U.S. Geological Survey Open-File Report 03-044
Version 1.0
The National Petroleum Reserve Alaska (NPRA) was partitioned into eight economic sub-areas (Figure 4) in order to estimate oil transportation costs to the Trans-Alaska Pipeline System (TAPS). The assessment geologists allocated the resources assessed in each play to the economic sub-areas, and to Federal and non-Federal ownership within each sub-area.
About 80 percent of the total undiscovered oil resources are from the Beautfortian Upper Jurassic Play Northeast and Northwest (Table 1). Most of this oil was assigned to blocks 110, 120, and 130. Table 3 shows that sub-areas 110 and 120 were assigned about 70 percent of the total oil. With the oil assigned to sub-area 130, the northern blocks (110, 120, and 130) account for 85 percent of the mean estimate of undiscovered oil. Alternatively for gas, the sub-areas 130, 220, and 230 account for almost 70 percent of the mean estimate of gas in gas accumulations; with sub-areas 220 and 230 accounting for just over half of the total gas.
For this study, the pipeline transportation system was assumed built incrementally starting with the eastern most sub-areas (110, 210) and moving west. Consequently, it was assumed that sufficient capacity would be available for the development of discoveries from sub-areas 120 and 130. For example, the regional pipeline connection build-out for sub-area 120 will go from the middle of sub-area 120 (east-west) to the middle of 110, where the pipeline build-out will connect with a pre-built part of the regional pipeline that transports oil from sub-area 110 to the Kuparuk field pipeline that transports the product to the Trans-Alaska Pipeline System (TAPS) Pump Station 1. A similar scheme was envisioned for the sub-areas to the south of 210 and 220, except the oil would be taken to TAPS Pump Station 2. Table A-1 shows the distances.
Within each sub-area, it is assumed that either a 12-inch or 16 inch diameter lateral feeder line from the field to the regional pipeline would be constructed and operated as a separate common carrier. The size of the feeder line would depend on the accumulation size. New discoveries larger than 130 million barrels are assumed to use16 inch laterals and smaller discoveries are assumed to use 12-inch lateral feeder lines. The lateral distances assumed are also shown in Table A-1.
A regulated common carrier pipeline entity was assumed to build and operate the regional pipeline to Kuparuk and Pump Station 2. Pipeline tariff charges were set to assure investors a 12 percent after-tax return on investment. Cost functions presented in Broderick (1992, written communication) were updated to reflect reductions in costs since 1990. First, recent pipeline cost data gathered from the literature and from applications to the Alaska State Pipeline Office (T. Braden, Alaska Pipeline Office, written communication 1998). These data were analyzed and extrapolated to compute costs of pipelines of comparable sizes to those depicted by Broderick (written communication, 1992). These cost estimates were typical of the Prudhoe Bay-Kuparuk area and were increased by 30 percent to compensate for the absence of infrastructure and for the special costs of operating in the National Petroleum Reserve Alaska (NPRA). After review of the trend in 2001 materials cost indices, it was decided to use the investment cost function presented in Attanasi (1999) for computing pipeline investment costs (Figure A-1). The discrete shift in the cost function at distances of every 90 miles reflects the requirement of installation of facilities for an intermediate pump station (Young and Hauser, 1986; Broderick, written communication, 1992).
The estimated investment costs for the 24 inch regional pipeline segments servicing sub-areas 110, 120, and 130, respectively are 275, 294, and 294 million dollars. Similarly, investment costs for the 20 inch regional pipeline segments servicing sub-areas 210, 220, and 230 were 504, 278, and 484 million dollars, respectively.
The estimated tariff (trf) for the lateral feeder lines from the individual field to the regional pipeline was based on accumulation specific reserves. The following formula presented in Thomas and others (1993) and Broderick (written communication, 1992) was used to provide an approximation to the corresponding levelized charge:
trf = [(investment cost)/(field recovery)]*3.35
where the investment cost was calculated for an 12 inch or 16 inch diameter line with the required distances based on those distances shown in Table A-1. Required investment for the short 12-inch and 16-inch lateral feeder lines were estimated at 1.2 million and 1.6 million dollars per mile for the Prudhoe Bay area and inflated by 30 percent for the NPRA. Table A-2 shows the distances and example calculations of pipeline tariffs used in the economic analysis for accumulations with 300 and 600 million barrels of recoverable oil.
It was generally assumed that accumulations were developed as stand-alone fields. Field development costs include well costs (drilling and completion) and the facilities costs. Actual development costs will depend on site-specific characteristics of prospects. Play analysis, however, is not location specific. In the process of developing generic cost functions, a number of simplifying assumptions were made to keep the economic analysis tractable. Undiscovered accumulations were grouped into field size categories starting with 16 to 32 million barrels of oil in oil accumulations, 32 to 64 million barrels, 64 to 128 million barrels, and so forth. Undiscovered accumulations were also grouped by 5,000-foot depth intervals. Development cost estimates for a representative accumulation for each size and depth class were estimated and tested against an economic screen to determine whether all the accumulations in the size and depth category were commercially developable.
A conventional well spacing of 160 acres was assumed. With this assumption, average well productivity (recoverable reserves per well) for an accumulation was computed by using the simulated reservoir attribute values (Scheunemeyer, 2002, unpublished data). For a single accumulation, the number of production wells required for development was computed as the ratio of the technically recoverable oil divided by the average well productivity.
For each accumulation size and depth category, average well productivity (based on an assumed production well spacing) was calculated as the weighted average (based on assessed technically recoverable oil volume) of the well productivity of the predicted accumulations occurring in that size and depth category. Well productivity estimates varied across different depth intervals and within the same field-size category, reflecting the broad variations in reservoir quality of the plays occurring in the depth interval.
As noted in the text nearly seven-eighths of the oil assessed was assigned to depths between 5,000 and 10,000 feet. Conventional well productivity values for this depth are shown in Table A-3. They are representative of the productivity computed from the simulations of the reservoir model. Beaufortian Upper Jurassic plays. These productivity values do not reflect the application of horizontal drilling technologies that might be applied if site-specific conditions are favorable. In order to include the effect of horizontal production wells in the analysis, it was assumed that the conventional well productivity’s shown in Table A-3 could be doubled by drilling horizontal wells with a lateral (horizontal) section of sufficient length. Calculations comparing optimal well locations and drainage patterns indicated that the resources accessed by four conventional wells at 160 acre spacing could be drained by two strategically placed horizontal wells with horizontal laterals of about 3000 feet (Jim Craig, MMS, verbal communication, 2002).
Estimated total drilling costs for conventional wells are based on the number of wells and well drilling and completion costs. The costs of drilling and completing for production wells were estimated from the historical costs reported in the Joint Association Survey (JAS) on 1996-2000 drilling costs (American Petroleum Institute, 1997, 1999, 2000, 2001) for Alaska oil wells. Data from the cost survey were examined, and costs were estimated for three 5,000-foot vertical depth intervals (Note; The assessment geologists did not assign any oil to depths greater than 15,000 feet). The JAS data showed that the 1999 and 2000 per foot costs had increased relative to previous years. The empirical data as well as the initial estimates for 2001 were based on the level of infrastructure in the vicinity of Prudhoe Bay. Cost estimates for NPRA were increased by 30 percent over the costs typical of the Prudhoe Bay area to offset expected extra costs due to the absence of infrastructure or special environmental precautions in the NPRA. The estimated costs of drilling and completing conventional oil production wells in the NPRA are $2.5 million at depths to 5,000 feet, $3.2 million at depths of 5,000 to 10,000 feet, and $5.16 million at depths greater than 10,000 feet.
The following example illustrates the cost estimation procedure for horizontal wells. Suppose the target vertical depth is at 8,000 feet. The vertical portion of the well is deviated until it reaches the target depth, adding as much as 20 percent to drilling length. At the target depth, a lateral portion of 3,000 feet is drilled. The average per foot drilling and completion cost of $270 per foot was assumed to be characteristic for the Prudhoe Bay area. This rate was increased by 30 percent for drilling in the NPRA, so the following relation was used to estimate horizontal development well drilling and completion costs for targets at a vertical depth of 8,000 feet:
[8000ft (1.2) ($270/ft) +3000ft *$270/ft)] *1.3= $4.4 million per well
In this example, the horizontal well adds about 30 percent to the costs of drilling and completing a conventional development well but the horizontal wells reduce the required number of development-wells by half. In addition, it was assumed that 0.4 injection wells will be drilled for each conventional production well (National Petroleum Council, 1981b; Young and Hauser, 1986; Broderick, written communication, 1992). For accumulations developed by horizontal wells, one injection well was assumed to be required for each production well. This assumption insures that there are a sufficient number of injection wells for pressure maintenance via gas and water injection.
Production facilities include drill pads, flow lines from drilling sites, a central processing unit, and infrastructure (and amenities) required for housing workers. Facilities design and costs depend on peak production rates and field size. As of the beginning of 1998, there are seven stand-alone fields operating in Northern Alaska. These fields include Prudhoe Bay, Kaparuk, Lisburne, Milne Point, Endicott, Badami, Alpine, and Northstar. British Petroleum is in the process of shutting down Badami. Endicott, which started producing in 1987, was the last stand-alone field developed until Badami, Alpine, and Northstar came on-line in the early 2001 and 2002.
Little information about the costs of facilities in oil development in Northern Alaska from private operators is in the public domain. A version of the Northstar field development plan, along with generic drilling, pipeline, and facilities costs, was made public by British Petroleum when it requested relief of profit sharing provisions of the State lease. With this information and with inferred facilities cost estimates from published reports for other fields under development, a cost relationship that specified investment cost per barrel as a function of peak fluid flow rates for facilities for fields in the Prudhoe Bay area was calibrated [1] . These estimates, when applied to new discoveries in the NPRA, were increased 30 percent to compensate for the absence of infrastructure and special rules associated with field development in the NPRA.
A previous study (Attanasi, 1999) provided the basis for the facilities investment cost estimates by accumulation size class (Table A-4). The flurry of activity in the oil industry during 2000 resulted in some inflation in oil field equipment costs but there appears some return to earlier levels. Moreover, implementation of new technology continues to reduce costs in Northern Alaska (Williams, 2002a; Advance Resources International, 2001). The costs shown in Table A-4 were increased by 5 percent to account for general cost increases in oil field equipment that occurred from 1996 to 2000 (American Petroleum Institute, 2001).
The Point McIntyre, Niakuk, North Prudhoe Bay, and West Beach fields share the central processing facilities at the Lisburne field. Use of the central processing unit at the Lisburne field saved the Point McIntyre operators 35 percent in overall facilities investment costs (Thomas and others, 1993). Such savings, however, are highly site-specific. Distances between production wells and central processing units may limit sharing opportunities. In this economic study, facilities-sharing was limited to sub-areas 110 and 120 and to fields having less than 130 million barrels of technically recoverable oil. It was assumed that facilities sharing would, on average, result in a 30 percent reduction in facilities investment costs.
Future discoveries are assumed to attain peak annual rates of production equal to the percentage of the accumulation’s ultimate oil recovery. Table A-5 shows the assumptions relating to the accumulation production profile. Those accumulations having less than 130 million barrels of recoverable oil are assumed to reach peak production in the second production year and to maintain the peak production level for 2 years, after which annual production will decline 12 percent per year. Accumulations larger than 130 million barrels are assumed to reach peak production in the third year, maintain the peak production level for 2 years (through year 5), after which annual production will decline at 12 percent per year. Accumulations larger than 1 billion barrels of oil are assumed to reach peak production in year 3, maintain the peak production level for 3 years (through year 6), after which annual production will decline at a rate of 12 percent per year.
At first glance, the 12 percent field production decline rate appears to be very rapid. Observed field decline rates are typically less rapid because of the application of well enhanced recovery techniques to prolong field life. However, the success of appropriate enhanced recovery techniques will depend on site-specific conditions. Recovery factors of oil-in-place that were posited by the assessors were assumed to include primary production and water-flood/pressure maintenance production, but not the maximum production that might be recoverable by enhanced recovery.
The volume of produced water was projected with the production profile for oil, the degree of accumulation depletion, and functions that relate water cut percentages to the percentage of reservoir depletion. For undiscovered accumulations in sub-area 110, 120 and 130 the function presented in Arco and others (1998) was used (Figure A-2). Else where the water cut function for the Kuparuk reservoir (see figure 3, from Thomas and others, 1991) was applied. The figures show the percentage water (water cut) expected in production with depletion of the accumulation. Volumes of natural gas and natural gas liquids production were projected using annual oil production, the expected values of the gas to oil ratio, and NGL to gas ratios associated with the representative accumulation’s size and depth classification.
Field operating costs include labor, supervision, overhead and administration, communications, catering, supplies, consumables, well service and workovers, facilities maintenance and insurance, and transportation. Some of these costs, such as well work-over and labor costs, have declined dramatically during the last decade due to the introduction of coiled tubing technology and to the institution of automation in field operations. Annual operating costs are characterized as a function of daily fluid volumes (National Petroleum Council, 1981a, Young and Hauser, 1986). The annual operating cost function presented by Young and Hauser (1986) was adjusted using the Energy Information Administration’s index of oil field operating costs for 1996 and then for 2000 (Energy Information Administration, 1997, 2002). Figure A-4 shows annual operating costs as a function of the daily fluid production. These fluid (hydrocarbon and water) volumes from production were projected in annual increments using field production forecasts and water cut functions (Figures A-2 and A-3), so that per barrel costs of oil reflect the increases in costs that result from a higher water cut as the accumulation is depleted.
Severance Tax for oil:
12.25 % for years 1 through 5 adjusted for economic limit factor (elr)
15.00 % after year 5 adjusted for the economic limit factor
floor of $0.80 per barrel adjusted for the economic limit factor
elr = (1-(300/ADWR))a
where a = (150000/ADFR) 1.5333
ADWR = average daily production per producing well in barrels per day (bb/d)
ADFR= average daily field production (bbo/d)
Severance Tax for gas:
10.00 % adjusted for the economic limit for
floor $0.064 per thousand cubic feet adjusted for the economic limit factor
elr = (1-(3000/ADWR))
ADWR = average daily production per producing well (mcf/d)
For both cases, if elr is less than or equal to zero, then the severance tax is zero
Ad valorem tax
Tax equal to 2 percent of the economic value of pipelines, facilities,
and equipment. For pipelines, a 25-year life was assumed. For tangible well
costs, oil field equipment costs, and facilities costs, depreciation
of the asset was based on the unit of production method.
State Income tax
For planning purposes, Alaska state agencies use 1.4 to 3.0 percent of net income. The rate used here was 2.4 of net income. Depreciation of capital assets associated with oil field development is permitted on a unit of production basis. For other capital, depreciation depends on the economic life of the equipment.
State conservation tax
Tax is $0.004 per barrel, and the conservation surcharge tax is $0.03 per barrel.
Federal royalty rate
Royalty rate is considered to be a payment to the landowner and the rate was assumed to be 16.7 percent of gross revenue for the high potential sub-area 110. For other sub-areas, a rate of 12.5 percent of gross revenue was assumed.
Federal income taxes
A Federal income tax rate of 35 percent of taxable income was assumed. Based on the 1986 Tax Reform Act, 30 percent of development well drilling costs is classified as tangible cost and is therefore capitalized over 7 years. Of the remaining 70 percent of drilling cost (that is, the intangible drilling costs), 30 percent is depreciated over 5 years and the remaining 70 percent is expensed immediately.
Table A-1. Distances assumed for transport of crude oil to the Trans-Alaska Pipeline System (TAPS).
Sub-area Pipeline Segment Total distance to Kuparuk (mi)
regional (mi) lateral(mi)
110 65 10 From middle 110 to Kuparuk 65
120 70 8 From middle 120 to middle 110 135
130 70 17 From middle 120 to middle 120 205
Sub-area Pipeline Segment Total distance to Pump Station 2 (mi)
regional (mi) lateral (mi)
210 104 12.5 From middle 210 to pump station 2 104
220 69 17.5 From middle 220 to middle of 210 172
230 95 17.5 From middle 230 to middle of 220 270
Table A-2. Estimated costs (in dollars per barrel) for transport used from the accumulation to the Trans-Alaska Pipeline System (TAPS).
Segment Estimate tariff to TAPS
distance Lateral size Lateral size
|
North |
miles |
500kb/d |
+21cents* |
12 inch** |
16 inch*** |
12 inch** |
16 inch*** |
|---|---|---|---|---|---|---|---|
|
110 |
65 |
0.42 |
0.63 |
0.17 |
0.12 |
0.80 |
0.75 |
|
120 |
70+65 |
0.87 |
1.08 |
0.31 |
0.21 |
1.39 |
1.29 |
|
130 |
70+70+65 |
1.32 |
1.53 |
0.30 |
0.20 |
1.83 |
1.73 |
|
South |
300kb/d |
not needed |
|||||
|
210 |
104 |
1.29 |
1.29 |
0.22 |
0.15 |
1.51 |
1.44 |
|
220 |
69+104 |
2.00 |
2.00 |
0.30 |
0.20 |
2.30 |
2.20 |
|
230 |
97+69+104 |
3.24 |
3.24 |
0.30 |
0.20 |
3.54 |
3.44 |
kb/d = thousand barrels per day.
* Based on charge of 21 cents from Kuparuk field to TAPS Pump Station 1.
**Based on an accumulation with 300 million barrels of recoverable oil.
*** Based on an accumulation with 600 million barrels of recoverable oil.
Table A-3. Conventional well productivity, by oil accumulation size class, for accumulations in the Beaufortian Upper Jurassic oil plays of the National Petroleum Reserve Alaska (based on data from the mean volume estimate).
|
Accumulation Size Class |
Well Productivity MMBO/Well |
|---|---|
|
16-32 |
1.03 |
|
32-64 |
1.82 |
|
64-128 |
2.21 |
|
128-256 |
2.45 |
|
256-512 |
2.87 |
|
512-1024 |
3.67 |
|
1024-2048 |
5.28 |
Table A-4. Estimates of facilities investment cost in 1996 dollars, from Attanasi (1999).
|
Field size (MMBO) |
Investment Cost $/bbl |
|---|---|
|
32 |
7.75 |
|
48 |
5.83 |
|
64 |
4.77 |
|
96 |
3.59 |
|
128 |
2.97 |
|
192 |
2.43 |
|
256 |
2.10 |
|
384 |
1.72 |
|
512 |
1.49 |
|
768 |
1.22 |
|
1024 |
1.05 |
|
1536 |
0.86 |
Table A-5. Accumulation production profiles assumed for new discoveries in the National Petroleum Reserve Alaska.
Peak rate as
Accumulation Years percent of Years of peak
sizes buildup ultimate production
MMBO
8-16 2 11 3
16-32 2 11 3
32-64 2 11 3
128-256 2 11 3
256-512 2 11 3
512-1024 3 10 4
1024-2048 3 9 4
[1] The costs relation was similar in form to those presented by the National Petroleum Council (1981b) and Young and Hauser (1986).