ASSESSING THE°ENVIRONMENTAL IMPACTS
OF OIL AND GAS
DEVELOPMENT IN ALASKA
APPENDIX
DEVELOPMENT ALTERNATIVES
Revised March 30, 1975
RESOURCE PLANNING ASSOCIATES
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ASSESSING THE ENVIRONMENTAL IMPACTS
OF OIL AND GAS
DEVELOPMENT IN ALASKA
APPENDIX
DEVELOPMENT ALTERNATIVES
Revised March 30, 1975
RCSOUKCt PtANNfSG ASSOCf/fl'S, INC.
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DEVELOPMENT ALTERNATIVES
Over the next, several yearg, a number of difficult decisions will
have to be made about if, when, and how oil and gas development should
occur in Alaska. To provide a framework for such decision making,
Resource Planning Associates has developed a number of alternative
development projections. These alternatives are detailed in this hand-
out, which acts as an appendix to the visual progress report presented
today, in terms of:
• The elements of a development alternative
• How the 13 development alternatives were ranked, as well
as the ranking itself
• The assumptions to be used for each of the 13 alternatives,
together with projected development schedules and maps of
likely primary impact sites.
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A - ELEMENTS OF A DEVELOPMENT ALTERNATIVE
Projecting the statewide and regional impacts of oil and gas
development on Alaska will be difficult at best because of the size and
extent of the potential hydrocarbon reserves. Nevertheless, as a first
step in determining what those impacts will be, we have developed a
range of probable levels of activity - i.e., various development alter-
natives. Specifically, we
• Developed a base case, which reflects the level of develop-
ment already completed or in progress on the North Slope
or in the Upper Cook Inlet,
« Fashioned 13 separate development alternatives, each
assuming the base case plus some other level of activity.
Each development alternative consists of seven major elements:
(1) recognition and precise estimation of oil and gas potential; (1:)
leasing; (3) exploration; (4) discovery; (5) delineation; (6) production;
and (7) transport out of the primary impact site. Exhibit 1 is a con-
ceptual diagram of these elements, which are discussed in turn in the
remainder of this section.
ESTIMATION OF POTENTIAL
A precise estimate of the oil and gas potential in any given area
is extremely important because the level of exploration and development
depend on how much oil and gas is expected to be discovered. The accuracy
of this estimate depends of course on the level of exploration to date.
For instance, the 9.6-billion barrel total estimated for Prudhoe Bay
oil production is probably quite accurate since over 100 wells have
been drilled and the operating companies have a good idea of the size,
thickness, and recovery rate of the producing zone. On the other hand,
the 4-billion barrel total estimated for the Chukchi Sea is probably
highly inaccurate because no wells have been drilled as yet.
Estimates of reserves are based on published figures* and on our
own estimates of potential oil and gas deposits. In turn, these esti-
mates are based on the degree of exploration in the area to date, on
the proximity of suspected fields to known producing areas, and on the
production characteristics of those already productive areas.
LEASING
Since exploration by drilling cannot begin until acreage has been
leased (unless it is a stratigraphic well, drilled not to find reserves
but to determine the types of rock in the area), the date of the lease
* - Project Independence Blueprint, Oil and Gas Journal, PCS Oil
and Gas, industry estimates.
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sale will be one important determinant of how quickly an area is
explored. Additionally, the "type" of lessor will affect the speed of
development. In Alaska, the major lessors are the Federal Government
(i.e., the Department of the Interior), the State of Alaska, and the native
associations. Each has different objectives and competes with the others
for industry funds. Also, each has a different impact on the flow of
money into Alaska, with proportionally more money remaining in the state
if native- or state-owned lands are leased.
There are several different methods of leasing that also affect cash
flow. The standard native agreement with an oil company requires periodic
payments over the length of the lease, which means a longer term but lower
level cash flow into Alaska. On the other hand, leases sold through com-
petitive bids by the state or the U.S. Department of the Interior require
lump-sum payments, thereby providing a sudden but unsustained influx of a
substantial amount of money.
EXPLORATION
The level of exploration will depend on:
1. The level of leasing activity. Historically rig activity
is greatest prior to and within a short period subsequent
to a lease sale. It is assumed that leasing will proceed
at a rate sufficient to insure orderly exploration and
evaluation of potential in an area.
2. The estimated cost per well. For example, in northern
Alaska, an exploratory onshore well of 10,000 feet costs
approximately $7 million; in the Gulf of Alaska, the cost
is roughly half that. Thus, an oil company can drill two
wells in "the Gulf for the same price as one in northern
Alaska.
3. The rate of discovery. A discovery in an exploratory
area tends to increase the level of future exploration
in that area.
4. The size of the exploratory area. A geographically large
area will require more wells to evaluate the field fully
than a geographically small area.
5. The.length of the drilling season. Areas with short
exploratory drilling seasons such as the North Slope will
require more rigs to perform the same level of exploration
than areas where weather permits year-round drilling.
6. Availability of equipment/facilities. Although there is
a current worldwide shortage of drilling rigs, tubular goods,
and other resources required for oil and gas exploration
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and development, we assumed these shortages will not affect
exploration and development for individual Alaskan scenarios.
Moreover, it was assumed that there will be no competition for
resources among the development alternatives, and that the.
price of oil or the price of gas will not deter exploration
and development.
7. The development of drilling technology. Obviously, the
availability of sophisticated drilling technology will
accelerate exploration. However, the present state of the
art does not allow exploration and development of such areas
as Chukchi Sea at this time. But it was assumed, neverthe-
less, that the oil industry's and the government's research
and development efforts will proceed at a rate that permits
exploration and development in these areas by 1985.
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Exhibit 1
ALASKA MODEL DEVELOPMENT
Time
¦H
.Lease
\
\
Exploration¦
->> Field Discovery
I
Field Discovery
I
De line ation >
Delineation
I
Field
Development
Field Development.
Pipeline
Transport
Production and
transport^
* Production and transport
*- ^
Waterflood and
. transport
11 Waterflood and transport,
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DISCOVERY
Each development alternative assumes that, after a period of explor-
ation, a discovery will result. How quickly discoveries occur depends
on whether industry explores the most, promising prospects first, thereby
leading, presumably, to early discoveries. In any event, it was assumed
most of the potential will be discovered within 15 years of commencement
of exploration.
The number of discoveries depends on the discovery experience in the
area and adjacent areas, and on the size of the total discovery necessary
for lucrative commercial production. For example, on the North Slope,
discoveries were classed as Prudhoe size (i.e., 6-10 billion barrels),
Kuparuk or Lisburne size (i.e., 1-2 billion barrels), or intermediate size
(2-6 billion barrels). In the Gulf of Alaska, discoveries were classified
as 2 billion barrels, with the proviso that a discovery could be made up
of several smaller discoveries in the vicinity if, cumulatively, they
justified the expense of production and tanker facilities. This appears
to be the minimum economic size for development in the Gulf of Alaska.
DELINEATION
After a discovery has been made, several years are usually required
to build platforms, and support facilities and to plan development and
production facilities. During this pre-development period, the field area
is delineated by drilling 10-15-delineation wells. Each such well is assumed
to cost two-thirds the cost of an exploratory well, as knowledge of the
stratigraphy, formation pressures, and depth to the pay zone will allow
rapid drilling and preclude drilling beyond the pay zone.
DEVELOPMENT
The development element of each development alternative is based on
the assumption that there will be no competition among development areas
for resources. This assumption was made to allow evaluation of individual
alternatives. As alternatives are combined (to form scenarios), this
assumption becomes invalid. Development schedules will then be altered
to allow for competition according to priorities established by the ranking
of the alternatives.
The number of needed oil development wells is calculated by dividing
the delineated field size by 320 acres. (Three-hundred-twenty-acre spacing
was chosen to permit uniformity among the areas and to allow for secondary
recovery efforts such as waterflood.) It is assumed that eight wells will
be drilled from a platform or drilling pad during development; this will
allow the development of 2,560 acres by each pad.
For gas development, it is assumed 640 acre spacing will be required,
and no secondary recovery will occur. While gas stimulation techniques
such as fracturing or acidizing may be used, it is impossible to predict
their use.
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Development time is determined by estimating, the time necessary to
prepare production facilities and the rate of decline of a field before
waterflood was necessary. In most alternatives, it was assumed that one-
half of the development wells will be drilled after full production is
achieved. The remaining one-half will be drilled prior to secondary re-
covery. In some cases this schedule was altered to account for pipeline
delays or pipeline capacity criteria that might delay bringing later dis-
coveries into production.
PRODUCTION
Production depends on the number of wells producing, the rate at
which each well produces, the rate of decline of each well, and the life
of the field. The typical production cycle for a field includes initial
production, build-up to a maximum production rate as more wells are brought
into production, and decline. As decline begins, secondary recovery is
assumed to allow for a steady production rate until the field is depleted.
It is further assumed in most development alternatives that secondary
recovery will begin within 3 years of full production and continue for
7 years, at which time beginning of "breakthrough" of water into the oil
producing wells, will occur. At this point the field will undergo a rapid
decline in production (25 percent per year).
Gas production is different from oil production in that it is assumed
to decline at a much slower rate. Moreover, no secondary recovery is assumed
for gas.
The lag time between discoveries and development and production tends
to stretch out the useful life of pipeline and transport facilities and to
require a smaller capacity for these facilities than if all discoveries
were brought into production at the same time.
TRANSPORTATION
In developing the various alternatives, only the TAPS pipeline was
assumed to predate the development alternatives. Consequently, in each
development alternative, additional pipeline and transport requirements
had to be calculated. However, where appropriate, total pipeline and
transport needs were integrated.
* * *
In addition to the seven major elements of a development alternative
conceptualized in Exhibit 1 and discussed above, estimate must be made
of the facilities needed to support the projected development. To this end,
facilities are divided into two classes - temporary and permanent. Explor-
ation and delineation require temporary facilities, development requires
both temporary and permanent facilities, and production requires permanent
facilities. In several cases, such as the offshore development, the develop-
ment phase requires large onshore temporary facilities that will be abandoned
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when production begins. Similarly, development of the smaller onshore
fields requires large temporary facilities, but minimal permanent pro-
duction facilities.
Facility types considered were:
1. Support facilities - docks, airstrips
2. Development facilities - housing, roads
3. Pipeline facilities - gathering centers, flow stations,
roads, temporary airstrips
4. Transport facilities - docks, pipeline terminals, offshore
tanker sites, liquefied natural gas plants
5. Refineries.
Facility and transportation requirements are discussed briefly for each
alternative. They will be considered in more detail in a separate appendix.
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B - RANKING OP DEVELOPMENT ALTERNATIVES
At present some 13 onshore And offshore areas in Alaska may have
economically recoverable reserves of oil and gas. Including the base-
line development areas, they are:
1. Upper Cook Inlet and Prudhoe Bay Oil
2. Other private development at Prudhoe Bay
3. Southern Cook Inlet
4. Prudhoe Gas - El Paso
5. Gulf of Alaska offshore (includes Kodiak Island subprovince)
6. Beaufort Sea offshore
7. Naval Petroleum Reserve #4 development case - slow
8. Kotzebue Sound (onshore and offshore)
9. Bristol Bay (includes onshore Bristol Basin)
10. Naval Petroleum Reserve #4 development case - fast
11. Bering Sea (includes onshore Bethel Basin)
12. Chukchi Sea
13. Arctic Wildlife Refuge
This listing infixes a ranking of the potential producing areas,
and indeed they have been ranked from highest to lowest probability of
development by the year 2000.*. To cirrive at this ranking, we consi-
dered a variety of factors. Current plans for lease sales -and announced
exploratory drilling were assumed to indicate: (1) substantial interest
on the part of the oil industry and/or the controlling agency; and (2)
a degree of certainty that some level of development would occur in the
next two decades. In the absence of any announced intentions to open
an area for leasing or drilling, other factors such as proximity to an
area under development or the availability of proven, environmentally
safe technology were considered. The way in which these and other fac-
tors influenced the final rankings is discussed for the base case and
each of the 13 potential development alternatives identified.
1. Upper Cook Inlet and Prudhoe Bay. These two areas form the base
case because development of oil and gas wells is either already
completed or in.progress. That these areas will be impor-
tant producing areas in the near future is a virtual cer-
tainty, given the approval of the appropriate environmental
impact statements and the nation's urgent need for addition-
al-oil supplies.
* This ranking does not necessarily imply the sequence in which these
areas will be developed. For example, although certain interior
areas of Alaska have good hydrocarbon-bearing potential, are adja-
cent to the route proposed for the TAPS pipeline, and are onshore
and relatively close to the crude pipeline, the quantity of oil in
those fields may be insufficient for economic recovery. On the
other hand, some of the more remote areas have far higher potential
for oil production; consequently, they are more likely to be devel-
oped if oil were discovered in the rather large geologic structures
that have been located to date.
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2. Prudhoe Bay - Private. When the TAPS pipeline is installed,
current projections indicate that only'1.6 million barrels of
oil per day of the pipeline's capacity will be utilized by the
presently planned Prudhoe Bay developments. Unless.development
is accelerated at Prudhoe Bay, this available capacity could be
used by some reasonably'large discoveries that have been made,
adjacent to the existing and planned Prudhoe facilities. If
Prudhoe Bay development is accelerated, these discoveries could
be used to fill the pipeline as production at Prudhoe Bay declines.
Although these fields have not yet been delineated, their prox-
imity to the pipeline alone makes their commercialization highly
probable (i.e., 90 percent).
3. Cook Inlet, Southern portion. This region is adjacent to the
upper, or northern, Cook Inlet which is already producing both
oil and gas. In addition, state and federal government lease
sales are scheduled for 1975. These two factors and the fact
that Cook Inlet waters are relatively ice-free and convenient
for tankers indicate this region will probably—a 90-percent
probability, in fact—be developed rather quickly.
4. Prudhoe Bay natural gas development (El Paso). Natural gas
reserves on the North Slope have been delineated, and the pipe-
lining and conversion to liquefied natural gas appear economically
feasible. However, although the proposal for the pipeline has
been submitted, it has not yet been approved, nor has the environ-
mental impact statement been prepared. This leaves some minor
doubts about construction of a natural gas pipeline parallel to
the TAPS pipeline, which has been approved. But since environ-
mental concerns about gas transport are generally less severe
than for oil, the major uncertainty appears to be the economic
viability of building a pipeline and liquefaction plant to trans-
port the gas to the West Coast. The probability for this develop-
ment is about 75 percent.
5. Gulf of Alaska. Offshore development seems likely because:
(a) the possibility of finding large fields is high; (b) the
technology for producing oil from 500- to 600-foot depths is
available; and (c) the waters of the Gulf are ice-free and (d)
the area is the closest by tanker to the West Coast, where
most of the oil will be used. And although offshore drilling,
especially in an area of seismic activity, is costly and dif-
ficult, the region has the advantage of not needing a major
pipeline to transport the oil to a tanker terminal; single-
point moorings would be feasible. Consequently, the Gulf of
Alaska is very likely (75 percent) to be developed.
6. Beaufort Sea. The Beaufort Sea by itself would probably not
have been attractive without the prior discoveries and accum-
ulated operating experience at Prudhoe Bay. However, there
is a 60-percent probability of production because there are
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large, potential oil structures in areas adjacent to known pro-
duction, technology exists for performing the exploratory dril-
ling and delineation from natural and/or man-made islands in
the shallow waters (this is already being done in the Mackenzie
River delta in Canada), and federal and state lease sales are
scheduled in the next few years.
7. Naval Petroleum Reserve #4 (NPR-4) (slow development case).
Exploratory drilling* commissioned by the Navy is already under
way, and initial seismic analyses indicate the possibility of
structures of Prudhoe magnitude. Moreover, since the major re-
serves are onshore, no new technology is required to tap the
fields. The major uncertainty associated with NPR-4 develop-
ment, however, is the status of the state-claimed offshore
acreage out to the 3-mile limit and the outcome of U.S. Depart-
ment of the Interior's efforts to open the reserve to leasing.
Because of this uncertainty, there is only a 50-percent proba-
bility of slow development of the NPR-4.
8. Kotzebue Sound. These native- and state-controlled lands and
waters are already being explored under special exploration
agreements. Although there is promising potential, the loca-
tion presents problems. Winter ice formation will interfere
with offshore exploratory drilling as well as prevent or at
least hamper the use of tankers in the area. Consequently, a
pipeline may have to be constructed to connect the region to
an ice-free port in the south or to one in which the ice will
not interfere with shipping operations. In spite of the good
potential of Kotzebue, then, there is only a 50-percent proba-
bility of development there by 1990.
9. Bristol Bay. Some onshore exploratory drilling has already taken
place, and although the results have been negative, initial seismic
analyses indicate a reasonably good potential for the area. In
addition, lease sales have been scheduled. However, major fac-
tors impeding production, should oil be discovered, are mid-
winter ice that creates transportation problems and competi-
tion with Gulf of Alaska development for drilling equipment.
Moreover, no environmental impact statement has been filed as
yet. These factors, in toto, imply development by 1990 has
only a 40-percent probability.
10. Naval Petroleum Reserve #4 (fast" development case). As noted
for the slow development alternative, exploration is under way
in NPR-4. Whether the area is developed quickly or slowly will
probably depend on the size of the initial discovery, i.e., an
extensive discovery would encourage more rapid development to
alleviate the nation's energy shortage. Counteracting these
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pressures for rapid development will be the Navy's reluctance
to relinquish control of the reserve to the U.S. Department of
the Interior. Political entanglements over who will benefit"
from NPR-4 also promise to inhibit rapid development. Weigh-
ing these factors subjectively, the probability of this alter-
native is only 35 percent.
11. Bering Sea. The lack of exploration in the Bering Sea under-
standably creates some doubt about the region's potential, al-
though seismic data indicate moderately promising structures.
Lease sales have been scheduled for 1976, but no environmental
impact statement has been submitted. Considering the problems
created by the winter ice formation and competition with the
Gulf of Alaska and Bristol Bay development efforts for equip-
ment, the Bering Sea has only a 30-percent chance of being de-
veloped by 1990.
12. Chukchi Sea. The Chukchi Sea, like the Bering Sea, is still a
questionable development area since no exploration has been
conducted. The area is remote from existing or planned pipe-
line and tanker transport; consequently, its development in
this century will depend to a great extent on the discovery
of large reserves in adjacent onshore and Beaufort Sea areas.
Moreover, ice movements in the deeper waters present drilling
and production problems. Therefore, the probability of the
Chukchi Sea's being developed by 1990 is quite low - i.e.,
20 percent.
13. Arctic Wildlife Refuge. This area has a very large, onshore
oil potential which should make it attractive for exploration.
However, the area has been withdrawn from exploration by the
Department of the Interior, and there is strong environmental
opposition to allowing exploration.
There are sfeveral onshore provinces that have not been considered in
this ranking. These include the Koyokuk Basin (State of Alaska Division
of Oil and Gas potential estimate 3.4 billion barrels oil, 9.3 trillion
cubic feet gas), the Yukon-Kandik Basin (potential estimate 1.7 billion
barrels oil, 11.4 trillion cubic feet gas) and the Copper River Basin
(potential estimate .2 billion barrels oil, 1.2 trillion cubic feet gas).
Although they may be explored at some time in the future, the uncertain
status of native and Federal withdrawals in the potential areas precludes
reasonable appraisal of development and production. Furthermore, the rela-
tively small size of the potential, when compared to the potential of other
areas, would seem to imply smaller socio-economic impacts on the Alaskan
community.
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C - ASSUMPTIONS FOR EACH ALTERNATIVE
COOK INLET BASE CASE
General Assumptions
Oil and gas development is currently in progress in the Upper Cook
Inlet Basin of southeastern Alaska. The current level of production of
oil is 195,000 barrels per day from 6 fields. Marketed production of
natural gas from. Cook Inlet totaled 136 billion cubic feet in 1973, with
total production of casinghead and dry gas of 225 BCF.
According to Future Petroleum Provinces of the United States, the
discovered oil-in-place is estimated at 2.6 billion barrels and the gas at
5 trillion cubic feet.
All development to date has occurred on private or state lands. Although
leasing is scheduled for the future, it will not be considered in this case
but rather as a part of the Southern Cook Inlet development alternative.
Exploration
Oil in commercial quantities was discovered at Swanson River on the
Kenai Peninsula in 1957. Since then, exploration has continued, with 10
wildcats drilled in 1974 alone. No further exploration is assumed in the
Upper Cook Inlet area.
Development
Since 1957, six oil fields and 21 gas fields have been discovered.
Development is nearly complete on all the oil fields. Of the gas fields,
8 are producing, 2 are depleted and 11 are shut-in. Most of the shut-in fields
have only 1 or 2 completions and cannot be considered developed.
Production
Oil. Statistics for the six onshore and offshore oil-producing areas
are:
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1973 Estimated
Production Number Depth
(Thousand Bbls.) Of Wells (feet)
Offshore
Granite Point 4,233 25 8,772
McArthur River 39,191 52 9,572
Middle Ground
Shoal 9,033 33 9,000
Trading Bay 8,000 42 5,650
Beaver Creek 416 1
Onshore
Swanson River 9,741 37
The McArthur River Field was the major producing field in the state,
producing 53.2 percent-of all oil produced. The average production rate for the
field was 2,090 barrels of oil per well per day. Secondary recovery
(waterflood) is utilized in the field, as it is in all the Cook Inlet oil
fields. Both water and gas injection are used at Swanson River Field.
*
Gas. There are both onshore and offshore gas-producing areas. The
offshore producing areas are North Cook Inlet, Redoubt Shoal, West Foreland,
North Middle Ground Shoal, and Ivan River. Onshore areas are West Fork,
Beaver Creek, Sterling, Falls Creek, Beluga River, Moquawkie, Nicolai Creek,
Birch Falls and Kenai. Gas is also produced at the oil fields, but is
generally reinjected. Kenai is listed by The Division of Oil and Gas, State
of Alaska as the Inajor gas-producing field in the state, having produced
72 billion cubic feet of gas from 18 wells in 1973. As of December 1973,
there were 53 active producing gas wells in eight fields.
Facilities
Two refineries are currently operating at Kenai. The Standard Oil of
California refinery has a daily capacity of 22,000 barrels, while the re-
finery run by Tesoro-Alaskan Petroleum Corporation has a capacity of 38,000
barrels per day.
Oil pipelines transport crude oil produced from the Granite Point,
Middel Ground Shoal (both offshore),.and Swanson River (onshore) to the
coastal site of.Nikiski. Another oil pipeline connects the Trading Bay
and McArthur River producing areas with Drift River.
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Several gas pipelines are also in existence. One runs from Kenai
through Sterling and West Fork to Anchorage. Another runs from the North
Cook inlet producing area underwater and then onshore along the coast to
Nikiski. There is a third pipeline from Kenai to Nikiski.
Of the 135 BCF of gas sold in Alaska in 1973, 26 BCF was shipped through
pipelines to Anchorage; 61 BCF was processed at the Phillips Marathon gas
liquefaction plant for shipment to Japan; 21 BCF was used at the Collier
Carbon and Chemical ammonia-urea plant; and 11 BCF was used to generate elec-
tricity for Chugach Electric, the City of Kenai, Nikiski, the Standard
Refinery, Consolidated Utilities and the ARCO Spark platform. The remainder
of the gas sold was used for gas injection as part of the Swanson River
pressure maintenance program.
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PRUDHOE BASE CASE (SADLEROCHIT RESERVOIR ONLY)
General Assumptions
Exploratory oil drilling has been in progress onshore at Prudhoe
Bay, following discovery in 1968, for several years. Current de-
velopment drilling is not expected to lead to oil production until
mid-1977, when it is assumed that the Alyeska pipeline will be ready
for operation. No commercial gas production is expected. Gas escaping
from wells will be fed intb a gas-injection plant, to be subsequently
injected back into the producing zone.
The published American Petroleum Institute estimate of potential
recoverable reserves in the Sadlerochit Reservoir alone is 9i6 billion
barrels. It is assumed that initial production will be only from this
reservoir, gas drive as the recovery mechanism. Subsequent decisions
whether to waterflood will be made after several years of production.
Accelerated production requiring additional development.wells to fill
the pipeline to its capacity of 2 million BOPD is not considered.
Exploration
Exploration of the Sadlerochit Reservoir has been completed. No
further exploration or delineation of the field is assumed, although the
size of the field may be extended during development.
Development
Atlantic Richfield is the only company currently involved in
development drilling. It is assumed that 30-45 days, are required to
drill a development well, the average depth of which will be 10,000
feet. Development drilling will probably be completed by 1980-1981.
Six-hundred-forty-acre spacing is assumed for initial development
drilling, with 320 then 160 spacing assumed for accelerated production
or waterflood. Initial development is confined to an oil column 200 feet
in thickness with later wells moving both upstructure and downstructure
of this interval.
Production
The rate of production is assumed to be 8,000 barrels of oil per
day (BOPD) per well. Production will be initiated in 1977 at 1.2
million BOPD, peaking to 1.6 million BOPD by 1980. If the participating
companies decide to accelerate development, however, production may reach
a peak of 2.0 million BOPD by 1980. One-hundred-fifty wells are assumed
for initial production, while 500 wells may ultimately be drilled.
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Facilities
Oil production from Prudhoe, Bay cannot be realized until a
satisfactory oil transportation network is in operation. It is
assumed that Alyeska will complete its trans-Alaska pipeline by mid-
1977. Right-of-way permits have been granted by both federal and
state authorities for the pipeline route from Prudhoe Bay to
Valdez. Parallel haul-road construction along the pipeline right-
of-way is expected to be completed by mid-1975, when construction of
the pipeline structure is scheduled to begin. However, possible
shortages of necessary supplies - i.e., all forms of steel equipment
and particularly tubular goods - may deter realizing completion of
the pipeline during 1977. Construction of a temporary dock has
been finished at the Valdez terminal site. The schedule for con-
struction of all transport-related facilities is as follows:
Phase I:
1974 . Existing camps upgraded and new camp construction
begun (33 total)
Road from the Yukon River to Prudhoe Bay completed
Clearing of righ't-of-way for pipeline south of the
Yukon River
Preparation of pump station sites
Beginning of construction of Valdez tanker terminal
Laying of pipeline south of the Yukon
Beginning of pump station installation
Clearing of right-of-way for pipeline north of the
Yukon
Laying of pipeline north of the Yukon
Installation of pump stations 1, 3, 4, 8, and 10
The pipeline capacity would be 1.2 million BOPD at com-
pletion of this phase.
1975 .
1976 .
1977 .
Phase II:
1977
-78
Completion of installation of pump stations 6, 9, and 12
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RtSOUKCf PIANNINC, ASSOCIAIIS. INC
44 WMIII Mill I • (MwttKIIMJ MA\V«. HI 'I t Iv
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Completion of two of five planned supertanker berths at
Valdez
Pipeline capacity would be 1.6 million BOPD at completion
of this phase.
Phase III:
1978
-80
Completion of installation of pump stations 2, 5, 7, and
11
•Pipeline capacity would be 2.0 million BOPD at completion
of this.phase.
In summary, facilities will include, in addition" to the pipeline
and its related structures, several airstrips, an operations center for
each company (150-225 men each), gathering centers (flow stations) with
300,000 BOPD capacity each, a small refinery of 6,300 BOPD capacity
(presently in operation)to provide fuel for use at the Prudhoe Bay location,
and service and drilling company facilities.
Impact Area
Two hundred square miles (128,000 acres) will be affected by currently
planned oil development in Prudhoe Bay. Of this, approximately 80,000
acres will be affected by initial development (area of 200-foot oil column),
with additional acreage being developed over time. The pipeline will
be 789 miles in length with a 150-foot right-of-way. According to the
TAPS-EIS, 940 square thiles of the state's 572,000 would be occupied by the
oil field and pipeline system. The terminal at Valdez would cover approx-
imately 900 acres.
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Rl^Ol'RCE PIVNNINt; ASSOriAflS, INC
M Mill I • ( M4SS4I rm\MIS 0.'l »
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Exhibit 2
MAP KEY FOR EXHIBITS 3 to 33
Potential Development Areas
Trans Alaskan Pipeline System
Onshore Impact Site
Potential Exploratory Area
-Onshore
-Primary Development Impact Area
-Offshore (no primary impact area assigned)
Central Gathering and Flow Center
Gathering Center
Gas Field - Discovered
Oil Field - Discovered
Small Diameter Pipeline
Large Diameter Pipeline
Possible Pipeline
Currently Developed Areas (base case)
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Exhibit 3
PRUDHOE BAY AND COOK INLET
\-4 'i.
c^' -^P'-£?'->
i S'— ^ <
-------
Exhibit 4
-OOK INLET
BASE CASE
(detail)
-~s-r.
hloW«*n«
Mtff t! V».,
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'(twin.;.J. ify
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PRUDHOE - PRIVATE
General Assumptions
The Prudhoe Bay Field Sadlerochit Reservoir (described in the base
case) is estimated to have a production capacity of 1.6 million BOPD by
1977 assuming the present development plan (according to the Project
Independence Blueprint, Oil Task Force Report, Exhibit IV-2). Therefore,
to operate the Trans-Alaska pipeline at its design capacity of 2 million
BOPD, an additional 400,000 BOPD will be needed. Potential sources of
this additional oil are: the Prudhoe Bay Kuparuk Reservoir, which extends
west from the Prudhoe Bay Unit Area; the Prudhoe Lisburne Reservoir, which
lies 500 feet beneath the Sadlerochit Reservoir; and a shallow, heavy oil
accumulation located west of the Prudhoe Bay Unit. The potential amount
of recoverable reserves in three areas are estimated at 1.5-2.0 billion
barrels, 1.0-2.0 billion barrels, and 200 million barrels (of a total
in place of 2 billion barrels), respectively. In addition to oil, the
Lisburne formation is estimated to contain 8 trillion cubic feet of gas
(RPA estimate). At §7.00/barrel, the heavy oil deposit is not commer-
cially viable, but new technology is assumed to make heavy oil production
feasible by 1985.
Other development on state lands and lands open to native withdrawal appear
possible. The potential area extends from the Canning River (Arctic
Wildlife Refuge) to the east to the Colville River (Naval Petroleum Reserve
No. 4) to the west. Recoverable potential is estimated at 300 million
barrels of oil and 2 trillion cubic feet of gas (RPA estimate). Gas
potential includes the Kavik, Kemik, and Gubik gas fields, which have been
discovered but whose total potential is not known.
Exploration
No new exploratory drilling is assumed in the Kuparuk and Lisburne
fields. In the heavy oil area, 10 exploratory wells are likely to be
drilled beginning in 1980, followed by 10 delineation wells beginning
in 1983. Other North Slope exploration is assumed to require 25 explor-
ation wells, followed by 10 delineation wells. Exploration of this
latter area will proceed 1 year after state and native leasing takes
place over the period of 1976 to 1980.
Development and Production
Development of the Kuparuk Reservoir is expected to begin in 1978
and be completed by the end of 1981. Production from the reservoir is
expected to reach 400,000 BOPD by 1982, with an average production rate
of 2,000 BOPD per well. Approximately 250 development wells will be
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*4 MIII ^ lilt I ' rtUIUSl MA\>V IKMIIN IIMU
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drilled with 320 acre spacing. Very little gas has been discovered in
the Kuparuk Reservoir to date. Therefore, no gas development or pro-
duction is assumed.
The first development wells will be drilled at the Lisburne
Reservoir in 1980 and the last by the end of 1985. Initial production
from the reservoir is expected to be 450,000 BOPD in 1981, building to
a peak of 600,000 BOPD in 1986. At peak production, approximately 200
wells will be producing an average of 3,000 BOPD. From this peak,
reservoir production is expected to decline at about 14 percent per
year without secondary recovery. Overall life of the reservoir is
estimated at 16 years.
Gas will also be produced from the Lisburne Reservoir, both as a
by-product of oil production and from separate gas wells. It is assumed
that each oil well will produce 1 MMCFGPD. Each gas well will produce
8 MMCFGPD. Gas development is assumed to lag oil development by two
years, with gas and oil production beginning simultaneously. Gas production
is assumed to peak at 1 BCFGPD within two years of production. Overall
life of the gas reservoir is estimated at 16 years.
With the advent of new technology by 1985, development at the Heavy
Oil Reservoir will likely begin in 1985 and be concluded by the end of
1985. Initial production is assumed to be 80,000 BOPD in 1986, reaching
a peak of 100,000 BOPD in 1989. At maximum production, approximately
200 wells will be producing at a rate of 500 BOPD, with 320 acre spacing.
Development is expected to begin on Other North Slope {onshore,
private) in 1985" and be completed by the end of 1992. By 1990, pro-
duction from these smaller reservoirs is estimated to reach, in aggregate,
100,000 BOPD and 400 million cubic feet of gas. Assuming 320 acre
spacing for oil wells and 640 acres for gas, average production per
well is assumed to be 1,000 BOPD and 10 million cubic feet of gas for
the 100 oil and 40 gas wells likely to be developed.
Facilities
The development of these additional North Slope reservoirs requires
very few additional facilities relative to the massive Prudhoe Bay
development. In Kuparuk, two gathering centers of 200,000 BOPD capacity
will probably be needed, while for the Lisburne Reservoir, two 300,000
BOPD gathering centers are more likely. Small collection systems are
required for the heavy oil and other reservoir production. Small dia-
meter pipes will have to be laid to connect the gathering systems to
TAPS.
Other than piping, other new facilities will probably be needed
for development and pipeline construction, especially between the Kavik
airstrip and the Sagavanirktok River.
-on-
RtSOURCI I'lANNINi; ASSOC IAIIS. INC
*4 maiin kiam • u/tu
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Impact Areas
Since the Kuparuk and Lisburne Reservoirs are adjacent to the massive
Prudhoe developments, additional land impacts are relatively insignificant.
Heavy Oil Reservoir and Other Development Reservoir, on the other hand,
are expected to affect about 50,000 acres and 150,000 acres, respectively.
Of the latter figure 50,000 acres will be affected by oil development, with
100,000 acres impacted by gas.
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RCSOUKO f'lANMNC ASSOCIAffS, IN'C
*4 MM III Mill I • I MANNM IflftlllN OJI M
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SOUTHERN COOK INLET
General Assumptions
This alternative involves development in the southern portion of
the Cook Inlet Basin. Six oil fields and 21 gas fields have been dis-
covered in the northern portion of the basin. Four lease sales are
assumed under the U.S. Department of the Interior schedule for 1975-
1978, with one sale occurring each year. As many as 2.5 million acres
could potentially be leased by a joint federal/state program through
the mid-1990's. The State of Alaska Division of Oil and Gas
estimated the potential recoverable reserves in the Southern Cook
Inlet at 2.5 billion barrels of oil and 18.4 trillion cubic feet of
gas (1974 estimate). As this estimate may include additional pro-
duction in the northern portion of the Cook Inlet, especially the Ktnai
Field, we assumed a potential of 2.4 billion barrels of oil and 12
trillion cubic feet of gas as a reasonable estimate of Southern Cook
Inlet potential.
Exploration
The closeness of the alternative area to known oil and gas pro-
duction is likely to induce a high level of exploration. Assuming lease
sales are conducted according to schedule, oil exploration would com-
mence in 1975 and be completed by 1993; gas exploration would parallel
that for oil. It has been assumed that 6 oil and 6 gas discoveries will
occur during this period, the majority occurring within 10 years of the
commencement of exploration. 5 delineation wells are assumed to be
drilled in the two years subsequent to each discovery to outline the
field.
Development
It is assumed that the discovery size wili be 400 million barrels
of oil and 2 trillion cubic feet of gas. These are the average sizes
of the Northern Cook Inlet discoveries. Discoveries may consist of
several smaller fields adjacent to one another that allow simultaneous
development and utilize the same transport facilities. Four platforms,
with 24 development wells each,ar2 assumed to be necessary for each oil
field development. Eight wells per year are assumed to be drilled on
each platform until development of the platform has been completed.
Gas development is assumed to require 320 acre spacing, with 8 wells
being drilled from each platform.
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RISOURO HANNINC ASSfX IAIfS INC
M MAllll lltll I • (AMUUM, MV.VWMUMIIV iUIIB
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Production
The initial well flow rate in the Southern Cook Inlet is assumed
to be 1500 barrels per day. This will decline to 1000 barrels per
day, at which time the field would be put on secondary recovery. Gas
is assumed to be produced both as a by-product of oil production and
from gas wells. Each oil well is assumed to produce 1.5 MMCFGPD, and
each gas well 15 MMCFGPD.
Facilities
As production of oil and gas increases in Southern Cook Inlet,
more oil and gas facilities will be constructed on the Kenai Peninsula
to support producing activities. Offshore platforms will have the
facilities for gas/liquid separation and self-sustaining power generation.
Onshore, required new facilities will include a dock and loading
facilities for oil and gas transport. Unlike more remote areas, housing
for personnel will be in adjacent towns.
Oil produced offshore will flow to onshore gathering centers and
from there to storage at a new terminal. If oil development occurs as
expected, the new crude terminal will be built on the Kenai Peninsula
adjacent to the producing areas, perhaps near Anchor Point at the end
of Kachemak Bay.
Major facilities there would include:
e Buildings for offices, control and maintenance
• Power plant
• 2 berths, capable of handling 250,000 DWT tankers
• 7-500,000 barrel crude tanks initially and 10 tanks
ultimately .
Gas produced in the Southern Cook Inlet will be processed and
liquefied onshore in a new LNG plant(s). This facility in the Southern
Cook Inlet area is expected to be built on the land near Anchor Point.
Existing LNG facilities are currently operating in the Upper Cook
Inlet. However, as oil and gas development occur in the Southern Section,
new LNG facilities will be required there, because the volume of gas
will be very much greater. To process and transport all of the gas
anticipated from this province, gas processing and liquefaction
facilities will have to have a total capacity of 1.5 to 2.0 billion
SCFD, consisting of 3 or 4 500 MMSCFD refrigeration/compression units.
The associated terminal would have two berths capable of servicing LNG
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RISOlWf HlA.NM.v; ANSOCIAIIS, INC
44 aiMlll Mill I • «*«»«.I* J lllrj t |S OJI W
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carriers of up. to 165,000 cubic meters capacity.
There is also the possibility for the construction of a large
refinery (200,000 BPD) in the Cook Inlet to supply fuel oil and
distillates to the West Coast in the mid to late 1980*s. Production
of crude would support such a refinery by 1985, but its construction
depends on the need for new refinery capacity on the West Coast. It
is more likely that a large refinery would be built near Seward
utilizing crude oil from the Gulf of Alaska.
Impact Area
Oil and gas development in Cook Inlet could directly affect
80,000 offshore acres, as well as onshore acreage for the LNG plant
and transport facilities.
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RESOURCE PLANNING AViUfJAIIS. INC
44 tt41llt Slim • (AMJfllKJ M>iSVU Ifinj Its
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PRUDHOE GAS - EL PASO
General Assumptions
There is no gas currently being produced from the Prudhoe Bay
region, and none is expected under the base case scenario. Gas pro-
duced with the oil will be fed into a gas-injection plant to be
directed back into the original producing zone until facilities cire
available for its production.
The El Paso Alaska Company, a subsidiary of El Paso natural Gas
Company, has estimated the in-place gas reserves at Prudhoe Bay to be
13.4 trillion cubic feet of solution gas and 21.7 trillion cubic feet
of associated gas. Recoverable reserves are estimated to be in excess
of 27 trillion cubic feet - 29.2 trillion cubic feet over a 25-year
period (El Paso). This development alternative assumes that the El
Paso Alaska Company will be able to render transportation service to
"parties" who may own or control Alaskan gas in the Prudhoe Bay region.
The El Paso Trans-Alaska Gas Project will include a gas pipeline system,
a liquified natural gas plant, a marine terminal, and a liquefied
natural gas carrier fleet.
Exploration and Development
It is expected that exploration and development for gas, which have
already been initiated in Prudhoe Bay in conjunction with oil explora-
tion and development, will continue until the pipeline is prepared to
operate. An initial 800 million cubic feet per day of solution gas will
be produced for 3 years from oil wells prior to the start-up of the
pipeline system. Six-hundred-forty-acre development spacing is assumed
for this development alternative.
Production
It is assumed for the purposes of the alternative that Federal
Power Commission approval will be granted to the El Paso pipeline pro-
ject by 1976, that accelerated construction activity will last through
1979, that construction of the compression stations will be completed
in l1! years," and that the pipeline will be ready to operate by mid-1980.
Gas production during that year is expected to be 2,100 million cubic
feet per day, and gas available to the pipeline is expected to be 1,600
million cubic feet per day. The production forecast' is a gradual build-
up to 4 billion cubic feet per day in the 10th year of operation,
declining to 3.3 billion cubic feet per day by 2000.
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fUSOUKU PLANNING ASSOIIAIIS. INC
M ¦ftAtlll MINI • (Atdt'lMj UAVSMJHIMm »l/l«
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Facilities
Necessary pipeline facilities will include a central gathering
center at Prudhoe Bay; 809 miles'of 42" pipeline from Prudhoe Bay to
Gravina Point on the southeast coast of Alaska; and 12 compressor stations.
Hie gas liquefaction plant will require:
• Carbon dioxide gas removal (50 ppm or less) facilities
• Molecular sieve dehydration units
• Eight refrigeration/compression modules of approximately 380
million SCFD capacity
• Four 550,000 barrel insulated storage tanks
• Vapor recovery system for tanks and vessel loading equipment
• A power plant - gas turbine driven with diesel engine backup
® Air fractionation equipment to provide nitrogen for purging and
blanketing
• Buildings for administration, maintenance shops, warehouse space,
process control and cafeteria
• Permanent onsite houses and a recreation facility
• itoo berths each capable of handling LNG carriers of up to 165,000
cubic meters capacity.
The land requirement for the plant is approximately 1200 acres of
which 395 acres is for the plant, 55 acres for support facilities (e.g.,
housing, heliport) aftd 750 acres for a green belt around the plant.
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RESOURCE IM.ANNINC* ASM >C IATIS. INC
44 MAftll Mill! • lAMIIflM.! I t\ >U\ 10
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Exhibit 15
EL PASO GAS
primary impact
is* « r
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GULF OF ALASKA
General Assumptions
The Gulf of Alaska's potential reserve area encompasses a large
offshore section of the Pacific Ocean, stretching from the tip of
Rodiak Island north along the coast and then south to the Alexander
Archipelago. Both federal anfl state lease sales are scheduled for
locations within this area in the near future. Federal sales are planned
for 1975 and 1976 by the Department of the Interior, with the 1975 sale
area extending off Alaska's southern shores seaward from the 3-mile
state territorial water boundary out to the 200-mile line, from the cen-
tral Prince William Sound area east to Yakutat and down to Cape Fair-
weather. It is on a general east-west line north of Juneau. The
federal sale scheduled for 1976 will occur in a region east and south
of Kodiak Island. A state sale is scheduled for 1977 in the Yakutat
Bay region. This development alternative assumes that leasing and
exploration will commence according to the above-mentioned leasing
schedule, although weather conditions which are somewhat severe, and
the substantial potential for earthquake occurrence may alter this
schedule.
Recoverable reserves have, been estimated at 10 billion barrels of
oil and 40 trillion cubic feet of gas (RPA).
Exploration.
Fifty geologic structures and 340 exploratory wells are assumed
for this development alternative. Exploration is expected to commence
in 1977 and cease in 1996. Further, the exploration and discovery
process will occur in "jumps" - i.e., if one field were discovered in
an area," exploration would most likely be intensified, resulting in the
high probability of discover/ of other, smaller fields. Oil discoveries
are assumed for 1979, 1981, 1983, 1985, and 1990, with 2 billion barrels
of oil per discovery. Gas discoveries are assumed to parallel oil
discoveries. Fifteen delineation wells are expected for each oil field,
five for each gas field. Delineation wells are drilled from rigs
similar to those used for e^qploration.
Development
Development is assumed to begin in 1983 and to be completed by
1998. Three-hundred-twenty-acre spacing is assumed for development,
with eight wells to. a platform. Moreover, since we assumed 200 wells
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RIM)URCF PlANNINi; ASSIXTIAIIS, INC
M MltJI • ( AM4*0K J. WAViAl Hlrd t fS rt/IU
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will be required to develop each oil field, 25 platforms will be needed
per field. It will take 1 year to move each platform into location and
to begin operations. Gas development is assumed to lag oil development
by one year, with 64 wells being drilled for each gas field (320-640
acre spacing).
Production
Initial oil production is assumed to occur in the fourth year of
development, with full production estimated for the fifth year. When
production begins in the Gulf of Alaska, the output is estimated to be
480,000 BOPD. Total production is expected to peak in 1997, with an
annual output of over 2.0 million BOPD. Initial production from each
well is assumed to be 3,000 BOPD, declining to 2,000 BOPD. When water-
flood occurs, 100 wells in each field will be producers, each producing
4,000 BOPD. Hie normal life for each field is projected to be 16 years.
Gas. production includes both production as a by-product from oil
production and production from gas wells. Each oil well is assumed to
produce gas at a rate of 2 MMCFGPD. Each gas well produces at 20 MMCFpp.
Thus each oil field has a production capacity of 4Q0 MMCFGPD, each gas
field a production capacity of 1280 MMCFGPD.
A total of 1,719 wells are estimated for the Gulf of Alaska region,
1,384 of which will be production wells (500 water injection). The
remaining 435 will be exploratory and delineation wells.
Facilities
The land facilities required to support such production levels will
include docks and the construction or expansion of air strips at Yakutat,
Cape Yakutaga, Cape Junken, Seward, Kodiak and Sitkalidak island. An
alternative site for development of facilities is Cordova which might
serve areas off Montague and Hinchinbrook Islands.
Each field would require construction of sea-floor gathering centers
and pipelines to onshore gas facilities. Oil production from each of the
six discovery area*; is assumed to be loaded onto tankers via less expen-
sive single point moorings and floating storage systems developed for
North Sea use.
Gas produced from the Gulf is assumed to be shipped to the contigu-
ous 48 states for sale. Consequently, processing and liquefaction plants,
and terminals for LNG carriers will be required for each of the six
major offshore areas. The sequence of probable construction and estimated
size ranges are:
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REMMIKCL I'LANNINC. A>VH'IAHS. INC
«4 UAIIII MBIII • I 4MIIDHJ M»SSAl m>M MS
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Plant Location
Production Rate
Probable Date
of Initial
Production
1. Yakutat
1.5-2.0 Billion SCFD 1985
2. Cape Yakataga (Cape Suckling 1.5-2.0 Billion SCFD 1987
to Icy Bay area)
3. Cape Junken (offshore pro- 0.5-1.5 Billion SCFD 1990-95
duction South of Montague
and Hinchinbrook, Islands)
4. Seward Area (Resurrection
Bay or Day Harbor)
0.5-1.5 Billion SCFD 1990-95
5. Kodiak (or Maimot Island)
1.0-2.0 Billion SCFD 1985-95
6* Sitkalidak Island
1.0-2.0 Billion SCFD 1985-95
As discussed in more detail in the appendix on oil and gas facili-
ties, there is a significant possibility of a large 200,000 barrel per
day refinery being built in Alaska after 1985. By that time oil develop-
ment will have begun in the Gulf of Alaska, making crude available
adjacent to good prospective deepwater terminal sites. In this alter-
native it is expected then that one 200,000 3PD refinery will be built
on the Gulf of Alaska by 1990, probably on Ressurrection Bay near
As a potential refinery site (if oil is discovered within a reason-
able proximity), Seward has several advantages over other locations.
The most important advantage is that the city of Seward has an infra-
structure capable of absorbing the increased social and economic activity
resulting from the operation of a large plaint employing approximately
400 workers. An additional favorable aspect of a Seward site is that a
refinery built on Resurrection Bay near Seward would have road access to
Anchorage and other areas of the State. Its proximity to the population
center of Alaska would increase the access to more goods and services
for the plant as well as for the employees. Unlike the TAPS terminal
at Valdez, a Seward/Resurrection Bay site would have relatively clear
access to open seas in the Gulf of Alaska, thus minimizing the risk of
oil spill from an accident at sea.
Any site along the rim of the Gulf of Alaska raises the spector of
damage caused by seismic activity. In the Seward area the risk of earth-
quake damage is relatively low compared to other sites. Few geologic
faults exist in the vicinity and the rock base in the area is not as
unstable during an earthquake as the area around the Cook Inlet and
Anchorage.
Seward
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MSOURCE PLANNING ASSOCIATE, INC
u nAtM imn • CAMticuu. MAWutftAiiiv iuim
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An alternative to a Seward site would be a refinery on the Kenai
Peninsula in the Cook Inlet. Crude oil production is expected to
reach 200,000 BPD there by 1985, which would support a large refinery.
However, whether a site is selepted at Seward or Kenai will depend to
a large extent on the time at which large refining capacity additions
will be required on the West Coast and may be supplemented by Alaskan
refining capacity.
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RCSOURCC PLANNING ASSOCIATES, INC
44 nAflU STftllf • CAMUHHJ, MASVAOUAim Oil to
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BEAUFORT SEA
General Assumptions
This alternative involves development of the Alaskan offshore area
extending from the U.S.-Canadian border to Point Barrow in the Beaufort
Sea. In developing the initial exploration and production projections
for this alternative, we assumed that drilling in ice-bound waters will
be limited to depths of 20 feet or less until about 1985.
Currently, federal and state lease sales are scheduled for 1975,
1976, 1977, and 1978. Given the existence of some promising geologic
structures offshore from (and also within) the National Arctic Wildlife
Refuge, significant offshore discoveries in the Beaufort Sea would pro-
bably result in a lease sale off the coast of the Refuge. To considet.
the near maximum impact of oil and gas development, it was assumed that
even this sensitive offshore acreage will be leased in 1980.
Estimates of economically recoverable oil reserves in the Beaufort
Sea are about 8 billion barrels, and it was assumed this oil will be
discovered in four major pools.
Exploration
Until 1985 exploration will be confined to water depths of 20 feet
and/or to offshore islands. Beyond 1985, new technology will allow
drilling in deeper water.
Beginning with announced plans and projecting exploration paralleling
the Prudhoe "model," exploration will begin in 1975 and is expected to
continue until about 1990. Discoveries are assumed to occur in 1978,
1979, 1980, and 1990, consisting of an average of 2 billion barrels of
recoverable oil reserves and 3 trillion cubic feet of gas per discovery.
A discovery may actually consist of several smaller pools in the same
general area, which are thus*economic to develop. Each discovery is assumed
to contain both oil and gas in economic quantities. Given the experience
of North Slope development, we assumed 15 delineation wells will be drilled
per discovery.
Development
Completion of development wells is assumed to lag discoveries by
4 years. Therefore, oil development wells, with 320 acre spacing, will be
drilled beginning in 1982 and completed in 1996. Gas development, utilizing
640 acre spacing will lag oil development by one year. Gathering centers
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Rf SOURCl PLANNING ASSOUAHS. INC
*• MM1lt Mint • ( AMMUH4 »nni I I* fU'l M
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are assumed to be connected to the system feeding TAPS or another parallel
pipeline of roughly equivalent capacity.
Production
Oil production is expected to follow exploration by 4 to 6 years.
Average production rate per well is assumed to be 6,000 BOPD initially,
declining to 4,000 BOPD, then remaining relatively constant over time
because of the application of waterflooding to the reservoirs to main-
tain an economic producing rate. The flopr rate will be 480,000 BOPD
in 1984, reaching a maximym of 1.68 million BOPD in 1994.
Gas production is assumed to result both as a by-product of oil
production and from the gas wells. Each oil well will produce gas at a
rate of 1 MMCFGPD, each gas well at a rate of 8 MMCFGPD. Gas production
is assumed to begin in 1985 at a rate of 800 MMCFGPD, peaking in 1990
at 3 BCFGPD. A 12 year life is assumed for the gas cap of each field.
Facilities
The onshore facilities required to support this development will be
a dock for summer use, permanent quarters with 200 beds, and an airstrip
for delivering supplies in the-winter. Other than the wells and rigs,
additional producing facilities required will be an onshore gathering
center and separation oil/gas facilities, and a small topping (distillation)
plant with a capacity of 4,500-5,000 barrels per day to provide fuel
oil to power the. equipment.
Impact Area
The area directly affected by the producing operations is expected
to be some 50,000 acres per field offshore. Not all of the area will
be covered by facilities; rather, the figure represents the total acre-
age traversed by pipelines and bounded by wells. Onshore support facili-
ties such as the airstrip and housing will affect an estimated 10,000
acres per field.
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RIMJURCE HANN1NC, ASS<>CIAUS, INC
44 HAIIII Slllit • < 4S4RHM.I MV.SAI IN r,ll It «»; I ta
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Exhibit 1?
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NAVAL PETROLEUM RESERVE #4 (SLOW)
General Assumptions
Naval Petroleum Reserve (NPR) #4 encompasses an extensive area of
northern Alaska, from the Colville River on the east to approximately
Icy Cape on the west. It extends from the coast of the Arctic Ocean
to at least 50 miles south of Lookout Ridge in the Brooks Mountain
Range.
Potential reserves are estimated at 10 billion barrels of oil and
14 trillion cubic feet of gas (RPA). The normal leasing procedure is
not expected to occur within NPR-4 unless Congress places the area
under the aegis of the U.S. Department of the Interior. Unless this
occurs, it is assumed the Navy will continue to manage and thus control
exploration and development of oil and gas in the region. However, the
Navy has let contracts for exploratory drilling services in the past,
but iii any case, all development will be conducted under contract to
either the Navy or the Department of the Interior.
Exploration
It is assumed that exploration will be pursued on the 'basis of
maximizing reserves rather than following a competitive strategy. The
first 10 years of exploration are expected to be concentrated in the
northern half of. NPR-4, with further exploration (1985-2000) focusing
on the southern portion.
The first stage of exploration is assumed to commence after 1975,
with discoveries assumed in 1978, 1980, 1982, and 1983. The 1978
discovery is expected to be a medium-size reservoir resembling the
Sadlerochit Reservoir of Prudhoe Bay. This would consist of a poten-
tially recoverable 4 billion barrels of oil and 8 trillion cubic feet
of gas. The subsequent discovery of three smaller fields in 1980,
1982, and 1983 could reveal the potential of 2 billion barrels of
recoverable oil and 2 trillion cubic feet of recoverable gas per field.
(It should be noted that discovery of a field would not necessarily
encourage accelerated exploration in this alternative.)
The second stage of exploration, projected to occur from 1988 to
2000, is assumed to lead to discoveries of several small fields the
size of Umiat (100 million barrels of oil) or of Gubik (500-1000
billion cubic feet of gas). These would be developed in the late 1990's
on a basis similar to the development alternative for Prudhoe Private.
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RtNOUKCf PLANNING ASSOCI-MIS. INC.
44 IIAIIIt Mllll ~ (AMaUMJ MA\VM ItlrMlft 0'IM
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Development
Development of the medium-size field assumed to be discovered in
the northern portion of NPR-4 1^1978 would commence in 1983 and be
completed by 1989. Development of the three smaller fields would begin"
in 1983, 1985, and 1988, and end in 1988, 1990, and 1993, respectively.
Production
A 14-year life for oi^. fields and a 12-year life for gas fields is
assumed. Initial production from the medium-size oil field is expected
to be 750,000 BOPD in 1986. Total production will rise to a peak of
2.0 million BOPD the following year as the smaller fields are brought
into production. Gas production is estimated to commence at 1.0 billion
cubic feet of gas per day in 1989, reaching a high of 3.5 billion cubic
feet of gas per day by 1990. The production rate for the medium-size
oil field is assumed to be 5,000 BOPD initially, declining to 3,000 BOPD;
the rate for the siaaller fields is assumed to be 3,000 BOPD initially
declining to 2,000 BOPD.
Three-hundred-twenty acre spacing is assumed for oil development;
640 acre spacing is assumed for gas wells.
Facilities
The NPR-4 (Slow) alternative assumes an original plan to loop into
the TAPS pipeline. However, as smaller field discoveries demand
additional capacity in 1983, a new pipeline(s) will have to be constructed
along the TAPS route. * Work on this additional pipeline is expected to
commence in 1983 and be completed by 1987. A 150-mile extension from
the TAPS route to the medium-size field will be completed in 1989.
An alternative route South from NPR-4 is also feasible linking with
East-West pipelines to the TAPS route in the East or a new Western Alaskan
pipeline to the West. Though this is possible the more likely occurrence
is a pipeline to the origin of the TAPS line. The reason for this judgment
is that in the course of constructing the TAPS pipeline all major support
structures (such as bridges) have been designed to accommodate a second
crude pipeline should it become necessary. As a result, a considerable
construction cost saving would be achieved by using the TAPS route and a
major parallel pipeline.
Smaller-diameter pipelines will connect the fields to a central
gathering center with facilities of Prudhoe Bay size. Each field is
expected to have large, temporary facilities during development, with
small-to-medium permanent facilities during actual production. Two
dock.facilities will also be required.
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KtSOUKCt riANNINC*. ASM K.IAIIS, INC.
44 MAITII Mllll » (AMUIItaj MASVM HIM I i\ (1*1 If
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Impact Area
The area of direct development impact is assumed to be 64,000.acres
for each of the three smaller fields and 96,000 for the medium-size field.
Each gathering center will require the use of 20,000 acres.
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RtSOUKl E MANNING ASSOCIAHN. INL
44 UMIII Mill I • '.AMMKMJ MAV.AT.IMrj I l> tf.'t HI
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pnj(Src4
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KOTZEBUE - KOTZEBUE SOUND AREA
General Assumptions
This arm of the Chukchi Sea was considered a separate oil and
gas subregion because it consists primarily of native- and state-controlled
acreage and because exploratory drilling is already under way.on native
lands, which distinguishes Kotzebue from the much later development
expected in the Chukchi Sea.
Estimates by the State of Alaska's Department of Natural Resources
puts potential recoverable reserves at 700 million barrels of oil/ 5 trillion
cubic feet of gas.
Exploration and Development
Assuming the state will obtain leasing rights to a majority of
Kotzebue Sound, exploration will probably proceed rapidly. Indeed,
native lands will be explored under concession agreements already
negotiated.
Onshore and offshore leasing is expected to occur over the 1975-
1983 period, and will result in two discoveries in 1977' and 1979 of
about 350 million barrels each: An average of five delineation wells
are assumed per discovery well. Development will probably cover the
period from 1978 to the end of 1985.
Production
Initial oil production is likely to occur in 1980, reaching a peak of
200,000 BOPD in 1985. Gas production is not considered in the scenario,
principally due to transportation requirements. These would probably make
gas production uneconomic until the Chukchi Sea production begins in the
late 1990's.
Facilities
Support facilities are likely to include the expansion of the airstrip
at Kotzebue, the.construction of a dock, a small topping plant (2,000-2500 BOPD)
for fuel oii and permanent living quarters for approximately 200 persons.
An onshore gathering center with 170,000 BOPD capacity will also be required.
North of the Aleutian Island chain the existence of pack ice is fairly
common and the likelihood of technology becoming available to permit year-
round tanker operation in the Bering Sea is unlikely. Even if tankers
like the ESSO Manhattan were fitted or designed with special hulls, the
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krsoi'kn punsiv; av>ociaiis. inc
44HMIII Stllll • f *M**llV» MASSAI tflMIIS (UIU
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ice movements would undoubtedly damage any kind.of fixed berth or single
point mooring device now known. Consequently, it is estimated* that a
second major crude oil pipeline will probably be required to deliver oil
from Kotzebue and Norton Sounds to the ice-free Gulf of Alaska.
The oil flow from Kotzebue, which is expected to reach 170,000 BOPD
by 1985, will not justify a new 650-700 mile pipeline to the Gulf of Alaska.
However, given the potential for oil in Norton Sound, the Bethel Basin,
and Bristol Bay, a Western Alaska pipeline route is feasible. The portion
of such a pipeline originating at Kotzebue Sound will be necessarily small
(perhaps 24" diameter) connecting with larger pipe at Koyukuk.
Another possibility for transport would be the construction of a large
pipeline in Western Alaska-to carry oil from the Chukchi Sea province.
While this is certainly feasible, it is more likely that Chukchi oil will
be transported via the TAPS route. The late development of Chukchi would
permit an increasing quantity of Chukchi oil to fill the capacity of the
TAPS (1st or 2nd) line as North Slope production declines.
Should no oil be found in Norton Sound or the Bethel Basin (Kuskokwim
Bay area) a western route seems less likely. In that case, a line may be
constructed eastward to connect with the TAPS line.
Impact Area
An estimated 22,000 acres per field offshore and another 10,000 acres
per field onshore will be affected by Kotzebue development.
*RPA estimate.
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RCSOIJKCC riANNINt, ASSOCIAUS. INC
44 UAItlf Slim • I AUttnxj miMlttlUIII
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Exhibit 23
kotzebue- kotzebue sound
BEXMMtt IM^C1 ««A
( »• >* f *m .« »• ,« •« » — » •
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\fiSi » i • t «'* fc » # * ~ , ^ - A<
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u ¦•¦¦»'> * • • • • •••- • * , _ •
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• • . fT • " ~srxf~f»J' , : .. '. f ^'ijULf I } i »• <
: : j : .rdyf ¦¦/^SLj r^T' ' •
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-------
BRISTOL BAY
General Assumptions
The Bristol Basin is a potential oil-producing area that covers
about 95,000 square miles of Bristol Bay (a section of the Bering Sea)
and adjacent onshore areas. Development of this region will be com-
plicated by the fact that federal, state, and native leasing programs
must be taken into consideration. However, since the higher potential
areas lie in the 80 percent of the basin that is offshore, most of the
exploration, development, and production is assumed to occur in the
federal and state offshore acreage.
Leasing in the Bristol Basin area is expected to follow three
separate schedules, depending on whether the acreage is federal-,
state-, or native-owned. Federal sales are expected to begin in 1976
and recur at 2-year intervals until 1984. Only one state sale is
expected to occur (in 1980) , while native concession agreements with
oil companies are likely to be made by 1986.
Exploration
To date nine exploratory wells have been drilled onshore. Another
10 wells are expected to be drilled onshore in the next 2 years, pri-
marily to satisfy native concession agreements. Offshore exploration,
on the other hand, will not begin until 1977, and will probably be
completed only by 1995.
The potential recoverable reserves are assumed to be 5 billion
barrels of oil, of which 90 percent is offshore. In the basin, approx-
imately 25 oil-bearing structures are assumed, requiring 50 exploratory
wells. Discoveries are anticipated in 1979, 1981, and 1985; the
discoveries are assumed to be 2 billion barrels each. In actuality,
however, each discovery may consist of several smaller fields found
during delineation. In this case, 15 delineation wells are expected
per discovery.
Development
Development (mainly offshore) of the.Bristol Bay area is expected to
begin in 1981 and be completed by 1992. As in other areas, wells are
assumed to be drilled with 320 acre spacing, with eight wells drilled
per platform.
Production
Initial total production (i.e., in 1981) is expected to be 200,000
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RrsOURCf PIANNINC. A
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BOPD, peaking in 1987 at 500,000 BOPD. The average rate per well in
1981 will be 3,000 BOPD. As the well-production rate declines to 2,000
BOPD, water flooding will be instituted to sustain that rate until the
field is depleted.
Facilities
Since most of the production will be offshore, and since tankers
will take on the oil offshore, it is assumed that permanent onshore
facilities requirements wij.1 be small. However, a dock for summer use,
an airstrip for access throughout the year, and living and service
facilities for approximately 400 persons will be necessary.
An alternative to offshore tanker transport is a pipeline to Cook
Inlet, from which transport to the lower 48 states would be effected.
This alternative is discussed in the Kotzebue alternative.
Impact Areas
The areas affected by this development are assumed to be 60,000
acres offshore and 10,000 acres onshore for each of the first two dis-
coveries. The third discovery will affect 30,000 acres offshore and
another 5,000 onshore.
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RLSOURll I'iANNINC ASSOCIAIIS. INC.
44 HAT III SIIIII • lAMIftllM.t IAN I Is >UtV
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NAVAL PETROLEUM RESERVE #4 (FAST)
General Assumptions
Naval Petroleum Reserve (NPR) #4 encompasses an extensive area of
northern Alaska, from the Colville River on the east to approximately
the Kokolik River on the west. It extends from the coast of the Arctic
Ocean to at least 50 miles south of Lookout Ridge in the Brooks Mountain
Range.
Potential reserves are estimated to be 20 billion barrels of oil
and 27 trillion cubic feet of gas (RPA). The normal leasing procedure
is not expected to occur within NPR-4 unless Congress places the area
under the aegis of the U.S. Department of the Interior. Unless this
occurs, it is assumed the Navy will continue to manage and thus control
exploration and development of oil and gas in the region. However, the
Navy has let contracts for exploratory drilling services in the past,
but in any case, all development will be conducted under contract to
either the Navy or the Department of the Interior.
Exploration
Exploration is assumed to pursue a maximum-discovery strategy, with
the first 10 years of exploration (1975-1985) concentrated in the northern
half of NPR-4; further exploration (1985-1995) will be concentrated in
the southern portion of NPR-4. Small field development in the late
1990's will be similar to that described in the NPR-4 (Slow) alternative.
Discovery of a giant field is expected in 1978, with the potential
recovery of 10 billion barrels of oil and 15 trillion cubic feet of
gas. As a result of this discovery, exploratory activity will be accel-
erated, .thereby leading to discoveries of five smaller fields in 1979,
1981, 1982, 1983, and 1985.
Development
Development of the giant oil field will begin in 1981, with over
200 wells to be drilled by 1987. Oil development in the giant field
will be completed by 1988; waterflood, by 1988. Oil development in the
smaller fields will commence in 1982 and be completed by 1995. Gas
development would last from 1983 to 1990.
Production
Average production in the giant field is assumed to commence at
8,000 BOPD, declining to 5,000 BOPD; thereafter, the field will be put
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RISOUKO PIANNIN<; ASSOOAMS. INC
44 IRAl IK ^1 til I . < AMIIHM A MASvSf rsll 11.M 10
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on waterflood, producing 10,000 BOPD per well (assuming 200 producers).
Average oil production for the smaller fields is expected to be 4,000
BOPD per well, declining to 2,000 BOPD; thereafter, these fields will
be put on waterflood (assuming 100 producers), producing 4,000 BOPD per
well. Three-hundred-twenty acre spacing is assumed for all oil development.
Gas production beginning in 1986 will last until 1997. Six-hundred-
Eorty acre spacing for additional gas development (i.e., beyond the time
oil development has ceased) is assumed. Gas production will consist of
gas produced as a by-product of oil production, as well as gas produced
from gas wells.
Facilities
Development of the giant field will require an additional 48" oil
pipeline along the TAPS route plus a 150-mile extension along the North
Slope to the field; a gas pipeline along the same route plus a 150-mile
extension; facilities on the scale of Prudhoe Bay; and two docks.
Smaller-field development will require an additional oil and gas
pipeline along the TAPS route; a 150-mile extension along the North
Slope to a central gethering center; small-diameter pipelines from the
central gathering center to the fields; facilities at the gathering
center; temporary development facilities and small permanent production
facilities at each field; and two docks.
Gas production would require pipeline and liquefaction facilites
similar to those for the El Paso alternative.
Several alternative pipeline routes are possible other than the
one shown in Exhibit 27. One route would consist of running the pipeline
through Anaktuvuk Pass to the west of the pipeline route, than joining
TAPS at a point further to the south. Another route would involve a
western pipeline to Kotzebue, then to Cook Inlet (see Bering Sea alter-
native) . The route chosen would probably depend on the combined amount
of oil and gas from the alternative areas and the capacity constraints
of existing pipeline and transport facilites.
Impact Area
The primary area of impact of oil and gas development will involve
120,000 acreas at the giant field and 64,000 acres for each of the smaller
fields. The pipeline(s) route would require a 100 right-of-way. Each
gathering center would necessitate the use of 20,000 acres.
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RISOtJKCC PLANNING ASSOClA I IS. I.\r
44 II 4 IIII M III t « | twaiUN.I IIIN III -J.-: 14
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Exhibit 27
NPR-
PRIMABY ]
g»,aAe«^
Po>nt i0y
-------
BERING SEA
General Assumptions
This development alternative assumes that leasing and exploration
will commence in late 1976, when the U.S. Department of the Interior
has scheduled a sale, despite the lack of environmental impact studies
on the area and the fact the area has not yet been divided into leasing
blocks. This sale will be in the St. George Basin, in the area near
the Pribilof Islands. Subsequent sales, beginning with Norton Sound,
are assumed to occur at 2-year intervals, ending in 1986. (The Bristol
Basin, which consists of Bristol Bay and adjacent onshore areas, is
considered in a separate development alternative.)
The Bering Sea alternative is complicated by potential native and
state leasing in the Bethel Basin, which extends to Kuskokwim Bay and
includes the land area surrounding Norton Sound. It is assumed that
some exploratory activity will commence in these areas prior to federal
lease sales in the Bering Sea; this will tend to escalate the potential
of the outer continental shelf areas.
At present, only geophysical surveys have been conducted in the
Bering Sea; as a result, the potential of the area is undetermined.
We have therefore assigned a potential of 8 billion barrels of oil to
the area. Gas is not considered in the development alternative.
Exploration-
Assuming ejqploration and development will be similar to the Gulf
of Alaska alternative, and drillships will be available to explore with-
out competition for rigs from the Gulf of Alaska, we estimated there will
be 50 geologic structures requiring 100 exploratory wells.
Exploration is assumed to begin in 1977 and be completed by 1990,
resulting in discoveries in 1979, 1981, 1985, and 1987, with 2 billion
barrels of oil per discovery. (Each discovery may in fact consist of
several smaller discoveries in the same area.) Smaller discoveries may
continue into the .1990'sr which will tend to extend the life of develop-
ment and production facilities, but will be too tentative to incorporate
in this development alternative. For this offshore area, approximately
10 delineation wells will be drilled per discovery.
Development
Development will commence in 1982 and be completed by 1994. (Gas
development, which is not considered in this alternative, would probably
extend development to 1999.) To determine the maximum reasonable
RESOURCI WANNINC. *$sOOAIIS. INC,
«4 UAIItl Mllll • iAMMUkJ kU^AIIIlNIIV'UIH
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impacts of development, we assumed the level of development will not be
impaired by competition for resources from the Gulf of Alaska development.
As in the case of other regions, 320 acre spacing for development wells,
with eight wells to a platform, is assumed.
Production
When the Bering Sea begins oil production in 1985, the total output
is estimated to be 300,000 BOPlJ, increasing to 500,000 BOPD in 1986 and
peaking in 1991 at 1 million barrels per day. Average production per
well is estimated at 4,000 BOPD initially, declining to 3,000 BOPD, at
which point waterflooding will probably be used to sustain an economic
rate until the fields are depleted.
Facilities
Hie large distances between potential fields make separate develop-
ment and production facilities necessary for each field. The land facili-
ties required to support production consist of a dock for water access
in the summer, an airstrip (and/or an expanded airstrip in Kuskokwim or
Nome) for continuous access, and additional permanent quarters equipped
with 200 beds.
Production itself will be almost entirely sea-based, except for the
state- or native-controlled areas, which will require land-based facilities.
Gathering centers associated with each field will be connected to
flow centers, pooling flows to a major pipeline.
As noted in the Rotzebue scenario the construction of a Western
Alaska pipeline is expected to transport oil to the ice-free Gulf of
Alaska. At Morton Sound, spur pipelines of about 200 miles will be needed
to connect to the large pipeline system at Koyukuk. Farther south at
Kuskokwim, another pipeline spur would originate at gathering centers
around the mouth of the Kuskokwim river and follow the river basin to a
junction with the anticipated Western pipeline.
Impact Area
The area directly impacted by production (bounded by gathering
lines and wells) is estimated to be about 50,000 acres per field.
The onshore area affected by temporary exploratory facilities and
permanent land-based, production-related facilities is estimated
to be another 10,000 acres per field.
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RESOUKU PLANNING ASSOt.lAllS. INC
m Mitu • i j mrd m turn
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Exhibit 29
KOTZEBUE-NORTON SOUND-BRISTOL BAY-COOK INLET
PIPELINE
(CHUKCHI SEA EXTENSION DASHED)
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CHUKCHI SEA
General Assumptions
This development alternative assumes leasing and exploration in this
region will not commence until 1985, when technology to permit year-
round exploration and development in ice-bound waters deeper than 20
feet will have been developed. It also assumes that federally-sponsored
development of NPR-4 and private development in the Point Bay area (west
of NPR-4) will provide geologic information about this unexplored area.
Leasing in the Chukchi Sea is not expected to occur before 1985, at
which time both state and federal offshore areas are assumed to be
available.
Emigration
Without detailed seismic analyses to draw upon, we have assumed
20 geologic structures will be needed, requiring 40 exploratory wells.
Exploration beginning in 1985 will be completed by 1995. Two discoveries
are expected to be made in 1988 and 1990, each containing approximately
2 billion barrels of oil. (Actually, each discovery may consist of
several smaller discoveries in- the general area.) Potential discoveries
after 1990 will have no effect in the timeframe of this study, and have
therefore been disregarded. Gas has not been included in this alternative,
as any gas production would occur late in the 1990's. An average of
15 delineation wells will probably be drilled per discovery.
Development
Chukchi Sea development is expected to lag discoveries by about 3
years. Therefore first development will occur in 1991, and subsequent
development will commence around 1993. As in other areas, 320 acre
spacing is assumed.
Production
Initial total production from Chukchi in 1994 is anticipated to be
500,000 BOPD, with peak total production of 1 million BOPD occurring in
2000. The average well size is assumed to be 4,000 BOPD. The fields will
be put on waterflood after 3 years for the remainder of their 12-year
life to maintain the average well production at 3,000 BOPD.
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RLbOUKCi PLANNING ASSOUAIIS, INC.
44 Mftllll tltlll • I
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Facilities
The onshore facilities required to support this development are a
dock for summer use, permanent quarters with 200 beds, and an airstrip
for delivering supplies in the winter. Other than the wells and rigs,
additional producing facilities required are an onshore gathering cente:
and separation oil/gas facilities, and a small topping (distillation)
plant with a capacity of 4,500-5,000 barrels per day to provide fuel
oil to power the equipment.
Additional facilities required for Chukchi development are alter-
native pipeline connections to transport systems. The first and most
likely alternative, given the timing of Chukchi growth, is a pipeline
linking Chukchi gathering centers to the NPR-4 pipeline system, which
will, in turn, connect to TAPS or a parallel pipeline to southern
Alaska. The second alternative is the installation of a 24" pipeline
connecting Chukchi to the transport facilities assumed to be developed
in the Nome-Kotzebue area to handle production from Kotzebue Sound.
Impact Area
The total affected area is estimated to be 80,000 acres for each
of the two offshore fields and 30,000 acres per field for onshore
support facilities and the topping plant. An additional land impact
will be created by the need for 150 miles of 100-foot right-of-way for
the connecting pipeline.
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RESOliKCt PlANNINC. A">S< H"l M1 S. INC
•« atAini >t*nr • tuuaciifcj ma\s*< ml-mii* u/nt
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ARCTIC WILDLIFE REFUGE
General Assumptions
She prospect of opening the Arctic Wildlife Refuge for oil explor-
ation is bound to be an extremely sensitive issue, strongly opposed by
environmental conservationists. However, the likelihood of significant
discoveries in adjacent offshore areas of the Beaufort Sea and the
existence of large, high-potential geologic structures in the Refuge make
eventual development of some kind quite possible. Therefore, this pro-
jection assumes that, by 1985, sufficient environmental precautions will
have been taken and the need for oil will be so great that the Refuge
will be opened for exploration.
Exploration and Development
A cautious exploration program is expected to begin in 1985 and
continue until 1990. One majore discovery, assumed to occur around
1966, of Prudhoe dimensions (i.e., 10 billion barrels) is plausible.
Development of the field is likely to span the period 1988-1993.
Production
Production is expected to parallel the Prudhoe Sadlerochit develop-
ment, but peaking at 2 million barrels per day by 1994. Initial pro-
duction rates per well are expected to be 8,000 BOPD, declining to
5,000 BOPD, at which point this production level will be maintained by
waterflooding.
Facilities
A pipeline will be required across the North Slope to TAPS, where
oil from the refuge will fill the TAPS line as Prudhoe declines. Gas
produced would be transported either by the proposed El Paso Trans-
Alaska gas pipeline to Valdez or by the proposed Arctic Gas Pipeline
through Canada. In either case a gas pipeline would be required to
connect the Arctic Wildlife Field to a central flow station at the
pipeline.
Impact Area
The estimated impact area is 120,000 acres.
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RlMH RCL I*I4NMN<; ASSTK M1IS JNC
M M>' .1 V«llf • V i til •>> 1 1 > n.'l is
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ErrhiMt 33
ARCTIC
\ '
WILDLIFE REFUGE
/V
PRIMARY IMPACT AREA \
.«•,« '«:»•».» «»f ¦«»v» * =¦£?*11 * * t* v°- '••* • : '¦• i' *' v^rr
• • •»". «... . . • i : . ** j
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Exhibit 35
Hypothetical Development Levels for
Alaskan Oil ami Gas, 1977-2000
Dovelopnent
Recoverable
P.eserves
Initial
Production Schedule
(thousand barrels per dayi million cubic f
Transportation
Oil
(billion
Ga3
(trillion
Development
Date
Alternatives
1977
1980
19J5
1990
1995
2000
Facility
Location
barrels)
cubic feet)
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Co 3k Inlet Ease
Case
0.8
5
1958
195
300
195
400
17,
¦
800
90
800
800
300
Pipelines
Anchorage and shipping tonamolg
Prudhoe Oil
3aso. Case
9.6
1969
1200
1600
1600
1200
Pipeline (TAPS)
Prudhoe to Valdez
Prudr.oe Private
>*.-jparuk
1.5-2.C
-
1978
334
250-
250
100
Lisburie
Heavy Oil
1.0-2.0
0.2
8.0
1980
1985
50ft
1000
381
86
1000
179
40
1000
84
lodo
Pipeline connec-
tions to TAPS
Other
0.3
2.0
1985,
100
400
47
400
400
Sub-Tctal
2.5-4.5
10.0
384
750
817
400
366
400
84
400
souzh Cook Inlec
2.4
12.0
1980
204
960
384
1600 '
428
1700
1500
Pipelines
Anchorage and shippirg terminals
rruihoe Gas-
Si raso
2S.2
1975-6
2100
3800
3900
4000
3300
Pipeline
Prudhoe to Gravina Pt.
Gulf of Alaska
10.0
40.0
1983
480
1700
1443
6300
1600
7500
1300
5000
Pipelines
Central offshore gatho-ir.cj sta-
tions for transfer to lanfccrs
Beaufort Sea
e.o
16.0
1982
480
800
1240
3000
1680
3000
600
1400
Pipeline connec-
tions to TAPS
Onshore gathering cent its
NPP.-4 (Slew)
10.0
14.0
1982 .
20on
2000
2000
3500
660
3500
Connection*to TAPS
until new pipe-
line along TAPS
route plus ex-
tension
Kotzobue
0.7
5.0
1983
170
160
45
Pipeline
Kotzebue to Norton Sou id
Bristol Bay
5.0
16.0
1981
200
600
1100
2800
1100
3000
800
1700
Pipelines
Central offshore gathering
stations for transfer :o
tankers - o::shore pipe •
lino for native lands.
N'PR-4 (Fast)
20.0
27.0
1982
2000
3600
4000
7200
3700
7200
1560
3600
New pipeline along
TAPS route tor oil
and gas plus exten-
sion
boring Sea
8.0
32.0
1981
700
1200
1700
6000
1700
7000
1200
4500
central offshore gathering
stations for transfer :o
tankers - onshore pi^clino
for native lands
Chukchi Sea
4.0
16.0
1991
340
700
1000
2700
New pipeline or
extension to~joi~n~
NPR-4 system
Norton Sound to Kotzebue
Arctic Wildlife
Refuse
10.0
30.0
1.988
2000
3300
2000
3600
Pipeline to TAPS
------- |