent of the mud dispersion and whether they are in two primary directions, along isobaths, as was seen during the CaMP

studies, or more cross-shelf. Additional detail on the

physical oceanography of the study area may be found

in section 4.4.

Gato Canyon. Mid-depth and bottom current

measurements taken in the Santa Ynez Unit, just east

of the proposed Gato Canyon Unit drilling site indicated that currents tended westward, toward the western Channel exit at current meter stations to the shelfbreak, about 200 m (ADL, 1984). Deeper than that,

currents began to experience the Ekman spiral, where

the Coriolis effects begins to be felt and twists currents to the right with depth. The proposed Gato Canyon well site location is in about 230 m (755 ft) water

depth so that drilling discharges from there may experience some Eckman-related current modification to

the southwest. Averaged mid-depth and bottom current speeds were on the order of 10 to 12 cm/s (0.19 to

0.23 kts) somewhat comparable to the 7 cm/s (0.14

kts) current speeds described for the CaMP study area

(SAIC, 1986). Therefore, much of the drilling muds

would be carried along the west to southwest direction, spreading throughout the water column and dispersing to background particulate levels.

Bonito Unit. The Bonito Unit is located to the

west of the Arguello platforms and in deeper water.

The well sites under consideration by Nuevo for drilling range in water depth from about 300 to 500 m

(960 to 1,600 ft). No site-specific mid-depth or bottom

current measurements have been taken in this area.

However, it is reasonable to estimate that these currents would be similar to those measured for the Point

Arguello area, except with greater variability and more

cross-bathymetric characteristics (pers. comm. David

Browne, Oceanographer, MMS). Thus, due to greater

current variability and water depth, both drilling muds

and cuttings would be spread over a potentially very

large volume of water, falling onto the sea floor over a

wide-spread area, perhaps on the order of several hundred square kilometers.

Point Sal and Purisima Point Units. The water

depth for the locations of these proposed well sites

range from 60 to 100 m (192 to 320 ft). An ongoing

MMS-sponsored study has been examining the currents in the Santa Maria Basin. Results from this

study indicate, as was seen for the Point Arguello area,

that mid-depth and bottom currents are nearly constantly poleward. Since the slope of the sea floor in

the area of these well sites gently slopes to the west,

there would not be much of a cross-shelf current aspect. Mid-depth and bottom current speeds may range
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

from 27 to 50 cm/s (0.5 to 1 kt) with occasional burst

of 150 cm/s (2.9 kts) according to manned submersible observations (ADL, 1985). Drilling mud discharges may not contact the sea floor anywhere near

the discharge point, given current speeds such as these,

even though the water depth is fairly shallow. Given

the potential turbulence and mixing capability of the

currents and waves, dispersion of drilling muds and

cuttings would be very rapid.

Impacts to water quality from the discharge of

drilling muds and cuttings to water quality from these

projects are anticipated to be low because:

• Discharges at any particular drilling site would

occur from only one well;

• The combination of water depth and mid-depth

and bottom currents at all sites will disperse

drilling muds over a wide area, arriving at

background levels at distances between 100 and

7,000 m (320 to 22,400 ft) from the discharge

point.

• The operator will be following the limits of the

new General NPDES permit. This includes

use of generic muds, toxicity limits, inventory

of mud ingredients used, and mercury and cadmium limits in barite.

IMPACTS UNIQUE TO EACH UNIT

There are no unit-specific impacts to water quality from the Proposed Action.

5.2.2.1.1 SUMMARY AND CONCLUSIONS

Overall, activities associated with the proposed

delineation activities are expected to cause low impacts

to water quality because the projects do not cause or

contribute to changes in standard, measurable water

quality parameters resulting in unreasonable degradation to the water quality. This is due to the following reasons:

• The new General NPDES permit will be in place

by the time these proposed wells are drilled.

The level of monitoring and more strict limitations on all the effluents, including drilling

discharges will help to ensure that water quality is protected.

• Water quality impacts will be limited to the discharge of drilling muds and cuttings.

• Only one well will be drilled at each site, thus

limiting the overall amount of drilling effluents discharged.

• While changes to standard, measurable water

quality parameters will occur during the discharge of muds and cuttings, they will be transient and temporary, and limited to between

100 and 7,000 m, (320 to 22,400 ft) at most,

from the discharge point.

• While resuspension of discharged drilling mud

will occur for the small amount (less than 2

percent of the total volume of the muds and 20

percent of the total solids) that will contact

the sea floor, since the overall amount of muds

subjected to this process is small and the process does not impinge upward into the water

column more than 10 to 20 m (32 to 64 ft),

only negligible impact to water quality is anticipated.

• Other discharges will not cause any impacts

to water quality due to the small volume of the

discharge, the treatment systems required, and

the short-term nature of the drilling activities

at each unit. Each of the discharges will dilute quickly to background levels within 100

m (320 ft).

5.2.2.1.2 MITIGATION MEASURES FOR

IMPACTS FROM THE PROPOSED

ACTION

Mitigation measures are actions taken on the

part of the operator, either as part of the Proposed

Action or as conditions of approval, that serve to reduce the severity of impacts on the environment due

to the Proposed Action. One mitigation measure will

help to reduce the already low impacts to the water

quality, as follows:

• EPA/MMS NPDES monitoring and enforcement . EPA Region 9 and MMS’s Pacific Region conduct inspections and collect samples

for analysis. These are compared to the standards in the inspected facility’s NPDES permit. If EPA identifies exceedences, they can

take appropriate steps, which may range from

corrective (for example, working with the operator to apply mechanical fixes and personnel training) to both civil and criminal actions.

Over the past 10 years, only two exceedences

have been detected during nearly 130 individual

inspections.
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Delineation Drilling Activities Offshore Santa Barbara County

5.2.2.2 CUMULATIVE IMPACT ANALYSIS

FOR WATER QUALITY

5.2.2.2.1 CUMULATIVE IMPACTS (2002-2006)

CUMULATIVE IMPACTS WITHOUT THE

PROPOSED ACTION (2002-2006)

The following discussion on cumulative impacts

to water quality considers these reasonably foreseeable projects with the potential to impact water quality and are likely to occur between 2002 and 2006:

• Offshore oil and gas development and production projects (including the possibility of oil

spills):

• The existing 22 offshore oil and gas platforms;

• Cavern Point Unit exploration and subsequent

development;

• Rocky Point Unit development;

• Sword Unit development;

• Tranquillon Ridge Unit development;

• Pacific Offshore Operators, Inc. (POOI) Federal/State development.

NON-OCS ACTIVITIES INCLUDING:

• Municipal and industrial wastewater discharges;

• River runoff and other nonpoint sources;

• Oil spills from nonOCS-associated tankering.

Water quality impacts from these items are assessed below. These impacts are then compared with

the timeframe and impacts associated with the proposed exploratory projects and an assessment made to

determine if these is any overlap in time and space

between the two. If there was an overlap, a determination of level of impact according to the significance

criteria in section 5.2.2 was made. More specifically,

only those aspects of the proposal that affected water

quality will be addressed in this section. A discussion

of all possible sources of cumulative impacts to water

quality by development of the 36 undeveloped leases is

below in section 6.2.2.

Offshore oil and gas exploration, development,

and production. The variety of potential effluents that

could be discharged from any existing or future OCS

exploratory or development and production facilities

are given below (table 5.2.2.2-1). Not all effluents

would be discharged from any particular facility; however, this table shows all potential effluents for completeness. Likewise, not all effluents will be analyzed

in this section since, for example, no produced water

will be discharged from the delineation drilling activities. As noted above, a more comprehensive cumulative impact discussion that addresses all potential impacts to water quality due to the potential development of the 36 undeveloped leases is given in section

6.2.2.

Drilling muds and cuttings. Impacts to water

quality from these effluents was described in section

5.2.2.1. To summarize, some drilling muds flocculate

and fall from the water column to the sea floor. Those

that do no flocculate, may drift some distance (perhaps, greater than 16 km) from the point of discharge.

This dispersion process may dilute to 1500 to 1 within

32 to 96 m (100-300 ft) from the point of discharge

(ADL, 1984a). The fine particulate material may average around 12 percent of the total volume of the

drilling mud discharged. While the concentration of

mud particulates, during a mud dump, could exceed

the ambient concentration by about 500 times at 100

m (320 ft) from the discharge point (according to a

generalized model), this condition is temporary due to

dispersion of the particulate material over a wide area

and throughout the water column. Average bottom

accumulation of drilling particulate material of 1.5 to

7.5 microns (1 micron equal 1 millionth of a meter)

was measured by SAIC, and MEC (1995), corresponding to a depositional area of 100 to 550 km2

 (24,710 to

123,500 acres) depending on particle size, as well as

the dispersion of 40 to 80 percent of the finest-grained

material beyond the CaMP study region.

Drilled cuttings fall more quickly to the sea floor

than do drill muds and are not expected to remain in

the water column more than an hour after they leave

the end of the disposal caisson (de Margerie, 1989). A

continuous plume of drilling mud drifts from the cuttings discharge due to muds adhering to the cuttings

will drift down-current. Also, there will be some

amount of mud in the cuttings pile near the base of

any facility that had discharged cuttings. Since the

cuttings will not remain in the water column for very

long and fall relatively close to the discharge point,

there will be only negligible impacts to the water quality. Section 5.2.2.1 also discussed the resuspension of

drilling muds, turbidity, and effects of metals and additives, all of which resulted in a finding of low impact

to the water quality.

Section 5.2.2.1 also discusses all the other types

of discharges listed in table 5.2.2.1-1. It was concluded

there that none of those discharges would cause any

water quality impacts due to the small volume of the

discharge and the treatment systems required. Similarly, since there is no overlap in space between existing or future exploration or development and production offshore oil and gas activities, as listed above (al-
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

Effluent* Estimated Distance of 

Effect (meters)** General Permit Limits 

Anchoring activities 100 to 500 Turbidity 

001 Drilling Discharges 

(muds and cuttings) 

(MODU & Platform) 

1,000 Total volume limits applied to each platform 

End-of well toxicity 

No discharge of oil-based drilling mud or mud 

 contaminated with diesel 

Limits on cadmium and mercury in barite 

Continuous constituent and additive inventory 

Static sheen test 

Use of generic mud 

002 Produced Water 

(Platform) 

100 Weekly oil and grease samples (29 mg/l monthly 

 average; 42 mg/l daily max.) 

Flow limits applied for each platform 

Quarterly monitoring of metals and other parameters 

Whole effluent toxicity (chronic) 

003 Well Treatment, 

Completion and Workover 

Fluids (Platform) 

100 Volume monitoring 

No discharge of free oil monitored by static sheen test 

Once per job oil and grease samples (29 mg/l monthly 

 average; 42 mg/l daily max.) 

004 Deck Drainage 

(MODU & Platform) 

100 Volume monitoring 

No discharge of free oil monitored by visual observations 

005 Sanitary / Domestic 

Wastes 

(MODU & Platform) 

100 / At the point of 

discharge 

Flow rate 

Observation of floating solids (for facilities manned by 9 

 or fewer persons) 

Residual chlorine and foam for domestic wastes (for 

 facilities manned by 9 or more persons) 

006 Blow-out Preventer 

Fluid (MODU) 

100 / At the point of 

discharge 

No free oil in the receiving water 

Floating solids and foam 

007 Desalination Unit 

Discharge 

(MODU & Platform) 

At the point of discharge Floating solids and foam 

008 Fire Control System 

Test Water 

(MODU & Platform) 

At the point of discharge Chemical inventory 

Chlorine (for antifouling) 

Floating solids and foam 

009 Noncontact Cooling 

Water 

(MODU & Platform) 

100 / At the point of 

discharge 

Flow rate 

Chemical inventory (if chemicals are used in the effluent) 

Chlorine (for antifouling) 

Floating solids and foam 

010 Ballast and Storage 

Displacement Water 

(MODU) 

100 / At the point of 

discharge 

Flow rate 

No free oil in the receiving water 

Floating solids and foam 

011 Bilge Water 

(MODU) 

100 / At the point of 

discharge 

Flow rate 

No free oil in the receiving water 

Floating solids and foam 

012 Boiler Blowdown 

(MODU) 

At the point of discharge Floating solids and foam 

013 Test Fluids 

(MODU & Platform) 

100 / At the point of 

discharge 

Flow rate 

No free oil in the receiving water 

Chemical inventory 

Floating solids and foam 

014 Diatomaceous Earth 

Filter Media (Platform) 

At the point of discharge No free oil in the receiving water 

Floating solids and foam 

Table 5.2.2.2-1. Possible effluents, the type of facility (Platform/MODU), distance of influence on

water quality, and limitations from the new General NPDES Permit.
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Delineation Drilling Activities Offshore Santa Barbara County

Effluent* Estimated Distance of 

Effect (meters)** General Permit Limits 

015 Bulk Transfer Material 

Overflow 

(MODU & Platform) 

At the point of discharge Floating solids and foam 

016 Uncontaminated Water 

(MODU & Platform) 

At the point of discharge Floating solids and foam 

017 Water flooding 

(Platform) 

100 No free oil in the receiving water 

Chemical inventory 

Floating solids and foam 

018 Laboratory wastes 

(MODU & Platform) 

100 / At the point of 

discharge 

No free oil in the receiving water 

Floating solids and foam 

019 Excess Cement Slurry 

(MODU) 

100 / At the point of 

discharge 

Flow rate 

No free oil in the receiving water 

Floating solids and foam 

020 Muds, Cuttings and 

Cement at Seafloor 

(MODU) 

100 / At the point of 

discharge 

No free oil in the receiving water 

Floating solids and foam 

021 Hydrotest water 

(Platform) 

100 / At the point of 

discharge 

Flow rate 

No free oil in the receiving water 

Chemical inventory 

Chlorine 

Floating solids and foam 

022 H2S Gas Processing 

Waste Water (Platform) 

100 / At the point of 

discharge 

Flow rate 

No free oil in the receiving water 

Floating solids and foam 

*For clarity, the words, “Platform” and “MODU,” are inserted in the “Effluent” column; this indicates when some effluents will 

only occur from one source or the other or both. 

**As seen in the General Permit Limits column, some limits consist of water quality-related limitations (e.g., chlorine) and others 

consist of nonwater quality-related limits (e.g., floating foam and solids). Water quality limits must be met within 100 m of the 

discharge (according to the General NPDES permit) while nonwater quality-related limits must be met at the point of discharge.

though all of the existing facilities will be discharging

during the time the proposed projects are ongoing).

Thus, there is no cumulative impact to water quality

parameters due to the proposed projects.

OIL SPILLS

No oil spills are expected to result from the proposed activities. As discussed in Section 5.1.3, the

cumulative oil spill risk for the project area results

from several sources: ongoing and projected oil and

gas production from existing OCS facilities in the Santa

Barbara Channel and Santa Maria Basin, several proposed development projects on the Federal OCS, ongoing production from one facility in State waters in the

Santa Barbara Channel, two reasonably foreseeable

oil and gas projects in State waters, and the tankering

of Alaskan and foreign-import oil through area waters (table 4.0.1-9). Tables 5.1.3.1-2, and 5.1.3.1-3

present the estimated mean number of spills of various sizes and the probability of their occurrence as a

result of the described activities.

Three different oil spill scenarios are discussed

in this analysis. They are:

• The most likely oil spill scenario for existing

and proposed offshore oil and gas activities is

that one or more oil spills in the 50 to 1,000-

bbl range would occur over the period 2002-

2006, and that such a spill would most likely

be 200 bbl or less in volume. The probability

that one or more spills of this size will occur

during this period is 73.9 percent.

• The maximum reasonably foreseeable oil spill

volume from future offshore oil and gas activities is 2,000 bbl, assumed for purposes of analysis to be a pipeline spill. The probability of a

spill of this size occurring during the period

2002-2006 is 22.3 percent.

• Based on data from tanker spills in U. S. waters, the mean size for a tanker spill is assumed

Table 5.2.2.2-1. Possible effluents, the type of facility (Platform/MODU), distance of influence on

water quality, and limitations from the new General NPDES Permit (continued).
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

to be 22,800 bbl (with a probability of occurrence of 38.8 percent for this period). The rationale for these estimated spill sizes is presented in section 5.1.3. This oil spill scenario

is discussed below with other non-OCS potential impacting agents, such as river plumes and

sewage outfalls.

The following analysis does not consider oil spills

(bunker or diesel) from non-tankship spills, such as

container or bulk carrier vessels, although spills have

and could occur from these sources. A general, qualitative, description of the effects of oil on water quality

is below, followed by size-specific descriptions of effects. Additional, general information regarding

sources of oil, and responses to spills can be found in

section 5.1.3 and appendix 5.3.

As described in section 5.2.2, effects on water

quality from oil spills, can range from a few days, to

several weeks or months, depending on the size of the

spill, the type of oil spilled, and the response dedicated

to the spill. Expected water quality effects due to spills

could occur in the top 10 to 20 m (32 to 64 ft) of the

water column, depending on sea state and the type of

oil. These effects include turbidity, biological and

chemical oxygen demand and release of hydrocarbons,

such as BETX (benzene, ethylbenzene, toluene and xylene), into the water column. The surface slick would

be affected by several factors including wind and wave

action, dissolution, and volitilization losses. The majority of the dissolved components (BETX and others,

which make up about 20 to 50 percent of crude oils)

would be lost to volitilization and other processes with

24 to 48 hours (Jordan and Payne, 1980). They would

also be subject to dispersion and dilution, as well as

to degradation via photolysis and microbial processes.

Clean-up actions would also contribute to the minimization of impacts to water quality.

In addition to the spills discussed below, small

spills, in the range of less than 1 bbl to 5 to 10 bbl,

may occur from any of several sources (for example,

minor platform operational mishaps or diesel transfers). For these sized spills, no impacts to water quality are expected.

A 200-bbl spill. Historically, responses to spills

of this size have lasted from a few days to a couple of

weeks before mechanical recovery and natural processes removed the oil from the sea surface (for example, Platform Irene pipeline, 1997; Platform Heritage, 1996). Meanwhile, processes within the water

column, such as dispersion and dissolution, would have

served to spread various light-end hydrocarbons (benzene, ethylbenzene, toluene and xylene) to background

levels. Depending on the oil, these light-end hydrocarbons would vary in concentration in the water column. Also, depending on the sea state, mixing of oil

and its components into the water column would contribute to dispersion, perhaps as deep as 10 m (32 ft)

until background levels were reached.

A 2,000 bbl pipeline spill. There has never been

a pipeline spill of this magnitude in the Pacific Region. While the Platform Irene spill emanated from a

pipeline, the amount of oil spilled was estimated to be

163 bbl. Another aspect of pipeline spills that is somewhat confounding compared to spills from facilities or

tankers (see below) is that some pipelines carry wet

oil and others dry oil. Wet oil has not been dewatered

and may carry as much as 80 percent water and only

20 percent oil. This was the case for the Platform

Irene spill. The total amount of fluid escaping from

the pipeline for that spill was estimated to be 815 bbl.

It is unclear what effect the presence or absence

of water in an oil spill would have on the fate of oil

that emerges into the water column from a pipeline

laying on sea floor. It depends, in part, on the emulsion characteristics of the oil/water mixture and how

well-mixed and tightly bound that mixture is. For

example, some amount of the fluid spilled during the

Irene event was water only, separated on the bottom

of the pipeline, but not emulsified with the oil. This

water, probably had dissolved portion of oil in it and

was dispersed and diluted into the water column. If

an 2,000-bbl spill occurred under these circumstances,

water quality could be affected for several kilometers

down-current. However, this would dissipate after

several days to background.

Dry oil spills would contribute dissolved components from the bottom to the sea surface for as long

as the oil leaked from the pipeline3. However, since

most of the oil would eventually arrive at the sea surface, the depth of the water through which the oil

passed would define the amount of hydrocarbons from

the oil would remain in the water column. The resulting hydrocarbon plume would disperse more or less

rapidly depending on the type of oil, water depth, current speed, and sea state. Once this subsurface plume

dissipates, the remaining oil on the sea surface would

be subject to the same processes as described above

for the 200-bbl spill, except that much of the dissolved

components would have been removed during the passage of the oil through the water column. Under this

scenario, more water column effects would probably

occur during the initial spill than later.

NON-OCS ACTIVITIES

As was discussed in section 5.2.2.1 and summarized below, water quality in the study area may be

generally divided into two subregions. The offshore

oil and gas units proposed to be drilled are as follows:

3

 The largest spill from a pipeline ever to occur in the Pacific

Region was 900 bbl in December, 1969.
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Delineation Drilling Activities Offshore Santa Barbara County

1. Point Lobos to the western entrance of the

Santa Barbara Channel (Point Sal, Purisima,

and Bonito); and

2. The northern Southern California Bight (SCB):

Santa Barbara Channel to Point Fermin (Bonito and Gato Canyon).

Municipal and industrial wastewater discharges.

Only two Publicly-Owned Treatment Works (POTW’s

or sewage treatment plants), discharge directly into

the Pacific Ocean in San Luis Obispo County while

three others discharge into local rivers. All the dischargers are small, according to EPA criteria (less than

25 million gallons per day [mgd]). There are no other

industrial wastewater discharges north of Point Conception.

There are six POTW’s that discharge treated effluent to the Channel. They are all small dischargers

whose effluents are at a mixed primary/secondary level

of treatment (SCCWRP, 1996). The few other point

sources of pollution along the shorelines of the Channel include several power plants discharging heated

water, and including some chlorine, which is used to

prevent fouling of heat exchangers.

Overall, there are 24 discrete sources of pollution from Point Conception to Point Dume including

six sewage dischargers, two power plants, six industrial waste dischargers and 10 sources of runoff (Anderson et al., 1993). The 1975-1978 BLM-sponsored

baseline studies in the Southern California Bight (SCB)

indicated that most of the metal and hydrocarbon loads

of the four basins examined (Santa Barbara Channel,

San Pedro, Santa Monica, and San Nicolas) were derived from industrial and municipal wastes, entering

the marine environment through direct discharge, indirect run-off and atmospheric transport, all centering around the Los Angeles metropolitan area (BLM,

1979).

River plumes. Rivers are the primary non-point

source of pollution within the study area. In part,

this is because the relatively easy reductions in point

sources of pollution have been accomplished. While

non-point sources of pollution have long been recognized, improvements in this source of pollution has

been slow and difficult. This is due to the diversity of

these sources, resistance to regulatory solutions and

the multiple pathways through which the pollution

may reach the coastal and ocean environments (NRC,

2001).

The Santa Maria River, on the border of Santa

Barbara and San Luis Obispo Counties, and the Santa

Ynez River, which flows into the ocean between Points

Purisima and Arguello, are the primary sources of

pollution to the ocean that exist in the northern-most

subregion. Pollutants that could be associated with

these rivers are predominantly agricultural.

The two major rivers in the Santa Barbara Channel, the Santa Clara and Ventura, are both in Ventura

County and drain largely agricultural lands, although

the urban areas of Ojai, Ventura, Oxnard/Port Hueneme

and Camarillo contribute pollutants via storm drains

and other nonpoint source runoff.

Figure 5.2.2.2-1 shows a typical river plume situation for flows during winter rains for the rivers from

the northern Santa Maria Basin to Point Mugu. The

river system with the most particulate discharge is

the Ventura/Santa Clara river combination while the

Santa Ynez and Santa Maria Rivers do not appear to

contribute much sedimentation (Mertes et al., 1998).

Realizing that this is a “typical” snapshot, Hickey and

Kaschel (unpublished) show figures during extreme

El Niño-like events. During winter, high runoff periods associated with storm and rain conditions followed

by upwelling-favorable winds have driven these river

plumes south past Point Conception and to the vicinity of San Miguel Island (Hickey and Kaschel,

unpubl.). These river plumes occur only during periods of very high flow and may cross the Santa Barbara Channel to the waters of the Channel Islands

National Marine Sanctuary (for the Ventura/Santa

Clara Rivers) and, for the Santa Ynez/Santa Maria

River plumes, reach south past Point Conception.

Sediments that erode from the land and reach the coast

in runoff carry various contaminants bound to sediment particles, including trace metals, organic compounds and phosphorus (NRC, 2001). The sediments

themselves can constitute a potentially serious form

of pollution, including by decreasing water clarity.

While these events are episodic (seasonal for the

Mertes et al. (1998) and every 5-7 years for the Hickey

and Kaschel data), they would nonetheless overwhelm

Figure 5.2.2.2-1. View of a “typical” winter runoff

situation showing levels of sedimentation

emanating from the Ventura/Santa Clara River

system as well as from other small creeks and

rivers in the Santa Barbara Channel and northern

Santa Maria Basin. Source: Mertes (1998).
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Environmental Consequences, Cumulative Impacts (2002 - 2006), and Mitigation Measures

the effects of any particulate material discharged by

drilling operations, wherever the two plumes might

meet. Note that the higher the flow, the greater the

dilution and the only time the plumes impinge much

into the offshore area would be during times of high

flow. Thus, pollutants carried by plumes would become well-diluted as they disperse and mix into the

sea.

Storm drains. Storm drain-associated runoff is

the largest source of unregulated pollution to the waterways and coastal areas of the United States (CCC,

2000). However, storm drain-associated pollution

would be confined to the near-coastal vicinity since,

even during high runoff periods, the volume would

not be enough to carry pollutants very far offshore.

Also, many storm drains empty into local rivers and

streams, mixing with those high-flow effluents.

A 22,800-bbl marine tanker spill. Historically,

responses to spills of this size have lasted from a few

weeks to several months before mechanical recovery

and dispersants and in-situ burning (if allowed), and

natural processes removed the oil from the sea surface. The largest vessel-based spill to occur in the

Pacific Region was the 7,000 bbl American Trader spill

of Alaskan crude oil in February, 1990. The processes

described for the less-than 200-bbl spill, would essentially be the same, being different only in the matter

of scale. The major difference would be that the top

10 m (32 ft) or so of the water column would be affected for a longer period of time. There would not be

a subsurface plume as there would be for a pipeline

spill. However, the strength of the “pulse” of oil into

the environment would allow greater concentrations

of oil and the light-end components to exist for longer

in the water column than was described for the <200-

bbl spill size.

INCREMENTAL IMPACTS OF THE

PROPOSED ACTION (2002-2006)

The following discussion considers the impacts

of the proposal when added to the existing and reasonably foreseeable projects, discussed above. The

only aspect of the proposal that could affect water

quality when combined with the existing and reasonably foreseeable projects is drilling discharges. These

are discussed below.

Impacts Common to All Units. There are no

sources of pollution that combine in space and time

with other sources of pollution that are common to all

units. Drilling discharges are analyzed for each unit

because of specific oceanographic and water depth differences.

Impacts Unique to Each Unit. Drilling discharges are the only aspect of the proposal that could

affect water quality, and thus combine with other pollution sources. This is due to differences in currents

and water depths, and thus the fate of the drilling discharges. See below for more detailed information.

Drilling Discharges. It has been determined that

drilling muds may have impacts on benthic communities up to 1,000 m from the discharge point (Hard

Bottom Committee Report, 1989). Water quality parameters, however, may be affected beyond 1,000 m.

For example, Coats (1994) demonstrated that traces

of barium on the sea floor from drilling activities near

Point Conception could be detected as far as 6.8 km

from the point of discharge. This is an indication of

the distance drilling mud particulate material traveled for the CaMP studies. Thus, the ellipses shown

on figures 5.2.2.2-2 through 5.2.2.2-4 are 7 km (4.3

miles), in the longest direction, from the proposed drilling sites. The ellipsoid shape is due to the estimated

net direction of the currents near each proposed drilling site; that is, according to the direction and strength

of the net current flow, which results from a combination of all the currents that occur in the area. These

currents give a generalized picture of where drilling

muds that remain in the water column might be carried. A similar ellipsoid nature was found during the

CaMP studies and is illustrated in figure 5.2.2.2-3.

The ellipses are 7 km (4.3 mi) in the longest direction because that is as far as barium was detected

by Coats. However, as discussed in section 5.2.2.1,

about 7 to 18 percent of the total drilling mud discharge was silt/clay-sized particulate matter and about

80 percent of that material, was advected out of the

study area. To better assess unit-specific differences,

each proposed drilling site is discussed below by assessing the local oceanography, including an estimate

of current direction, for the mid- and near-bottom portion of the water column.

Gato Canyon Unit. The proposed Gato Canyon

well site is located approximately 8 km (5 miles) south

of Capitan and 13 km (8 miles) east of Platform Hondo

in the Santa Barbara Channel (figure 5.2.2.2-2). The

well site is in 230 m (755 ft) water depth. Annual net

current flow at all depths is westward. This was confirmed by mid-depth and bottom current measurements

taken in the Santa Ynez Unit, just east of the proposed Gato Canyon Unit drilling site, which indicated

that currents tended westward to the shelf-break,

about 200 m (640 ft) (ADL, 1984). Since the well site

is in reasonably deep water, the ellipse formed by the

drilling mud plume would tend to stretch westward to

at least 7 km (4.3 miles), with some cross-shelf spreading to a distance of about 3 km (1.9 miles) due to tides,

waves and other physical processes. Averaged middepth and bottom current speeds were on the order of

10 to 12 cm/s somewhat comparable to the 7 cm/s current speeds described for the CaMP study area (SAIC,

1986). Therefore, much of the drilling muds would be

carried along the west to southwest direction, spreading throughout the water column and dispersing to
5-82

Delineation Drilling Activities Offshore Santa Barbara County

background particulate levels. This plume does not

intersect with any of the plumes that could be emanating from the Santa Ynez Unit platforms (Hondo,

Harmony, and Heritage), if those platforms were discharging drilling muds at the time. Of the three, only

Platform Harmony would be discharging produced

water and the drilling discharges from the Gato Canyon Unit well site would not overlap in space with

that effluent. No other major anthropogenic effluents

or other sources of pollution exist near the Gato Canyon Unit well site. Therefore, cumulative impacts to

water quality due to drilling at this well site are negligible.

Bonito Unit. One or two wells are proposed to

be drilled at any of the four sites indicated on figure

5.2.2.2-3. Nuevo is currently considering which well

sites to drill although the current drill site priority, as

given by Nuevo in their latest Project Description

(Nuevo, 2000), in descending order, are as follows: 1.

OCS-P 0446 #5; 2. OCS-P 0443 #4; 4. OCS-P 0446

#3; 7. OCS-P 0500 #2. The oceanography is estimated

to be similar amongst all the potential well sites. The

Bonito Unit is northwest of the Point Arguello Unit,

the site of the CaMP drilling discharges monitoring

studies. During CaMP, net flow was to the northwest

(poleward). Data collected by the Scripps Institution

of Oceanography (SIO) under contract to Minerals

Management Service, indicates that net current flow

at mid- and near-bottom water depths are poleward

(pers. comm. David Browne, Oceanographer, MMS).

As can be seen on figure 5.2.2.2-3, the ellipses do overlap each other, but not any other source of anthropogenic pollution. Since any drilling will occur in sequence, no overlap of drilling discharges is expected.

The plumes also do not overlap in space with any of

the nearest existing platforms. Thus, cumulative impacts to water quality due to any proposed drilling at

these well sites would be negligible.

Purisima Point and Point Sal Units. One delineation well is being proposed on the Purisima Point

Unit at one of four possible sites and one delineation

well is being proposed on the Point Sal Unit at one of

three possible sites. Water depths at all seven sites

are fairly shallow, ranging from 74 to 112 m (238 to

358 ft). Data from the SIO studies again indicate that

the net current flow is estimated to be poleward (northerly). Since the water depths are so shallow, surfacebased physical processes (for example, waves and tides)

would help to laterally disperse drilling mud plumes.

Thus, these plumes would end up being slightly wider

than those in deeper water at the other units (figure

5.2.2.2-4). The plumes also do not overlap in space

with any of the nearest existing platforms. Due to the

lack of any other anthropogenic sources of pollution,

as described in section 5.2.2.1, cumulative impacts to

water quality due to any proposed drilling at these

well sites would be negligible.

SUMMARY AND CONCLUSION (2002-2006)

For the five-year period from 2002 through 2006,

only drilling muds and cuttings could overlap in time

and space with other existing and reasonably foreseeable projects and activities. Existing OCS oil and gas

operations may discharge drilling muds and cuttings

on an irregular basis (discussed in the unit-by-unit

summary, above). The authors of BLM (1979) suggested that oil and gas development activities would

provide only limited input of metals to the Southern

California Basins, except, possibly for barium and

maybe lead, which could be observably altered in surface sediments. They also noted that hydrocarbon levels increased in all the basins examined (Santa Barbara Channel, San Nicolas, San Pedro, and Santa

Monica). Both metals and hydrocarbon loads of the

four basins were derived from industrial and municipal wastes, entering the marine environment through

direct discharge, indirect run-off and atmospheric

transport, all centering around the Los Angeles metropolitan area.

Oil spills might affect water quality depending

on the amount and type of oil spilled and the source.

Nevertheless, oil spills by themselves could only constitute, at most, a moderate impact to water quality

for the short-term the first week or two) and low for

the long-term (beyond the first week to two).

Non-oil and gas projects and activities are dominated by onshore sewage discharges and by episodic

river runoff. These two items might overlap in time

and space with the drilling activities at the four units.

However, their contribution to the pollutant loading

of the study area greatly exceeds any discharges from

the proposed individual or combined wells. Thus, incremental impacts from the Proposed Action are low.

POTENTIAL MITIGATION MEASURES FOR

CUMULATIVE IMPACTS

The same mitigation measures described in sections 5.2.2.1 and 5.2.2.1.2 (NPDES permits and EPA/

MMS NPDES monitoring), will likely be in-place for

oil and gas operations for this time period, as well.