Impacts of coastal energy development on New Jersey's shorefront recreational resources and economy Study report / Appendix

[From the U.S. Government Printing Office, www.gpo.gov]

Impacts of Coastal Energy Development
on New Jersey-fs Shorefront
Recreational Resources and Economy

The New Jersey Department of Environmental Protection

Study Report
Appendix Volume 2

Appendix B: Facility Descriptions

Rogers, Golden & Halpern
Philadelphia, Pennsylvania
04

APPENDICES VOLUMES

Volume 1. Appendix A. User's Guide

Volume 2. Appendix B. Facility Descriptions

Volume 3. Appendix C. Facility Impact Assessment Matrices

Appendix D. Environmental Change Schedules for Coastal
Energy Facilities

Appendix E. New Jersey Shoref ront Tourism Regions

Appendix F. Questionnaiee Used for Group Estimation

Appendix G. Tourism Response Coefficients

Appendix H. New Jersey Shore Municipalities' Attitudes
Towards Development and Preservation

Appendix 1. Municipal Data File

Volume 4. Appendix J. Case Studies

Zr- Z-

Note to Readers

Changes in the descriptors of five of the six tourism regions used in the stu dy
Impacts of Coastal Energy Development on New Jersey's Shorefront Recreational
Resources occurred after final editing of this appendix volume and are not included in it.

Consequently, the reader is asked to substitute the descriptors found in this volume
(listed below, left) for those found in the summary report (listed below, right).

Former Version Final Version

Densely Settled Commuter Suburb Non-Seasonal Suburban

Northern Shorefront Year-Round and North Shore Non-Seasonal/Rural
Rural Community

Northern Shoref ront Seasonal North Shore Seasonal
Communities

Southern Shore Year-Round and Rural South Shore Non-Seasonal/Rural
Community

Southern Shoref ront Seasonal South Shore Seasonal
Communities

The tourism region Resort Gambling remains unchanged.

APPENDIX B. ENERGY FACILITY DESCRIPTIONS

The magnitude, composition, and timing of the environmental., social, and economic
impacts of developing energy facilities in coastal areas are dependent upon the
characteristics of the energy facility under consideration. A comprehensive policy
planning tool such as the Coastal Tourism Model depends on an understanding and a
specification of the functions, purposes, inputs, and impacts of each of the 15 energy
facilities being considered within the model. A primary component of the model is
therefore the set of 15 energy facility descriptions which contain information that
permit model users to begin to proceed along each of the three impact paths. In
addition, the descriptions contain information which provide model users with a base of
knowledge about the various facilities.

The 15 energy facilities are presented as follows:

0 Support Base
0 Oil and Natural Gas Pipelines
0 Oil Pumping and Gas Compressor Station
0 Gas Separation and Dehydration Plant
0 Gas Treatment Plant
0 Natural Gas Liquids (NGL) Fractionation Plant
0 Peak Shaving Facility
0 Tank Farm

0 Nuclear Power Plant

0 Coal-Fired Power Plant
0 Cogeneration Facility
0 Resource and Energy Recovery Facility
0 Electric Transmission Line
0 Coal-Handling Terminal
0 Offshore Oil Port

The accompanying energy facility descriptions contain the following components:

0 Facility Descri ption: Presents the purpose and functions of each facility, along-
with identification of its major components and design configurations.

B-1

0 Facility Size/Land Requirements: Notes the range in design capacities or
throughputs based on existing technology. Land requirements as a function of
size are also given.

0 Site Parameters: Lists the features of the physical and man-made environ-
ments which each facility requires for cost-effective development at a given

site.

0 Capital Costs: Capital costs as a function of size are presented in fourth
quarter, 1982 dollars.

0 Employment Profile: Describes on an annual basis the manual and non-manual
components of both the construction and operating labor forces over an
eleven-year period for the size of the facility most likely to be developed
within the study area.

0 Environmental Impacts: Describes the significant environmental impacts by
category that would accompany facility construction andoperation.

The descriptions utilize some of the information contained within the Coastal
Energy Facility Development Potential Study. The descriptions of facility processes and
design alternatives are more detailed in the Development Potential Study and interested
readers are referred to that document. In addition, the Development Potential Study
also contains much more useful data on how the site parameters influence the economics
of facility development at a particular site.

Each facility description is accompanied by a Facility Impact Assessment Matrix
and an Environmental Change Schedule. Each facility's matrix presents the type and
time of occurrence of the on-site activities during the construction and operation phases.
Listed for each activity are the direct impacts associated with these activities. The
Environmental Change Schedule lists the probability of occurrences of environmental
changes that will produce corresponding changes in the tourist visitation patterns. These
two components of the model are the primary mechanism for translating facility-related
environmental impacts into losses of tourism. The Environmental Change Schedules for

B-2

each facility are contained in Appendix D. The assumptions and information
incorporated into producing both of these items, along with an explanation of the how to
interpret the data presented on them, is contained in Impact Path 3, Tourist Response to
Environmental Impacts.

Each of the 15 energy facility types noted previousl y differs in terms of it's
probability of ever being located within the study area. This probability for each facility
is based on a number of factors, including:

0 the need for the facility as a function of changes in the market conditions for
the type of energy produced, processed, or handled by it;

0 the environmental impacts and associated costs of obtaining the required
permits associated with the facility's construction and operation;

0 uncertainty o the future regulatory and rate-making climates which affect the
probable capital cost and accompanyin g profitability of a facility;

0 the availability of suitable sites within the study area;

0 diminishing probability that the Baltimore and Hudson Canyons will prove to
have sufficient reserves of oil and natural gas to warrant commercial
development; and

0 the public's perception of the environmental and public health risks associated
with a facility's construction and operation.

Changing market conditions can be the primary determinant in the probability of
developing a particular energy facility. Changes in market condition can include the
development of competing facilities in other locations so that likelihood for developing
such facilities in New Jersey declines. Coal-handling terminals are a prime example, as
the large number of projects proposed in other states has diminished the probability of
developing a' facility in New Jersey. Other changes in market conditions can include
changes in the relative price of an energy product, such as oil, with the result that the
demand for that product declines.

B-3

The difficulty in obtaining the necessary environmental permits can also affect the
probability of developing a particular facility. Owners of the Louisiana Offshore Oil
Port have noted that the difficulty faced in obtaining the necessary environmental
licenses and approvals for their facility make it highly unlikely that a similar facility can
be profitably developed elsewhere in the country. In addition, this facility's long-term
profitability has declined due to increases in the price of oil, which have resulted in a
decrease in demand in the amount of oil imported into this country.

The regulatory uncertainty surrounding the construction of nuclear power plants,
along with the long lead times required to construct such capital-intensive facilities, has
diminished the probability of constructing these facilities in the near future.

There is a definite lack of suitable sites for some of the energy facilities within the
study area. Thus, the likelihood of their development within the study area is quite low.
Facilities include tank farms, an offshore oil port (assuming one could be profitably
developed) and a coal-handling terminal. The northern section of the study area in
Monmouth County is the only part which would have sufficient proximity to navigation
channels of proper depth. to warrant the expenditure of funds for'dredging of sufficient
depth to allow coal colliers or tankers access to a coal-handling terminal or a tank farm.
From Point Pleasant south, the presence of the heavily developed barrier islands makes
the siting of a tank farm or a coal-handling terminal highly unlikely.

Recent cessation of offshore exploration and drilling activity by major oil
companies in the Baltimore and Hudson Canyons diminished the probability that
commercial development of these areas will ever take place. As a result, the likelihood
of developing accompanying ancillary facilities such as support bases, oil or natural gas
pipelines, or the three natural gas processing facilities has likewise declined.

As a result of the consideration of these factors, this study estimates the
probability of developing each of the 15 energy facility types within the study area over
the next 10 to 20 years. Model users should be aware that these probabilities are
speculative and aer based on the conditions prevailing in early 1983. Future changes,
such as regulatory reform or. continuing declines in the price of oil, could significantly

B-4

affect these probabilities The probabilities within each group are presented in
descending order.

0 HIGH PROBABILITY (50% or better chance of occurrence)
Resource and Energy Recovery Facility
Coal-Fired Power Plant
Electric. Transmission Lines
Cogeneration

0 MODERATE PROBABILITY (less than 50%, but more than 20%)
Support Base
Oil and Natural Gas Pipelines
Oil Pumping and Gas Compressor Stations
Gas Separation and Dehydration Plant
Coal-Handling Terminal
Peak Shaving Facility

0 LOW PROBABILITY (20% or less)

Nuclear Power Plant

Gas Treatment Plant

NGL Fractionation Plant

Tank Farm

Offshore Oil Port

Each of the fifteen energy facilities also differs in terms of its dependency on
proximity to water. Water dependency is defined as the necessity of utilizing water as a
process input (i.e., cooling water for power plants), or the requirement to locate in, or
immediately adjacent to, a shorefront site. This dependency translates to the probability
of a specific facility type being sited in a shorefront location should it ever be developed
within the study area. The need to utilize water as a process input implies that
proximity to water is partially a cost-optimization factor. Generally, the closer an
energy facility location is to the water supply source, the lower the cost is of obtaining
the water. However, the need for water as a process input does not automatically imply
a coastal location. Coal-fired and nuclear power plants can be sited at inland locations
within the study area if sufficient cooling water supplies are present.

B-5

Some energy facilities require a coastal location as a precondition for feasible
operation. Such facilities are usually involved in the transfer of a bulk energy
commodity from one transportation mode to another. The obvious examples include
support bases, tank farms, and coal-handling terminals. If any of these facilities are
ever developed within the study area, they will certainly be sited in coastal locations.

Presented below are estimates of each facility type's probability of being located
in a shorefront location within the study area. These assessments are specific to the
study area being considered in this report. For obvious reasons, an offshore oil port's
probability is not considered.

Probability of One: Requires an oceanfront, riverfront or bayfront location
adjacent to navigable waters as a precondition for feasible
operation:
o Support Base

o Tank Farm
o Coal-Handling Terminal

High Probability: Location in, or as close as possible to, an oceanfront site
maximizes the economic efficiency and technical feasibility of
an energy facility:
� Gas Separation and Dehydration Plant

o Gas Treatment Plant
� Natural Gas Liquids Fractionation Plant
� Oil and Natural Gas Pipelines

The above four facilities' probabilities assume the presence of OCS oil and gas
development.

Moderate Probability: Proximity to an adequate supply is required; however, the need
for waterfront location does not translate into a need for an

oceanfront location:

o Nuclear Power Plant

o Coal-Fired Power Plant

B-6

Low or Zero
Probability: Proximity to a shorefront location or to a water supply source
has minor or no influcence on a facility's location:
o Oil Pumping and Gas Compressor Station
o Peak Shaving Facility
o Cogeneration Facility
o Resource and Energy Recovery Facility
o Electric Transmission Line

B-7

SUPPORT BASES

Facility Description

Support bases link onshore and offshore activities during all phases of Outer
Continental Shelf (OCS) oil and gas exploration, development, and production. Materials
are assembled and stored at these bases for delivery to offshore drilling rigs and
production platforms. There are three types of support bases:

� bases supporting exploration,
0 bases supporting development and production, and
� bases supporting platform and pipeline installation.

Bases Supporting Exploration. Temporary support bases are set up during explora-
tory drilling operations to transfer materials and workers between shore and the offshore
drilling rigs. Supply and crew boats and helicopters operate from these bases usually on
a 24-hour, 7-day-week basis, shuttling food, water, fuel, drilling mud, cement, drill pipe,
casing, and equipment to t -he rigs and bringing back refuse that cannot be disposed of at
.sea. Weather conditions and the distance from the offshore drilling locations determine
whether helicopters or crew boats are used as the predominant mode of crew transfers.

Bases Supporting Development and Production. Support bases set up during the
development or production phases of OCS activities serve basically the sa me function as
temporary support bases--i.e., transferring materials and workers between shore and the
offshore facilities on a 24-hour, 7-day-week basis--but on a larger scale. Permanent
support bases may be set up by the oil companies involved or by service companies. The
land is either purchased or leased on a long-term basis. In some cases a decision is made
to simply expand the existing temporary support base. The company operating the base
may opt to either bring in other companies such as cement companies, caterers, and
other specialist suppliers as tenants, or act as an agent for ordering and distributing
supplies.

Bases Supporting Platform and Pipeline Installation. Very similar to the support
bases set up during the exploratory phase are the bases set up to support installation of
platforms and pipelines for OCS development. Unless a large volume of work over an

B-8

extended period of time is anticipated, these bases are set up on a short-term basis.
Their main requirements are waterfront warehouse space, and service and maintenance
facilities for vessels and barges. Road and/or rail access is essential for transporting

material into the base.

Facility Size/Land Requirements

Bases supporting exploration have up to 20 berths for supply ships, and they require
f ive acres (ac) per drilling rig being serviced. Pages 3-33 of the Energy Facility
Development Potential Study give the vessel requirements during the various offshore
phases. Approximately five acres per platform being serviced is the required land area
for a supply base supporting development and production or platform and pipe instal-
lation. A site with an area of five acres is generally adequate for the installation of a
pipeline or up to four platforms. For both platform and pipeline operations a minimum
of 200 feet of wharf is required. An additional 200 feet is preferable for each "spread"
(about three ships) supporting the platform or pipeline installation operation.

Site Parameters

Siting of support bases involves consideration of several key factors. Properly
sited facilities should be areas with the following characteristics:

0 adequate flood protection
0 fresh water delivery capabilities
� high load bearing capacity soils
� relatively flat topography
0 access to railroads and highways
� access to an all-weather harbor with an adequate wharf or pier
� reasonable proximity to offshore activity
� access to and availability of ancillary services

B-9

Capital Costs

The total capital cost for a supply base can be estimated using the following
equation. Remember that the number of berths required varies with the phase (i.e.,
exploration, development and production, etc.).
Capital Cost $1,500,000 (NB)

Where:

NB number of berths at the support base.

Sources:
John F. McMullen, 1981; Rogers, Golden & Halpern, 1979.

Employment Profiles

The level of construction employment at a support base is low, as the primary
activity consists of site preparation (i.e., grading and clearing, construction of
docks/wharves and buildings) as opposed to construction of a highly complex processing
or production facility.

Construction Profiles:

temporary service base permanent service base
manual 18 34

Non-manual 7 13

Total 25 47

Bases supporting exploration and pipeline/platform installation are considered
temporary bases. Bases supporting development and production are permanent service
bases. Construction is expected to take six months to one year.

Operating Equipment:

The level of operating employment at a support base varies according to the type
of offshore activity being supported. Permanent bases have larger employment levels
due to the amounts of materials and services required by the offshore facilities.

B-10

helicopter exploration development prod. pipe./plat.
base base base base instal. base

Manual 15 70 93 56 75

Non-manual 5 5 7 4 10

Total 20 75 100 60 85

Source:
Roy F. Weston, Inc., July 1978. Methodology for Assessing Onshore Impacts for Outer
Continental Shelf Oil and Gas Development.

Environmental Impacts

Air Waste Disposal

During construction, heavy machinery will emit hydrocarbons, carbon monoxide and
nitrogen oxides during use. Yearly vehicle emission inspection by The New Jersey
Department of Motor Vehicles should keep emissions within allowable limits.

Sources of air emissions during the operation of a support base are:

0 evaporation f rom f uel tanks f or the storage of f uel,
0 combustion from machinery and vehicles, and
p accidental spills, breaks, etc.

The magnitude of air emissions depends on the volume of delivery, storage, and
transfer of fuel, supplies, and waste associated with offshore oil and gas operations.

Support bases involved in the storage and transfer of dry, pumped cement and mud
are major sources of dust emissions. Large dust clouds can form as a result of accidental
spillage or hose blowouts.

Recreation and tourism impacts, as a result of support base air waste disposal, are
anticipated to be minimal. Dust clouds, because of their high visibility, cause the most
serious potential impact.

B-1 I

Water Use/Water Discharge

Support bases commonly have three sources of wastewater, namely sewage, bilge
water, and ballast water. Sewage wastes generated by a support base are discharged into
municipal sewage treatment systems. The dischar ge of sewage wastes f rom support or
crew boats is controlled by Coast Guard-approved sanitary waste devices. Any system
that cannot meet the regulated standards would have to utilize holding tanks for sewage.

Bilge and ballast water are generated by work boats utilizing the support base.
Bilge water could contain petroleum and heavy metals that would be toxic to marine
organisms if discharged into coastal waters. Ballast water could contain similar
contaminants and fecal bacteria that would have a: high biological oxygen demand. As a
result, the Coast Guard actively enforces regulations that require bilge and waste water
discharges to be made to onshore receptacles or to be released greater than 50 miles to

the coast.

Impacts to recreation and tourism will be minimal with proper adherence to
regulations. Impacts to biota and the aesthetic quality of an area could result because of
improper waste water disposal and in turn adversely impact tourism and recreation.

Solid Waste

During OCS drilling operations, drilling muds and drill cuttings are used to aid the
process. Drilling muds are chemical mixtures which are circulated through a well bore
during drilling, while drill cuttings are those rock particles displaced during the drilling
of a well. The primary functions of drilling muds are to cool and lubricate one drill bit
and drill pipe; transport drill cuttings to the surface; and provide hydrostatic pressure to
prevent blowouts., (U.S. Dept. of the Interior, 1981)

The discharge of drilling muds and cuttings is regulated by NJPDES pe rmit
requirements. Although the discharge at sea of oil-based muds is prohibited, substantial
quantities of conventionally-used muds can be discharged at sea. The large quantities of
oil-based wastes must be returned to the shore through the service base.

B-12

Because drilling wastes often contain hazardous materials, such as oils, acids or
heavy metals, they must be disposed of in secure landfills where there is no danger of
groundwater contamination, surface water runoff, or evaporation (NERBC, 1978).

Solid waste generated by the support base operation can be incinerated, disposed of
by landfilling, or disposed of with sewage. Little adverse environmental impact is
anticipated if these materials are disposed of in accordance with existing regulations.
(NERBC, 1978).

Impacts to tourism and recreation are anticipated to be minimal with normal
operation. However, as with any hazardous waste, the potential exists for groundwater
contamination and the subsequent diminished usability of an area.

Noise

Because a support base is in operation 24 hours a day, noise is generated
continually. Sources of noise from a support base include pneumatic power tools, air
compressors, pumps, compressed air machinery for painting and c leaning, and industrial

trucks and cranes.

Impacts to tourism and recreation are dependent upon the size of the support base,
proximity to recreation area and the existence of a buffer zone. In general, a noticeable
increase in the ambient noise level will detract from the quality of a recreation area,
and may affect use of the area.

Aesthetic Impact

The aesthetic impact of a support base, in any of the three phases, will depend
primarily upon the area in which the base is located. In an industrial port, a support base
would have minimal impact. In an undeveloped port a 24-hour lighted storage facility
with heavy machinery in continual operation and trucks, trains and boats constantly
arriving and leaving, would have a much greater aesthetic impact.

Impacts to tourism and recreation would be dependent upon the size of the support
base, the amount of activity generated, and the existence of a buffer zone. Because of

B-13

the essentially non'residential character of the study area, the aesthetic impact of a
support base is anticipated to be noticeable.

References

Baldwin, Mark. Offshore Center Inc., Alice, Texas. Personal communication, June 1982.

John J. McMullen Associates, Inc., February 1981. An Offshore Supply Base in the City
of Perth Amboy: Final Report, New York.

New England River Basin Commission and the Resource and Land Investigations Program
of the U.S. Department of the Interior, 1976. Onshore Facilities Related to Offshore Oil
and Gas Development: Factbook, Boston.

Rogers, Golden & Halpern, 1981. New Jersey Energy Facility Development Potential
Study. Prepared for the New Jersey Department of Environmental Protection, Division
of Coastal Resources, Philadelphia.

Rutgers State University, Center for Coastal and Environmental Studies, September
1977. Onshore Support Bases for OCS Oil and Gas Development: Implications for New
Jersey.

United States Department of the Interior, 1981. Draft Environmental Impact Statement:
OCS Sale No. 59. Prepared by the Bureau of Land Management.

B-14

PIPELINES

Facility Description

The pipelines considered in this study include oil and natural gas pipelines on land,
and offshore to the 3-mile (mi) limit.

Oil pipelines are generally built by the companies producing oil, either on an
individual or cooperative basis. Natural gas is usually sold on the platform to a gas
transmission company, which builds the pipeline to transport the gas from the platform
to its transmission line.

Offshore Pipelines. A pipeline system servicing offshore activity, whether for oil
or gas, may consist of a pressure source (if well pressure is not sufficient), gathering
lines, a main pipeline, intermediate pressure booster stations, a landfall, and an onshore
destination. When several companies are operating in the same general area, they are
required by Federal regulations to build a common carrier pipeline that transports their
combined products. Careful metering of the throughput at both ends ensures that each
company receives its share.

Usually the marine pipeline is routed to the nearest point of land because of the
expense of building marine pipelines (approximately 1.5 times the cost of building
onshore pipelines). However, other factors such as earthquake fault' zones, bathymetry
and underwater obstructions (i. e., pipelines or cables), excessive depths, bottom currents,
shifting sand dunes, environmental sensitivity, marine activity in the area, and proximity
to existing or potential onshore facility sites may necessitate a longer route.

Pipeline Landfall. The landfall is the section between the last points where lay-
barges and conventional onland pipelaying equipment can operate. The selection of a
landfall site involves minimizing the length of the more costly marine section,
considering the onland pipeline route, and accommodating the siting of associated
onshore facilities.

B-15

If incoming oil is to be transshipped by tanker, the landfall must be located near a
site suitable for a tanker terminal and tank farm. If the oil is to continue by onland pipe
to a refinery, a pumping station may be the only facility associated with the landfall.

The landfall for a gas pipeline is usually located near an existing or potential gas
separation/dehydration plant or gas treatment plant. These facilities are owned by the
producer, who retains the rights to the liquefiable hydrocarbons contained in the gas
stream and recovered in the separation process.

Beach-upland areas (referred to as the headlands in New Jersey) often include a
bluff or steppe upgrade, composed of rock or compacted sediment, adjacent to a narrow,
sometimes nonexistent beach. Construction in these areas tends to be very difficult and
expensive due to high erosion rates, corresponding steep offshore slope, and lack of
sufficient sediment for burial. Techniques such as sheet-piled cofferdams and explosives
would be utilized in conjunction with techniques employed with a landfall in a barrier
island beach-dune system.

Onshore Pipeline. An onland pipeline system consists of a 'main pipeline, valves,
and pressure booster stations. It may also include branch pipelines, loops, multiple main
lines, and/or meter stations.

Onshore pipelines (oil or gas) may be very inconspicuous after completion,
particularly where it does not pass through a wooded area. A pipeline right of way
(ROW), either purchased in fee or as an easement, is required for construction of oil and
gas pipelines. Revegetation can be hastened by separation of topsoil and subsoil during
excavation. It is general practice and the expressed use policy for pipelines and
associated facilities-as stated in the New Jersey State Coastal Management Program to
locate pipeline ROW corridors in or parallel to existing ROWs of highways, power
transmission lines, railroads, other pipelines, or similar facilities.

Factors influencing pipeline route selection include topography, geology and soils,
type and number of crossings (water bodies, roads, and railroads), and land use.

When the pipeline crosses bodies of water, roads, or railroads, special pipelaying
techniques must be used. These involve additional construction costs. Stream crossings

B-16

may utilize one or more of the following methods: bottom pull, floating bridge, f loating
barge, and directionally controlled horizontal drilling. Road and railroad crossings may
also be accomplished by several methods, including open cutting of roadway (unpaved or
lightly traveled), and boring under roadways (heavily traveled roads or railroads).

Facility Size/Land Requirements

The diameter of transmission pipelines, whether for oil or gas, ranges from 6 to 48
inches. Throughput capacities range from .5 to 10,000 million cubic feet/day (MMcfd)
for gas (at 1,100 pounds per square inch maximum) and 5 to 2,000 thousand barrels/day
(Mbpd) for oil (at 1,440 pounds per square inch maximum). Onland ROWs vary from 50 to
100 feet in width.

Onshore oil pipelines and gas pipelines require 6 to 12 acres per mile. The acreage
requirement varies with the pipeline's capacity and corresponding diameter.

Site Parameters

Because of their high cost, the shortest route is often the most important criterion
for locating pipelines. Marine pipeline routes should avoid anchorage areas, existing
underwater objects, active faults, rock out-crops, mud slide areas, and areas which are
environmentally sensitive. The shore approach should be gently sloping with sufficient
depth of- sand or shingle to give not less than ten f eet of cover over the pipel,ine at the
low water mark and seven feet of cover at a depth of 50 feet. Areas subject to seabed
shifting or strong tidal flows should be avoided. Erosion caused by shifting could
undermine pipeline support, placing additional stress on the pipeline and possibly causing
it to f ail.

Criteria for a landfall site include a flat approach or a reasonably gentle transition
from marine to land environment. Proximity to acreage for a pre-existing compressor
and pumping station or tank farm may also be included in the site parameter.

On-land pipelines also attempt to find the shortest route. . However, pipelines
should be routed around environmentally sensitive and densely populated areas. The lack
of availability of land, and its.high cost in developed areas weigh against pipeline ROWs

B-17

in these areas Pipeline routes should minimize the number of special crossings (i.e'.,
roads, rivers) and areas of high relief as construction costs are higher in these areas.

Capital Costs

The cost of constructing an offshore oil or gas pipeline is approximated as follows:
Capital Cost = 277,000 (1.0356D)L

The cost of constructing an onshore pipeline is approximately-

Capital Cost 77,000 (1.0705D)L
Where:

D the pipeline diameter in inches
L length of the pipeline route in miles.

The total cost for a 36" onshore pipeline extending 100 miles would be:

Capital Cost = (77,000 $/inch of diameter/mile)(1-0356 36inches)(,,, miles)
$27,127,153

Employment Profile

Employment figures for construction of onshore and offshore pipelines to some
degree vary with the length of the pipeline. Construction crews will also vary depending
on pipeline diameter, topography, and bathymetry. As longer pipelines are constructed,
instead of having one construction crew work for a longer period, companies often use
several crews to construct different segments of the line simultaneously.

In order to present a complete picture, sets of data are listed' below for both
onshore and offshore pipelines. The 5-mile offshore pipeline would take six months to
install, while the 100-mile offshore pipeline would take one year. The two onshore
pipelines would take one year to construct.

B-18

Offshore Construction Employment:
.5-Mile Pipeline 100-Mile Pipeline

Manual 246 303

Non-manual 26 25

Total 272 328

Onshore Construction Employment:

150-Mile Pipeline 1,500-Mile Pipeline

Manual 160 1,090

Non-manual 22 120

Total 182 1,210

Construction crews for pipelines usually include the following types of workers;
welders, oilers, mechanics, electricians, pipefitters, plumbers, laborers. The 1,500-mile
pipeline consists of three groups of workers and equipment (known as "spreads") working
simultaneously, averaging 400 workers per spread.

Operational employment for pipelines consists of maintenance crews that make
regularly scheduled, periodic inspections of the pipeline to check for leaks or damage. In
addition, work crews regularly maintain the ROW by clearing vegetation, etc.

Sources:
BLM/Alaska OCS Office, 1979; Northern Tier Pipeline Company; Roy F. Weston Inc.,
1979; Santa Fe International Corp., 1979.

Environmental Impact

Spill/Accidental Discharge

Spills of petroleum onto land or into fresh or salt water resulting from breaks in
pipelines are the potentially greatest impacts from operational pipelines. Causes of

B-19

pipeline breakage can include any of the following: external corrosion, damage from
equipment (anchors, fishing nets), defective pipeline seams, internal corrosion, and
improper operation by personnel. Although quality control measures and technological
advances have increased in recent years, the potential for an oil spill still remains.

Clean-up efforts involve the following techniques:

0 burning the oil floating on the water's surface,
0 utilizing sinking agents,
0 utilizing dispersants, and
0 skimming and absorbing the oil.

Of the clean-up efforts available, only the last option--skimming and absorbing the
oil--is widely used. The remaining options all have possible additional polluting effects.

The operation of marine pipelines may also involve chronic low level leaks. The
petroleum leaks dissolve into the surrounding water and terrain during normal operation.

Biological resources-are adversely affected by an oil spill 'because of the petro-
leum's toxicity and/or coating properties. The extent of the impact is the subject of a
great deal of research. If an oil spill reaches a recreational boating, swimming and/or
fishing area, the aesthetic impact is obvious. Impacts to tourism and recreation
activities can be expected, but the degree of impact is influenced by media coverage,
cle an-up efforts, and the volume of the spill.

Solid Waste

Normally, operating pipelines do not generate solid waste. However, solid waste is
associated with pipelines in the event of an oil spill. Absorbants are commonly used to
"soak up" the oil, and any non-recoverable oil and oily waste must be disposed of in a
hazardous waste landfill.

B-20

Aesthetic Impact

Depending upon site restoration practices at the time of construction, pipelines
may not be noticeable. However, where the vegetation is not as easily restored the
impact could be more severe. Aesthetic impacts can be particularly noticeable where
pipeline ROWs pass through forested areas, resulting in highly visible linear gashes
standing in contrast to the surrounding natural scenery. Impacts related to pipelines may
be less important than aesthetic impacts associated.with other onshore energy facilities.

Ecological Impacts Due to Construction

The Department of the Interior requires the burial of pipelines in water less than
200 feet deep. The trenching method used to bury the pipeline removes sediments under
the pipeline through the use of high pressure jets. As a result, increased turbidity may
affect benthic organisms. In shallow waters, contour restoration is more rapid than in
deeper waters. In bedrock areas, the necessary blasting may kill marine animals in the
blasting area.

At the landfall site, construction impacts may be greater because of the critical
areas at the marine--land interface. Special construction procedures are necessary to
protect dunes, barrier islands, marshes and estuaries.

Onshore pipeline construction activities disrupt soil, vegetation, and animal habi-
tats. The impact depends on the characteristics of the site. Where pipelines cross rivers
and streams the impact potential is greater than for flat, upland sites. Long-term
modifications in water quality, water table levels, and vegetation could result if water-
holding properties of soil layers in wetlands were not restored to pre-construction
conditions. Tourist-related impacts would be largely confined to the construction phase.

References

'Federal Energy Regulatory Commission, 1980. Cost of Pipeli ne and Compressor Station
Construction Under Non-Budget Pipeline Certificate Authorization for the Years 1976
through 1979, Washington, D.C.

B-21

New Jersey Department of Environmental Protection, Division of Coastal Resources,
1981. New Jersey Energy Facility Development Potential Study, Trenton.

New Jersey Department of Environmental Protection, Division of Coastal Resources,
September 1980. New Jersey Outer Continental Shelf Natural Gas Pipeline Siting Study
Phase 1: Corridor Identification, Trenton.

Roy F. Weston, Inc., 1979. Methodology for Assessing Onshore Impacts for Outer
Continental Shelf Oil and Gas Development, Vol. 2: Methodology.

Rutgers State University, Center for Coastal and Environmental Studies, 1980. OCS
Natural Gas Pipelines: An Analysis of Routing Issues. Prepared for the Office of
Planning and Policy Analysis, New Jersey Department of Energy, Newark.

United States Department of the Interior, Bureau of Land Management, 1980. Draft
Environmental Impact Statement: Eastern Gulf of Alaska, Sale No. 55, Washington, DC.

United States Department of the Interior, Bureau of Land Management, 1980. Final
Environmental Statement: Crude Oil Transportation Systems, Vol. I of 4, Washington,
DC.

B-22

OIL PUMPING AND GAS COMPRESSOR STATIONS

Facility Description

These facilities are required to transport the oil or natural gas through the
pipeline, and to maintain desired operating pressure in the pipeline. A typical gas
compressor station consists of one or more compressors, depending upon the volume of
gas in the pipeline, and the temperature and pressure to which the incoming gas must be
compressed. Station size in terms of horsepower (HP) requirements generally increases
with higher throughput capacity, higher operating pressures, and/or greater transmission
distances between stations. Pumping stations for crude oil pipelines usually consist of
one of more pumps linked together in series that send the crude oil from one station (or
other departure point such as a tank farm) to the next pumping station or other
destination (e.g., a refinery). The number of pumps required, and the HP of each one is
dependent upon a number of factors, including the daily throughput capacity in thousands
of barrels per day, the type of crude (i.e., different- crudes have varying specific
gravities), topography, and the maximum operating pressure of the pipeline.

Facility Size/Land Requirements
Oil pumping and gas compressor stations may have* ten or more compressors or
pumps with total station energy requirements approaching 40,000 HP. Throughput
capacities for oil pumping stations can range as high as 2 million barrels/day (MMbpd)
and for gas compressor stations as high as 2,000 MMcfd. Gas compressor stations
generally have total energy requirements between 2,000 and 10,000 HP, while oil
pumping stations have total station energy requirements of between 5,000 and 15,000
HP.

An oil pumping station may require as much as 40 ac of land and includes storage
tanks, an office, and the pumping station itself. Onshore gas compressor stations, fueled
by natural gas or refinery gas, require from 10 to 25 ac of land located along the pipeline
corridor. Land requirements would increase only minimally as a function of throughput
capacity. This is because additional pumps or compressors require little additional land

area.

B-23

Site Parameters

Oil pumping or gas compressor station locations are usually dictated by the
operating conditions (i.e., temperature and pressure of the pipeline, as well as physical
and chemical characteristics of the substance being transported). Locations for pumping
or compressor stations should be flat, with well drained soils, and not be subject to
flooding (coastal or riverine) or coastal erosion. Sites should be large enough to have
adequate land for a buffer zone, and should be located in rural or undeveloped areas. Oil
pumping stations often need to be located near existing electric transmission lines in
order to obtain energy to drive the pumps. In cases such as the Trans-Alaska Pipeline,
small on-site refineries called topping plants are used to produce a kerosene-like fuel
from crude oil extracted from the pipeline which is then used to drive the compressors.
They do not, therefore, require proximity to electric transmission lines.

Capital Costs

Oil Pipeline Pumping Station - Onshore:

Capital Cost = (470$/hp)(HP)

Where:
HP = the total pumping station horsepower

The equation assumes the use of centrifugal pumps.

Source:
United States Department of the Interior, Bureau of Land Management, 1979.

Natural Gas Compres or Stations - Onshore:

Capital Cost = $113,000 + (415$/hp)(HP)
The equation assumes the use of centrifugal compressors.

B-24

Source:
Federal Energy Regulatory Commission, 1980, Oil & Gas Journal, Annual "Pipeline
Economics" issuesfrom 1978-82.

Employment Profile

The labor force required to construct and operate both oil pumping and gas
compressor stations are presented as follows:

Construction:

Oil Pumping Station (500 Mbpd) Gas Compressor Station (2,000 MMcfd)

Manual 27 Manual 48

Non-manual 7 Non-manual 6

Total 34 Total 54

Oil pumping and gas compressor stations generally take from four to six months to construct.

Operation:

Oil Pumping Station (500 Mbpd) Gas Compressor Station (2,000 MMcfd)

Manual 6 Manual 14

Non-manual 1 Non-manual 2

Total 7 Total 16

The number of operating personnel at an oil pumping station increases gradually up to
1,000 Mbpd and then levels off at ten operating employees, one non-manual and nine

manual workers.

The number of operating personnel at a gas compressor rises slowly from lower
production rates but levels off at 2,000 MMcfd. Smaller pumping and compressor

B-25

stations are almost totally automated, and require only periodic visits by operating
personnel.

Sources:
Roy F. Weston, Inc., 1978.; U.S. Department of the Interior, Bureau of Land Manage-
ment, 1979.

Environmental Impact

Air Waste Disposal

During the operational phase, air emissions will be generated from compressors and
pumping stations. The pumps and compressors are fueled by either natural gas or
refinery gas (i.e., fuel produced by small on-site refinery-like facilities which obtain fuel
from crude oil extracted from the pipeline). The major emissions are sulfur oxides and
hydrocarbons. Nitrogen oxides are also emitted from gas compressors and are a direct
function of the load on thecompressor engine.

The overall impact of removal pumping and compressor station operations on
ambient air quality appears to be minimal. This is because the amount of emissions
generated by pumping or compressor stations would not be significant enough to result in
decreases in local ambient air quality conditions. Impacts on recreation and tourism are
anticipated to be minimal.

Spill/Accidental Discharge

For a complete discussion of oil spills related to pipeline and pum ping/com pressor
station operation, refer to the Spill/Accidental Discharge Section in the Pipeline facility
write-up.

Noise

Compressors generate the most noise during operation, approximately 92 to 100
"All weighted decibels dB(A) at the source. The pumps and compressors run day and

B-26

night so their presence could significantly increase nighttime ambient sound levels in
adjacent areas. Silencers built into the compressors can lower the noise level
Approximately once a year, venting of high pressure gas in a pipeline and at the
compressor station occurs, lasting approximately 45 minutes on the pipeline and five
minutes at the station. Uncontrolled noise levels peak at 140 dB(A), but silencers can
lower the level to almost half.

With proper controls, sound levels can be controlled and buffered, resulting in little
or no impact on tourism and recreation. Use of improper controls can, however, reduce
the quality of an area and may impact the number of participants using
recreation/tourist areas.

References

Federal Energy Regulatory Commission, 1980. Cost of Pipeline and Compressor Station
Under Non-Budget Pipeline Certificate Authorization for the Years 1976 through 1979,
Washington, D.C.

Federal Energy Regulatory Commission, Oil and Gas Journal, Annual "Pipeline
Economics" issues from 1978-82.

Roy F. Weston, Inc., 1978. Methodology for Assessing Onshore Impacts for Outer
Continental Shelf Oil and Gas Development, Vol. 2.

Sieck, Ronald and Becnel, C.L., January 1980. Oil & Gas Journal, Vol. 78, No. 2,
"Adjustable Speed Motors Offer Alternative for Pipeline Pumps." Tulsa, Oklahoma:
Petroleum Publishing Co.

United States Department of the Interior, Bureau of Land Management, January 1979.
Final Environmental Statement: Crude Oil Transportation Systems. Prepared for the
Northern Tier Pipeline Company, Northwest Energy Company, Kitimat Pipeline Ltd., and
Trans Mountain Oil Pipeline Corporation.

B-27

GAS SEPARATION AND DEHYDRATION PLANT

Facility Description

Gas separation and dehydration involves separating the gas, oil, and f ree water
components of the well stream into separate components, and dehydrating the liberated
gas to remove water vapor. Free natural gas is obtained from the well stream by either
a two-phase process which separates gas from the rest of the well stream or by a three-
phase process which results in separate gas, oil, and free water components. Heavy
liquid hydrocarbons are settled out in one or a series of separation vessels, each at
successively lower pressures. (These recovered liquids are subsequently processed
"downstream.")

The liberated gas passes through a valve at the phase interface and on to the
dehydration process. Dehydration, by removing water vapor that remains in the gas
stream after separation, prevents the build-up of solid hydrates along the pipeline and
minimizes corrosion by acid gases often present in the gas stream. The most common
dehydration process involves the use of absorbers containing triethylene glycol, which
removes the water vapor from the gas as it passes through the dehydrator.

Onshore separation/dehydration facilities are generally located as close as possible
to the pipeline landfall either as a separate facility, or together with a marine terminal,
an NGL fractionation plant, or a gas treatment plant. A location at the pipeline landfall
is desired so as to minimize the higher costs incurred in transporting the unprocessed
gas, as well as to enable pipeline-ready gas to be available for sale as soon as possible.
Gas separation/dehydration plants are generally owned and operated by gas pipeline
companies or purchasers of the gas (i.e., utilities).

Facility Size/Land Requirements

There are no standard sizes or process configurations for a gas Separation/dehydra-
tion plant as each one is individually designed around a particular gas stream's chemical
composition and flow. Gas separation/dehydration plants have throughput capacities
ranging in size from 20 MMcfd to 2,000 MMcfd. The smaller gas se par ation /dehydration
facilities are portable plants mounted on skids, while the larger plants (above 100

B-28

MMcfd) are permanent structures. Most permanent gas separati on/dehyd ration plants
have throughput capacities of between 200 and 500 MMcfd.

The amount of land required for a gas separation/dehydration plant is related, but
not directly proportional, to the plant's throughput capacity. Two-thirds of the total
land area is required for the facility with one-third for buffering. The following equation
can be used to estimate the land area required for a separation /dehydration plant:

LAND = .03(CAP) + 20

Where:
CAP = throughput capacity in MMcfd
LAND = total land area in acres

Site Parameters

Coastal sites are preferred which are immediately adjacent to pipeline landfalls
and easily accessible by highways and/or a railroad siding. Locations should not be in
areas subject to periodic coastal flooding or erosion. Potential sites should be level,
contain well-drained soils, and be of sufficient size to provide adequate buffering.

Capital Costs

The following equation may be used to estimate the capital cost of a gas separation
and dehydration plant:

Capital Cost =-$15,500,000 + (33,000$/MMcfd)(V)

Where:
V = Daily throughput in MMcfd.

As a comparison, a 200 MMcfd gas separatio n and dehydration facility that also
includes gas treatment, gas processing (i.e., removal of natural gas liquids), and
fractionation is estimated to cost between $50 - $80 million (Dr. V. Mohr, Lotepro, Inc.,
1982).

B-29

Employment Profile

The construction duration and construction labor force requirements of a gas 200
MMcfd separation and dehydration plant are presented below.

Year 1 Year 2'(6 months)

Manual 130 300

Non-manual 15 35

Total 145 335

The peak labor force for the above facility is estimated to be approximately 500
workers. As a comparison, the 200 MMcfd gas separation and dehydration plant, that
also includes gas processing, treatment, and fractionation components, would have a
peak labor force of approximately 1,500 workers on-site for a short period of time (3-4
months) (V. Mohr, Lotepro, Inc., 1982).

The operating labor force for a 200 MMcfd gas separation and dehydration plant is
estimated at 15-18 persons (New Jersey Department of Energy, 1981).

Environmental Impacts

Air Waste Disposal. There will be some occasional flaring of small amounts of
natural gas at a sep ara tio n/deh yd ration plant, along with releases into the atmosphere of
water vapor from the glycol reboilers. However, no major air pollutants will be emitted
from the facility, and the intermittent releases noted above would not be significant
enough to have any perceivable effect on local air quality such that tourist activity

would decline.

Liquid Waste. The major source of liquid waste would be the glycol compounds
used in the dehydration unit that serve as liquid dessicants (a dessicant is a solid or liquid
having an affinity for water; in the above case gas is bubbled upward through a glycol
solution, which removes the water vapor from the gas). If properly disposed, glycol
compounds should not pose any significant health or environmental risk.

B-30

Water Use/Water Discharge. Gas separation/dehydration plants do not consume
water for processing or cooling. However, the process of separation results in the
removal of water from the gas stream, which has a high salt content. This water is often
stored on-site in tanks before removal to an off-site disposal location. In other cases,
the salt wastewater is disposed of through deep well injection. The disposal of the
wastewater should not result in any significant impact on recreational activities if it is
disposed of in a proper manner.

Spill/Accidental Discharge. A number of liquids that are either used or produced as
a result of the separation/dehydration of gas could cause environmental damage if
released because of an accidental spill or discharge. These include the natural gas
liquids and salt water generated by the separation process, and the glycols used in the
dehydration process. The accidental release of these liquids from oceanfront gas
separation/ dehydration plants could have adverse impacts on the surrounding area's
environment, thus potentially reducing its attractiveness as a recreational location. The
magnitude and duration of any adverse impacts would be a function of the facility's
throughput capacity.

Noise

Apart from the heavy equipment needed during the construction of a gas
separation/ dehy dra ti on plant, the major impact on ambient sound levels would be from
the operation of compressors. They would only be required in instances where the
pressure from offshore wells is not enough to drive the gas to the nearest interstate gas
pipeline. Use of a compressor with proper on-site soundproofing would not increase
ambient sound levels at 300 meters by more than five decibels (NJDOE, 1981). When
required, compressors would operate continuously, having a substantial effect on
ambient, nighttime sound levels. This could have adverse, localized effects on tourism in
areas whose attractiveness depends in part on their perception as tranquil locations
offering an opportunity for rest and relaxation.

Aesthetics

The most visible structures of a gas separation/dehydration plant would be
approximately 40-50 feet high. Thus, any adverse aesthetic impacts would be confined

B-31

to a small area. However, the facility's continuous operation and accompanying evening
lighting, along with the intermittent flaring of gas, could constitute a more adverse,
localized aesthetic effect than the presence of the structures. In some instances a
communication tower, ranging up to 500 feet in length, could be required. A structure
this size would be clearly visible for quite a distance in the flat, coastal locations that
comprise the study area. The other adverse tourism-related aesthetic impact would be
where the facility's presence is visually incompatible with an adjacent scenic, natural, or
coastal location.

Ref erences

Federal Energy Regulatory Commission, Office of Pipeline and Producer Regulation,
July 1980. Final Environmental Impact Statement: Prudhoe Bay Project, Washington,
D.C.

Ikoku, Chi U, 1980. Natural Gas Engineering: A Systems Approach, Tulsa, Oklahoma.

Larrea, James, Proser Processes and Systems, Inc., Houston. Personal communication,

1981.

Mohr, Dr. Volker, Lotepro, Inc., New York. Personal communication, 1982.

New Jersey Department of Energy, March 1981. New Jersey OCS Handbook, Newark.

Roy F. Weston, Inc., 1978. Methodology for Assessing Onshore Impacts for Outer
Continental Shelf Oil and Gas Development, Vol. 2.

Transcontinental Gas Pipeline Corp., Houston. Personal communication, 198 1.

B-32

GAS TREATMENT PLANT

Facility Description

Natural gas often contains acid gases, primarily hydrogen sulfide (H 25) and carbon
dioxide (CO 2). Natural gas streams with high concentrations of either H2S or C02 are
referred to as "sour" gas, and the process of removing acid gases is known as
"sweetening". A gas treatment plant is the facility used for removing acid gases from
the natural gas stream.

Hydrogen sulfide must be removed from the gas stream because it is a toxic,
poisonous gas, and because, in the presence of water vapor, it is extremely corrosive. Its
presence in the gas stream decreases the useful life of pipe, valves, and pressure vessels;
and increases operating and maintenance (0 & M) costs for the pipeline. In addition, it is
very expensive to provide specially coated pipe and handling facilities capable of
resisting the corrosive effects of the gas when it is being sent over long distances.
Removal of carbon dioxide is desired because it is also corrosive when water is present in
the gas stream, and because carbon dioxide is conducive to the f ormation of hydrates,
whose formation can lessen flow rates and impair the functioning of the pipeline.

As with a gas separation and dehydration plant, a gas treatment plant is designed
specifically for the chemical composition of the gas stream it will be treating. Some of
the major processes used in a gas treatment plant include iron-sponge sweetening,
absorption with an amine solution, and a molecular sieve.

facility Size/Land Requirements

Gas treatment plants can range in size from 2 to 2,000 MMcfd in terms of
throughput capacity. Typical facility sizes range between 200 and 500 MMcfd.

Approximately 50-75 acres per 1,000 MMcfd of daily throughput capacity is
requir ed, with approximately one-third of the total site required for buffering.

A sulfur recovery plant often accompanies the const"ruction of a gas treatment
plant in instances where the natural gas stream has a high concentration of hydrogen

B-33

sulfide. The sulfur recovery plant converts the H 2S into elemental sulfur which can
then be sold for other industrial process uses. The most common sulfur recovery process
is the Claus process, in which H2 S is first oxidized to remove most of the sulfur, with the
rest being removed in catalytic converters. Preliminary indications are that natural gas
found off New Jersey would not likely require the use of a sulfur recovery plant, as it is
fairly "sweet" gas.

Site Parameters

On-shore gas treatment plants should be located as close as possible to the pipeline
landfall. This minimizes the extra costs that result from the corrosive effects of sour
gas, and the extra energy costs incurred in pumping the sour gas constituents.

A gas treatment plant is often co-located with a gas separation/dehydration plant
at a shorefront location. A site should be level, with well-drained soils, and not situated
in areas subject to coastal flooding or areas with seasonably high water levels. Finally,
sites should be accessible by highways and railroads.

Capital Costs

The capital cost of a gas treatment plant varies widely based on the volume and
chemical composition of the gas stream. In addition, there are economies of scale that
are gained when a gas treatment plant is constructed at the same location as any of the
other natural gas facilities. Smaller units, treating less than 50 MMcfd, are often
mounted on skids for temporary installation, while larger treatment facilities are
permanent structures.

The capital cost of a gas treatment plant may be estimated using the following
equation:

Capital Cost = (12,700,000$/MMcfd) (1.0034 V

Where:

V = throughput capacity in MMcfd

B-34

This equation applies to units with capacities of 30 MMcfd or greater

Sources:
Ford, Bacon & Davis, Dallas, Texas, 1982; Pacific Offshore Pipeline Co., 1982; Proser
Co., Houston, 1982; Superior Oil Company, 1982.

Employment Profile

The construction labor force requirements for a 60 MMcfd and a 200 MMcfd plant

are listed as follows:

Year 1 Year 2 (6 months)
60 MMcfd 200 MMcfd 60 MMcfd 200 MMcfd

Manual 150 250 225 350

Non-manual 12 15 20 30

Total 162 265 245 380

The operating labor force for a gas treatment plant increases only marginally for
plant sizes above 50 MMcfd due to the use of automated control systems. Operating
labor force for a gas treatment plant would be approximately 20 - 25 persons.

Sources:

Pacific Offhore Pipeline Co., 1982; Superior Oil Co., 1982.

Environmental Impacts

Air Waste Disposal

Cons tructi on-relat ed pollutant emissions would depend on the type and amount of
heavy equipment utilized, however, as noted previously, New Jersey's vehicle emission
standards should minimize the impacts of construction activities on ambient air quality.

During operation, gas treatment plants produce hydrogen sulfide, which if produced
in amounts too small to economically justify sulfur recovery, may be flare-vented or
incinerated if permitted by local air quality regulations. The pollutants released to the

B-35

atmosphere include sulfur dioxide (SO 2), nitrogen oxides (NOX) and smaller amounts of
hydrocarbons. In cases where a sulfur recovery plant accompanies a gas treatment plant,
significant amounts of sulfur dioxide are produced.

If gas treatment plants, without accompanying sulfur recovery plants are con
structed in New Jersey (as seems likely given the relatively "sweet" gas off New Jersey),
the impact of air emissions on ambient air quality should be minimal. As a comparison,
the 2,300 MMcfd gas treatment plant (without sulfur recovery) proposed for Prudhoe
Bay, a class II area in terms of air quality, was projected not to result in any significant
deterioration of ambient air quality (FERC, 1980). The corresponding effects on tourism
should likewise be minimal.

Water Use/Water Discharge

Wastewater is produced as' part of the gas treatment process, however, in most
sweetening processes, little of this is process water. The wastewater discharges can, for
the most part, be accommodated by the local municipal sewer system, though some pre-
treatment may be required for cooling water and process water. The environmental
impacts and the accompanying effects on tourism should be negligible.

Spill/Accidental Discharge

A malfunction at a gas treatment plant could result in spillage where sweetening
processes use liquid chemicals (i.e., amines) or liquid solvents as absorbents. The
magnitude and direction of the environmental effects accompanying any spills would
vary widely according to site-specific conditions and the size of the plant.

Noise

The operation of a gas treatment plant results in noise being produced by the
continuous operation of compressors, boilers, scrubbers, and flarestacks. The location of
a gas treatment plant in a commercially developed coastal location (with an ambient
sound level (LEQ) in the vicinity of 50-55 decibels), could result in a significant increase
in ambient sound levels in the vicinity of the plant. However, as with a separation/dehy-
dration plant, if the site is properly buffered and proper sound attenuation measures are

B-36

adopted, sound levels would likely not increase by more than five decibels above ambient
levels at 300 meters (NJDOE, 1981).

The presence of a gas treatment plant in an area prized for its rural ambience and
solitude (i.e., with an LEQ of between 40 and 50 decibels) could adversely impact tourism
activities in the immediate area. However, this impact would be very localized,
extending no more than a quarter of a mile from the site.

Aesthetics

Gas treatment plants' primary adverse aesthetic impacts would come from the
flaring of natural gas and the presence of lights from 24-hour operation. A gas
treatment facility's structures would be relatively low (under 50 feet), and would
therefore not be visible over a substantial area. As with other facilities, the siting of a
gas treatment plant in a scenic natural or coastal location would be incompatible with
the existing aesthetic environment. The incompatibility of the structure itself vis-a-vis
the surrounding environment, as well as the flaring and lighting effects, could decrease a
location's attractiveness as an area for tourism activities.

Odor

Odors are produced by the incomplete combustion and occasional venting and
flaring of hydrogen sulfide. The unpleasant odor associated with this gas could certainly
have a significant adverse effe ct on tourism activities occurring in thesurrounding area.
The magnitude of the effect would depend on the frequency of the releases and
prevailing atmospheric conditions around the site.

Ref erences;

Federal E nergy Regulatory Commission, Office of Pipeline and Producer Regulation,
July 1980. Final Environmental Impact Statement: Prudhoe Bay Project, Washington,

D.C.

Ford, Bacon & Davis, Dallas, Texas. Written communication, November 1982.

B-37

Ikoku, Chi U1 1980'. Natural Gas Engineering- A Systems Approach*. Tulsa, Oklahoma:
Pen Well Publishing Co.

Larrea, James, Proser Processes and Systems, Inc., Houston. Personal communication,
1981.

Mohr, Dr. Volker, Lotepro, Inc., New York. Personal communication, 1982.

New Jersey Department of Energy, March 1981. New Jersey OCS Handbook, Newark.

Perry Gas Processors, Inc., April 1977. Fundamentals of Gas Treating Manual for Design
of Gas Treaters, Odessa, Texas.

Roy F. Weston, Inc, 197.8. Methodology for Assessing Onshore Impacts for Outer
Continental Shelf Oil and Gas Development, Vol. 2.

University of Oklahoma, Sc ien ce and Public Policy Program, 1980. Energy From the
West: Energy Resource Development Systems Report, Vol. 5: Oil and Gas.

Yates, Mel, Pacific Offshore Pipeline Company. Personal communication, October 1982.

B-38

NATURAL GAS LIQUIDS (NGL) FRACTIONATION PLANT

Facility Description

In addition to oil, water, and "sour" (i.e., hydrogen sulfide and carbon dioxide)
components, liquefiable hydrocarbons such as ethane, butane, and propane may also be
present in a natural gas stream. If the gas stream is rich in these natural gas liquids, it
may be economically attractive to separate the bulk liquids content into these individual
components. A gas processing plant is first used for removing liquefiable hydrocarbons
from the gas stream. A natural gas liquids fractionation plant then separates the
liquefiable hydrocarbons into their constituent components. Both the gas processing
plant and the fractionation plant are located "downstream" from a gas treatment plant.

NGL relies on the different vaporization temperatures of the products. The
process is performed in a series of fractionating towers. The lighter, more volatile
products are vaporized first, condensed, and collected, while the remaining liquid is fed
to the next tower, where the process is repeated for the heavier products. The major
constituents usually separated out by a fractionation facility include ethane, propane,
butane, and pentane. The individual fractionating towers are named for the product they
remove, and are thus called a dethanizer, a depropanizer, a debutanizer, etc. The
specific design of a fractionation plant depends on throughput capacity, the relative
abundance of desired products in the bulk liquid, and the desired recovery rate of those
products.

An NGL fractionation plant would be located at a gas separation/dehydration plant,
or at a gas-processing plant only if the volume of NGL recovered from a single facility
were large enough to economically justify the operation of a fractionation plant. In most
other cases, a fractionation plant would be centrally located so as to receive the NGL
produced by a number of gas separation/dehydration or gas processing plants. In New
Jersey it is likely that NGL would be collected at individual locations and shipped by
tanker truck to a centrally located fractionation plant.

B-39

Facility Size/Land Requirements

Fractionation plants may be designed for any volume. Typical throughput
capacities of these facilities range from 5 to 50 Mbpd of natural gas liquids.

As with the other natural gas-related facilities, the land required for an NGL
fractionation plant is related, but not directly proportional, to the plant's throughput
capacity. The following equation can be used to estimate land requirements:

LAND= .03(CAP) +30

Where:

LAND plant area in acres
CAP plant daily processing capacity in thousands of barrels (Mbpd)

Site Parameters

Fractionation plants, have the same general siting requirements as gas separa-
tion/dehydration and gas treatment'plants. The one exception is that they do not have to
be located close to pipeline landfalls or close to the interstate gas pipelines.

Capital Costs

The capital costs of a 10,000 barrel/d,ay gas liquids fractionation plant are

estimated as follows:

Capital Cost = (400$/barrel per day)(BPD) + $4,000,000

Where:
BPD = barrels of condensate processed per day

This assumes the fractionation of the condensate into propane, butane, and pentane.

Sources:

Ford, Bacon & Davis, 1982; Pervin and Gurtz, 1981.

B-40

Employment Profile

The employment required to construct and operate a natural gas liquids-frac-
tionation plant is small in comparison with most of the other n atur al-gas-r elated energy
facilities. This is due to the small size of the facility.

The construction labor force consists of:

Year 1 (6 months)

Manual 98
Non-manual -6
Total 104

The operating labor force will be small for two reasons. First, fractionation
facilities will generally be located at gas processing plants, and the labor force required
to operate these facilities would also have the responsibility of overseeing the frac-
tionation facility. Second, state-of-the-art fractionation facilities employ highly auto-
mated control systems and would require a minimal amount of operating labor. It is
estimated that no more than five persons (all manual) would be required to operate a gas
liquids fractionation plant.

Environmental Impacts

Air Waste Disposal

As with other energy facilities, there will be emissions from vehicles and heavy
equipment utilized on-site during the construction of an NGL fractionation plant. Given
the relatively short construction period for this facility, and the existing vehicle
emission control program in New Jersey, the impacts during the construction phase
should be minimal. During operation an NGL fractionation plant will release small
amounts of hydrocarbons from valves and fittings during the fractionation process. In
addition, combustion-related emissions from the operation of boilers and compressors
will also occur. The environmental impacts accompanying these emissions would be
minimal, and would not be expected to have discernible effects on tourism.

B-41

Water Use/Water Discharge

The major consumptive use of water in an NGL fractionation plant is for cooling
and condesning each constituent as it leaves each fractionator. This water usually
contains chemicals which prevent scaling and fouling in the condenser and cooling
system, and this water would likely have to be pre-treated on-site before being sent to a
local municipal wastewater treatment system. Process requirements would be of a
lesser degree than cooling water requirements, but would also require pre-treatment
before being released to the local wastewater treatment system. The volume of water
required by an NGL fractionation plant would not be large enough to have any significant
effect on local water supplies (i.e., as compared to the cooling water requirements of an
electric generating plant). Similarly, the environmental effects accompanying the
wastewater generated by this facility should be minimal if all applicable environmental
standards are adhered to. The related impacts on tourism should also be minimal.

Spill/Accidental Disch arge

A malfunction at an NGL fractionation plant would result in the release of the
separated components (i.e. butane, propane etc.) being stored on-s'ite. The magnitude of
the environmental effects accompanying any such release would be dependent upon the
site-specific conditions and on the volume of the release.

Noise

As with the other natural-gas-related facilities, an NGL fractionation plant
involves the use of compressors and boilers. Similarly, the continuous operation of such
a facility in a rural -site would result in a signif icant increase in nighttime ambient sound
levels. The magnitude of the increase in ambient sound levels would be similar to those
noted previously for a gas treatment plant and a gas separation/dehydration facility. In
conclusion, the noise effect will be localized and, depending on site-specific conditions,
could have an adverse impact on the suitability of the adjacent areas as a location for
tourism-related activities.

B-42

Aesthetics

The aesthetic impacts of an NGL fractionation facility would be very similar, but
somewhat larger than those noted elsewhere for a gas treatment plant. The most visible
component of a fractionation plant would be the individual fractionators which can range
as high as 150 feet. They would be clearly visible over a significant area due to the flat
topography of the study area. The presence of clearly visible fractionators, in coastal
locations desired for their aesthetic qualities, would constitute an adverse visual

intrusion.

References

Ford, Bacon and Davis, Dallas, Texas. Written communication, November 1982.

Ikoku, Chi U, 1980. Natural Gas Engineering: A Systems Approach. Tulsa, Oklahoma:
Pen Well Publishing Co.

New Jersey Department of Energy, March 1980. New Jersey OCS Handbook, Newark.

Pervin and Gurtz, Houston, Texas. Personal communication, 1981.

B-43

PEAK SHAVING FACILITIES

Facility Description

Peak shaving facilities constitute reserve storage facilities which can supply
natural gas to utilities and other consumers during peak demand periods. The obvious
advantage of storing natural gas in a liquefied form is that 600 cubic feet of natural gas
can be condensed and cooled to occupy one cubic foot in its liquid form. One barrel of
LNG is equivalent to approximately 3,450 cubic feet of natural gas.

There are three fundamental steps in the peak shaving process. Natural gas
entering the plant is first liquefied by compression and cooling to -2600 F. The liquefied
natural gas is then stored in specially insulated storage vessels. Finally, the gas is re-
vaporized and reinserted into a natural gas transmission and distribution system for
distribution to consumers.

A number of storage options exist, but the most commonly used is the conventional
above-ground, double-insulated metal tank. These tanks genera lly have a steel outer
wall and an'inner wall of aluminum, 9% nickel steel, or austenitic stainless steel. The
material of the inner wall must retain its ductility at cryogenic temperatures. In order
.to contain the contents of the tank in the event of a spill, each tank is surrounded by a
diked impounding area with a capacity of at least 100% of the tank capacity. It is
generally bottom-lined with moist sand and 2.5 inches of shotcrete to help withstand the
thermal shock of a spill.

Facility Size/Land Requirements

Peak shaving plants may contain two or more storage vessels with each having a
capacity of up to 900,000 barrels of LNG (equivalent to 3,100 MMcfd of natural gas).
They can vaporize up to 116,000 barrels of LNG per day, delivering 400 MMcfd to meet
peak demand. The daily delivery capacity (i.e., rate at which gas can be vaporized and
delivered to a pipeline) is generally about one-fifth of a peak shaving plant's total
storage capacity.

B-44

As with other natural gas-related facilities, land requirements for peak shaving
plants are indirectly associated with total plant capacity.

The following equation can be used to estimate total land requirements:

Land Area = 94 + .03 + _SCP

Where:

Land area = site size in acres
SCP = storage capacity in thousands of barrels of LNG

The facilities would occupy about half the total site while the remainder would be used
as a buffer area for safety reasons.

Site Parameters

Peak shaving plants should be located in areas where the soil has good bearing capacity,
because of the considerable weight of the liquefied natural gas. Sites should be flat, and
situated out of flood plains, areas subject to coastal flooding, and seismically active
areas. They should be directly adjacent to an existing gas transmission line. Finally,
peak shaving plants should not be located in areas where concentrations of population are
adjacent to the site due to the flammability of LNG.

Capital Costs

Capital Cost (13,440,000$/thousands of barrels) (1.0017 SCP

Where:
SCP storage capacity in thousands of barrels.

The foundation costs are included in the baseline capital cost equation. This
equation assumes the use of a concrete mat foundation over selected backfill.

B-45

Sources:
Chicago Bridge and Iron Co., 1982; Ikoku, Natural Gas Engineering, 1980; Public Service
Electric and Gas, 198 1.

Employment Profile

The construction labor forces for two sizes of peak shaving plants are presented
below.

290,000 Barrel 580,000 Barrel
Storage Capacity Storage Capacity

Year I Year 2 Year I Year 2
(9 months only)

Manual 45 58 75 98

Non-manual 5 7 8 12

Total 50 65 83 110

The operating labor force for a peak shaving plant does not'vary by size, as these
facilities are highly automated and use computerized control systems. The operating
labor force for facilities in the size range noted above would consist of 17 persons over a
24-hour shift, 3 non-manual and 14 manual.

Sources:
Bimonte, Joe, July 1982; Transcontinental Gas Pipeline Company, Carlstadt, New Jersey;
Wilson, Peter, September 1982, Chicago Bridge and Iron.

Environmental Impact

Air Waste Disposal

During the construction of a peak shaving facility, clearing grading and earthwork
activities can generate dust. Dust can be controlled by spraying water on - the disturbed
areas. With proper dust suppression methods implemented, impacts to air quality and to
tourism and recreation are anticipated to be minimal.

B-46

operation of a peak shaving plant will include an occasional vaporization of the gas
supply . As a result, nitrogen oxides are emitted in significant amounts. However,
because vaporization units are operated approximately 20 days a year, the annual
emissions of nitrogen oxides are a relatively insignificant amount. The impacts to air
quality and to tourism and recreation are anticipated to be negligible.

Noise

During various phases of facility construction, noise levels will rise and may
produce an impact on ambient noise levels. Because of the limited duration of noise and
occurrence primarily (if not solely) during daylight hours, construction noise levels are
not considered to be a significant impact.

Sources of noise generated during operation are the turbin e/com pressor set, heat
exchangers, and primarily the vaporizer units. Because of the amount of noise generated
(113 dB(A) at a reference distance of 3 feet), acoustical treatment is most often a
component of the facility's plans. One option includes housing the equipment in an
acoustically treated building.

Because of the relatively non-industrial, suburban characteristics of the study area,
the increase in ambient noise levels could be a significant impact. An increase in
ambient noise levels could be interpreted as a decrease in the quality of an area and
could, in turn, affect the number of tourism and recreation participants.

Aesthetic Impact

Large storage tanks may approach 150 feet, thus the aesthetic impacts would be
similar to those noted previously for other natural gas-related facilities. In addition, in
an effort to maintain safety standards near the facility, trees, bushes and other
landscaping are not permitted as a measure to reduce the amount of combustible
material near the facility. As a result, the facility's appearance becomes even more

blatant.

B-47

Accident

LNG is a liquefied flammable gas which is readily vaporized when exposed to
external heat sources. The vaporized LNG is not flammable when unconfined (Federal
Power Commission, 1976), but is flammable in enclosed areas. A potentially flammable
vapor cloud could form if a storage tank were ruptured and LNG escaped into the
atmosphere. The probability of an accidental release of LNG due to a storage tank
rupture is quite low; conversely, the probability of a release of other flammable liquids,
used in either the liquefaction or vaporization processes, is much higher.

The process of liquefying pipeline gas to liquid natural gas will probably entail the
use of a mixed refrigerant. The refrigerant consists of hydrocarbons, most likely a
mixture of ethane, propane, butane, nitrogen and methane. All of the components
except for nitrogen are flammable. A processing accident could leak the refrigerant and
result in the potential for a fire or explosion. Methanol, also flammable, may be used
during the pretreatment of gas to remove water and carbon dioxide. The potential for
fire and/or explosion also exists with the storage and processing of methanol.

Hazard detection, prevention, and mitigation constitute major efforts in the
construction and operation of a peak shaving facility. Because of the incorporation of a
protective buffer zone around the facility, and siting in low density population areas,
danger to the nearby public is reduced.

Ref erences

Federal Energy Regulatory Commission, February 1980. In the Matter of Energy,
Terminal Services Corporation, Docket No. CP74-122, Washington, D.C.

Federal Power Commission, December 1976. Draft Environmental Impact Statement:
West Deptford LNG Project, Tenneco LNG Inc, Docket No. CP76-16, Washington, D.C.

Ikoku, Chi U, 1980. Natural Gas Engineering: A Systems Approach. Tulsa, Oklahoma:
Pen Well Publishing Co.

B-48

Transcontinental Gas Pipeline Corporation,' Carlstaadt, New Jersey. Personal communi-
cation, August 1982

Transcontinental Gas Pipeline Corporation, 1979. "Let's Talk About Storage of Natural
Gas." Houston, Texas.

Wilson, Peter, Chicago Bridge and Iron Company, Philadelphia. Personal communication,
1982.

B-49

TANK FARMS

Facility Description

Petroleum tank farms are used for the storage of crude oil and refined petroleum
products. Tank farms store oil arriving from outer continental shelf drilling operations
via pipelines, and oil arriving by tanker- from overseas producers. When they are located
at marine terminals, tank farms store oil offloaded from tankers, or oil sent via overland
pipelines awaiting loading onto tankers. Tank farms are also essential components of the
oil refining process, storing incoming crude oil prior to its being pumped through an
overland pipe to a refinery. Tank farms are also used for storing refined petroleum
products prior to their distribution by pipeline, rail, ship, barge, or truck.

Oil storage tank farms may be located at a number of different facilities,
depending upon the oil processing and transportation schemes being used. If crude oil is
being piped to shore, tank farms may be located near the pipeline landfall, associated
with either pumping stations or marine terminals. From either of these facilities the oil
is transshipped to refineries in other regions.

Facility Size/Land Requirements

The individual storage tanks can be built to store up to one'million barrels each,
but storage between 150,000 and 300,000 barrels per tank is more typical. Oil tank
farms are also sized on the basis of their throughput capacities. This is the number of
barrels per day the facility is capable of pumping from offloading tankers, and it is
determined by the capacity of the pipeline supplying the tank farm. Throughput
capacities range as high as 1,000,000 barrels/day, with- 250,000-500,000 barrels/day being
the most common. As a general rule, throughput capacities are generally about one-
eightieth of a tank farm's total storage capacity.

The acreage of the tank farm depends on the total storage capacity required and
the rate at which incoming oil enters the facility. Tank farms may contain up to 20
storage tanks with total storage capacities approaching five million barrels. The amount
of land required for a tank farm depends on its total storage capacity. Approximately 13
to 20 acres are required per one million barrels of oil stored.

B-50

Site Parameters

Sites for the tank farm should be flat, not subject to coastal flooding, and have
soils capable of bearing the heavy loads associated with storage tanks. If the tank farms
are to be used by tankers, the site must also be adequate in terms of wind and wave
conditions, and bathymetry. Waterfront locations must be sheltered from adverse
weather and wave conditions and the mooring areas must have sufficient depth to
accommodate the draft of the largest anticipated tanker expected to utilize the facility.

Capital Costs

As with the land requirements, the costs of a tank farm are'dependent upon the
total storage capacity of the facility. Capital costs can be estimated using the following
equation:

Capital.Cost = (18,020,000$/10 6barrels)(V) - $5,600,000

Where:
V = total storage capacity in 10 (millions) of barrels

The design assumptions include a reinforced concrete ring foundation on top of a graded
and compacted surface with a sand-grav el and asphalt subbase. The tanks are assumed
to have fixed-roofs. It should be noted that the above costs are for the oil storage
facilities only, and do not include the required unloading/ loading facilities. In addition,
these costs assume that the storage tanks would be designed, fabricated, and erected at
a remote site and delivered to the site by rail, barge, or truck transportation.

Sources:
U.S. Dept. of Interior, Bureau of Land Management, 1979; Oil & Gas Journal, Annual
"Pipeline Economics" issues from 1978-80.

B-51

Construction Personnel

The number of annual manual and ann-ual non-manual employees required to
construct a tank farm with a total storage capacity of 4 million barrels is presented as

f ollows:

Manual 175

Non-manual 25

Total 200

The construction period would last approximately 24 months. Due to economies of scale,
additional construction labor force requirements are minimal for facilities with storage
capacities greater than 4 million barrels. However, the length of the construction phase
would increase.

Following is the number of manual and non-manual employees required to operate a
tank farm with a storage capacity of four million barrels:

Manual 27

Non-manual 3

Total 30

The number of employees required to operate tank farms with larger storage capacities
would not change due to the highly automated and computerized control systems used in

new tank farms.

Sources:
Northern Tier Pipeline Co., Northwest Energy Co., Kitimat Pipeline Ltd., and Trans
Mountain Oil Pipeline Corp., Environmental Statement Crude Oil Transportation
Systems, Volume 1, 1979; Roy F. Weston Inc., July 1978.

B-52

Environmental Impact

Air Waste Disposal

During the construction of tank farms, combustion emissions from heavy machinery
operating on-site include nitrogen oxide and carbon monoxide. Dust is also generated by
heavy machinery moving topsoil.

Hydrocarbons are the primary emissions from tank farms. Controlling hydrocarbon
emissions is important because of their reaction with nitrogen oxides in the presence of
sunlight to produce ozone and smog. Sources of hydrocarbon emissions include:

0 evaporation from storage tanks,
0 evaporation during the transfer of crude oil and fuel, and
0 accidental spills and small leaks.

The magnitude of the hydrocarbon air emissions on the ambient air quality is influenced
by several of the following factors:

0 number of storage tanks
0 number of marine vessels (transfer points)

0 ambient air conditions
0 tank design and tank paint color (colors that increase the reflectivity of light
from takes can increase the formation of smog in adjacent areas)

Impacts to tourism and recreation are not anticipated from construction machinery
emissions because of New Jersey's Motor Vehicle yearly emission testing to meet
specif ic standards. Impacts to tourism and recreational activities as a result of
hydrocarbon emissions will be minimal if emissions are kept to a minimum. If
hydrocarbon emissions increase substantially, however, the resultant smog will lessen the
quality of the recreation area. Developing ozone is not only harmful to the atmosphere
bu@ causes coughing, eye irritation, headache, and damages vegetation. As a result,
increased hydrocarbon emissions could make an area undesirable and unsafe, reducing
recreation activities.

B-53

Solid Waste

Sediment sludges must be removed from the bottom of storage tanks to maintain
maximum holding capacity. The sludges are considered hazardous and contain iron rust,
iron sulfides, sand, and oil. Disposal in a secured landfill is required.

The impact of tank farm solid waste will be minimal unless the dump site is not
properly secured and the sediment sludges are allowed to contaminate the groundwater.

Spill/Accidental Discharge

Because of the large volume of oil stored and transferred at tank farms, oil spills
may occur at any time. A spill would have a significant impact on biological resources in
the vicinity because of the coating and toxic properties of the oil. A spill might also
result in an aesthetic impact if the slick coated recreational beaches or boating areas.

A major oil spill could severely impact tourism and recreation. Fishing, boating,
and swimming could conceivably be curtailed as a result of a spill. Clean-up efforts,
water current patterns, and site locations all influence the degree of impact of an oil
spill on recreation and tourism.

Noise

If the construction of a dock or bulkhead is required, pile drivers will be used.
Although they are used only temporarily, they do generate a considerable amount of
noise, and ambient sound levels can be expected to increase. During operation, ambient
sound levels will rise because of pumps moving oil to and from tanks, pipelines, and

tankers.

Increases in ambient sound levels would be noticeable in shorefront recreational
areas, and particularly in sparsely-populated rural shorefront areas valued for peace and
quiet, thereby possibly affecting recreation and tourism. Higher ambient sound levels
would decrease tourists perceptions of a site's suitability as a location for relaxing and
escaping the pressures of everyday life. Buffer zones and proximity of the site to
recreation areas will determine the extent of the impacts.

B-54

Aesthetic Impact

The presence of numerous large tanks, possible round-the-clock operations, and
continual lighting would create adverse visual impacts in shorefront recreational areas.
In the event of a major oil spill, patches of oil washing up on sandy beaches would have a
devastating effect on the visual attractiveness of such areas. In addition, floating oil
slicks would adversely affect the visual appearance of water, and result in oil lines on
boats and waterfront structures. The presence of oil tanks and the possibilty of adverse
aesthetic effects can be mitigated by several factors, including the following:

0 buf f er zone

0 landscaping
0 oil spill clean-up measures
0 location away from recreation areas

The aesthetic impact of tank farms on recreational and tourism activities can range
from a marginal effect to a complete reduction in the area's recreational usage (as in the
case of a major spill). -Certainly, oil slicks covering sandy beaches will result in
swimmers going to other, unaffected beaches. Similarly, recreational boating would
decline, and other potential visitors seeking an attractive shorefront location for rest
and relaxation would change their patterns of visitation.

Other-Fire Hazard

Tank farms store large volumes of oil and other petrochemicals and, as a result,
fires and explosions are ever-present hazards. Even a small fire may produce enough
heat to cause explosions of nearby stored oil.

A buffer zone would increase protection for nearby tourists and participants in
recreational areas, but would also increase industrial land usage, thereby possibly
decreasing recreational areas. An explosion would obviously seriously affect recreation
and tourism in the vicinity of the tank farm.

B-55

Other-''Dredging

If oil is expected to be loaded or unloaded from tankers, construction activities will
also include dredging and jetty construction. Dredging will alter the biological resources
in the vicinity of the dredged site, due to increases in turbidity, siltation, and the
disruption of benthic organisms. If the dredging is extensive, it may change water
currents significantly enough to alter the coastline.

Construction and dredging impacts are anticipated to be temporary, and have
minimal effect on tourism and recreation. However, a more significant impact will be
the use of the coastline for an industrial purpose rather than a recreational purpose.

Ref erences

New England River Basin Commission and the Resource and Land Investigations Program
of the U.S. Department of the Interior, November 1976. Onshore Facilities Related to
Offshore Oil and Gas Development: Factbook Boston.

New Jersey Department of Environmental Protection, Division of Coastal Resources,
198 1. New Jersey Energy Facility Development Potential Study, Trenton.

Roy F. Weston, Inc., July 1978. Methodology for Assessing Onshore Impacts for Outer
Continental Shelf Oil and Gas Development.

United States Department of the Interior, Bureau of Land Management, January, 1979.
Final Environmental Statement: Crude Oil Transportation Systems. Prepared for the
Northern Tier Pipeline Company, Northwest Energy Company, Kitimat Pipeline Ltd., and
Trans Mountain Oil Pipeline Corporation.

B-56

NUCLEAR POWER PLANTS

Facility Description

Nuclear power plants generate electricity by capturing the heat from the control-
led fission of uranium-235 (U-235), transferring the heat to water, and using the resulting
steam to drive turbines that are linked to generators. In the United States, light water
reactors are used. Light water refers to the use of ordinary water to cool the reactor
core. Heavy water reactors use heavy water, water whose hydrogen atom has an extra
neutron, to cool the reactor core.

There are two types of light water reactors--pressurized water reactors (PWRs),
and boiling water reactors (BWRs).

A PWR is based on a two-step heat transfer process. Water that circulates around
the reactor vessel, contained in a closed high-pressure system called the primary water
system, is pumped to a heat exchanger, where its heat is transferred to the secondary
water system, producing the stream that drives the generator's turbines. The spent
stream is condensed to water by a third water system, often a once-through pass of
water from a river, lake, or other source that is consumed by evaporative cooling.

In BWRs, the water that circulates around the reactor core and carries away the
heat from U-235 is allowed to vaporize to steam, which directly drives the turbogenera-
tor. Since this water is highly radioactive due to its close association with the fuel
module, greater design and operating precautions are necessary against possible leakage
of radioactive material. However, a higher thermal efficiency is achieved in this one-
step coolant cycle design than in the PWR's two-step cycle.

Facility Size/Lan'd Requirements

Currently operating nuclear power plants have net electric-generating capacities
of between 200 megawatts and 1,200 megawatts per unit. Most plants have generating
capacities of between 800 and 1,200 megawatts. In many instances two or more
generating units are co-located.

B-57

Minimum site acreages for nuclear power plants are determined by the Nuclear
Regulatory Commission's (NRCIs) criteria for determining the exclusion area. The radius
of the exclusion area around the plant is determined by the dosage a person would
receive in the event of an accidental release of radiation, which in turn is related to
plant size.

Exclusion areas are typically .4 mile (NRC, 1979, NUREG 0625). Thus, assuming a
half-mile radius around a plant for the exclusion area, and assuming a square site, yields
a minimum site size of 650 acres per generating unit.

Site Parameters

Proper siting of a nuclear power plant involves consideration of several factors
including:

0 proper topography with adequate flood protection and soils with good load
bearing capacity;
0 a seismically inactive region;
0 proximity to electric transmission lines and access to highways;
0 access to and availability of large amounts of water;
0 suitable distance from airport-restricted zones and man-made hazards, and
0 areas of low population density.

The Nuclear Regulatory Commission has very specific regulations concerning
population densities permitted within 30 miles of a potential plant site.

Capital Costs

For a plant beginning commercial operation in 1982, the following equation can be
used to estimate capital costs:

Capital Cost $31,840 (MWe-' 4921) KWe

Where:
MWe net electrical generating capacity in megawatts

B-58

K We = net electrical generating capacity in kilowatts

The capital cost of a 1,000 MWe nuclear power plant beginning commercial
operation in late 1982 would be:

Capital Cost = (31,840 $ 103 watts)(1000-*4921 x 106 w atts)(1,000,000 x 103
watts)
= (31,840 $ 103 watts)( 29.94 x 106 watts)(1,000,000 X 10 3 watts)

= $1,063,460,524

These costs are expressed in as-spent dollars. "As spent" dollars are defined as the
amount of a revenue or expenditure expressed in the current or nominal dollar amount
prevailing at the time. the revenue or expenditure was incurred. Thus, the total "as
spent" cost of a nuclear power plant beginning commercial operation in 1990 would
consist of the sum of the current dollars costs incurred each year throughout the
construction period (i.e., 1985 current dollar outlays plus 1986 current dollar outlays,
etc.). As an example, assume $1,000 is spent for concrete in 1985, and $1,050 for the
same amount of concrete -in 1986 (i.e., inflation is 5%/yr.). The total "as spent" cost of
concrete during the two-year period would be $2,050.

The equation assumes a location 10 feet above the 100-year flood plain and a

concrete mat foundation on bedrock.

Sources:
Budwani, R., Power Engineering, May 1980; Oak Ridge National Laboratory and United
Engineers and Constructors, 1980; United Engineers and Constructors, 1977.

Employment Profile:

The labor force required to construct a nuclear power plant is given in table 1.

The manual laborers consist primarily of skilled trades personnel (i.e., boiler-
makers, pipefitters, electricians, carpenters, etc.). Non-manual laborers consist of

B-59

clerical and support personnel (about 20%) and foremen, construction managers and
engineers (about 80%).

The operating labor force requirements for the two plant configurations noted in
table I are indicated as follows:.

One 1,000 Mwe Unit Two 1,000 Mwe Units

Manual 40 70

Non-manual 160 285

Total 200 355

Manual workers consist of equipment operators and laborers (i.e., maintenance personnel),
while non-manual workers consist of skilled plant operators, engineers, managers, supervisors,
and support personnel.

Sources:
EPRI, 1982; Oak Ridge National Laboratory, 1980; Pennsylvania. Power & Light, 1978.

B-60

Construction and Operating Labor Force
Requirements of Nuclear Power Plants

One 1,000 Mwe Unit

Year 1 2 3 4 5 6 7 a 9 10

Manual 52 418 680 1177 1440 2010 1465 628 209 91
Non-manual 13 91 183 243 277 344 328 247 133 47

Total 65 509 863 1420 1717 2354 1783 875 342 138

Two 1050 Mwe Units (constructed concurrently)

Year 1 2 3 4 5 6 7 8 9 10

Manual 100 800 1300 2750 2750 3840 .2800 1200 400 175
Non-manual 25 175 350 465 530 659 638 472 256 90

Total 125 975 1650 3215 3280 4499 3438 1672 656 265

Enviro nmental Impact

Air Waste Disposal

Construction machinery required for a nuclear power plant can be anticipated to
emit carbon monoxides, nitrogen oxides, sulphur dioxide, and hyrocarbons. Required
vehicle emission testing by the State of New Jersey should keep pollutants at a
minimum, with minimal tourist impact.

The use of saline water in the mechanical draft cooling towers will most likely
result in salt deposition near the facility. Vegetation in the vicinity of the power plant
could be adversely affected because of the salt deposition. Impacts to tourism and
recreation from air waste disposal are anticipated to be minimal.

Water Use/Water Discharge

Heat from the fission of nuclear fuel in the reactor is used to produce steam at
high temperature and pressure, which in turn drives a turbine connected to a generator.
The "spent" steam is condensed by passing it through condensers with large amounts of
water. The heat is transferred to the cooling water.

Substantial amounts of water are required by the condensers to cool the steam. As
a result, organisms small enough to pass through the intake screens and be drawn into the
system will be killed. Mortality is due to mechanical, thermal, or chemical shock.
Intake screens may impinge fish not large or strong enough to swim safely away.
Mortality is anticipated to be 100% for those fish impinged on screens.

Blowdown, the effluent from cooling towers, is discharged continuously, most often
at a higher temperature than when originally withdrawn and containing added chemicals.
Changes in water temperature may af f ect. reproduction, growth, and survival of larval
forms, juveniles, and adults. The warmer water has a lower dissolved oxygen content.
Possibility exists for fish and/or plankton kills. Alteration of the aquatic community in
the immediate vicinity of the discharge site is anticipated.

B-62

Because of state and federal controls on point discharges of liquid wastes, impacts
to tourism and recreation should be minimal with proper operations and controls.
However, in the event of a large volume of heated waste water being discharged, the
water quality and biotic quality will decrease. This may be interpreted as a decrease in
the quality of a -recreation area and may result in a decline in the number of
participants.

Aesthetic Impacts

The most visible components of a nuclear power plant would be natural draft
cooling towers (where they are required) and the reactor containment building. Natural
draft cooling towers can be as high as 500 feet and would be clearly visible over a sizable
viewshed, perhaps as far as 3.5 miles given the flat terrain of the study area. Reactor
containment buildings may approach 200 feet in height, and would also be highly visible
structures. There would be no way to screen either of these structures through the use
of vegetation or intervening structures. Thus, the presence of one or more natural draft
cooling towers, or a reactor containment building in scenic coastal locations would
adversely affect the aesthetic quality of such areas by introd ucing a highly visible
structure clearly incompatible with the existing visual setting.

Radiological Impacts

The. major potential impact associated with a nuclear power plant is the release of
radiological liquid and gaseous effluents. Plant design includes shielding of the reactor,
hold-up tanks, filters, and demineralizers. Potential releases of radionuclides also exists
in the transportation of the nuclear fuel.

Small doses of radiation from the cooling towers and cooling water discharges that
are within state and federal limits should pose no threat to wildlife, vegetation, or man.
Direct radiation from the machinery within the plant is not expected to be significant at
the plant boundary.

A significant effect of building a nuclear power plant is the public's perception of
the probability of a malfunction that would release radiation into the surrounding
environment. Since Three Mile Island, the public's awareness of the potential or

B-63

unplanned radioactive release from a facility has certainly been heightened*. It is likely
that the public's perception of the probability of an unplanned release of radiation is
higher than the actual probability of occurrence. Clearly, this heightened perception by
the public could act to also significantly decrease their perception of the recreational
suitability of an area located in the vicinity of a nuclear power plant.

Ref erences

Braid, Robert, April 1981. "Better Work Force Projections Needed for Nuclear Power
Plant Construction", Power Engineering.

Budwani, Ramesh N., August 1982.. "Power Plant Scheduling, Construction and Costs: 10
Year Analysis", Power Engineering.

------ May 1980. "Power Plant Capital Cost Analysis", Power Engineering.

Consumers Power Company, 1981. Midland Nuclear Power Plant Report, Jackson,
Michigan.

Electric Power Research Institute, February 1982. Socioeconomic Impacts of Power
Plants. EPRI EA 2228, Palo Alto, California.

Friedlander, Gordon, October 1981. "Coal or Nuclear? Economics Govern", Electrical

World.

Oak Ridge National Laboratories and United Engineers and Constructors, 1980. Power
Plant Capital Investment Cost Estimates: Current Trends and Sensitivity to Economic
Parameters. Prepared for the U.S. Department of Energy, Washington, D.C.

Susquehanna Steam Electric Station: An Update, Allentown, Pennsylvania.

United Engineers and Constructors, Inc., 1977. Commercial Electric Power Cost Studies,
Vols. 1-8. Prepared for the U.S. Nuclear Regulatory Commission, NUREG-0247.

B-64

United States Department of Energy, Office of Environmental Assessments, 1979.
Technology Characterizations: Environmental Information Handbook, DOE/EV-0072,
Washington, D.C.

B-65

COAL--FIRED POWER PLANT

Facility Description

The electricity is produced as steam expands over the length of the turbine,
causing it to spin, in turn driving the generator which produces electricity. The
combustion of coal requires extensive on-site materials handling capability (i.e., convey-
ors, stacker/reclaimers, and storage space), and requires the installation of extensive
pollution control equipment (i.e., scrubbers and precipitators) to remove the particulates
and other pollutants produced during combustion. Coal-fired power plants use large
amounts of water to remove the excess heat produced by the combustion of coal (i.e.,
electric generating plants convert only about one-third of the total heat produced into
electricity; the remaining two-thirds is removed by the cooling water).

Coal-fired power plants burn coal in order to produce steam, which is sent through
a turbine generator, producing electricity. The major components of a coal-fired power
plant include:

Facility Size/Land Requirements

Coal-fired power plants generally range from 100 to 1,000 gross megawatts
electrical energy in output capacity per unit. Up to four generating units have been built
at a given location. In terms of land use, a large plant (800 megawatts) may require over
1,000 acres of land, mostly for fuel storage and waste disposal. To determine the
approximate acreage, output capacity of the plant in megawatts is to be inserted into
the following equation:

AC = 200 + .5(NEGC)

Where:
AC = plant site in acres
NEGC = plant net electrical generating capacity in megawatts

B-66

Site Parameters

The site for a coal-fired power plant should be relatively flat, with a good load-
bearing capacity soil and a low ground water contamination potential. Cooling water
must be available near the site. The site must also be near rail or barge transportation,
or both, for fuel delivery. A coal slurry pipeline is another possible fuel delivery option.
The plant should also be sited within a reasonable distance of an existing electric

transmission line.

Capital Costs

The total capital cost of a coal-fired power plan t beginning commercial operation
in 1982 can be estimated using the following equation:

Capital Cost= (NEGC ` 3538)(NEGCK)

Where:
NEGC = net electrical generating capacity in megawatts (10 6watts)
NEGCK = n et electrical generating capacity in kilowatts (103watts)

The equation yields the following result for a 500 megawatt coal-fired power plant
beginning commercial operation in late 1982.

Capital Cost = ($8451 103 watts)(500 `3538 x 106watts)(500,000 x 103 watts)
= ($8451 103 wattsX. 11094 x 10-6 watts)(500,000 x 103 watts)
= $468,607,950

The total "as spent" cost of a power plant with a 1990 start-up date would consist
of the sum of the current dollar costs incurred for each year throughout the construction
period (i.e., 1985 current dollar outlays plus 1986 current outlays, etc). "Current,"
dollars are defined as the amount of a revenue or expenditure expressed in the nominal
dollar amount prevailing at the time the revenue or expenditure was incurred. A

S
pecified amount of concrete may cost $100,000 in 1985 and the amount may cost
$110,000 in 1986. The total "as spent" cost for concrete during 1985 and 1986 would be
$210,000.

B-67

Capital Cost = $15,072 (NEGC -,3538 ) NEGCK

Sources:
Oak Ridge National Laboratory and United Engineers and Constructors, Inc., 1980, Power
Plant Capital Investment Costs Estimates: Current Trends and Sensitivity to Economic
Parameters; Budwani, Ramesh, May 1980, "Power Plant Capital Costs Analysis", Power
Engineering

Employment Profile

Table I shows the annual average manpower requirements for a 500 megawatt
coal-fired power plant and a 1,000 megawatt facility consisting of twin 500 megawatt
units during construction. The figures represent full time, annual workers.

Manual workers include laborers, equipment operators, and skilled trades (i.e.,
boilermakers, pipefitters, electricians, etc.). Non-manual workers include administrative
and managerial workers, secretaries, and engineers.

Sources:
Bechtel Power Corporation, 1982; Budwani, 1982; Burns and Roe, 1978; Electric Power
Research Institute,* 1982.

The following table shows the operational work force for both of the power plant
configurations noted previously.

One 500 Megawatt Unit Two 500 Megawatt Units

Non-manual 12 17

Manual 90 123

Total 102 140

Sources:
Burns and Roe, 1978;. Delmarva Power & Light, 1982.

B-68

Environmental Impacts

Air Waste Disposal

During construction of a coal-fired power plant, combustion emissions from heavy
machinery operating on the site include nitrogen oxide and carbon monoxide. Dust is
also generated by heavy machinery moving topsoil. Yearly vehicle emission testing by
the State of New Jersey will keep emissions to a minimum.

Emissions from an operating coal-fired power plant will include sulphur oxides,
formed as a result of the combustion of the sulfur in coal, and particulates, consisting of
silicates, metal salts, and sodium chloride. Also emitted in lesser amounts from coal-
fired power plants are nitrogen oxides, hydrocarbons, carbon monoxide, and metallic
compounds.

Air quality impacts are influenced by composition of coal M ash and % sulphur by
weight), efficiency of the emission control equipment, and local climatic conditions. The
perceived impacts of air waste disposal on tourism and recreation will be negligible with
proper environmental controls and compliance with ambient air quality standards.

Water Use/Water Discharge

During construction, sites cleared of vegetation result in exposed topsoil, which
decreases the infiltration capacity of the soil. In turn, erosion will increase, producing
increased turbidity and siltation in receiving waters.

Operation of a coal-fired power plant involves the use of cooling and process
water. The quantity of water used daily creates two problems. Quantity demand may
exceed supply during seasonal, low flow periods; and the quantity of water affects
biological resources near and around intake pipes and screens, and discharge pipes and

structures.

Cooling water discharges can have a thermal impact on receiving waters by raising
their temperature and lowering the dissolved oxygen levels. If corrosion-prevention

B-69

chemicals have been added to the cooling water, the chemicals may affect surface water
quality when they are discharged with the cooling water . Surface water may also be
adversely affected by the acidic quality of coal-pile runoff. The results of increases in
water temperature and declines in water quality include adverse impacts on aquatic
ecosystems (i.e., declines in species diversity and productivity of habitats), and decreases
in the potability of water.

The impact to drinking water sources and/or aquatic resources as a result of water
use and discharge could also impact tourism and recreational activities in the vicinity of
the plant. A reduction in the number or type of fish species, or a decline in the
productivity of habitats near the site would adversely affect recreational fishing and
perhaps boating. Algal growth sometimes associated with a thermal discharge may also
cause an aesthetic impact and reduce the use of an area for swimming or recreation
boating.

Solid Waste

Operation of a coal-fired power plant results in the production of a considerable
amount of solid waste, primarily fly and bottom ash, and scrubber sludge. On-site
disposal of these wastes is increasingly becoming the preferred alternative. Large piles
of ash and sludge, commonly thirty to forty feet high, would constitute a visual intrusion
that is out of character with natural settings of recreational areas. Similarly, the large
amounts of land required for disposal would diminish the amount of available land
available for recreational uses.

Noise

Ambient sound levels in a non-industrial area can be expected to increase with the
construction of a coal-fired power plant. Heavy machinery involved in construction
would be the source of increased sound levels.

During operation, ambient sound levels will increase as a result of the operation of
coal trains, coal unloading and transfer equipment, and mechanical draft cooling towers.

B-70

Because of the non-industrial character of shoref ront recreational areas, an
increase in ambient sound levels would be a significant impact. Although higher sound
levels may not directly decrease the usability of some areas, the subjective perception of
a locale's recreational suitability may diminish because it is perceived to be "noisier."
The attractiveness of other areas prized for their natural, rural settings as places of
relaxation would definitely decline due to an increase in ambient sound levels.

Aesthetic Impact

Although landscaped buffer zones can conceal parts of an energy facility, a coal-
fired power plant has three tall and noticeable structures--a stack, a cooling tower, and
a coal pile. In the relatively flat, recreational study area these three structures would
be visible from a considerable distance. They would be visual intrusions into formerly
natural viewsheds.

If the visual and aesthetic impact detracted significantly from the existing
aesthetic quality of an area, recreation and tourism activities could diminish as a result
of perceptions by users that the suitability or "attractiveness" an area had declined.

Ref erences

Budwani, Ramesh N., August 1982. "Power Plant Scheduling Construction and Costs: 10
Year Analysis," Power Engineering.

------ May 1980. "Power Plant Capital Cost Analysis," Power Engineering.

Burns and Roe, Inc., January 1980. Considerations in Electric Power Plant Siting Coal
Fired Power Plants 50 to 2400 Megawatts. Prepared for the Power Plant Siting Program,
Minnesota Environmental Quality Control Board, Oradell, New Jersey.

Delmarva Power & Light Company, Wilmington, Delaware. Written communication,
June 1982.

Electric Power Research Institute, February 1982. Socioeconomic Impacts of Power
Plants, EPRI EA-2228, Palo Alto, California.

B-71

Friedlander, Gordon, October 1981. "Coal or Nuclear? Economics Govern," Electrical
World.

Nobile, P.A., and Kettler, D.J., March 1981. "Selecting An Optimum-Size Coal-fired
Unit," Electrical World.

Oak Ridge National Laboratories, and United Engineers and Constructors, Inc., 1980.
Power Plant Capital Investment Cost Estimates: Current Trends and Sensitivity to
Economic Parameters. Prepared for the U.S. Department of Energy, Washington, D.C.

United Engineers and Constructors, Inc., 1977. Commercial Electric Power Cost Studies,
Vols. 1-8. Prepared for the U.S. Nuclear Regulatory Commission, NUREG-0247.

United States Department of Energy, Office of Environmental Assessments, 1979.
Technology Characterizations: Environmental Information Handbook, Washington, D.C.,
DOE/EV-0072.

B-72

COGENERATION

Facility Description

Cogeneration is broadly defined as a system in which mechanical or electrical
energy, and thermal energy are simultaneously produced at one location. The advantage
of cogeneration is to utilize what was formerly wasted energy (i.e., hot exhaust gases or
hot cooling water) to produce another form of energy. For example, hot exhaust gases
can be used.to heat steam that in turn is passed through a turbine generator to produce
electricity, or hot cooling water can be used for space heating. Given amounts of
electricity and thermal energy can be produced for lower fuel inputs than would be
required if the same amount of energy were produced in two separate facilities.

Cogeneration configurations in which electricity is first produced, and then the
steam or hot cooling water is used for process @ or space heating, are known as topping
cycles. Conversely, a configuration in which thermal energy is first produced (i.e.,
exhaust gases from an industrial boiler), then used to produce steam that is sent through
a turbine generator, is known as a bottoming cycle. Due to the v ariety of cogeneration
configuration, there is no typical application or type of facility. The development of a
specific cogeneration application depends upon the energy needs of the primary producer
and the needs of the consumer of the cogenerated energy, particularly if the consumer is
different than the primary producer. The range of cogeneration applications include the
following examples:

0 A utility sending hot cooling water from an electric generating plant to a
district heating system

0 An industrial plant using hot exhaust gases from a smelter to produce steam,
then electricity

0 A municipal resource and energy recovery facility in which steam is passed
through a turbine generator, producing electricity that is sold to the local
utility prior to the steam being used in a district heating system

B-73

Facility Size/Land Requirements

The size of different cogeneration configurations, in terms of their cogenerated
energy outputs, varies widely. The range of the electrical outputs varies from as low as
.5-10 megawatts for steam bottoming cycles, up to 5-100 megawatts for steam topping
cycles (Detroit Edison, 1980). The thermal output of cogeneration systems ranges from
less than 100,000 lbs/hr. of steam to approximately 800,000 lbs./hr. In addition, thermal
energy outputs can range from steam at temperatures of up to 1,OOOOF and pressures of
up to 900 pounds per square inch (psi), down to hot water at temperatures of up to 250OF
and pressures of up to 200 psi (Detroit Edison, 1980).

Land requirements may range from virtually nothing for a steam bottoming
configuration at an existing industrial boiler to site acreages associated with electric-
generating facilities and resource and energy recovery facilities which incorporate
cogeneration into their designs. Site acreages for these two facilities are given in their
f acility descriptions.

Site Parameters

Sites for cogeneration facilities should have similar parameters as sites for
elect ric-generating facilities, and resource and energy recovery facilities. Thus, the
sites should be flat, with good load-bearing soil, low groundwater contamination
potential, and low seasonal water table levels. Sites should be located near surface
water bodies in order to obtain cooling water, as well as being located near railroads or
large unloading sites for fuel delivery.

In addition, cogeneration facilities have to be located near the consumers of the
cogenerated energy. Steam is capable of being sent up to five miles through insulated
pipes, while hot water can be sent up to 70 miles (Detroit Edison, 1980). Finally,
resource and energy recovery facilities cogenerating electricity must be located near the
centers of solid waste generation so as to minimize transportation costs.

B-74

Capital Costs

Installed capital costs for various cogeneration cycle configurations range from
$550-$830/kW of electrical output for bottoming cycles to $685-830/kW for topping
cycles (Power Engineering, 1978). As an example, the installed capital cost of new
steam topping cogeneration equipment at the American Cyanamid plant in Bound Brook,
New Jersey is estimated at approximately $780/kW of generating capacity (Argonne
National Laboratory, 1980). The capital costs for electric-generating facilities and
resource and energy recovery facilities that incorporate cogeneration into their designs
would be slightly higher than the capital costs given for these two facilities in their
respective descriptions.

The most likely application of cogeneration within the study area is a resource and
energy recovery facility that burns municipal solid waste (MSW) in a mass burning unit.
This facility produces steam for use in an adjacent district heating system; the steam is
first sent through a turbine to cogenerate electricity prior to being extracted from the
turbine and sent on to the district heating system. A facility processing 1,800 tons per
day of MSW that would produce 370,000 lbs./hr. of steam and generate 30 megawatts of
electricity is estimated to have a capital cost of $119,130,'000, while a facility
processing 3,000 tons per day that would produce 610,000 lbs./hr. of steam and generate
5 megawatts of electricity would cost $176,330,000 (Gilbert Commonwealth, 1981).

Sources:
Argonne National Laboratory, March 1980; Det rolt Edison, September 1980; Power
Engineering, March 1978.

Employment Profile

The labor force required for constructing cogeneration facilities differs widely due
to variations in designs and variations in the composition of energy outputs from
cogeneration configuration. Electric-generating plants and resource and energy recovery
facilities incorporating cogeneration into their designs would have construction labor
requirements similar to those presented for the two facilities in their respective
descriptions.

B-75

Following are construction employment figures for a resource and energy recovery
facility that consumes 2,000 tons/day of MSW in cogenerating electricity (from steam)
that is eventually sent on to a district heating system.

Year I Year 2 Year 3

Manual 84 350 190
Non-manual 16 50 -30
Total 100 400 220

This facility would have a peak employment figure of between 500 and 750 workers
occurring during the second year.

The operating labor force for the above facility would consist of approximately 65
manual and 15 non-manual employees spread over two shifts per day, six days a week.

Source:
Mitre Corporation, March 1981, Draft Report: Environmental Impact Statement for a

I
Resource Recovery Facility in Detroit.

Environmental Impact

Air Waste Disposal

During construction, emissions will be generated by the mechanized equipment and
vehicles used on-site. These emissions would consist of nitrogen oxide, carbon monoxide,
and sulphur dioxide. As with other facilities, New Jersey's yearly vehicle emission
testing should keep these emissions at a minimum so that the impacts on recreational
and tourist activities would be negligible.

During operation, the air type and quantity of air emissions will be largely
determined by the type of fuel used in producing the primary form of energy. Resou rce
and energy recovery facilities that burn municipal solid waste in waterwall incinerators
would produce hydrocarbons, hydrochloric and hydroflouric acid, and particulate emis-
sions. Conversely, industrial facilities burning coal in boilers where the hot exhaust

B-76

gases are used in a steam bottoming application would produce the emissions normally
associated with the combustion of coal.

The impact of air waste disposal from cogeneration applications will vary accord-
ing to the type and size of the energy facility in which the cogeneration occurs. Coal-
fired power plants that cogenerate steam for district heating applications would have air
waste disposal impacts virtually identical to those for coal-fired power plants that do not
cogenerate. Similarly, in industrial applications where the heat from exhaust gases is
used to produce steam in a bottoming cycle, there would be no change in the level of air
pollutant emissions. In summation, the impact of air waste disposal from cogeneration
facilities will correspond with those already described in other sections for the facility
that produces the primary form of energy.

Water Use/Water Discharge

Site preparation operations resulting in the clearance of vegetation and the top
layer of soil increase the potential for erosion and resulting sedimentation in nearby
surface waters. However, if soil erosion and control laws are followed during
construction, the temporary impacts on surface water bodies should be minimal.

Substantial quantities of water are required for cogeneration facilities where
steam is either used in the production of electricity, or circulated through a district
heating system. However, in some instances, the cogeneration of steam for use in
district heating systems may actually lessen overall water requirements for a facility by
eliminating the need for a condenser or a cooling tower to remove the rejected heat.
The volumes of water required will also be largely determined by the type of facility and
the type and quantity of primary energy being produced.

The impacts of water use or water discharge from cogeneration facilities on
tourism and recreation, as with air emission impacts, will largely parallel those already
described elsewhere for the energy facility producing the primary energy output.

B-77

Solid Waste

Cogeneration facilities will produce process or combustion residues from the
production of the primary energy output. Thus, a resource and energy recovery facility
where MSW is burned, and steam is used to cogenerate electricity, would produce process
and ash residuals from the combustion of the MSW. The application of cogeneration
equipment to an existing primary energy production facility would not generally result in
the production of additional amounts of solid waste beyond that already being produced.
For example, using steam bottoming cycles to generate electricity in industrial boilers
producing hot exhaust gases, the initiation of cogeneration would not result in the
additional generation of any solid wastes.

As with the other environmental effects already noted, solid waste production and
disposal impacts on tourism and recreational activities associated with a cogeneration
facility will be similar to those described elsewhere for the energy facility type
producing the primary energy output. Thus, landfilling would be required for the process
and combustion residuals produced by a resource and energy recovery facility cogenerat-
ing' electricity. The result would be the potential to adversely affect groundwater
quality through the seepage of leachate from the landfill. The retrofitting of existing
industrial boilers to cogenerate energy would result in negligible impacts on tourism, as
these facilities are not located in or adjacent to desirable coastal recreation areas.

Noise

The construction of a cogeneration facility would generate significant noise levels
from the mechanized equipment use on-site. Sources of sound generatiorl include heavy
equipment such as bulldozers, pile drivers, and scrapers. The increase in ambient sound
levels from this equipment would be a short term impact, confined to the construction
period.

During operation, the size of any increase in ambient sound levels would be a
function of the size and type of the energy facility being used to produce the primary
energy output. These two factors determine the type of noise-generating equipment that
would be present on-site. For example, coal-fired power plants sending steam to a

B-78

central heating system would include the full complement of equipment such as coal
crushers, conveyors and rail car unloaders needed to handle the coal on-site. In
addition, resource an'd energy recovery "facilities that cogenerate energy would result in
increases in ambient sound levels in adjacent areas due to the movement of trucks to and

from the site.

Without proper mitigating measures, the presence of a cogeneration facility in a
recreational area would likely result in an increase in the ambient sound level and a
corresponding decrease in the perceived recreational quality of an area.

Aesthetic Impact

Some cogeneration applications would include large structures that would be
clearly visible in the coastal areas comprising the study area. Resource and energy
recovery facilities would contain a stack up to 300 feet and a main building housing the
incinerator and the turbine generator up to 150 feet. Similarly, a coal-fired power plant
with cogeneration would contain the highly visible structures already noted previously in
the description for that fa cility. In most instances, the siting of a cogeneration facility
in a recreation area prized for its scenic view would constitute a visual intrusion into the
landscape that would decrease tourists' perceptions of the recreational suitability of the

area.

Odor

Resource and energy recovery facilities would be the cogeneration application with
the most significant odor impacts. The storage of MSW prior to combustion can release
unpleasant odors to -the surrounding arreas if the waste is not properly stored in a closed,
sealed enclosure. The presence of such a facility adjacent to a recreational area would
certainly result in a decrease in tourists' perceptions of the suitability of the area if
odors periodically escaped from the facility.

B-79

Ref erences

Argonne National Laboratory, Energy and Environmental Systems Division, Industrial
Cogeneration Case Study #2: American Cyanamid Chemical Company. Prepared for the
United States Department of Energy, ANL/CNSV-TM-37, Bound Brook, New Jersey.

Case Study #3, April 1980. Industrial Cogeneration Case Study #3: Mead
C--or-p*oration Paper Mill. Prepared for the United States Department of Energy,
ANL/CNSV-TM-37, Kingsport, Tennessee.

Bauer, F.W. and Melick, G.F., 1981. The Reference Plant Concept of Cogeneration.
Available from Stone and Webster Engineering Corporation, Cherry Hill, New Jersey.

Detroit Edison, September 1980. The Future Potential of Cogeneration in the Detroit
Edison Service Area, Detroit.

Mitre Corporation, March 1981. Environmental Impact Statement for A Resource
Recovery Facility in the City of Detroit. Prepared for Combustion Engineering, Inc.

Power Engineering, March 1978. Cogeneration.

Public Service Electric &- Gas, January 1977. Cogeneration Evaluation, Newark, N.J.

Stone and Webster, Inc., 1981. Central Heating System Study. Prepared for the Detroit
Edison Company, Cherry Hill, New Jersey.

B-80

RESOURCE AND ENERGY RECOVERY FACILITY

Facility Description

A resource and energy recovery facility is any facility that processes and combusts
solid waste and utilizes the thermal energy from combustion for the production of other
energy, namely steam and electricity. The technologies used include pyrolysis and the
combustion of refuse-derived fuel (RDF) or municipal solid waste WSW).

Pyrolysis is the thermal decomposition of materials in the abse 'nce or near-absence
of oxygen. The products of pyrolysis are a gas, a liquid, and a char, all of which can be
used for energy production. Pyrolysis is as yet an unproven technology, although it
offers promise for the future.

Incineration with heat recovery can be accomplished either by waterwall incinera-
tion or by modular incineration, both of'which have been used successfully for solid
waste disposal. Both processes have the advantage of producing useful energy and using
proven technology. The steam generated by these facilities can be used as industrial
process steam for heating or for driving electric generators. The facilities may also
incorporate the cogeneration of energy, where steam used for district heating or process
purposes is first sent through a turbine generator to produce electricity. Two types of
fuel are used for incineration, municipal solid waste (MSW) and refuse-derived fuel
(R DF).

RDF is produced by processing municipal solid waste (through shredding, magnetic
separation, air classification, or other separation techniques) to remove noncombustible
materials. The shredded product may be combusted or further processed to form pellets
or briquettes.

If a suitable market for the energy produced by a resource and energy recovery
facility is not located within economical distance, the RDF produced may be used at
other locations to produce steam in a dedicated boiler. The metal and glass by-products
can be sold as an additional source of revenue. A number of operational problems
associated with mass burning of solid waste can be eliminated by separating out the
metal and glass by-products and other non-com bustibles prior to combustion.

B-81

Facility Size/Land Requirements

Resource and energy recovery facilities have processing and incineration capacities
of between 500 and 3,500 tons per day. Most currently operating or proposed facilities
range between 1,000 and 2,000 tons per day. Resource and energy recovery facilities
may produce up to 40 megawatts of electricity or one million lbs/hr. of steam. However,
energy production amounts of 10-15 megawatts or 600,000 pounds per hour of steam are

more common.

Resource and energy recovery facilities require 7 to 25 acres of land per facility.
The size of the site depends on the capacity and design of the facility and on whether or
not the fuel preparation and firing operations are in one location.

Site Parameters

Following are considerations for the establishment of site parameters for a
resource and energy recovery facility:

0 flood protection-
0 relatively flat land
0 proximity to highway, railroad and/or barge transportation
0 access to electric transmission lines

In addition, resource recovery facilities have locational requirements that affect siting
and, in the long run, affect operating and transportation costs. Locational requirements
include the following considerations:

0 proximity to sources of waste generation which reflect transportation costs
for hauling municipal solid waste,
0 waste composition which influences the amount and type of recoverable
material, energy content, types of pollutants, and amount of ash,
0 proximity to markets for recoverable materials (iron, steel, glass, and alumi-
num), and
0 proximity to a sewage treatment plant for those resource recovery facilities
(RRFs) designed to burn sewage sludge.

13-82

Capital Costs

Capital Cost = 50,400 (TL) + 28,500,000

Where:
TL = daily combustion capacity in tons.

This is for a resource and energy recovery facility that processes MSW to produce
RDF, which is then burned in a waterwall incinerator. The steam produced is sent
through a turbine generator to cogenerate electricity prior to being sent off-site for
heating or process uses. This cost includes a mechanical draf t cooling tower and the
necessary air pollution control equipment.

Sources:
Electric Light & Power Magazine, July 1981, Ocean County Solid Waste Management
Plan; Union County Solid Waste Management Plan.

Employment Profile

Profiles are for a facility designed to handle 2,000 tons per day of municipal solid

waste with a waterwall incinerator.

Construction: Year I Year 2 Year 3

Manual 84 350 190

Non-manual 16 50 30

Total 100 400 220

Peak employment occurs during the second year and averages between 500 and 750.

Operation:

Manual 63

Non-manual 11

Total 74

Plant is staffed for two shifts per day, five days a week.

B-83

Source:
Mitre Corporation, March 19811 Draft: Env ironmental Impact Statement for a Resource
Recovery Facility in the City of Detroit.

Environmental Impact

Air Waste Disposal

During construction of a resource recovery facility, combustion emissions from
heavy machinery at the site will include nitrogen oxide, carbon monoxide and sulphur
dioxide. New Jersey's yearly vehicle emission testing should keep the pollutants at a
minimum.

During operation, emissions will be generated by the facility itself and by the
trucks or barges transporting the solid was te. Hydrocarbons, hydrochloric and hydro-
flouric acid, and particulates will be emitted during the operation of the facility.
Emission levels will depend upon the process used to burn MSW or RFD and upon the type
of air pollution control equipment used. Air emissions associated with the transfer of
solid waste will include nitrogen oxide, carbon monoxide, and sulphur dioxide. Siting
parameters and capital costs encourage a central location for hauling trucks to minimize
travel time and costs, thereby minimizing vehicle-related air pollution effects. In
addition to a central location, New Jersey's emission testing program will aid in limiting
exhaust emissions.

The impact of air waste disposal from a resource and energy recovery facility on
tourism and recreation is expected to be minimal. Strict New Jersey laws concerning air
pollution will keep air quality degradation to a minimum.

Water Use/Water Discharge

During construction, the site is cleared of vegetation and, as a result, the exposed
topsoil alters the water retention property of the soil. Erosion and siltation will increase
and produce greater turbidity and possible plant growth in nearby surface waters.

B-84

Large quantities of water are requi .red for the operation of a resource and energy
recovery facility, resulting in the generation of significant amounts of wastewater.
Major water requirements include cooling tower makeup (where applicable), steam or hot
water production, and boiler makeup. Major sources of wastewater are boiler blowdown,
cooling tower blowdown, and ash-handling equipment. Wastewater would probably be
pretreated before discharge to a municipal sewer system.

Impacts of water discharges from an RRF on tourism and recreation are antici-
pated to be minimal. The amount of water used by a resource recovery facility is not
likely to low'er water supplies.

Solid Waste

Process residue (i.e., waste not included as either RDF or separated out because of
its commercial value) and ash residue comprise the majority of solid waste from a
resource recovery facility. The non-com bustibles and ash must be disposed of in a secure
landfill, usually located near the facility.

The solid waste generated by an RRF will have minimal i mpact on tourism and
recreation. However, solid waste disposal by landfilling does have the potential to
adversely affect groundwater by leaching, and could impact the number of recreation
participants drawn to an area.

Noise

During construction of a resource recovery facility, pile drivers and heavy
machinery may generate considerable noise and increase ambient sound levels. This
effect would be especially noticeable in a non-industrial area.

Noise from an o perating facility will be generated by the acceleration of trucks
(delivering MSW) and by several pieces of machinery including:

0 shredders,

0 conveyors,
0 magnetic separators,

B-85

0 turbine generators, and
0 crushers.

Impacts to tourists and recreation participants would be lessened with the
incorporation of buffer zones and effective landscaping. However, without these efforts,
the perceived quality of an area'could decrease and would be expected to adversely
affect the number of participants.

Aesthetic Impact

Resource and energy recovery facilities have several large structures that would be
easily visible from locations within the relatively flat coastal plain, which constitutes
the study area. The building housing the main combustion equipment and turbine
generator may be as high as 150 feet, while the stack for some larger facilities may be
300 f eet high. Thus, the siting of a large (3,000 ton per day) resource and energy
recovery facility in a coastal setting prized for its scenic view would constitute a visual

intrusion that detracts from the natural ambience and recreational nature of such
locations. The introduction of a visual element clearly out of character with its setting
could decrease tourists' perceptions of the suitability of an area as a location for the
enjoyment of recreational facilities.

Odor

Accumulated municipal solid waste may create an odor problem prior to burning.
This is generally controlled by storing MSW in closed, covered areas with negative draft
ventilation (drawing air into the structure) to prevent odor from escaping. In addition,
continuous burning at resource recovery facilities ensures that MSW is not stored for any
length of time and that combustion is complete.

With proper operation, odors from resource recovery facilities will have minimal
impacts on recreation and tourism in the vicinity. Any malfunction in odor control
operations would lower the quality and aesthetics of the area, and could conceivably
detract from the tourism industry.

B-86

Other-Traf fic

If the primary method of transporting municipal solid waste is by truck, traffic
near the resource recovery area could become congested during peak commuting periods.
Siting parameters influence the degree of traffic congestion in and around the site. In
most cases, highways and major travel routes will not be affected. Traffic problems will
be more evident closer to the facility site. Main routes used by tourists heading to the
shore at peak periods (i.e., Friday afternoons) could be temporarily congested due to
conflicts with trucks hauling waste to the site.

References

Albrecht, Oscar, August 1981. "What Happened to the Gold in Garbage," American City
and County Magazine.

American Iron and Steel Institute, 1981. Summary Report of Solid Waste Processing
Facilities, Washington, D.C.

Congress of the United States, Office of Technology Assessment, 1979. Materials and
Energy from Municipal Solid Waste, Washington, D.C.

Cunningham, J.A.; Hazzard, N.D.; and Smith, M.L., February 1981. Economic and
Reliable Disposal of Solid Waste by Combustion Engineering. Combustion Engineering,
Inc.: Windsor, Connecticut.

Electric Power & Light , July 1981. "Success Elusive in Garbage Power," Vol. 59, No. 5,
Barrington, Illinois.

Electric Power Research Institute, May 1982. Technology Assessment: Municipal Solid
Waste as a Utility Fuel, EPRI CS-2409, Palo Alto, California. Prepared by Ebasco
Services, New York, New York.

M. Disko Associates, June 1979. Ocean County Solid Waste Disposal and Resource
Recovery Management Study; Proposed -Solid Waste Disposal Plan. Prepared for the
Ocean County Board of Chosen Freeholders, Toms-River, New Jersey.

B-87

Union County District Solid Waste Management Plan. Prepared for the Union
County Board of Chosen Freeholders, Toms River, New Jersey.

Mitre Corporation, March 1981. Environmental Impact State ment for a Resource
Recovery Facility in the City of Detroit. Prepared for Combustion Engineering, Inc.,
Windsor, Connecticut.

Stone and Webster, Inc., 1981. Central Heating System Study. Prepared for the Detroit
Edison Company, Cherry Hill, New Jersey.

B-88

ELECTRIC TRANSMISSION LINES

Facility Description

High-voltage electric transmission lines (69 kV and greater) must be installed for
bulk transfers of electric power from the power-generating source to the existing
electrical transmission system. Transformers at the generating site step up the voltage
of the plant-generated electricity to the main transmission voltage.

Economic, technical, and environmental factors determine the size and type of
transmission line selected. The line voltage and circuitry needed, length of transmission
line, costs, land use, aesthetics, and compatibility with the existing system are factors

that affect this decision.

The structural design of electric transmission lines varies greatly. Design variables
include structural type and materials, insulation configuration, and number of circuits.
Transmission towers may be single-pole wood, single-pole steel, single-pole concrete,
wood-pole H-frame, concrete H-frame, or lattice steel. Insulators are configured in
horizontal vees, vertical vees, or single string suspension. Single' or double circuits can
be used. The rationale for using two full-capacity circuits is partly based on having a
backup; if there should be a power outage on one circuit, the line could continue to
transmit electricity at full output on the other.

Facility Size/Land Requirem ents

Transmission capacities for electrical lines range from 69 to 765 kV. ROW widths
vary from 90 to 280 feet, accordingly. Generally for most tower types, between five and
seven towers per mile are required.

Approximately 9 to 42 acres are required per mile of electric transmission line.
Land requirements vary with the capacity of the line and the capacity affects ROW
width requirements.

B-89

Site Parameters

Electric transmission lines are generally routed so as to minimize the disturbance
to environmentally sensitive areas, minimize adverse aesthetic impacts (i.e. clear cuts
through forests), and minimize cost (i.e., shortest route, lowest ROW clearance and
installation costs). In some cases, avoidance (if sensitive areas must be balanced with
costs where such avoidance would require unusually long corridors. Transmission line
corridors passing through regions of high relief, areas having a substantial number of
special crossings (i.e., over major highways, rivers, etc.), or heavily wooded or densely
populated areas, would result in higher capital costs. Suitable locations for individual
towers consist of level areas with soils of sufficient bearing capacity to accommodate
the towers, and locations that would be easily accessible for bringing construction
materials and power equipment to the site.

Capital Costs

Capital Costs for transmission lines installed above the ground are represented as
f ollows:

169 kV CC = $162,000 D
230 kV CC = $285,600 D
345 kV s.c. CC = $540,000 D
345 kV d.c. CC = $1,080,000 D
500 kV s.c. CC = $756,000 D
500 kV d.c. CC = $1,566,000 D

Capital Costs for transmission lines greater than 230 KV installed below ground are
calculated as follows:

Capital Cost = $1,836,000 D

Where:

D = distance in miles
s.c. single circuit
d.c. double circuit

B-90

These costs assume level topography and minimal special construction costs such as river
crossings. In addition, average soil conditions are assumed, which imply concrete mat
supports without piles. The cost for underground transmission lines assumes rural/subur-
ban conditions with no pavement-breaking and subsequent recovering. All costs may
vary depending on topography, type of ground cover, land use, etc.

Sources:
Burns and Roe, 1980; Electrical World, March 1981; Public Service Electric & Gas, 1981;
Rogers and Golden, 1979.

Employment ProfUe

Construction of an electric transmission line is usually performed in sections along
the proposed route, rather than all at once over the entire length of the line.
Construction involves two phases--surveying and clearing and tower and line construc-
tion.

Individual work crews required during surveying and site clearing range from two to
ten workers, with up to ten workers needed in heavily forested areas. A total of up to 40
workers, dispersed among four, five, or more work crews, are generally working on
separate locations clearing the ROW along segments of up to 40 miles in length. During
construction, up to 60 workers would be dispersed among several work crews over a
similarly-sized segment of the transmission line.

Preconstruction crews are expected to move at the rate of ten miles per month.
Crews constructing a 138 kV transmission line with single wood towers are anticipated to
work at the rate of -10 miles per month. Construction of a 345 kV transmission line with
steel towers will take more time, with crews expected to work at a pace of five miles
per month. (USDOE, March 1978). Generally, construction work crews can construct
between five and ten miles of transmission line per month.

Apart from occasional inspection of lines and maintenance of the right-of -way, no
operating personnel are required.

B-91

Environmental Impact

Aesthetic Impact

The towers carrying transmission lines vary in size and type. The structures
include single wooden poles carrying three wires, and steel lattice structures of up to 150
feet in height carrying up to six conductor cables. The structures may obstruct views for
private homeowners in residential areas and may seriously affect the visual quality of
natural settings on public lands. The imposition of cleared ROWs in heavily forested
areas can constitute a particularly severe aesthetic impact. Selective clearing and
vegetative screening can mitigate visual impacts to natural areas, but it is not possible
to hide transmission towers entirely.

Impacts on recreation and tourism depend on existing visual quality of the area,
topography, and extent of mitigating efforts.

Other-Electrical Effect

Audible noise, communications interference, and ozone production are all caused
by "corona" discharges from transmission lines. A corona is an electrical discharge
produced when the electric field intensity at a conductor surface exceeds the electric
breakdown potential of the surrounding air. The released electrons collide with air
molecules to cause the disturbances (Roig, 1979).

Noise due to corona discharges consists of a sizzling sound in wet weather and a
barely audible sound in dry weather. Radio interference from corona discharges is
evident especially in rainy weather for AM reception near the power line. Interference
is usually negligible for FM radio and T.V. reception. Corona discharges from high-
voltage power transmission lines produce ozone, similar to the production of ozone
during lightening discharges. Because of very small amounts of ozone emitted, it is
reasonable to conclude that emission of ozone from transmission lines would not
seriously affect air quality.

Because electrical effects are so slight, they are not expected to affect tourism
and recreation participants.

B-92

References

Atlantic Electric, May 1980. Coal-Fired Power Plant Site Selection Study. Prepared by
Dames and Moore, Cranford, New Jersey.

Burns and Roe, Inc., January 1980. Considerations in Electric Power Plant Siting: Coal-
Fired Power Plants from 50 to 2400 Megawatts. Prepared for the Power Plant Siting
Program, Minnesota Environmental Quality Board, Oradell, New Jersey.

Electric World, March 1981.

New Jersey Department of Environmental Protection, September 1981. New Jersey
Energy Facility Development Potential Study. Prepared by Rogers, Golden & Halpern,
Philadelphia, Pennsylvania.

------ 1979. Coastal Development Potential Study. Prepared by Rogers, Golden
Halpern, Philadelphia, Pennsylvania.

Public Service Electric & Gas, Newark, New Jersey. Written communication, 198 1.

Roig, Dr. Randy, 1979. Record of the Maryland Power Plant Siting Act, "The Effects of
Transmission Lines," Power Plant Siting Program, Maryland Department of Natural
Resources.

U.S. Department of Energy, March 1978. Environmental Impact Statement: Dickey-
Lincoln School Lakes Transmission Project, Bangor, Maine.

B-93

COAL-HANDLING TERMINAL

Facility Description

Coal-handling facilities are involved in the transshipment of coal between water
and land modes of transportation. They operate as centers for the export of U.S. coal,
and, to a lesser degree, as distribution points for regional utilities and industries. These
facilities contain materials handling equipment to move the coal from one transport
mode to another, and often have on-site storage capacity.

Coal-handling operations differ in size and on-site facilities, depending on the
specific materials-handling system and site of the facility. There are three fundamental
approaches to loading coal onto an outgoing collier:

0 reclamation of coal entirely from stock,
0 loading directly from railcars and/or barges, and
0 loading directly from railcars and/or barges as well as reclamation from stock.

Facility Size/Land Requirements

Coal-handling terminals measure capacity or throughput in torls handled per year.
In determining land requirements, six acres are required for every million tons per year.
Most recently announced plans involve facilities in the range of 10-15 million tons per
year, although two million tons per year is a feasible lower limit.

Site Parameters

Siting parameters for a coal-handling terminal include consideration of the
following factors:

0 flood protection,
0 proper topography (relatively flat land with good weight-bearing, capacity
soils),
0 access to railroads,
0 access to an all-weather'harbor and adequate wharf or pier,

B-94

0 suitable amounts of land, and
0 groundwater contamination protection

The volumes associated with specific siting parameters (harbor and.acreage) will depend
on throughput capacity and draft requirements of ships.

Capital Costs

The equation to determine the approximate cost of constructing a coal-handling
terminal is listed as follows:.

Capital Cost = ($12,000,000)T

Where:
T = the throughput capacity of the terminal in 10 6 tons per year.

This equation assumes foundation costs are included. The foundation design
consists of a. concrete mat foundation on selected backfill for the onshore loading/un-
loading equipment. It alsd includes dredging, and wharf or pier costs. In some locations,
expenditures for a large volume of dredging, or high capital costs for a long trestle
linking an offshore loading/unloading facility to the mainland, could significantly
increase capital costs.

Source:
Alabama State Docks, 1981; Alla-Ohio Coal Co., 1981; Dravo Corp 1981; Port Authority
of New York and New Jersey, 1981; Soros Associates, 1981.

Employment Profile

Following are employment profiles for a coal terminal in Virginia, with a 12 million
ton per year capacity:

B-95

Construction: Year I Year 2

Manual 365 365
Non-manual -37 37
Total 402 402

Manual workers include carpenters, electricians, iron workers, laborers, operating
engineers, pipe filters, welders, and pile drivers. Non-manual workers include secretarial
and administrative persons, engineers, and project managers. Construction is assumed to
be over a 24-month period with the numbers reflecting peak employment at the
beginning of the second year.

Operation

Manual 92

Non-manual 4

Total 96

Manual labor will include coal handlers, coal samplers, electricians, quality c ontrol
inspectors, and maintenance people.

Sources:

A.T. Massey Coal Co.,.Inc.,. 1982; Soros Associates, 1981.

Environmental Impacts

Air Waste Disposal

During construction of a coal-handling terminal, combustion emissions from heavy
machinery at the site will include nitrogen oxide, carbon monoxide, and sulphur dioxide.
New Jersey's yearly vehicle emission testing should keep the pollutants at a minimum.

Operation of a coal-handling terminal involves the transportation of millions of
tons of coal. Fugitive coal dust is a major source of air quality degradation. Sources of

B-96

coal dust include coal handling and coal storage Coal dust deposited on surrounding

areas can:

0 inhibit photosynthesis in plants,
0 harm wildlife that consumes food covered by coal dust,
0 alter soil permeability characteristics,
0 alter the visual quality of the surrounding region, and/or
0 cause respiratory disease.

Means of alleviating sources of coal dust include enclosed systems, dust collection, and
water or chemical sprays.

Spontaneous heating and combustion within coal storage areas can create serious
environmental and safety problems at transshipment facilities. Spontaneous heating is
primarily an oxidation phenomenon involving coal, pyrite, and impure coal substances.
Factors affecting spontaneous heating include composition of coal, amount of volatiles in
coal, and the method of stockpiling and transportation. Air circulation is the key in
preventing spontaneous heating and combustion.

Because the study area has a non-industrial character, air quality degradation in
the form of coal dust will be a noticeable impact. Coal dust will affect the quality of
recreation and tourist areas and may affect the number of participants. The degree of
tourism and recreational impact will depend on the type of coal dust air quality controls.

Water Use/Water Discharge

During construction, the coal terminal site is cleared of egetation, and, as a
result, the exposed topsoil alters the water retention property of vthe soil. Erosion and
siltation will increase and produce greater turbidity and sedimentation in nearby surface

waters.

A suitable wharf or pier accessible via a channel of proper depth is required.
Dredging will be required to provide sufficient water depth at dockside as well as

B-97

sufficient channel depth. Dredging will alter the biological resources in the vicinity of
the dredged site'. If the dredging is extensive, it may change water current patterns
significantly enough to alter the coastline.

During operation of a coal-handling terminal, water runoff contaminated by coal
and other chemical products can degrade surface and groundwater resources. Pollutants
enter the waterways as water, reacts with coal pits, dust fallout, and coal spillage.
Contaminated runoff contains acids, metals, trace substances, and suspended and
dissolved solids. The degree of surface and groundwater impact from coal pile runoff is
influenced by the following factors:

0 volume of the stored coal

0 amount of precipitation

0 climate
0 terrain and hydrology surrounding the coal pile

Without proper controls, surface and gr oundwater can be degraded by coal pile
runoff, thereby damaging biological resources in the area and lowering the area's
aesthetic quality. As a result of poorer water quality, tourists and recreational
participants may choose other more usable, aesthetically-pleasing areas for activities
such as swimming and fishing.

Noise

Construction activity for a coal-handling terminal includes grading, hauling, and
erection of structures. As a result, ambient sound levels can be expected to increase
temporarily. . During the operation of a coal terminal, the movement of trains and barges
to and from the site and the use of coal-handling equipment will increase ambient sound
levels. If sound levels rise significantly enough, wildlife in the vicinity of the site may
disappear. The aesthetic quality of an area may also decrease with an increased ambient
sound level. In an effort to reduce sound levels, control options include enclosing,
insulating, shielding, or buffering the site or equipment.

Impacts to tourism and recreation, as a result of the noise generated by coal
terminal operation, will be dependent upon the ambient sound levels and the sound

B-98

control equipment. Because the study area has a relatively non-industrial character, an
increase in ambient sound levels will be a noticeable impact on the area thereby possibly
degrading the aesthetic quality of an area.

Aesthetic Impact

The major visual quality impact caused by coal-handling terminals results from the
obstruction of the horizon. Shiploaders, stacker/reclaimers, the control tower, and the
coal stockpile are the tallest structures having the potential to intrude upon the
viewsheds of coastal locations. Due to the level topography of the study area, the
stockpile and some of the taller equipment could be visible from adjacent areas.

The impact of facility development on visual quality depends on design, type of
equipment, and land use. Without the proper siting and design considerations, the
aesthetic impact of a coal-handling t erminal near a recreation area could lower the
quality of an area, thereby reducing the number of participants.

Ref erences

Allumena, Bill, Dravo Corporation, Pittsburgh, Pennsylvania. Personal communication,
May 198 1.

Bary, James, President, . Massay Coal Company, Newport News, Virginia. Personal
communication, June 1982.

Browning, Buddy, Alabama State Docks, Mobile, Alabama, Personal communication,
March 198 1.

Dravo Corporation, 1980. U.S. Coal Ports Market Study 1980 to 2000. Marketing
Department, Engineering Works Division, Pittsburgh, Pennsylvania.

New Jersey Department of Environmental Protection, Division of Coastal Resources,
198 1. New Jersey Energy Facility Development Potential Study.

B-99

Port Authority of New York and New Jersey, New York, New York. Written
communication, 1981*.

Rogers, Golden & Halpern, 1982. Environmental Assessment of Coal Transshipment
Facilities, Camden County Environmental Agency, Camden, New Jersey.

Soros, Paul, 1981. "Coal Shiploaders for the Mississippi." WWS/World Ports Magazine,
October/November 198 1.

United States Environmental Protection Agency, December 1980. The Environmental
Impact of Coal Transfer and Terminal Operations. EPA 600/57-8--169. Prepared by
Delon Hampton Associates, Silver Spring, Maryland.

Von Dobeneck, Klaus, Soros Associates, New York, New York. Personal communication,
May 198 1.

F3-1 00

OFFSHORE OIL PORTS

Description

Offshore oil ports are deepwater ports for unloading crude oil shipments from
supertankers (tankers over 175,000 dead weight tons (dwt)) and very large crude carriers
(VLCCs). The crude oil is then sent to shore via a pipeline for transportation to other
facilities (i.e., tank farm, refinery).

The tankers anchor at unloading buoys called single-point moorings (SPMs). There
are several types of SPMs that can be used in transferring crude oil from tankers to
pipelines. All include as components an anchored floating buoy, floating hoses for
conn ecting the tanker manifold to the buoy, and undersea hoses connecting the buoy to
submarine pipelines. The tanker is attached to the buoy with bow anchor lines and is
free to weathervane around the buoy. The oil is transferred through the pipeline to an
offshore platform that gathers oil from multiple single-point mooring stations. From
here the oil is pumped onshore.

Facility Size/Land Requirements

The recently completed Louisiana Offshore Oil Port (LOOP) has three single point
mooring buoys, a 4811 pipeline from the offshore pumping station to shore, and an initial
unloading capacity of 1.4 million barrels/day. Other proposed offshore oil ports would
have similar capacities.

The amount of onshore land required for offshore oil ports depends on the type of
support services provided (i.e., pipeline landfall, tank farm, or complete marine
terminal). Refer to other energy facility descriptions and their land requirements.

Site Parameters

Factors determining the siting of an offshore oil port include: offshore location for
mooring system and pipeline with acceptable wind and wave conditions; bathymetry and
marine geology; proximity to onshore storage tanks and oil terminals; and proximity to
man-made hazards (i.e. shipping lanes).

B-101

Capital Costs

There is no equation for the capital costs of offshore oil ports due to the limited
sampling size. The cost of the recently completed Louisiana Offshore Oil Port was
approximately $700 million. The Port Authority of New York and New Jersey estimates
the cost of a facility transferring 1.4 to 1.5 million barrels per day at approximately $1.2
billion Ct15%) in 1981 dollars. The capital cost varies widely depending upon the quantity
of oil transported and the type of onshore storage -facilities required.

The total capital cost for a proposed offshore unloading system with a 500,000
barrel per day capacity consisting of two singlepoint mooring buoys, each connected to
an onshore tank farm by a 2.5 mile, 4811 submarine pipeline is estimated at approximately
$62,800,000. This cost includes the undersea pipeline, but does not include any onshore
support facilities (United States Department of the Interior, Bureau of Land Manage-
ment, 1979).

Employment Profile

The employment figures reflect the construction of the Seadock Offshore Oil Port,
twenty-six miles off the Texas coast. Seadock consists of two 52-inch crude oil
pipelines, an offshore pumping platform, four single point moorings, and an offloading
capacity of 2.5 million barrels/day.

Construction:

Year I Year 2 Year 3
Manual (89%) 89 196 178
Non-manual (1 M 11 24 22

Total 100 220 200

Manual workers consist of laborers, equipment operators, and skilled trades workers (i.e.,
boilermakers, pipefitters, and electricians). Non-manual workers consist of secretarial,
managerial, and administrative employees, as well as engineers.

B-102

Operation:

Manual (77%) 54
Non-manual (23%) -16
Total 70

The construction employment figures for the 500,000 barrel per day facility noted
previously are as follows:

Constructionr Year I Year 2
(8 months)

Manual 135 135

Non-manual 15 15

Total. 150 150

Sources:

Roy F. Weston, 1978; U.S. Dept. of the Interior, 1979; and U.S. Department of
Transportation, U.S. Coast Guard, 1976.

Environmental Impacts

Offshore oil ports themselves have few environmental impacts (except for a large
oil spill). However, associated with offshore oil ports are onshore facilities, including:
support bases, tank farms, pipeline landfalls, and marine terminals. The facilities
supporting the offshore oil port will have more significant environmental effects that
may affect recreation and tourism. These facilities are discussed in accompanying
sections and can be reviewed for environmental and associated tourism-related impacts.

Air Waste Disposal

Hydrocarbon emissions can be expected in very small quantities from offshore oil
ports during the transfer of oil. Impacts on recreation and tourism as a result of
hydrocarbon emissions will be negligible.

B-103

Spill/Accidental Discharge

Because of the large amounts of oil being transferred and transported from tankers
and through pipelines, the risk of an oil spill is present during operation. Spills can range
in size from small operating, accidental spills, to larger more significant spills. Although
oil spill clean-up equipment has become more advanced, potential impacts from spilled
oil remain. Spilled oil has a detrimental effect on biological resources because of its
toxic and coating properties.

The most significant impact of an oil spill to tourism would be the soiling of
beaches and recreation areas. If the spill moved onto the coast, the aesthetic
degradation would be obvious. In addition, swimming, fishing, and boating activities
would be hampered. The impact on recreation and tourism would reflect a significant
drop in the number of those industries' participants.

Ref erences

Civil Engineering, June 1982. The LOOP Project: Taking the Port to the Ship.

Loop Inc., Harvey, Louisiana. Written communication, 1981.

Oil and Gas Journal, June 28, 1982. "Declining Imports Cloud Outlook for U.S.
Deepwater Port Projects."

Roy F. Weston, Inc., July 1978. Methodology for Assessing Onshore Impacts of Outer
Continental Shelf Oil and Gas Development.

Travato, Terry, LOOP Inc. Harvey, Louisiana. Personal communication, 1981.

U.S. Department of the Interior, Bureau of Land Management, 1979. Final Environ-
mental Impact Statement: Crude Oil Transportation Systems, Washington, D.C.

U.S. Department of Transportation, U.S. Coast Guard, 1976. Final Environmental Impact
Statement for the Seadock Deepwater Port License Application, Washington, D.C.

B-104

NO" COASTAL SERVICES CM LIBRARY

3 6668 14111320 1