R
Assessing Natural Gas and
Oil Resources
Technical Details of Resource Allocation
and Economic Analysis
E. H. Vidas, R. H. Hugman, and P. S. Springer
Prepared for William and Flora Hewlett Foundation
RAND Science and Technology
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PREFACE
This report, prepared for RAND Science and Technology by researchers at Energy
and Environmental Analysis, Inc., presents supplemental material to Assessing
Natural Gas and Oil Resources: An Example of a New Approach in the Greater Green
River Basin (MR-1683-WFHF), which is a new approach to assessing natural gas and
crude oil resources and the results of applying that approach to the Greater Green
River Basin in southwestern Wyoming. The methodology builds upon existing
assessments of technically recoverable resources by evaluating economic and
environmental considerations and including these into the assessment as additional
resource attributes. The primary objectives of this effort are to inform government
officials and other stakeholders involved in land use planning, development of
energy policies, and energy development and utilization planning. The approach
aims to guide strategic (i.e., large-scale and long-term) planning, and is not intended
to replace existing project-specific economic or land use planning processes. The
initial framework for this approach was presented in two earlier reports:
•
Assessing Gas and Oil Resources in the Intermountain West: Review of Methods
and Framework for a New Approach, RAND MR-1553-WFHF (2002).
•
A New Approach to Assessing Gas and Oil Resources in the Intermountain West,
RAND IP-225-WFHF (2002).
This report should be of interest to federal, state, and local government land managers; and it is also expected to be useful to producers and the associated investment
community, electric and natural gas utilities, and state planning agencies to help
guide strategic business planning, improve long-term forecasting, and foster dialog
among stakeholders. The study was funded by the William and Flora Hewlett
Foundation.
RAND SCIENCE AND TECHNOLOGY
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through research and analysis. RAND Science and Technology (S&T), one of RAND’s
research units, assists government and corporate decisionmakers in developing options to address challenges created by scientific innovation, rapid technological
change, and world events. RAND S&T’s research agenda is diverse. Its main areas of
concentration are: science and technology aspects of energy supply and use; envi-
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infrastructure; biotechnology; and the federal R&D portfolio.
Inquiries regarding RAND Science and Technology may be directed to:
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Other contact information:
E. H. Vidas, R. H. Hugman, and P. S. Springer
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CONTENTS
1. Introduction
2. Green River Basin Oil and Gas Resources
3. Cost Data and Discounted Cash Flow Analysis
4. Modeling of Resource Depletion
5. Results
6. References
1. Introduction
This report documents the results of a study of the economics of oil and gas resources in
the Greater Green River Basin of SW Wyoming and NW Colorado.
The objective of the study was to develop a spreadsheet model of resource economics for
the Green River Basin at the individual play level. The model is used to generate "supply
curves" showing the volume of gas resources available at a given wellhead gas price.
The project involved several areas of work. Two resource base assessments were to be
used -- the 1995 U.S. Geological Survey (USGS) assessment and the 1999 National
Petroleum Council (NPC) assessment. The NPC published results for both current and
advanced (2010) technology. Thus there were three resource base scenarios for the
study.
The initial project involved evaluation of the existing assessment information and
allocation of the assessments to the individual plays. The play definitions were primarily
based upon the USGS assessment as the NPC assessment was only performed at the play
level for non-conventional resources.
Another project involved the development of cost factors for the economic analysis. Data
were collected for drilling costs, stimulation costs, operating costs, and other factors.
Each of these were developed in such a way as to be applied to individual plays.
A significant effort was directed to the area of well recovery and distribution of well
recoveries within each play. This involved analysis of historical data from the IHS
commercial database, as well as published estimates from the USGS and other sources.
EEA developed a distribution of well recoveries for some subplays, resulting in an
economic analysis that is more representative of the true resource.
An economic analysis spreadsheet was developed for each of the three resource
scenarios. This spreadsheet includes all of the cost and recovery data that goes into the
analysis. The user can change input values or assumptions or use the default values. The
model generates supply curves on a total gas or barrels of oil equivalent (BOE) basis.
2. Green River Basin Gas and Oil Resources
1. Overview and Objectives
The Greater Green River Basin is located in southwestern Wyoming and northwestern
Colorado. The basin encompasses a surface area of approximately 28,600 square miles.
Major structural features of the basin are shown in Figure 2-1. The objective of the
current study is to evaluate in detail the economics of undeveloped oil and gas resources
in the basin using detailed play level analysis.
The approach used is to disaggregate the undiscovered resource base at the play level,
and to evaluate the economics of individual plays. The cumulative volume of play level
resources is used to define the basin "supply curve" or relationship between resource cost
in dollars per MMBtu and available volumes of recoverable gas and oil. The resource
cost is the selling price required at the wellhead to compensate producers for their
investments, operating costs, taxes, royalties and cost of capital. It is computed using a
discounted cash flow analysis wherein the present value of the investment is exactly zero
when all negative (costs) and positive (revenues) cash flows are discounted at the average
cost of capital.
This section describes the resource assessment approach. The approach to economic
analysis is described separately.
Individual play units of analysis were defined and were assigned volumes of unproved
and undiscovered resources. The 1995 U.S. Geological Survey (USGS) assessment
formed the basis of the play definition, although, as described below, a greater level of
detail was developed (1995 USGS).
Three resource scenarios have been evaluated in the current study: Scenario A - based
upon the USGS assessment, Scenario B - inspired by the 1999 National Petroleum
Figure 2-1
Major Structures of the Green River Basin
Council (NPC) assessment of current technology, and Scenario C - inspired by the NPC
assessment of advanced technology.
2. Existing Published Assessments
The assessments of primary interest are the 1995 USGS assessment and the 1999 NPC
assessment. The 1995 USGS assessment is the most recent national assessment
published by that organization. The assessment was developed at the individual play
level, with at total of 20 plays in the Green River Basin (USGS Province 37). The NPC
assessment was developed at the region level for conventional resources and at the play
level for non-conventional (tight and coalbed) resources. Hydrocarbon Supply Model
regions in the Rocky Mountain region include the Rocky Mountain Foreland Province
(which includes the Green River Basin) and the Western Overthrust Belt.
Another published assessment that is often referenced is the Potential Gas Committee or
PGC assessment. The most recent assessment was published in 2000. Resources are
evaluated at the basin level, and a Green River Basin assessment is published.
The basin and play resources developed by EEA for the current study include estimates
based upon various allocation methods. This was necessary in order to assign all
categories of resources to plays. In the case of the NPC resource base, estimates were
developed for several frontier plays. Because of this, the assessments are termed
"USGS-Based" and "NPC-Inspired" to differentiate them from the published
assessments.
3. Resource Categories and Definitions
Of interest are all proved and undeveloped/undiscovered hydrocarbon resources in the
Green River Basin, including gas and oil. Resources include non-associated (gas well)
and associated (oil well) gas, crude oil, and natural gas liquids. In general, gas resources
are documented here on a "net dry basis," which represents the marketable gas after gas
plant liquids are removed. Much of the gas in the Green River Basin contains significant
non-hydrocarbons, and it is important to account for this by reporting "net" gas, which
excludes non-hydrocarbons.
Resources are reported as "technically recoverable." Technically recoverable resources
represent the portion of the total in-place resource than can potentially be recovered given
current or anticipated technology. Economic recovery is that portion of the technical
recovery that is economic to develop at a given product price, and incorporates cost
factors, technology, ultimate recovery per well, and production characteristics.
Categories of proved resources include the following:
Cumulative production. The sum of past production from existing and abandoned
oil and gas wells.
Proved reserves. Quantities of oil and gas which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions.
Ultimate Recovery. The sum of cumulative production and proved reserves.
Categories of undiscovered/undeveloped resources include the following:
Reserve appreciation (reserve growth). The portion of the conventional resource
base that results from reserve additions in existing fields. Categories of reserve
additions include new pools, extensions, infill drilling, and revisions to existing
reserve estimates.
Conventional New Fields. Yet-to-be-discovered conventional oil and gas fields.
Tight Gas. A component of non-conventional gas resources represented by gas in
sandstone or chalk reservoirs with an in situ permeability of 0.1 millidarcies or
lower.
Coalbed Methane. A component of non-conventional gas resources represented
by gas in coal bed reservoirs. The coal is both the source rock and reservoir rock.
Shale Gas. A component of non-conventional gas resources represented by gas in
Devonian or other organic shale reservoirs. The shale is both the source and
reservoir rock. There is no currently assessed shale gas resource in the Green
River Basin.
Low-BTU Gas. Undeveloped gas that contains a large percentage of nonhydrocarbons, resulting in a gas with low heating content (BTU value). The nonhydrocarbons must be removed, resulting in additional costs.
4. Data Sources
Data sources for the resource portion of the study include the following:
1995 USGS Assessment. Published report and information on CD-ROM.
1999 NPC Assessment. Published report, information on CD-ROM and EEA
files.
2000 PGC Assessment. Published report.
IHS Production Data. This electronic database is reported at the completion level
and includes historical production from gas wells and oil wells.
IHS Well History Data. This electronic database is reported at the well level and
includes information on location, spud date, completion date, formation tops, total
well depth, tested intervals, artificial stimulation, and flow rates.
EEA Reserve Estimates. EEA has developed estimates of proved reserves and
ultimate recovery at the completion level that can be aggregated by formation or
area.
EEA Pool Discovery Analysis. EEA has evaluated historical new pool
discoveries within the basin to assist in the analysis of future potential
1994 GRI/ Barlow and Haun Green River Basin Report. This report includes
detailed structure maps of each major producing interval. These maps were used
to define depth-based subplays for tight gas.
5. Approach
Play Definition
For the current Green River Basin study, EEA developed 50 individual play units. These
plays, as shown on Table 2-1, are based upon the 1995 USGS study, and include
"subplays" for most of the USGS plays. (For simplicity, the new units are referred to as
"subplays" even though some of them are plays). The USGS defined 20 plays for the
Green River Basin. These consist of 9 "structural" plays, 5 tight plays, and 6 coalbed
plays. The structural plays represent resources associated with either known anticlinal
(dome) features such as the Moxa Arch and the Rock Springs Uplift, or along structural
trends, which are areas in which anticlinal fields are expected to be found. The tight gas
plays are regional "continuous" deposits within specific sandstone formations. Each of
these plays extends either across the entire portion of the basin that is not included in the
structural plays (basin center), or extends across a large portion of this area. Tight gas
plays are also termed "continuous" plays because there are no discreet accumulations and
Table 2-1
Subplay Definition and Areas
Green River Basin Study
see footnotes
subplay
count
USGS play
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Play /subplay
Type
3701 ROCK SPRINGS UPLIFT
Structural
A Tertiary
B Upper Cretaceous
C Lower Cretaceous
D Jurassic through Permian
E Pennsylvanian
Z Other
3702 CHEROKEE ARCH
Structural
A Tertiary
B Upper Cretaceous
C Lower Cretaceous
D Jurassic and Older
Z Other
3703 AXIAL UPLIFT
Structural
3704 MOXA ARCH
Structural
A Tertiary
B Upper Cretaceous
C Lower Cretaceous
D Jurassic through Pennsylvanian
Z Other
3705 BASIN MARGIN ANTICLINE
Structural
A Tertiary and Upper Cretaceous
B Lower Cretaceous
Z Other
3706 SUBTHRUST
Structural
3707 PLATFORM (EASTERN BASIN)Structural
A Cretaceous
B Pre-Cretaceous
Z Other
3708 JACKSON HOLE
Structural
3709 DEEP BASIN
Structural
3740 CLOVERLY FRONTIER TIGHT Tight
1 (0 - 14,999 ft)
2 (15,000 -16,999 ft)
3 (17,000-18,999 ft)
4 (19,000-20,999 ft)
5 (21,000 + ft)
total
3741 MESAVERDE TIGHT
1 (0 - 8,999 ft)
2 (9,000 - 10,999 ft)
3 (11,000 - 12,999 ft)
4 (13,000 - 14,999 ft)
5 (15,000 + ft)
total
Tight
32
33
34
35
36
3742 LEWIS TIGHT
1 (0 - 9,999 ft)
2 (10,000 -11,999 ft)
3 (12,000 + ft)
total
Tight
37
38
39
GRB_Play_township_assignments.xls
Number of
Townships
Area
Sq Miles \1
70
2,520
26
936
79
56
2,844
2,016
106
3,816
22
186
792
6,696
79
39
2,844
1,404 \2
54
99
79
54
96
382
1,944
3,564
2,844
1,944
3,456
13,752
26
66
42
41
49
224
936
2,376
1,512
1,476
1,764
8,064
35
35
52
122
1,260
1,260
1,872
4,392
6/19/02
Table 2-1
Subplay Definition and Areas
Green River Basin Study
see footnotes
subplay
count
USGS play
Play /subplay
Type
3743 FOX HILLS-LANCE TIGHT
1 (0-9,999 ft)
2 (10,000 -11,999 ft)
3 (12,000 + ft)
total
Tight
40
41
42
3744 FORT UNION TIGHT
1 (0-9,999 ft)
2 (10,000 -12,000 ft)
total
Tight
43
44
45
46
47
48
49
50
3750
3751
3752
3753
3754
3755
Coalbed
Coalbed
Coalbed
Coalbed
Coalbed
Coalbed
ROCK SPRINGS COALBED
ILES COALBED
WILLIAMS FORK COALBED
ALMOND COALBED
LANCE COALBED
FORT UNION COALBED
Number of
Townships
Area
Sq Miles \1
37
32
56
125
1,332
1,152
2,016
4,500
8
7
15
288
252
540
29
38
26
95
112
251
1,044
1,368
936
3,420
4,032
9,036
\1 Total area of Greater Green River Basin is approximately 28,600 square miles. Non-uplift or basinal
area is approximately 13,800 square miles (based upon the area of Cloverly--Frontier tight Play)
The main productive portion of the basin is the western area, which is approximately 22,000 square miles.
\2 From EEA/GRI gas composition study
GRB_Play_township_assignments.xls
6/19/02
the potential occurs in a regional area. The coalbed plays are defined by stratigraphic
interval and area.
EEA developed subplays for 5 of the structural plays and for all of the tight gas plays. No
subplays were developed for the coalbed resource as the USGS play definitions were
used.
For the structural plays, the EEA subplays are defined on the basis of formation or
geologic age interval. For example, the Moxa Arch play was divided into five subplays:
Tertiary, Upper Cretaceous, Lower Cretaceous, Jurassic through Pennslyvanian, and
Other. This type of division has several advantages for economic analysis: It allows for
determination of the productive characteristics of individual formations, and it allows for
formation-specific drilling depths and cost factors.
For USGS tight gas plays, EEA defined subplays on the basis of drilling depth interval
within the specified formation. EEA used published structure maps of each major
stratigraphic interval to determine the specific area represented by each major depth
interval. (Barlow and Haun, 1994). The surface "townships" (36 square mile areas) were
defined for each depth interval. These townships are mappable units that can be used in
a GIS analysis.
By dividing the resource base into subplays, EEA has developed a level of disaggregation
of the resource that is better suited to develop detailed supply curves for the Green River
Basin.
Table 2-1 shows the square mile area of each play or subplay. Note that for the structural
plays, the subplay areas are the same as that of the entire structure. For the tight plays,
the subplays represent depth intervals and so each subplay area is different. The tight gas
subplay areas sum to the total play area.
Resource Allocation Approach
Resource allocation is the process of assigning resources to basins, plays, and subplays.
The goal of this study was to assign resources at the subplay level. For both the USGS
and NPC resource bases, it was necessary to work with some data that were assessed at
the region level. Regional assessments were allocated to the Green River Basin and then
to subplays.
As mentioned above, the basin and play assessments presented here are derived from
USGS and NPC, but include EEA allocations and some estimates.
The following is a discussion of the allocation methods used:
Reserve appreciation. Both the USGS and NPC Rocky Mountain assessments
were developed at the region level and were allocated by EEA first to the Green
River Basin and then to plays. Proved reserve volumes were used for the
allocation factors at the basin and play level. The procedure was to first allocate
to the basin using the distribution of proved reserves by basin, then to allocate to
plays using play level proved reserves. USGS reserve growth volumes were
assigned only to the conventional plays. This is because of the methodology used
by USGS to assess appreciation potential. In the NPC study, a different method
was used to assess reserve appreciation. Because of this, some of the NPC
reserve appreciation volumes were assigned to the established tight gas plays.
One component of reserve appreciation in the NPC study is the so-called "Low
Btu" gas on the Moxa Arch, which was assessed for the NPC study at
approximately 14 Tcf. This 14 Tcf represents the hydrocarbon component of a
very large undeveloped low Btu accumulation on the Moxa Arch (a portion of the
accumulation has been developed and is being produced). The Mississippian
Madison Formation occurs at 15,000 feet and is believed to cover an area of 1,000
square miles. The published estimate of gas-in-place for the field is 167 Tcf. The
gas composition in the area of current production is 66 percent CO2, 5 percent
H2S, and 0.6 percent Helium. Methane content is about 22 percent and Nitrogen
content is 7 percent.
Other formations along the Moxa arch also contain low Btu gas. These include
the Nugget, Phosphoria, Tensleep, Weber, Morgan, and Bighorn.
Conventional New Fields. The USGS assessment was originally developed at the
play level, so it was only necessary to allocate volumes to subplays. Data on
post-1974 new pool discoveries were used for this allocation. Subplays with the
largest volumes of post-1974 new pool discoveries were assigned the greatest new
field potential. The NPC assessment was developed at the region level for the
Foreland Province. The assessment was first allocated to the Green River Basin
using the PGC basin level assessments, since this was judged by EEA to be the
best representation of the distribution of new fields within the Rockies.
A more detailed method was used to allocate NPC new field resources to plays
and subplays within the Green River Basin. The approach used was to first
evaluate each play and subplay in terms of the total square miles of area and the
proved area. The approach looked at the proved recovery per square mile in the
developed area, and involved an estimation procedure to assign resources to the
undeveloped area. Several factors were considered, including the recovery per
square mile implications, the USGS play assessments, and recent exploration
activity.
As with reserve appreciation, some of the NPC new conventional field potential
was allocated to the tight gas plays. This was necessary because of the new field
assessment method used for the Hydrocarbon Supply Model. The new field
potential assigned to the tight plays is the so-called "low permeability" component
of new fields in the model. Finally, the NPC allocations include estimates for
three plays -- Subthrust Play (3706), Jackson Hole (3708), and the Deep Basin
(3709). The USGS did not assess plays 3708 or 3709.
Tight Gas. The USGS assessment was developed at the play level so it was only
necessary to allocate volumes to subplays. EEA reviewed all of the information
on the USGS tight gas assessment to determine their assumptions about number
of successful wells, well recovery, and spacing for each play. Then a scenario
was developed to allocate wells and resources to subplays. In developing this
allocation, information on historical well recovery was evaluated to determine an
appropriate well recovery for each subplay.
The NPC tight gas assessment was developed at the play (basin and formation)
level, and it was necessary to allocate to subplays. EEA reviewed the "ERM"
tight gas files that were used in the NPC study, and allocated these resources to
subplays. One complication of the NPC evaluation was that the Mesaverde and
Lewis formations were combined in the original NPC ERM cells. Because of
this, it was necessary to estimate the breakout of play level resources between
these formations.
Coalbed Methane. A decision was made to evaluate the coalbed resource at the
play level, since there are six coalbed plays defined, and because the resource is
just starting to be developed. The USGS assessment was used "as is" at the play
level. The NPC current tech resource base was derived entirely from the USGS
study. (Note: The USGS recovery per well was not used. This is discussed
below).
Low-Btu Gas. As discussed above, the Low-Btu resource on the Moxa Arch is
approximately 14 Tcf as specified for the model. This has been added to the NPC
reserve appreciation resource for the current study (Play 3709).
6. Basin Level Resources
Proved Ultimate Recovery - Rocky Mountain Region
Table 2-2 shows the current assessment of proved recovery by basin for the Rocky
Mountain region. Total gas ultimate recovery in the region is approximately 51 Tcf and
total liquids (crude plus NGL) recovery is approximately 8.6 billion barrels. The Green
River Basin portion of this resource is 17.8 Tcf and 897 million barrels. Cumulative total
gas production in the basin is 11.2 Tcf and proved reserves are 6.6 Tcf. (all data through
year 2000).
For comparison, lower-48 total gas proved ultimate recovery is approximately 1,100 Tcf.
Proved reserves through 2000 were approximately 170 Tcf. The Green River basin
ultimate recovery represents 1.6 percent of the lower-48 total, while proved reserves
represent 3.9 percent of the total.
Table 2-3 shows the breakout of proved recovery for gas wells and oil wells. Of the 17.8
Tcf of total dry gas ultimate recovery, 16.6 Tcf or 93 percent is gas well gas. This shows
that historical discoveries in the Green River Basin are very gas-prone.
Basin Level Resource Assessments
Table 2-4 is a comparison of USGS and NPC basin level resources for the Rockies. The
basins shown are as defined by the USGS, and are generally equivalent to AAPG basins
(the industry standard definition for analysis), with the exception of the combined Uinta
and Piceance Basins. Three resource base assessments are presented: Scenario A - based
upon USGS current tech, Scenario B - inspired by NPC current tech, and Scenario C inspired by NPC advanced tech.
The USGS is significantly more conservative than the NPC. The largest difference in the
two regional assessments is the expectation for new conventional fields. The USGS
Table 2-2
Total Gas and Liquids Ultimate Recovery by AAPG Basin
Rockies Basins
Source: IHS production data through 2000
Basin
name
AAPG
Basin
code
Las Animas Arch
Las Vegas Raton
Overthrust
Powder River
Big Horn
Wind River
Green River
Denver
Uinta
Paradox
Piceance
450
455
507
515
520
530
535
540
575
585
595
Total
Uinta + Piceance
EUR_Basin.xls
Total
Total
Net Dry Gas Net Dry Gas
Cumulative Reserves
Bcf
Bcf
Total
Net Dry Gas
Ultimate
Bcf
Total
Liquids
Cumulative
MMB
Total
Liquids
Reserves
MMB
Total
Liquids
Ultimate
MMB
320
106
3,647
1,590
1,121
2,320
11,203
3,689
2,245
1,350
2,454
224
499
2,406
3,189
358
1,415
6,603
2,199
2,280
521
884
544
605
6,053
4,779
1,479
3,735
17,806
5,888
4,525
1,871
3,338
105
0
335
1,192
1,495
490
749
707
500
586
945
72
0
109
225
273
79
148
131
200
186
89
177
0
444
1,417
1,768
569
897
838
700
772
1,034
30,045
20,578
50,623
7,104
1,512
8,616
4,699
3,164
7,863
1,445
289
1,734
6/19/02
Table 2-3
Summary of Green River Basin Oil and Gas Recovery
Net Dry
Gas - Bcf
Liquids
MMB
Gas Wells
cumulative production
remaining reserves
ultimate recovery
10,320.63
6,285.93
16,606.56
116.26
49.95
166.21
cumulative production
remaining reserves
ultimate recovery
882.02
317.34
1,199.36
632.89
98.30
731.19
cumulative production
remaining reserves
ultimate recovery
11,202.65
6,603.27
17,805.92
749.15
148.25
897.40
Oil Wells
Total
grb_eur_data_PLAYTOTALS.xls
6/19/02
Table 2-4
Comparison of Basin Level Undiscovered Gas Assessments
Dry total gas
Includes allocations
Basins included in HSM Foreland and Overthrust Belt regions
Unadjusted for reference year
Scenario A - 1995 USGS-Based Gas - Current Tech
Gas
Ultimate
BCF
USGS
basin code
Gas Growth
BCF
Conv.
New Field
BCF
Tight
BCF
Coalbed
BCF
All Time
Total
BCF
Low BTU
BCF
Unproved
Total
BCF
USGS Basin
20
21
33
34
35
36
37
38
39
40
41
UINTA-PICEANCE
PARADOX
POWDER RIVER BASIN
BIGHORN BASIN
WIND RIVER BASIN
WYOMING THRUST BELT
SOUTHWEST WYOMING
PARK BASINS
DENVER BASIN
LAS ANIMAS ARCH
RATON-SIERRA GRANDE
total
7,863
1,871
4,779
1,479
3,735
6,053
17,806
0
5,888
544
605
50,623
2,361
563
809
387
1,530
2,602
8,327
0
2,378
242
1
19,200
4,540
2,020
1,600
620
1,240
10,680
1,580
20
750
530
40
23,620
16,741
194
0
0
0
0
119,171
0
3,156
0
0
139,262
10,705
0
1,107
0
426
0
3,889
0
0
0
1,775
17,902
0
0
0
0
0
0
0
0
0
0
0
0
42,210
4,648
8,295
2,486
6,931
19,335
150,773
20
12,172
1,316
2,421
250,607
34,347
2,777
3,516
1,007
3,196
13,282
132,967
20
6,284
772
1,816
199,984
Scenario B -1999 NPC-Inspired Gas - Current Tech
USGS
basin code
USGS Basin
20
21
33
34
35
36
37
38
39
40
41
UINTA-PICEANCE
PARADOX
POWDER RIVER BASIN
BIGHORN BASIN
WIND RIVER BASIN
WYOMING THRUST BELT
SOUTHWEST WYOMING
PARK BASINS
DENVER BASIN
LAS ANIMAS ARCH
RATON-SIERRA GRANDE
total
Gas
Ultimate
BCF
Gas Growth
BCF
7,863
1,871
4,779
1,479
3,735
6,053
17,806
0
5,888
544
605
50,623
4,119
983
1,411
675
2,668
702
14,523
0
4,147
422
2
29,651
Conv.
New Field
BCF
27,067
4,690
6,005
8,036
13,590
6,160
24,980
0
1,970
0
2,189
94,688
Tight
BCF
27,176
0
0
0
9,701
0
64,735
0
3,190
0
0
104,803
Coalbed
BCF
11,718
0
4,532
0
497
0
4,315
0
0
0
1,738
22,799
Low BTU
BCF
0
0
0
0
0
0
14,689
0
0
0
0
14,689
All Time
Total
BCF
77,943
7,544
16,727
10,190
30,191
12,915
141,047
0
15,195
966
4,534
317,253
Unproved
Total
BCF
70,080
5,673
11,948
8,711
26,456
6,862
123,241
0
9,307
422
3,929
266,630
Scenario C -1999 NPC-Inspired Gas - Advanced Tech
USGS
basin code
USGS Basin
20
21
33
34
35
36
37
38
39
40
41
UINTA-PICEANCE
PARADOX
POWDER RIVER BASIN
BIGHORN BASIN
WIND RIVER BASIN
WYOMING THRUST BELT
SOUTHWEST WYOMING
PARK BASINS
DENVER BASIN
LAS ANIMAS ARCH
RATON-SIERRA GRANDE
total
basin_resource_EEA_allocations.xls
Gas
Ultimate
BCF
7,863
1,871
4,779
1,479
3,735
6,053
17,806
0
5,888
544
605
50,623
Gas Growth
BCF
4,119
983
1,411
675
2,668
702
14,523
0
4,147
422
2
29,651
Conv.
New Field
BCF
30,324
5,255
6,728
9,003
15,225
6,731
27,986
0
2,207
0
2,452
105,911
Tight
BCF
35,520
0
0
0
12,680
0
84,610
0
4,170
0
0
136,980
Coalbed
BCF
15,100
0
5,840
0
640
0
5,560
0
0
0
2,240
29,380
Low BTU
BCF
0
0
0
0
0
0
14,689
0
0
0
0
14,689
All Time
Total
BCF
92,926
8,108
18,758
11,157
34,948
13,486
165,173
0
16,412
966
5,299
367,234
Unproved
Total
BCF
85,063
6,237
13,979
9,678
31,213
7,433
147,367
0
10,524
422
4,694
316,611
6/19/02
Table 2-4 (continued)
Scenario A - 1995 USGS Oil - Current Tech
Crude
Ultimate
MMB
USGS
basin code
Crude
Growth
MMB
Conv.
New Field
MMB
All Time
Total
MMB
Unproved
Total
MMB
USGS Basin
20
21
33
34
35
36
37
38
39
40
41
UINTA-PICEANCE
PARADOX
POWDER RIVER BASIN
BIGHORN BASIN
WIND RIVER BASIN
WYOMING THRUST BELT
SOUTHWEST WYOMING
PARK BASINS
DENVER BASIN
LAS ANIMAS ARCH
RATON-SIERRA GRANDE
total
1,719
763
1,390
1,764
557
253
731
0
708
176
0
8,061
1,374
895
1,069
1,316
363
382
672
0
387
343
0
6,800
210
310
1,940
390
160
630
170
30
230
140
0
4,210
3,303
1,968
4,399
3,470
1,080
1,265
1,573
30
1,325
659
0
19,071
1,584
1,205
3,009
1,706
523
1,012
842
30
617
483
0
11,010
Scenario B -1999 NPC Oil - Current Tech
USGS
basin code
USGS Basin
20
21
33
34
35
36
37
38
39
40
41
Crude
Ultimate
MMB
UINTA-PICEANCE
PARADOX
POWDER RIVER BASIN
BIGHORN BASIN
WIND RIVER BASIN
WYOMING THRUST BELT
SOUTHWEST WYOMING
PARK BASINS
DENVER BASIN
LAS ANIMAS ARCH
RATON-SIERRA GRANDE
total
1,719
763
1,390
1,764
557
253
731
0
708
176
0
8,061
Crude
Growth
MMB
216
141
168
207
57
53
106
0
61
54
0
1,061
Conv.
New Field
MMB
152
225
1,407
283
116
251
123
22
167
102
0
2,847
All Time
Total
MMB
2,087
1,128
2,965
2,253
730
557
960
22
936
331
0
11,969
Unproved
Total
MMB
368
365
1,575
489
173
304
229
22
228
155
0
3,908
Scenario C - 1999 NPC Oil - Advanced Tech
USGS
basin code
USGS Basin
20
21
33
34
35
36
37
38
39
40
41
UINTA-PICEANCE
PARADOX
POWDER RIVER BASIN
BIGHORN BASIN
WIND RIVER BASIN
WYOMING THRUST BELT
SOUTHWEST WYOMING
PARK BASINS
DENVER BASIN
LAS ANIMAS ARCH
RATON-SIERRA GRANDE
total
basin_resource_EEA_allocations.xls
Crude
Ultimate
MMB
1,719
763
1,390
1,764
557
253
731
0
708
176
0
8,061
Crude
Growth
MMB
216
141
168
207
57
53
106
0
61
54
0
1,061
Conv.
New Field
MMB
203
300
1,876
377
155
335
164
29
222
135
0
3,796
All Time
Total
MMB
2,138
1,203
3,433
2,348
769
641
1,001
29
991
365
0
12,918
Unproved
Total
MMB
419
440
2,043
584
212
388
270
29
283
189
0
4,857
6/19/02
assessment includes only 24 Tcf of new field potential, while the NPC current tech
assessment was for 95 Tcf. In general, although not shown here, much of the difference
lies in the expectation for deeper field discoveries. The NPC assessment includes a large
deep conventional resource base.
The tight gas resource base is very similar, with the exception that the USGS does not
include a tight resource in the Wind River Basin.
The coalbed resource base is similar with the exception of the Powder River Basin
assessment. The NPC Powder River assessment is higher at 4.5 to 5.8 Tcf. However,
both published assessments are now considered very low, and the Potential Gas
Committee assessment is 24 Tcf.
Green River Basin Resources
Table 2-5 summarizes the assessments of the Green River Basin. Proved resources are
broken out into cumulative production and proved reserves. Unproved resources include
reserve growth in existing fields, conventional new fields, tight gas, coalbed methane,
and low-BTU gas.
Some of the resources shown here are allocated resources rather than published resources
for the basin. The USGS and NPC reserve appreciation resources are allocated values.
The NPC conventional new field number is an allocated value.
The table shows that the NPC resource is significantly more optimistic for the Green
River Basin. The largest difference is in conventional new fields. The NPC resource
base includes a large volume of deeper conventional resources and resources that are
associated with frontier or conceptual plays.
Table 2-5
Greater Green River Basin Gas and Oil Resources
Net Dry Gas (Tcf)
Scenario A
USGS Based Assessment
Current Technology
Category
Total
Non-Assoc.
Scenario B
NPC - Inspired Assessment
Current Technology
Assoc.
Total
Non-Assoc.
Scenario C
NPC - Inspired Assessment
Advanced Technology
Assoc.
Total
Non-Assoc.
Assoc.
Cumulative production
Proved reserves
Ultimate recovery
11.203
6.603
17.806
10.321
6.286
16.607
0.882
0.317
1.199
11.203
6.603
17.806
10.321
6.286
16.607
0.882
0.317
1.199
11.203
6.603
17.806
10.321
6.286
16.607
0.882
0.317
1.199
Reserve appreciation
Conventional new fields
Tight gas
Coalbed methane
Low BTU gas
8.327
1.580
119.172
3.888
0.000
7.478
1.421
119.172
3.888
0.000
0.849
0.159
0.000
0.000
0.000
14.523
24.981
64.732
4.315
14.689
14.346
24.836
64.732
4.315
14.689
0.177
0.145
0.000
0.000
0.000
14.523
27.993
84.640
5.559
14.689
14.346
27.799
84.64
5.559
14.689
0.177
0.194
0.000
0.000
0.000
All time recovery
150.773
148.566
2.207
141.046
139.525
1.521
165.210
163.640
1.570
Reserve appreciation
plus Low BTU
29.212
29.212
Crude Oil (MMB)
Category
Scenario A
U.S.G.S. Based
Current Tech.
Scenario B
Scenario C
NPC NPC Inspired
Inspired
Current Tech. Advanced Tech.
Cumulative production
Proved reserves
Ultimate recovery
633
98
731
633
98
731
633
98
731
Reserve appreciation
Conventional new fields
672
170
106
123
106
164
1,573
960
1,001
All time recovery
Resource Summaries.xls
6/19/02
7. Play Level Resources
Historical Ultimate Recovery and Recovery Per Well
Table 2-6 presents data on historical recovery for each subplay. Gas completions and oil
completions have been evaluated. The table shows the total number of well completions,
the EUR (estimated ultimate recovery), and the EUR per well. Volumes shown on the
table are net, dry gas and liquids. Net dry gas is the volume of gas after removal of nonhydrocarbons and plant liquids. This is the marketable dry gas. Liquids on the table
include natural gas liquids in gas wells and crude in oil wells.
The Green River database contains a total of 7,234 gas completions, and 2,520 oil
completions.
Also shown are the Liquid to Gas Ratio for gas wells and the Gas-Oil Ratio for oil wells.
The USGS play with the largest volume of proved gas reserves is the Moxa Arch, which
represents 6.3 Tcf of non-associated ultimate recovery. The next largest non-associated
play is the Mesaverde tight play, which contains 2.9 Tcf of proved non-associated
recovery.
USGS and NPC Play Level Gas Resources
Table 2-7 presents a summary of the USGS resource base allocated to plays and
subplays. Table 2-8 presents this information for the advanced tech NPC-inspired
resource.
The tables contain three groups of columns - square mile area, recovery, and recovery per
square mile.
Table 2-6
Historical Recovery and Recovery Per Completion - Green River Basin Gas and Oil Completions
Net dry gas (Bcf) and Liquids (MMB)
Historical completions and recoveries
Gas completions
Oil completions
Non-assoc.
Non-assoc. EUR/
Liquids
EUR
completion EUR
BCF
BCF
MMB
play
Gas
comps
Liquids
EUR/
completion L/G ratio
MMB
bbl/mmcf
Assoc.
EUR
BCF
Oil
comps
Assoc.
EUR/
Liquids
completion EUR
BCF
MMB
Liquids
EUR/
Gas/oil
completion ratio
MMB
mcf/bbl
3701-A Rock Springs Uplift - Tertiary
3701-B Rock Springs Uplift - Upper K
3701-C Rock Springs Uplift - Lower K
3701-D Rock Springs Uplift - J thru Perm
3701-E Rock Springs Uplift - Penn
3701-Z Rock Springs Uplift - Misc.
total
3
218
333
34
21
30
639
0.79
716.35
565.64
33.46
558.27
269.18
2143.69
0.263
3.286
1.699
0.984
26.584
8.973
3.355
0.00
5.21
0.74
0.75
27.20
0.06
33.95
0.000
0.024
0.002
0.022
1.295
0.002
0.053
0.3
7.3
1.3
22.4
48.7
0.2
15.8
0
311
16
2
1
16
346
0.00
110.38
2.67
5.27
73.53
24.59
216.43
0.000
0.355
0.167
2.633
73.527
1.537
0.626
0.00
56.67
0.27
0.84
10.75
35.99
104.51
3702-A Cherokee Arch - Tertiary
3702-B Cherokee Arch - Upper K
3702-C Cherokee Arch - Lower K
3702-D Cherokee Arch - JR and older
3702-Z Cherokee Arch - Misc.
total
173
208
7
14
26
428
578.94
669.50
16.94
110.27
66.95
1442.60
3.346
3.219
2.420
7.877
2.575
3.371
3.93
1.97
0.00
0.00
0.20
6.10
0.023
0.009
0.001
0.000
0.008
0.014
6.8
2.9
0.3
0.0
3.0
4.2
37
6
0
0
8
51
65.59
5.65
0.00
0.00
17.23
88.47
1.773
0.942
0.000
0.000
2.153
1.735
10.27
0.06
0.00
0.00
0.45
10.78
43
33.54
0.780
0.81
0.019
24.2
191
28.41
0.149
231
234
3,241
13
61
3,780
233.79
243.17
5761.04
10.30
93.27
6341.58
1.012
1.039
1.778
0.792
1.529
1.678
2.08
1.86
41.25
0.50
0.26
45.95
0.009
0.008
0.013
0.038
0.004
0.012
8.9
7.6
7.2
48.6
2.8
7.2
423
338
127
21
145
1,054
18.88
24.81
134.50
2.77
56.19
237.15
110
61
2
173
257.94
59.21
3.64
320.79
2.345
0.971
1.821
1.854
3.28
1.12
0.06
4.46
0.030
0.018
0.032
0.026
12.7
18.9
17.4
13.9
9
4
1
14
0
0.00
0.000
0.00
109
29
66
204
38.30
32.73
28.52
99.55
0.351
1.129
0.432
0.488
0.91
8.10
1.65
10.66
0
0.00
0.000
0.00
23
1256.06
54.611
0.10
3703 Axial Uplift
3704-A Moxa Arch - Tertiary
3704-B Moxa Arch - Upper K
3704-C Moxa Arch - Lower K
3704-D Moxa Arch - J thru Penn
3704-Z Moxa Arch - Misc.
total
3705-A Basin Margin Anticline - Tertiary - Upper K
3705-B Basin Margin Anticline - Lower K
3705-Z Basin Margin Anticline - Misc.
total
3706 Subthrust (no production)
3707-A Platform (Eastern Basin) - Cretaceous
3707-B Platform (Eastern Basin) - Pre-Cretaceous
3707-Z Platform (Eastern Basin) - Misc.
total
3708 Jackson Hole (no production)
3709 Deep Basin
grb_eur_data_PLAYTOTALS.xls
0.008
0.279
0.025
0.052
0.004
23.9
247.4
57.7
107.1
0.1
0.182
0.017
0.422
10.747
2.249
0.302
1.9
9.9
6.2
6.8
0.7
2.1
0.278
0.011
6.4
87.8
0.056
0.211
38.7
8.2
64.76
0.339
0.4
0.045
0.073
1.059
0.132
0.387
0.225
41.90
26.77
13.27
10.62
13.28
105.83
0.099
0.079
0.104
0.506
0.092
0.100
0.5
0.9
10.1
0.3
4.2
2.2
4.40
0.00
0.00
4.40
0.489
0.000
0.000
0.315
0.61
0.01
0.03
0.66
0.068
0.004
0.029
0.047
7.2
0.1
0.0
6.7
0
0.00
0.000
0.00
182
419
190
791
6.61
519.56
32.93
559.10
0.036
1.240
0.173
0.707
28.81
265.81
147.35
441.98
0.158
0.634
0.776
0.559
0.2
2.0
0.2
1.3
0
0.00
0.000
0.00
0
0.00
0.000
0.00
6/19/02
Historical completions and recoveries
Gas completions
Non-assoc.
Non-assoc. EUR/
Liquids
EUR
completion EUR
BCF
BCF
MMB
play
Gas
comps
3740-1 Cloverly-Frontier Tight 0-14999 Ft
3740-2 Cloverly-Frontier Tight 15000-16999 Ft
3740-3 Cloverly-Frontier Tight 17000-18999 Ft
3740-4 Cloverly-Frontier Tight 19000-20999 Ft
3740-5 Cloverly-Frontier Tight 21000+ Ft
total
Oil completions
Liquids
EUR/
completion L/G ratio
MMB
bbl/mmcf
12
0
1
4
0
17
2.48
0.00
0.00
0.19
0.00
2.67
0.207
0.000
0.002
0.047
0.000
0.157
0.03
0.00
0.00
0.00
0.00
0.03
0.002
10.8
0.000
0.000
0.0
0.0
0.002
408
711
118
12
2
1,251
1081.88
1493.17
315.93
20.17
0.11
2911.25
2.652
2.100
2.677
1.681
0.055
2.327
16.36
23.32
1.54
0.13
0.00
41.35
3742-1 Lewis Tight 0-9999 Ft
3742-2 Lewis Tight 10000-11999 Ft
3742-3 Lewis Tight 12000+ Ft
total
289
87
21
397
499.72
121.78
24.83
646.34
1.729
1.400
1.183
1.628
3743-1 Fox Hills-Lance Tight 0-9999 Ft
3743-2 Fox Hills-Lance Tight 10000-11999 Ft
3743-3 Fox Hills-Lance Tight 12000+ Ft
total
228
18
25
271
1241.08
72.55
92.87
1406.50
3744-1 Fort Union Tight 0-9999 Ft
3744-2 Fort Union Tight 10000-11999 Ft
total
1
2
3
3750 - Rock Springs Coalbed
Assoc.
EUR
BCF
Oil
comps
Assoc.
EUR/
Liquids
completion EUR
BCF
MMB
Liquids
EUR/
Gas/oil
completion ratio
MMB
mcf/bbl
10.0
2
6
1
1
1
11
0.27
5.26
0.00
0.00
0.00
5.53
0.135
0.876
0.000
0.000
0.000
0.502
0.19
0.00
0.00
0.00
0.00
0.19
0.095
0.000
0.000
0.000
0.001
0.017
0.0
0.0
0.0
28.8
0.040
0.033
0.013
0.011
0.000
0.033
15.1
15.6
4.9
6.4
2.2
14.2
12
19
3
2
0
36
26.61
17.37
0.48
0.45
0.00
44.91
2.218
0.914
0.160
0.223
0.000
1.248
0.93
0.77
0.03
0.00
0.00
1.73
0.078
0.041
0.009
0.000
28.5
22.5
18.1
618.2
0.048
25.9
6.32
2.29
0.02
8.63
0.022
0.026
0.001
0.022
12.6
18.8
1.0
13.4
16
4
0
20
7.19
1.84
0.00
9.03
0.450
0.460
0.000
0.000
0.36
0.14
0.00
0.50
0.022
0.036
20.0
12.7
0.025
17.9
5.443
4.030
3.715
5.190
12.29
0.89
0.98
14.16
0.054
0.049
0.039
0.052
9.9
12.2
10.6
10.1
5
0
0
5
5.93
0.00
0.00
5.93
1.185
0.000
0.000
0.000
0.22
0.00
0.00
0.22
0.043
27.4
0.043
27.4
0.15
0.17
0.31
0.148
0.084
0.105
0.00
0.01
0.01
0.005
0.003
31.5
41.2
36.6
1
0
1
0.00
0.00
0.00
0.000
0.000
0.000
0.03
0.00
0.03
0.029
0.0
0.029
0.0
0
0.00
0.000
0.00
0.000
0.00
0
0.00
0.000
0.00
0.000
0.0
3751 - Iles Coalbed
0
0.00
0.000
0.00
0.000
0.00
0
0.00
0.000
0.00
0.000
0.0
3752 Williams Fork Coalbed
5
1.68
0.336
0.00
0.000
0.00
0
0.00
0.000
0.00
0.000
0.0
3753- Almond Coalbed
0
0.00
0.000
0.00
0.000
0.00
0
0.00
0.000
0.00
0.000
0.0
3754 - Lance Coalbed
0
0.00
0.000
0.00
0.000
0.00
0
0.00
0.000
0.00
0.000
0.0
3755- Fort Union Coalbed
0
0.00
0.000
0.00
0.000
0.00
0
0.00
0.000
0.00
0.000
0.0
7,234
16,607
2,520
1,199
3741-1 Mesaverde Tight 0-8999 Ft
3741-2 Mesaverde Tight 9000-10999 Ft
3741-3 Mesaverde Tight 11000-12999 Ft
3741-4 Mesaverde Tight 13000-14999 Ft
3741-5 Mesaverde Tight 15000+ Ft
total
BASIN TOTAL
grb_eur_data_PLAYTOTALS.xls
166
1.4
731
6/19/02
Table 2-7
USGS - Based Total Gas Resource Base Analysis - Green River Basin Scenario A
Square Mile Area
Play
3701-A Rock Springs Uplift - Tertiary
3701-B Rock Springs Uplift - Upper K
3701-C Rock Springs Uplift - Lower K
3701-D Rock Springs Uplift - J thru Perm
3701-E Rock Springs Uplift - Penn
3701-Z Rock Springs Uplift - Misc.
total
Mapped
Total
Area
BCF Recovery
Growth
Extension
Area
Proved
Area
New Fld
Plus ERM
Area
Ultimately
Productive
Area
Percent
Ultimately
Productive
Remaining
Unproductive
Area
Proved
BCF
Proved
plus
Infill
Infill
BCF
Extension
BCF
New Fld
Plus ERM
BCF
Total
BCF
2,520
2,520
2,520
2,520
2,520
2,520
2,520
2
234
196
30
18
32
512
0
53
49
15
11
4
132
0
62
52
10
6
8
138
2
349
297
55
35
44
782
0.1%
13.8%
11.8%
2.2%
1.4%
1.8%
n/a
2,518
2,171
2,223
2,465
2,485
2,476
n/a
1
827
568
39
632
294
2,360
0
132
99
14
258
29
532
1
959
667
53
890
323
2,892
0
132
99
14
258
29
532
0
152
106
9
150
50
467
1
1,243
872
75
1,298
402
3,891
936
936
936
936
936
936
116
91
5
11
19
242
19
33
1
7
3
64
27
1
1
8
16
54
162
125
7
26
39
360
17.3%
13.4%
0.8%
2.8%
4.1%
n/a
774
811
929
910
897
n/a
645
675
17
110
84
1,531
75
173
3
50
10
311
719
849
20
160
94
1,842
75
173
3
50
10
311
105
5
3
57
51
221
900
1,027
25
267
155
2,373
3703 Axial Uplift
2,844
234
26
173
433
15.2%
2,411
62
5
67
5
32
104
3704-A Moxa Arch - Tertiary
3704-B Moxa Arch - Upper K
3704-C Moxa Arch - Lower K
3704-D Moxa Arch - J thru Penn
3704-Z Moxa Arch - Misc.
total
2,016
2,016
2,016
2,016
2,016
2,016
163
146
885
24
67
1,285
40
94
514
2
23
673
41
48
68
7
46
209
244
288
1,467
32
136
2,167
12.1%
14.3%
72.7%
1.6%
6.7%
n/a
1,772
1,728
549
1,984
1,880
n/a
253
268
5,896
13
149
6,579
44
121
2,397
1
36
2,598
297
389
8,292
14
185
9,177
44
121
2,397
1
36
2,598
44
62
315
3
72
495
385
572
11,004
17
293
12,270
3705-A Basin Margin Anticline - Tertiary - Upper K
3705-B Basin Margin Anticline - Lower K
3705-Z Basin Margin Anticline - Misc.
total
3,816
3,816
3,816
3,816
70
38
2
110
89
33
3
126
40
36
4
80
199
107
9
316
5.2%
2.8%
0.2%
n/a
3,617
3,709
3,807
n/a
262
59
4
325
233
37
4
274
496
96
8
599
233
37
4
274
106
39
5
150
835
172
17
1,023
792
0
0
8
8
1.0%
784
0
0
0
0
110
110
3707-A Platform (Eastern Basin) - Cretaceous
3707-B Platform (Eastern Basin) - Pre-Cretaceous
3707-Z Platform (Eastern Basin) - Misc.
total
6,696
6,696
6,696
6,696
112
66
92
270
37
50
34
121
30
6
33
69
179
122
159
460
2.7%
1.8%
2.4%
n/a
6,517
6,574
6,537
n/a
45
552
61
659
10
293
16
319
55
845
77
978
10
293
16
319
8
35
15
59
74
1,173
109
1,356
3708 Jackson Hole (no production)
2,844
0
0
3
3
0.1%
2,841
0
0
0
0
46
46
3709 Deep Basin
1,404
23
7
0
30
2.1%
1,374
1,256
0
1,256
250
0
1,506
1,944
3,564
2,844
1,944
3,456
13,752
10
6
2
6
2
26
0
0
0
0
0
0
1,451
2,313
1,563
872
1,209
7,407
1,461
2,319
1,565
878
1,211
7,433
75.1%
65.1%
55.0%
45.2%
35.0%
54.1%
484
1,245
1,279
1,066
2,245
6,319
3
5
0
0
0
8
0
0
0
0
0
0
3
5
0
0
0
8
0
0
0
0
0
0
10,306
13,145
7,108
3,173
3,518
37,251
10,309
13,150
7,108
3,173
3,518
37,259
3702-A Cherokee Arch - Tertiary
3702-B Cherokee Arch - Upper K
3702-C Cherokee Arch - Lower K
3702-D Cherokee Arch - JR and older
3702-Z Cherokee Arch - Misc.
total
3706 Subthrust (no production)
3740-1 Cloverly-Frontier Tight 0-14999 Ft
3740-2 Cloverly-Frontier Tight 15000-16999 Ft
3740-3 Cloverly-Frontier Tight 17000-18999 Ft
3740-4 Cloverly-Frontier Tight 19000-20999 Ft
3740-5 Cloverly-Frontier Tight 21000+ Ft
total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-7
USGS - Based Total Gas Resource Base Analysis - Green River Basin Scenario A
Square Mile Area
Play
Mapped
Total
Area
BCF Recovery
Growth
Extension
Area
Proved
Area
New Fld
Plus ERM
Area
Ultimately
Productive
Area
Percent
Ultimately
Productive
Remaining
Unproductive
Area
Proved
BCF
Proved
plus
Infill
Infill
BCF
Extension
BCF
New Fld
Plus ERM
BCF
Total
BCF
3741-1 Mesaverde Tight 0-8999 Ft
3741-2 Mesaverde Tight 9000-10999 Ft
3741-3 Mesaverde Tight 11000-12999 Ft
3741-4 Mesaverde Tight 13000-14999 Ft
3741-5 Mesaverde Tight 15000+ Ft
total
936
2,376
1,512
1,476
1,764
8,064
209
353
98
14
2
676
0
0
0
0
0
0
582
1,416
848
731
705
4,282
791
1,769
946
745
707
4,958
84.5%
74.5%
62.6%
50.5%
40.1%
61.5%
0
0
141
292
529
962
1,108
1,511
316
21
0
2,956
0
0
0
0
0
0
1,108
1,511
316
21
0
2,956
0
0
0
0
0
0
10,298
20,058
9,614
6,627
5,111
51,708
11,406
21,569
9,930
6,647
5,112
54,663
3742-1 Lewis Tight 0-9999 Ft
3742-2 Lewis Tight 10000-11999 Ft
3742-3 Lewis Tight 12000+ Ft
total
1,260
1,260
1,872
4,392
170
61
17
248
0
0
0
0
872
839
1,113
2,824
1,042
900
1,130
3,072
82.7%
71.5%
60.4%
70.0%
0
120
371
491
507
124
25
655
0
0
0
0
507
124
25
655
0
0
0
0
7,135
5,651
6,217
19,003
7,853
5,780
6,026
19,659
3743-1 Fox Hills-Lance Tight 0-9999 Ft
3743-2 Fox Hills-Lance Tight 10000-11999 Ft
3743-3 Fox Hills-Lance Tight 12000+ Ft
total
1,332
1,152
2,016
4,500
57
16
19
92
0
0
0
0
893
681
998
2,572
950
697
1,017
2,664
71.3%
60.5%
50.5%
59.2%
383
455
999
1,836
1,247
73
93
1,412
0
0
0
0
1,247
73
93
1,412
0
0
0
0
4,394
2,684
3,146
10,224
5,641
2,757
3,239
11,637
288
252
540
2
2
4
0
0
0
172
125
297
174
127
301
60.3%
50.4%
55.7%
114
125
239
0
0
0
0
0
0
0
0
0
0
0
0
623
363
986
623
363
987
17,804
4,039
21,843
4,288
120,751
146,882
3744-1 Fort Union Tight 0-9999 Ft
3744-2 Fort Union Tight 10000-11999 Ft
total
Total - conventional and tight
3750 - Rock Springs Coalbed
1,044
0
0
370
370
35.4%
674
0
0
0
0
693
693
3751 - Iles Coalbed
1,368
0
0
533
533
39.0%
835
0
0
0
0
377
377
936
0
0
450
450
48.1%
486
0
0
0
0
1,385
1,385
3753- Almond Coalbed
3,420
0
0
1,056
1,056
30.9%
2,364
0
0
0
0
795
795
3754 - Lance Coalbed
4,032
0
0
873
873
21.7%
3,159
0
0
0
0
230
230
3755- Fort Union Coalbed
9,036
0
0
1,547
1,547
17.1%
7,489
0
0
0
0
408
408
0
0
0
0
3,889
3,889
17,804
4,039
21,843
4,288
124,639
150,771
3752 Williams Fork Coalbed
Coalbed total
Green River Basin Total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-7
USGS - Based Total Gas Resource Bas
Recovery Per Sq Mile - BCF/sq mi
Proved
Proved
plus infill
Extension
New Fld
Plus ERM
Play
3701-A Rock Springs Uplift - Tertiary
3701-B Rock Springs Uplift - Upper K
3701-C Rock Springs Uplift - Lower K
3701-D Rock Springs Uplift - J thru Perm
3701-E Rock Springs Uplift - Penn
3701-Z Rock Springs Uplift - Misc.
total
0.39
3.53
2.90
1.29
35.10
9.18
4.61
0.39
4.10
3.40
1.75
49.45
10.08
5.65
0.00
2.47
2.03
0.90
24.57
6.43
4.02
0.28
2.47
2.03
0.90
24.57
6.43
3.39
3702-A Cherokee Arch - Tertiary
3702-B Cherokee Arch - Upper K
3702-C Cherokee Arch - Lower K
3702-D Cherokee Arch - JR and older
3702-Z Cherokee Arch - Misc.
total
5.56
7.42
3.39
10.02
4.43
6.33
6.20
9.32
3.93
14.53
4.96
7.61
3.89
5.19
2.37
7.02
3.10
4.85
3.89
5.19
2.37
7.02
3.10
4.11
3703 Axial Uplift
0.26
0.29
0.19
0.19
3704-A Moxa Arch - Tertiary
3704-B Moxa Arch - Upper K
3704-C Moxa Arch - Lower K
3704-D Moxa Arch - J thru Penn
3704-Z Moxa Arch - Misc.
total
1.55
1.84
6.66
0.54
2.23
5.12
1.82
2.66
9.37
0.57
2.77
7.14
1.09
1.28
4.66
0.38
1.56
3.86
1.09
1.28
4.66
0.38
1.56
2.37
3705-A Basin Margin Anticline - Tertiary - Upper K
3705-B Basin Margin Anticline - Lower K
3705-Z Basin Margin Anticline - Misc.
total
3.75
1.56
1.82
2.96
7.08
2.52
3.80
5.45
2.62
1.09
1.27
2.18
2.62
1.09
1.27
1.87
3706 Subthrust (no production)
0.00
0.00
0.00
14.00
3707-A Platform (Eastern Basin) - Cretaceous
3707-B Platform (Eastern Basin) - Pre-Cretaceous
3707-Z Platform (Eastern Basin) - Misc.
total
0.40
8.37
0.67
2.44
0.49
12.80
0.84
3.62
0.28
5.86
0.47
2.63
0.28
5.86
0.47
0.86
3708 Jackson Hole (no production)
0.00
0.00
0.00
15.00
54.61
54.61
38.23
0.00
0.27
0.88
0.00
0.03
0.00
0.32
0.27
0.88
0.00
0.03
0.00
0.32
0.00
0.00
0.00
0.00
0.00
0.00
7.11
5.68
4.55
3.64
2.91
5.03
3709 Deep Basin
3740-1 Cloverly-Frontier Tight 0-14999 Ft
3740-2 Cloverly-Frontier Tight 15000-16999 Ft
3740-3 Cloverly-Frontier Tight 17000-18999 Ft
3740-4 Cloverly-Frontier Tight 19000-20999 Ft
3740-5 Cloverly-Frontier Tight 21000+ Ft
total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-7
USGS - Based Total Gas Resource Bas
Recovery Per Sq Mile - BCF/sq mi
Proved
Proved
plus infill
Extension
New Fld
Plus ERM
Play
3741-1 Mesaverde Tight 0-8999 Ft
3741-2 Mesaverde Tight 9000-10999 Ft
3741-3 Mesaverde Tight 11000-12999 Ft
3741-4 Mesaverde Tight 13000-14999 Ft
3741-5 Mesaverde Tight 15000+ Ft
total
5.30
4.28
3.23
1.47
0.05
4.37
5.30
4.28
3.23
1.47
0.05
4.37
0.00
0.00
0.00
0.00
0.00
0.00
17.71
14.16
11.33
9.07
7.25
8.05
3742-1 Lewis Tight 0-9999 Ft
3742-2 Lewis Tight 10000-11999 Ft
3742-3 Lewis Tight 12000+ Ft
total
2.98
2.03
1.46
2.64
2.98
2.03
1.46
2.64
0.00
0.00
0.00
0.00
8.42
6.74
5.39
5.20
21.88
4.53
4.89
15.35
21.88
4.53
4.89
15.35
0.00
0.00
0.00
0.00
4.92
3.94
3.15
3.97
0.07
0.08
0.08
0.07
0.08
0.08
0.00
0.00
0.00
3.63
2.90
3.33
3743-1 Fox Hills-Lance Tight 0-9999 Ft
3743-2 Fox Hills-Lance Tight 10000-11999 Ft
3743-3 Fox Hills-Lance Tight 12000+ Ft
total
3744-1 Fort Union Tight 0-9999 Ft
3744-2 Fort Union Tight 10000-11999 Ft
total
Total - conventional and tight
3750 - Rock Springs Coalbed
3751 - Iles Coalbed
3752 Williams Fork Coalbed
3753- Almond Coalbed
3754 - Lance Coalbed
3755- Fort Union Coalbed
Coalbed total
Green River Basin Total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-8
NPC - Inspired Total Gas Resource Base Analysis - Green River Basin Scenario C (Advanced Technology)
Square Mile Area
Play
3701-A Rock Springs Uplift - Tertiary
3701-B Rock Springs Uplift - Upper K
3701-C Rock Springs Uplift - Lower K
3701-D Rock Springs Uplift - J thru Perm
3701-E Rock Springs Uplift - Penn
3701-Z Rock Springs Uplift - Misc.
total
Mapped
Total
Area
BCF Recovery
Growth
Extension
Area
Proved
Area
New Fld
Plus ERM
Area
Ultimately
Productive
Area
Percent
Ultimately
Productive
Remaining
Unproductive
Area
Proved
BCF
Proved
plus
Infill
Infill
BCF
Extension
BCF
New Fld
Plus ERM
BCF
Total
BCF
2,520
2,520
2,520
2,520
2,520
2,520
2,520
2
234
196
30
18
32
512
0
53
48
15
10
4
130
2
287
244
45
28
66
671
4
573
488
90
57
102
1,314
0.2%
22.7%
19.4%
3.6%
2.2%
4.0%
n/a
2,516
1,947
2,032
2,430
2,463
2,418
n/a
1
827
568
39
632
294
2,360
0
130
97
14
254
28
523
1
957
665
52
886
322
2,883
0
130
97
14
254
28
523
1
709
495
41
696
421
2,362
1
1,795
1,257
107
1,836
772
5,769
936
936
936
936
936
936
116
91
5
11
19
242
19
33
1
7
3
63
135
124
11
52
99
422
270
248
17
70
122
727
28.8%
26.5%
1.8%
7.5%
13.0%
n/a
666
688
919
866
814
n/a
645
675
17
110
84
1,531
74
171
3
49
10
305
718
846
20
159
94
1,837
74
171
3
49
10
305
525
643
26
368
308
1,870
1,317
1,659
48
576
412
4,012
3703 Axial Uplift
2,844
234
26
260
520
18.3%
2,324
62
5
67
5
48
120
3704-A Moxa Arch - Tertiary
3704-B Moxa Arch - Upper K
3704-C Moxa Arch - Lower K
3704-D Moxa Arch - J thru Penn
3704-Z Moxa Arch - Misc.
total
2,016
2,016
2,016
2,016
2,016
2,016
163
146
885
24
67
1,285
40
93
506
2
23
662
406
477
139
230
358
1,610
608
716
1,530
256
448
3,557
30.2%
35.5%
75.9%
12.7%
22.2%
n/a
1,408
1,300
486
1,760
1,568
n/a
253
268
5,896
13
149
6,579
43
119
2,358
1
35
2,556
296
387
8,253
14
185
9,134
43
119
2,358
1
35
2,556
440
613
648
88
560
2,349
779
1,119
11,259
102
780
14,039
3705-A Basin Margin Anticline - Tertiary - Upper K
3705-B Basin Margin Anticline - Lower K
3705-Z Basin Margin Anticline - Misc.
total
3,816
3,816
3,816
3,816
70
38
2
110
88
33
3
124
1,418
922
94
2,434
1,575
993
99
2,667
41.3%
26.0%
2.6%
n/a
2,241
2,823
3,717
n/a
262
59
4
325
230
36
4
269
492
95
8
595
230
36
4
269
3,719
1,006
120
4,845
4,440
1,137
131
5,709
792
0
0
198
198
25.0%
594
0
0
0
0
2,772
2,772
3707-A Platform (Eastern Basin) - Cretaceous
3707-B Platform (Eastern Basin) - Pre-Cretaceous
3707-Z Platform (Eastern Basin) - Misc.
total
6,696
6,696
6,696
6,696
112
66
92
270
36
49
34
119
59
111
219
389
208
226
345
778
3.1%
3.4%
5.1%
n/a
6,488
6,470
6,351
n/a
45
552
61
659
10
288
16
314
55
840
77
973
10
288
16
314
17
648
102
767
82
1,776
195
2,053
3708 Jackson Hole (no production)
2,844
0
0
200
200
7.0%
2,644
0
0
0
0
3,000
3,000
3709 Deep Basin
1,404
23
377
300
700
49.8%
704
1,256
0
1,256
14,690
7,500
23,445
1,944
3,564
2,844
1,944
3,456
13,752
10
6
2
6
2
26
5
1
0
0
0
5
1,406
2,116
1,410
925
1,137
6,992
1,420
2,122
1,412
931
1,139
7,024
73.1%
59.5%
49.6%
47.9%
32.9%
51.1%
524
1,442
1,432
1,013
2,317
6,728
3
5
0
0
0
8
1
0
0
0
0
1
4
6
0
0
0
9
1
0
0
0
0
1
10,301
13,158
7,087
3,167
3,508
37,220
10,305
13,164
7,087
3,167
3,508
37,231
3702-A Cherokee Arch - Tertiary
3702-B Cherokee Arch - Upper K
3702-C Cherokee Arch - Lower K
3702-D Cherokee Arch - JR and older
3702-Z Cherokee Arch - Misc.
total
3706 Subthrust (no production)
3740-1 Cloverly-Frontier Tight 0-14999 Ft
3740-2 Cloverly-Frontier Tight 15000-16999 Ft
3740-3 Cloverly-Frontier Tight 17000-18999 Ft
3740-4 Cloverly-Frontier Tight 19000-20999 Ft
3740-5 Cloverly-Frontier Tight 21000+ Ft
total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-8
NPC - Inspired Total Gas Resource Base Analysis - Green River Basin Scenario C (Advanced Technology)
Square Mile Area
Play
Mapped
Total
Area
BCF Recovery
Growth
Extension
Area
Proved
Area
New Fld
Plus ERM
Area
Ultimately
Productive
Area
Percent
Ultimately
Productive
Remaining
Unproductive
Area
Proved
BCF
Proved
plus
Infill
Infill
BCF
Extension
BCF
New Fld
Plus ERM
BCF
Total
BCF
3741-1 Mesaverde Tight 0-8999 Ft
3741-2 Mesaverde Tight 9000-10999 Ft
3741-3 Mesaverde Tight 11000-12999 Ft
3741-4 Mesaverde Tight 13000-14999 Ft
3741-5 Mesaverde Tight 15000+ Ft
total
936
2,376
1,512
1,476
1,764
8,064
209
353
98
14
2
676
151
300
85
13
0
550
410
1,106
754
633
639
3,542
770
1,759
937
661
641
4,767
82.3%
74.0%
62.0%
44.8%
36.3%
59.1%
166
617
575
815
1,123
3,297
1,108
1,511
316
21
0
2,956
561
898
193
14
0
1,666
1,669
2,408
510
35
0
4,622
561
898
193
14
0
1,666
4,183
9,209
4,760
3,368
2,814
24,334
6,413
12,516
5,463
3,416
2,814
30,622
3742-1 Lewis Tight 0-9999 Ft
3742-2 Lewis Tight 10000-11999 Ft
3742-3 Lewis Tight 12000+ Ft
total
1,260
1,260
1,872
4,392
170
61
17
248
139
51
16
205
882
858
1,089
2,829
1,191
970
1,122
3,282
94.5%
76.9%
59.9%
74.7%
69
290
750
1,110
507
124
25
655
290
72
16
378
797
196
41
1,033
290
72
16
378
5,275
4,126
4,430
13,832
6,362
4,393
4,487
15,242
3743-1 Fox Hills-Lance Tight 0-9999 Ft
3743-2 Fox Hills-Lance Tight 10000-11999 Ft
3743-3 Fox Hills-Lance Tight 12000+ Ft
total
1,332
1,152
2,016
4,500
57
16
19
92
72
19
23
114
1,050
531
574
2,155
1,179
566
616
2,361
88.5%
49.2%
30.6%
52.5%
153
586
1,400
2,139
1,247
73
93
1,412
1,106
60
79
1,245
2,353
132
172
2,657
1,106
60
79
1,245
6,147
1,890
1,690
9,726
9,606
2,082
1,940
13,628
288
252
540
2
2
4
0
0
0
191
199
389
193
201
393
66.8%
79.6%
72.8%
96
52
147
0
0
0
0
0
0
0
0
0
0
0
0
1,002
1,003
2,005
1,002
1,003
2,005
17,804
7,261
25,065
21,951
112,631
159,647
3744-1 Fort Union Tight 0-9999 Ft
3744-2 Fort Union Tight 10000-11999 Ft
total
Total - conventional and tight
3750 - Rock Springs Coalbed
1,044
0
0
261
261
25.0%
783
0
0
0
0
991
991
3751 - Iles Coalbed
1,368
0
0
209
209
15.3%
1,159
0
0
0
0
539
539
936
0
0
353
353
37.7%
583
0
0
0
0
1,981
1,981
3753- Almond Coalbed
3,420
0
0
533
533
15.6%
2,887
0
0
0
0
1,137
1,137
3754 - Lance Coalbed
4,032
0
0
244
244
6.1%
3,788
0
0
0
0
328
328
3755- Fort Union Coalbed
9,036
0
0
434
434
4.8%
8,602
0
0
0
0
583
583
0
0
0
0
5,559
5,559
17,804
7,261
25,065
21,951
118,190
165,206
3752 Williams Fork Coalbed
Coalbed total
Green River Basin Total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-8
NPC - Inspired Total Gas Resource Bas
Recovery Per Sq Mile - BCF/sq mi
Proved
Proved
plus infill
New Fld
Extension Plus ERM
Play
3701-A Rock Springs Uplift - Tertiary
3701-B Rock Springs Uplift - Upper K
3701-C Rock Springs Uplift - Lower K
3701-D Rock Springs Uplift - J thru Perm
3701-E Rock Springs Uplift - Penn
3701-Z Rock Springs Uplift - Misc.
total
0.39
3.53
2.90
1.29
35.10
9.18
4.61
0.39
4.09
3.39
1.75
49.22
10.07
5.63
0.00
2.47
2.03
0.90
24.57
6.43
4.02
0.28
2.47
2.03
0.90
24.57
6.43
3.52
3702-A Cherokee Arch - Tertiary
3702-B Cherokee Arch - Upper K
3702-C Cherokee Arch - Lower K
3702-D Cherokee Arch - JR and older
3702-Z Cherokee Arch - Misc.
total
5.56
7.42
3.39
10.02
4.43
6.33
6.19
9.29
3.92
14.46
4.95
7.59
3.89
5.19
2.37
7.02
3.10
4.85
3.89
5.19
2.37
7.02
3.10
4.44
3703 Axial Uplift
0.26
0.29
0.19
0.19
3704-A Moxa Arch - Tertiary
3704-B Moxa Arch - Upper K
3704-C Moxa Arch - Lower K
3704-D Moxa Arch - J thru Penn
3704-Z Moxa Arch - Misc.
total
1.55
1.84
6.66
0.54
2.23
5.12
1.82
2.65
9.33
0.57
2.76
7.11
1.09
1.28
4.66
0.38
1.56
3.86
1.09
1.28
4.66
0.38
1.56
1.46
3705-A Basin Margin Anticline - Tertiary - Upper K
3705-B Basin Margin Anticline - Lower K
3705-Z Basin Margin Anticline - Misc.
total
3.75
1.56
1.82
2.96
7.03
2.50
3.77
5.41
2.62
1.09
1.27
2.18
2.62
1.09
1.27
1.99
3706 Subthrust (no production)
0.00
0.00
0.00
14.00
3707-A Platform (Eastern Basin) - Cretaceous
3707-B Platform (Eastern Basin) - Pre-Cretaceous
3707-Z Platform (Eastern Basin) - Misc.
total
0.40
8.37
0.67
2.44
0.49
12.73
0.84
3.60
0.28
5.86
0.47
2.63
0.28
5.86
0.47
1.97
3708 Jackson Hole (no production)
0.00
0.00
0.00
15.00
54.61
54.61
39.00
25.00
0.27
0.88
0.00
0.03
0.00
0.32
0.36
0.93
0.00
0.03
0.00
0.36
0.19
0.61
0.00
0.00
0.00
0.23
7.33
6.22
5.03
3.42
3.09
5.32
3709 Deep Basin
3740-1 Cloverly-Frontier Tight 0-14999 Ft
3740-2 Cloverly-Frontier Tight 15000-16999 Ft
3740-3 Cloverly-Frontier Tight 17000-18999 Ft
3740-4 Cloverly-Frontier Tight 19000-20999 Ft
3740-5 Cloverly-Frontier Tight 21000+ Ft
total
GRB_play_areas_recoveries.xls
7/10/02
Table 2-8
NPC - Inspired Total Gas Resource Bas
Recovery Per Sq Mile - BCF/sq mi
Proved
Proved
plus infill
New Fld
Extension Plus ERM
Play
3741-1 Mesaverde Tight 0-8999 Ft
3741-2 Mesaverde Tight 9000-10999 Ft
3741-3 Mesaverde Tight 11000-12999 Ft
3741-4 Mesaverde Tight 13000-14999 Ft
3741-5 Mesaverde Tight 15000+ Ft
total
5.30
4.28
3.23
1.47
0.05
4.37
7.99
6.82
5.20
2.46
0.05
6.84
3.71
3.00
2.26
1.03
0.00
3.03
10.20
8.33
6.32
5.32
4.41
6.87
3742-1 Lewis Tight 0-9999 Ft
3742-2 Lewis Tight 10000-11999 Ft
3742-3 Lewis Tight 12000+ Ft
total
2.98
2.03
1.46
2.64
4.69
3.21
2.40
4.17
2.09
1.42
1.02
1.84
5.98
4.81
4.07
4.89
21.88
4.53
4.89
15.35
41.28
8.28
9.03
28.88
15.31
3.17
3.42
10.91
5.85
3.56
2.95
4.51
0.07
0.08
0.08
0.07
0.08
0.08
0.00
0.00
0.00
5.26
5.05
5.15
3743-1 Fox Hills-Lance Tight 0-9999 Ft
3743-2 Fox Hills-Lance Tight 10000-11999 Ft
3743-3 Fox Hills-Lance Tight 12000+ Ft
total
3744-1 Fort Union Tight 0-9999 Ft
3744-2 Fort Union Tight 10000-11999 Ft
total
Total - conventional and tight
3750 - Rock Springs Coalbed
3751 - Iles Coalbed
3752 Williams Fork Coalbed
3753- Almond Coalbed
3754 - Lance Coalbed
3755- Fort Union Coalbed
Coalbed total
Green River Basin Total
GRB_play_areas_recoveries.xls
7/10/02
Resource categories shown are proved recovery, the infill drilling component of reserve
appreciation (estimated at one-half of the total reserve appreciation potential), the
extension portion of reserve appreciation, and new fields and "ERM" or Enhanced
Recovery resources. (The sum of new fields and ERM is the undiscovered portion of the
resource).
Under the area portion of the tables, one of the columns presents the "Percent Ultimately
Productive" area. This is the percentage of the total mapped play area that would
theoretically be developed when all resources are exhausted. This percentage is derived
from the input and assumptions made during the assessment and allocation process and is
not meant to imply that we know how much of each play's area will eventually be
developed. Rather, it shows that the assumptions used in the assessment are consistent
with the available resource area.
8. Recovery Per Well
Table 2-9 presents the estimated future recovery per well for each subplay and resource
category. The well recoveries input into the economic analysis model are presented in
the columns on the right side of the table. There are three columns of input well
recoveries: NPC current tech, NPC advanced tech, and USGS current tech. For each
subplay, the values for reserve growth and new fields are presented on separate rows of
the table.
Old field (reserve appreciation) and conventional new field well recoveries are estimated
as a fraction of historical average well recovery. Old field recoveries are assumed to be
lower than the historical average while new field recoveries are higher (assumed factors
of 0.923 for old fields and 1.319 for new fields). For tight gas, current technology well
recoveries are based upon the USGS assessment, and advanced tech recoveries for the
NPC are from NPC assumptions.
Current tech coalbed well recoveries are assumed to be one-half of the recoveries
estimated by USGS. The logic is that the USGS study assumed a 320 acre spacing, while
the current model assumes a 160 acre spacing, with correspondingly lower well
recoveries. This assumption results in well recoveries more in line with what is now
known about well recoveries in the Powder River Basin, and test and production rates
from the initial Green River Basin wells.
The economics model does not just use the mean value of recovery per well in
developing the supply curves. Each cell is assigned a range of well recoveries to
represent a distribution of resource quality (See chapter on resource depletion).
Table 2-9
RECOVERY PER WELL DATA AND ASSUMPTIONS - SCENARIOS A (USGS CURRENT),
B (NPC CURRENT), and C (NPC ADVANCED)
GREEN RIVER BASIN
PRODCODE
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
PLAYCD
3701A
3701A
3701B
3701B
3701C
3701C
3701D
3701D
3701E
3701E
3701Z
3701Z
3702A
3702A
3702B
3702B
3702C
3702C
3702D
3702D
3702Z
3702Z
3703
3703
3704A
3704A
3704B
3704B
3704C
3704C
3704D
3704D
3704Z
3704Z
3705A
3705A
3705B
3705B
3705Z
3705Z
3706
3706
3707A
3707A
3707B
3707B
3707Z
3707Z
3708
3708
3709
3709
3709
3709
3709
3709
37401
37401
37402
37402
37403
37403
37404
37404
37405
37405
37411
37411
well recovery table.xls
Rock Springs Uplift - Tertiary
- Gas
Rock Springs Uplift - Tertiary
- Gas
Rock Springs Uplift - Upper K
- Gas
Rock Springs Uplift - Upper K
- Gas
Rock Springs Uplift - Lower K
- Gas
Rock Springs Uplift - Lower K
- Gas
Rock Springs Uplift - J thru Perm
- Gas
Rock Springs Uplift - J thru Perm
- Gas
Rock Springs Uplift - Penn
- Gas
Rock Springs Uplift - Penn
- Gas
Rock Springs Uplift - Misc.
- Gas
Rock Springs Uplift - Misc.
- Gas
Cherokee Arch - Tertiary
- Gas
Cherokee Arch - Tertiary
- Gas
Cherokee Arch - Upper K
- Gas
Cherokee Arch - Upper K
- Gas
Cherokee Arch - Lower K
- Gas
Cherokee Arch - Lower K
- Gas
Cherokee Arch - JR and older
- Gas
Cherokee Arch - JR and older
- Gas
Cherokee Arch - Misc.
- Gas
Cherokee Arch - Misc.
- Gas
Axial Uplift
- Gas
Axial Uplift
- Gas
Moxa Arch - Tertiary
- Gas
Moxa Arch - Tertiary
- Gas
Moxa Arch - Upper K
- Gas
Moxa Arch - Upper K
- Gas
Moxa Arch - Lower K
- Gas
Moxa Arch - Lower K
- Gas
Moxa Arch - J thru Penn
- Gas
Moxa Arch - J thru Penn
- Gas
Moxa Arch - Misc.
- Gas
Moxa Arch - Misc.
- Gas
Basin Margin Anticline - Tertiary - Upper K - Gas
Basin Margin Anticline - Tertiary - Upper K - Gas
Basin Margin Anticline - Lower K
- Gas
Basin Margin Anticline - Lower K
- Gas
Basin Margin Anticline - Misc.
- Gas
Basin Margin Anticline - Misc.
- Gas
Subthrust
- Gas
Subthrust
- Gas
Platform (Eastern Basin) - Cretaceous
- Gas
Platform (Eastern Basin) - Cretaceous
- Gas
Platform (Eastern Basin) - Pre-Cretaceous - Gas
Platform (Eastern Basin) - Pre-Cretaceous - Gas
Platform (Eastern Basin) - Misc.
- Gas
Platform (Eastern Basin) - Misc.
- Gas
Jackson Hole
- Gas
Jackson Hole
- Gas
Deep Basin
- Gas
Deep Basin
- Gas
Deep Basin
- Gas
Deep Basin
- Gas
Deep Basin
- Gas
Deep Basin
- Gas
Cloverly-Frontier Tight 0-14999 Ft - Gas
Cloverly-Frontier Tight 0-14999 Ft - Gas
Cloverly-Frontier Tight 15000-16999 Ft - Gas
Cloverly-Frontier Tight 15000-16999 Ft - Gas
Cloverly-Frontier Tight 17000-18999 Ft - Gas
Cloverly-Frontier Tight 17000-18999 Ft - Gas
Cloverly-Frontier Tight 19000-20999 Ft - Gas
Cloverly-Frontier Tight 19000-20999 Ft - Gas
Cloverly-Frontier Tight 21000+ Ft
- Gas
Cloverly-Frontier Tight 21000+ Ft
- Gas
Mesaverde Tight 0-8999 Ft
- Gas
Mesaverde Tight 0-8999 Ft
- Gas
resource
category
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
resource
units
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
Scenario A
Scenario B
Scenario C
eur/compl
USGS current eur/compl NPC eur/compl NPC
tech
current tech
advanced tech
0.248
0.248
0.248
0.354
0.354
0.389
1.231
1.231
1.231
1.760
1.760
1.936
0.910
0.910
0.910
1.301
1.301
1.431
1.683
1.683
1.683
2.405
2.405
2.646
27.539
27.539
27.539
39.354
39.354
43.290
6.494
6.494
6.494
9.281
9.281
10.209
0.350
0.350
0.350
0.500
0.500
0.551
0.789
0.789
0.789
1.128
1.128
1.241
2.288
2.288
2.288
3.270
3.270
3.597
3.932
3.932
3.932
5.619
5.619
6.181
0.952
0.952
0.952
1.360
1.360
1.496
0.735
0.735
0.735
1.051
1.051
1.156
0.484
0.484
0.484
0.691
0.691
0.760
0.946
0.946
0.946
1.352
1.352
1.487
1.007
1.007
1.100
1.440
1.440
1.583
0.833
0.833
0.833
1.190
1.190
1.309
0.206
0.206
0.206
0.295
0.295
0.324
2.457
2.457
2.457
3.511
3.511
3.862
1.219
1.219
1.219
1.742
1.742
1.916
1.740
1.740
1.740
2.486
2.486
2.735
4.000
4.000
4.000
4.000
4.000
4.000
0.343
0.343
0.343
0.490
0.490
0.539
1.119
1.119
1.119
1.600
1.600
1.759
0.407
0.407
0.407
0.582
0.582
0.640
2.000
2.000
2.000
2.000
2.000
2.000
50.406
50.406
50.406
72.032
72.032
79.235
20.306
20.306
20.306
29.018
29.018
31.920
7.615
7.615
7.615
10.882
10.882
11.970
2.079
2.079
2.079
2.079
2.079
2.717
1.663
1.663
1.663
1.663
1.663
2.174
1.330
1.330
1.330
1.330
1.330
1.739
1.064
1.064
1.064
1.064
1.064
1.391
0.852
0.852
0.852
0.852
0.852
1.113
2.796
2.796
2.796
2.796
2.796
3.654
ratio of NPC
advanced to
current
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.092
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.000
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.000
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
6/19/02
Table 2-9
RECOVERY PER WELL DATA AND ASSUMPTIONS - SCENARIOS A (USGS CURRENT),
B (NPC CURRENT), and C (NPC ADVANCED)
GREEN RIVER BASIN
PRODCODE PLAYCD
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
37412
37412
37413
37413
37414
37414
37415
37415
37421
37421
37422
37422
37423
37423
37431
37431
37432
37432
37433
37433
37441
37441
37442
37442
3750
3750
3751
3751
3752
3752
3753
3753
3754
3754
3755
3755
3701B
3701B
3701C
3701C
3701D
3701D
3701E
3701E
3701Z
3701Z
3702A
3702A
3702B
3702B
3702C
3702C
3702Z
3702Z
3703
3703
3704A
3704A
3704B
3704B
3704C
3704C
3704D
3704D
3704Z
3704Z
3705A
3705A
well recovery table.xls
Mesaverde Tight 9000-10999 Ft
- Gas
Mesaverde Tight 9000-10999 Ft
- Gas
Mesaverde Tight 11000-12999 Ft
- Gas
Mesaverde Tight 11000-12999 Ft
- Gas
Mesaverde Tight 13000-14999 Ft
- Gas
Mesaverde Tight 13000-14999 Ft
- Gas
Mesaverde Tight 15000+ Ft
- Gas
Mesaverde Tight 15000+ Ft
- Gas
Lewis Tight 0-9999 Ft
- Gas
Lewis Tight 0-9999 Ft
- Gas
Lewis Tight 10000-11999 Ft
- Gas
Lewis Tight 10000-11999 Ft
- Gas
Lewis Tight 12000+ Ft
- Gas
Lewis Tight 12000+ Ft
- Gas
Fox Hills-Lance Tight 0-9999 Ft
- Gas
Fox Hills-Lance Tight 0-9999 Ft
- Gas
Fox Hills-Lance Tight 10000-11999 Ft - Gas
Fox Hills-Lance Tight 10000-11999 Ft - Gas
Fox Hills-Lance Tight 12000+ Ft
- Gas
Fox Hills-Lance Tight 12000+ Ft
- Gas
Fort Union Tight 0-9999 Ft
- Gas
Fort Union Tight 0-9999 Ft
- Gas
Fort Union Tight 10000-11999 Ft
- Gas
Fort Union Tight 10000-11999 Ft
- Gas
Rock Springs Coalbed
- Gas
Rock Springs Coalbed
- Gas
Iles Coalbed
- Gas
Iles Coalbed
- Gas
Williams Fork Coalbed
- Gas
Williams Fork Coalbed
- Gas
Almond Coalbed
- Gas
Almond Coalbed
- Gas
Lance Coalbed
- Gas
Lance Coalbed
- Gas
Fort Union Coalbed
- Gas
Fort Union Coalbed
- Gas
Rock Springs Uplift - Upper K
- Oil
Rock Springs Uplift - Upper K
- Oil
Rock Springs Uplift - Lower K
- Oil
Rock Springs Uplift - Lower K
- Oil
Rock Springs Uplift - J thru Perm
- Oil
Rock Springs Uplift - J thru Perm
- Oil
Rock Springs Uplift - Penn
- Oil
Rock Springs Uplift - Penn
- Oil
Rock Springs Uplift - Misc.
- Oil
Rock Springs Uplift - Misc.
- Oil
Cherokee Arch - Tertiary
- Oil
Cherokee Arch - Tertiary
- Oil
Cherokee Arch - Upper K
- Oil
Cherokee Arch - Upper K
- Oil
Cherokee Arch - Lower K
- Oil
Cherokee Arch - Lower K
- Oil
Cherokee Arch - Misc.
- Oil
Cherokee Arch - Misc.
- Oil
Axial Uplift
- Oil
Axial Uplift
- Oil
Moxa Arch - Tertiary
- Oil
Moxa Arch - Tertiary
- Oil
Moxa Arch - Upper K
- Oil
Moxa Arch - Upper K
- Oil
Moxa Arch - Lower K
- Oil
Moxa Arch - Lower K
- Oil
Moxa Arch - J thru Penn
- Oil
Moxa Arch - J thru Penn
- Oil
Moxa Arch - Misc.
- Oil
Moxa Arch - Misc.
- Oil
Basin Margin Anticline - Tertiary - Upper K - Oil
Basin Margin Anticline - Tertiary - Upper K - Oil
resource
category
resource
units
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
bcf wet
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
Scenario A
Scenario B
Scenario C
eur/compl
USGS current eur/compl NPC eur/compl NPC
tech
current tech
advanced tech
2.237
2.237
1.789
1.789
1.431
1.431
1.145
1.145
1.697
1.697
1.358
1.358
1.086
1.086
1.143
1.143
0.915
0.915
0.732
0.732
0.783
0.783
0.626
0.626
0.744
0.744
0.506
0.506
1.100
1.100
0.418
0.418
0.264
0.264
0.264
0.264
0.060
0.086
0.034
0.048
0.082
0.118
0.081
0.116
0.099
0.142
0.082
0.118
0.082
0.118
0.105
0.150
0.082
0.117
0.105
0.150
0.083
0.119
0.051
0.073
0.040
0.057
0.104
0.149
0.042
0.060
0.083
0.118
2.237
2.237
1.789
1.789
1.431
1.431
1.145
1.145
1.697
1.697
1.358
1.358
1.086
1.086
1.342
1.342
0.915
0.915
0.732
0.732
1.481
1.481
1.481
1.481
0.744
0.744
0.506
0.506
1.100
1.100
0.418
0.418
0.264
0.264
0.264
0.264
0.060
0.086
0.034
0.048
0.082
0.118
0.081
0.116
0.099
0.142
0.082
0.118
0.082
0.118
0.105
0.150
0.082
0.117
0.105
0.150
0.083
0.119
0.051
0.073
0.040
0.057
0.104
0.149
0.042
0.060
0.083
0.118
2.237
2.923
1.789
2.339
1.431
1.871
1.145
1.497
1.697
2.218
1.358
1.774
1.086
1.419
1.342
1.754
0.915
1.195
0.732
0.956
1.481
1.935
1.481
1.935
0.959
0.959
0.652
0.652
1.418
1.418
0.539
0.539
0.340
0.340
0.340
0.340
0.060
0.095
0.034
0.053
0.082
0.130
0.081
0.127
0.099
0.156
0.082
0.129
0.082
0.130
0.105
0.165
0.082
0.128
0.105
0.165
0.083
0.131
0.051
0.080
0.040
0.062
0.104
0.164
0.042
0.066
0.083
0.130
ratio of NPC
advanced to
current
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.289
1.289
1.289
1.289
1.289
1.289
1.289
1.289
1.289
1.289
1.289
1.289
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
6/19/02
Table 2-9
RECOVERY PER WELL DATA AND ASSUMPTIONS - SCENARIOS A (USGS CURRENT),
B (NPC CURRENT), and C (NPC ADVANCED)
GREEN RIVER BASIN
PRODCODE PLAYCD
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
O
3705B
3705B
3705Z
3705Z
3706
3706
3707A
3707A
3707B
3707B
3707Z
3707Z
3708
3708
37401
37401
37411
37411
37412
37412
37413
37413
37414
37414
37421
37421
37422
37422
37423
37423
37431
37431
37432
37432
37433
37433
37441
37441
well recovery table.xls
Basin Margin Anticline - Lower K
- Oil
Basin Margin Anticline - Lower K
- Oil
Basin Margin Anticline - Misc.
- Oil
Basin Margin Anticline - Misc.
- Oil
Subthrust
- Oil
Subthrust
- Oil
Platform (Eastern Basin) - Cretaceous
- Oil
Platform (Eastern Basin) - Cretaceous
- Oil
Platform (Eastern Basin) - Pre-Cretaceous - Oil
Platform (Eastern Basin) - Pre-Cretaceous - Oil
Platform (Eastern Basin) - Misc.
- Oil
Platform (Eastern Basin) - Misc.
- Oil
Jackson Hole
- Oil
Jackson Hole
- Oil
Cloverly-Frontier Tight 0-14999 Ft - Oil
Cloverly-Frontier Tight 0-14999 Ft - Oil
Mesaverde Tight 0-8999 Ft
- Oil
Mesaverde Tight 0-8999 Ft
- Oil
Mesaverde Tight 9000-10999 Ft
- Oil
Mesaverde Tight 9000-10999 Ft
- Oil
Mesaverde Tight 11000-12999 Ft
- Oil
Mesaverde Tight 11000-12999 Ft
- Oil
Mesaverde Tight 13000-14999 Ft
- Oil
Mesaverde Tight 13000-14999 Ft
- Oil
Lewis Tight 0-9999 Ft
- Oil
Lewis Tight 0-9999 Ft
- Oil
Lewis Tight 10000-11999 Ft
- Oil
Lewis Tight 10000-11999 Ft
- Oil
Lewis Tight 12000+ Ft
- Oil
Lewis Tight 12000+ Ft
- Oil
Fox Hills-Lance Tight 0-9999 Ft
- Oil
Fox Hills-Lance Tight 0-9999 Ft
- Oil
Fox Hills-Lance Tight 10000-11999 Ft - Oil
Fox Hills-Lance Tight 10000-11999 Ft - Oil
Fox Hills-Lance Tight 12000+ Ft
- Oil
Fox Hills-Lance Tight 12000+ Ft
- Oil
Fort Union Tight 0-9999 Ft
- Oil
Fort Union Tight 0-9999 Ft
- Oil
resource
category
resource
units
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
mmbbl
Scenario A
Scenario B
Scenario C
eur/compl
USGS current eur/compl NPC eur/compl NPC
tech
current tech
advanced tech
0.106
0.151
0.106
0.151
0.105
0.150
0.106
0.151
0.085
0.122
0.106
0.151
0.105
0.150
0.089
0.128
0.142
0.203
0.101
0.145
0.027
0.039
0.027
0.039
0.039
0.056
0.109
0.156
0.104
0.148
0.082
0.117
0.105
0.150
0.105
0.150
0.089
0.128
0.106
0.151
0.106
0.151
0.105
0.150
0.106
0.151
0.085
0.122
0.106
0.151
0.105
0.150
0.089
0.128
0.142
0.203
0.101
0.145
0.027
0.039
0.027
0.039
0.039
0.056
0.109
0.156
0.104
0.148
0.082
0.117
0.105
0.150
0.105
0.150
0.089
0.128
0.106
0.166
0.106
0.166
0.105
0.165
0.106
0.166
0.085
0.134
0.106
0.166
0.105
0.165
0.089
0.141
0.142
0.266
0.101
0.189
0.027
0.050
0.027
0.050
0.039
0.073
0.109
0.204
0.104
0.194
0.082
0.153
0.105
0.196
0.105
0.196
0.089
0.167
ratio of NPC
advanced to
current
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.100
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
1.000
1.307
6/19/02
3. Cost Data and Discounted Cash Flow Analysis
1. Introduction
EEA has developed a spreadsheet model to calculate the resource cost of each unit of
analysis in the study. The unit of analysis is the hydrocarbon resource (oil or gas volume)
attributed to a subplay, hydrocarbon type (oil or gas), and resource type (reserve
appreciation or undiscovered resource).
As an example, the following is a unit of analysis in the database:
•
Gas wells (non-associated gas)
•
Moxa arch USGS play; EEA Lower Cretaceous subplay
•
Undiscovered resource
The resource cost of each unit of analysis is determined on the basis of dollars per
thousand cubic feet (Mcf), and dollars per million Btu (MMBtu). This is the selling price
required at the wellhead to compensate producers for their investments, operating costs,
taxes, royalties and cost of capital. It is computed using a discounted cash flow analysis
wherein the present value of the investment is exactly zero when all negative (costs) and
positive (revenues) cash flows are discounted at the average cost of capital.
The finding and development cost is also determined. This is simply the total
investment divided by reserves added (on net working interest basis measured in barrels
of oil equivalent). This excludes operating costs, taxes and the time value of money. It
corresponds roughly to the finding and development (F&D) cost typically reported by
J.S. Herold and Arthur Andersen in their annual compilations of the financial reports of
E&P companies.
There are three resource scenarios for which costs are developed:
•
Scenario A -USGS - based current technology
•
Scenario B -NPC - inspired current technology
•
Scenario C -NPC - inspired advanced technology
The current technology cases include current well recoveries (as assessed by USGS or
NPC) and current costs. The NPC advanced technology scenario includes advanced
technology (2010) well recoveries and reductions in certain cost components.
2. Data Sources and Approach for Cost Components
Cost data for the spreadsheet were taken from several sources, including the Joint
Association Survey on Drilling Costs (API) and Costs and Indexes for Domestic Oil and
Gas Field Equipment and Production Operations (U.S. Department of Energy), and
government and industry literature and presentations. Drilling, stimulation, equipment, and
operating costs were estimated for each play or subplay. The costs first were estimated
assuming one completion per well, then adjusted for the average number of completions
per gas well.
Drilling Costs
Completed gas well costs were adapted from the 1998 Joint Association Survey (JAS)
report. A cost versus depth function was developed from this information. The JAS report
has information on Wyoming drilling costs by 2,500 foot interval, and reports costs for oil
wells, gas wells, and dry holes. Costs from the report were adjusted to approximate current
drilling costs by using published information on land rig rates over the past few years.
Equations were developed by EEA to input the estimated drilling depth for each subplay
and to calculate gas well and oil well costs and dry hole costs in dollars per foot.
Drilling costs for coalbed methane wells were derived from industry trade press and
company presentations.
Drilling costs are higher for wells drilled into sour gas reservoirs. For this analysis, sour
reservoirs are defined as those containing greater than 5 percent CO2 or 50 ppm H2S.
Wells drilled into these reservoirs require special wellhead and tubular steel alloys, and
more costly drilling programs. Overall drilling costs for sour reservoirs were estimated to
be 50 percent higher than in normal, "sweet" environments.
Stimulation Costs
EEA estimated artificial stimulation (hydraulic fracturing) costs on the basis of number of
zones stimulated and estimated average cost per zone. The IHS Well History database was
used to determine typical stimulation practices for each play. Cost estimates for each
treatment were taken from industry trade journals. The total stimulation cost for a well in a
specific subplay is the estimated number of zones times the cost per zone.
Equipment Costs
Equipment costs for producing wells were added to the cost of development. These
expenses include the costs of flowlines, separators, pumps and tanks. Estimates for the cost
of this equipment were derived from a survey conducted by the Dallas Field Office of EIA
and published in the December 2001 report titled "Oil and Gas Lease Equipment and
Operating Costs - 1986 Through 2000." This report contains equipment cost data for the
Rocky Mountain region by depth and well production rate. Items included in the cost
analysis for gas wells include the following:
•
flowlines and connections
•
production package
•
dehydrators
•
storage tanks
Costs for equipment intended for sour reservoir production were increased by a factor of
2.5. Costs for coalbed methane well equipment were estimated separately and include
water pumping and handling equipment and compressors needed to accommodate low
flowing pressures.
Conventional Operating Costs
Annual operating costs for conventional wells were taken from the December 2001 EIA
report titled "Oil and Gas Lease Equipment and Operating Costs - 1986 Through 2000."
This report contains operating cost data for the Rocky Mountain region by depth and well
production rate.
Items included in the cost analysis for gas wells include the following:
•
direct labor and overhead
•
fuel, chemicals and disposal
•
surface maintenance
•
subsurface maintenance
Special operating costs were developed for coalbed methane plays for water pumping and
handling, water disposal, and compressor operation (see below).
Gas Compression Operating Costs
Coalbed methane gas is produced at low pressures, and the gas requires compression before
entering the interstate pipeline. These compression costs are included in the capital and
annual operating cost for the coalbed subplays.
Table 3-1 presents the analysis of gas compression costs in dollars per MMBtu. Across the
top of the table are four pressure values ranging from 20 to 400 psi that represent the
flowing pressure at the wellhead near the inlet to the compressor unit. The costs for each
pressure value have been evaluated. The last row in the table shows the total capital and
operating cost in dollars per MMBtu including an allowance for the gas consumed by the
compressor. This cost ranges from $0.30 per MMBtu for 20 psi inlet pressure gas down to
a value of $0.07 per MMBtu for 400 psi gas.
In the current study, EEA is assuming an inlet pressure of 100 psi for coalbed. As shown
in the second column, the well volume is assumed to be 0.2 MMcfd. The outlet pressure
from the compressor is 1,000 psi. This is a compression ratio of 10. To achieve this
compression ratio, 3.32 compression stages are needed at a 1:2 ratio per stage.
Approximately 40 horsepower are needed per MMcfd per stage, resulting in the need for
26.6 HP per well in this case. (3.32 stages x 40 HP x 0.2 MMcfd). At a compressor cost of
Table 3-1
COMPRESSION COSTS EXAMPLES
Inlet pressure (psi)
Volume MMcfd/well
Outlet pressure (psi)
Compression ratio
Compressor stages (1:2)
20
0.200
1,000
50.0
5.64
100
0.200
1,000
10.0
3.32
200
0.200
1,000
5.0
2.32
400
0.200
1,000
2.5
1.32
HP/MMcfd (1:2 comp ratio)
HP needed/well
40
45.2
40
26.6
40
18.6
40
10.6
US$/HP compressor costs
$ for compressors/well
$ for compressors/Mcfd
$1,500
$67,726
$339
$1,500
$39,863
$199
$1,500
$27,863
$139
$1,500
$15,863
$79
8,500
9.21
1,000
200
4.61%
8,500
5.42
1,000
200
2.71%
8,500
3.79
1,000
200
1.89%
8,500
2.16
1,000
200
1.08%
$0.19
$0.12
$0.30
$0.11
$0.07
$0.18
$0.08
$0.05
$0.12
$0.04
$0.03
$0.07
Fuel use Btu/HP per HR
Fuel use MMBtu/day/well
Btu/cf of gas
Daily production in MMBtu
Compressor fuel use as % production
Costs per Unit of Production
Capital and O&M @20% of
capital costs/year
Fuel Value @ $2.50/MMBtu
Total $/MMBtu
$1,500 per HP, this results in a cost of $39,863 per well (26.6 x 1,500). The compressor
cost per Mcfd is $199 ($39,863 / 0.200 MMcfd / 1,000).
Fuel use is estimated to be 8,500 Btu per HP per hour, which translates into 5.42 MMBtu
per day per well. (8,500 x 26.6 x 24 / 1,000,000). Assuming a daily gas production rate of
200 MMBtu, the compressor fuel use represents 2.71 percent of total production.
The capital and O & M cost is calculated at 20% of capital costs per year and equals $0.11
per MMBtu ($199 x 0.2 / 365 days). The fuel value is calculated to be $0.07 per MMBtu
assuming a gas price of $2.50 per MMBtu ( $2.50 x 2.71%).
Gas Processing Operating Costs
Where gas processing of low quality gas is needed, additional costs are added to the
Operating and Maintenance costs. The source of this information is EEA internal analysis.
The gas composition of each subplay is known through processing by EEA of the
EEA/GTI gas composition database and other sources. Depending upon the gas
composition, removal of non-hydrocarbons may be required. In general, pipelines specify
that any gas that contains more than 2% CO2, 4% nitrogen, or 4 ppm of hydrogen sulfide
(H2S) is considered low quality gas that may require processing (or in some cases
blending) prior to marketing.
The Green River Basin contains large resources of low quality gas. One of the
accumulations of great importance is the deep Paleozoic low quality gas on the Moxa Arch.
The volume of gas in place is approximately 170 Tcf, and the gas contains CO2, nitrogen,
H2S, and helium. Exxon has developed part of the accumulation and has a very large gas
processing plant at Shute Creek. Most of the accumulation remains undeveloped, and even
though the gas quality is very low, there is a very large volume of methane present. EEA
has modeled this accumulation into three segments of varying gas composition.
Water Disposal Costs
Coalbed methane production is generally associated with a large volume of produced
water. The rate of water production is high compared to that of conventional reservoirs
because coalbeds contain fractures and pores that are water saturated, and because the
water must be removed to achieve gas production. Water in coalbeds contributes to
pressure in the reservoir that keeps the methane adsorbed to the coal. This water must be
removed by pumping (with a downhole pump) in order for the methane to desorb from the
coal and be produced. Over time, the volume of water produced from a coalbed well
generally declines, as the rate of gas production increases. The dewatering period required
to achieve peak gas production rates can be up to 6 months or longer.
The produced water may be discharged to the surface if it is determined by regulatory
agencies that the production rate and chemical composition is such that it will not be
harmful. Otherwise, re-injection into special injection wells or treatment is required.
Although coalbed methane production is just beginning in the Green River basin, current
information indicates that re-injection or treatment will be required for most or all of the
production due to relatively high salinity. The following text describing water composition
and handling was posted on the Wyoming State Water Plan website:
"There are significant differences between CBM resources of
the Powder River Basin and those of the Greater Green River
Basin including the quality of water associated with the
coals (Harju, 2000) and limitations of the quality of water
which may be discharged to the surface (Harju, 2000;
Neuman, 2000). The quality of water associated with the
coals is reportedly significantly worse in the Greater
Green River Basin than in the Powder River Basin (Harju,
2000). Limitations imposed by interstate compact on the
quality of water which is discharged in the Green River may
require that the co-produced water be treated or
reinjected. The BLM's current policy on federally developed
CBM resources in the Greater Green River Basin is that all
co-produced water must be re-injected or treated prior to
discharge on the surface (Neuman, 2000). The impacts of the
added costs of treatment or reinjection are unclear, but
may render some CBM projects uneconomical. At this time, it
appears unlikely that the level of development of CBM
resources in the Greater Green River Basin will match the
levels of development anticipated in the Powder River Basin
given current market and environmental conditions."
Table 3-2 shows an EEA analysis of projected well level coalbed gas and water production
in the Green River Basin. The table presents an annual production stream from an Upper
Table 3-2
Typical Green River Basin Almond CBM Well
Based upon Scenario C (advanced tech) well recovery
year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Sum
bbls/mcf
ratio
1.30
1.11
0.94
0.80
0.68
0.58
0.49
0.42
0.35
0.30
0.26
0.22
0.18
0.16
0.13
0.11
0.10
0.08
0.07
0.06
819.04
Average (15 year)
NPV@7% (15 year)
GAS
MMcf/yr
56
140
88
58
42
31
24
19
16
13
11
10
8
7
6
6
3
0
0
0
539
96.8
0.89
MMCF per well
annual decline rate in water ratio
coalbed water rate.xls
GAS
Mcf/d
152.5
383.7
240.9
160.0
114.0
85.4
66.3
53.0
43.3
36.1
30.5
26.1
22.6
19.8
17.5
15.5
9.4
0.0
0.0
0.0
WATER
bbl/d
198.3
424.0
226.2
127.8
77.4
49.2
32.5
22.1
15.3
10.9
7.8
5.7
4.2
3.1
2.3
1.8
0.9
0.0
0.0
0.0
WATER
bbl/y
72,381
154,753
82,572
46,629
28,243
17,974
11,867
8,061
5,601
3,965
2,850
2,075
1,528
1,136
852
643
332
0
0
0
441,462
80.5
401
358,706
539
15%
6/19/02
Cretaceous Almond formation coalbed well with an ultimate gas recovery of 539 MMcf.
Information on anticipated water production rates for coalbed wells in the basin is very
preliminary, and is taken from BLM environmental (EIS) documents submitted by
operators, as well as industry press releases. In this scenario, peak gas production occurs
in year 2 at 384 mcf per day. Peak water production from the well is 424 barrels per day,
and declines throughout the life of the well. Near the bottom of the table are the "net
present value" calculations for water and gas production. EEA uses the net present value to
define the water to gas ratio over the life of the well for economic analysis. In this
example, the NPV ratio of water production is 0.89 barrels per mcf.
Water disposal operating costs can range from $0.20 to $1.00 per barrel of water. The
current value used by EEA for the Green River Basin is $0.50 per bbl. The Powder River
cost is estimated to be the lowest value in the Rockies ($0.20 or less) because surface
discharge is allowed. The higher cost in the Green River Basin results entirely from the
assumed requirement for re-injection or treatment.
Table 3-3 presents the EEA analysis of water injection costs. The four columns represent
different drilling depths for the water injection well, ranging from 1,000 to 2,500 feet.
Taking the third column as an example, the depth of the injection well is 2,000 feet. The
cost of the injection well is $130,000 and the equipment including water distribution lines
and electrical pumps is $52,000. Annual operating cost is for the injection well is $20,650.
The Capital Recovery Factor (CRF) is 15%, which is applied to the capital cost to
determine the annual capital cost. This results in a total annual cost of $47, 954.
At an injection rate of 500 barrels of water per day, the annual cost is $0.26 per barrel. The
lower portion of the table shows the impact of water injection rate. If the water injection
rate is reduced to 250 barrels per day, the cost is $0.50 per barrel, which is the value used
as a best estimate for the current study.
Table 3-3
Example Costs for Water Injection Wells
Disposal Well Depth (FT)
1,000
1,500
2,000
2,500
Well Cost
Equipment *
Capital Total
$75,000
$52,027
$127,027
$105,000
$52,027
$157,027
$130,000
$52,027
$182,027
$150,000
$52,027
$202,027
Annual O&M
$18,650
$19,650
$20,650
$21,650
Annual CRF
Annual Cost
15%
$37,704
15%
$43,204
15%
$47,954
15%
$51,954
Barrels Water per Day
$/Barrel Water
500
500
500
500
$0.21
$0.24
$0.26
$0.28
Cost for Various Water Injection Rates ($/Barrel Water)
250
$0.39
$0.45
$0.50
$0.55
500
$0.21
$0.24
$0.26
$0.28
1,000
$0.12
$0.13
$0.14
$0.15
Equipment includes water distribution lines and electrical pumps.
EIAEquipment.xls
6/19/02
To determine the cost in dollars per mcf of water disposal, the cost of $0.50 per barrel is
multiplied by the value of 0.89 barrels of water per mcf, resulting in a cost of $0.45 per
mcf.
Geological and Geophysical and Lease Costs
Per-well geologic and geophysical expenses were estimated by distributing total geologic
and geophysical investment as reported by the API across all wells drilled. The count of
wells drilled was taken from the API Quarterly Completion Report. Leasing costs on an
average per-well basis were estimated in the same manner. Both geologic and leasing costs
were assumed to increase with depth with the national average per-well cost occurring in
the depth interval 5,000 to 7,500 feet. EEA has evaluated recent information on lease costs
in the Rocky Mountain region. For 2000 and 2001, the average lease cost in Wyoming for
federal and state land was approximately $32 per acre. Cost data are input into the
spreadsheet on the basis of cost per well. The lease cost put into the model is the bonus
cost and is a one time expenditure in the analysis.
Severance and Ad Valorem Taxes
Severance taxes are levied at the state level while ad valorem taxes vary by county. The
Wyoming severance tax rate is 6%, and EEA is using a value of 7% for ad valorem taxes or
a total of 13% for the Green River Basin.
Drilling Success Rates
EEA evaluated information in the IHS Well History database to determine an appropriate
drilling success rate for each play. Table 3-4 presents the drilling success rates on a
current technology basis. (Advanced tech success rates are slightly higher). Success rates
are determined separately for reserve appreciation and new fields. EEE estimates are used
in frontier and coalbed plays. The success rate for coalbed plays is set at 90 %. Using IHS
data, tight gas plays are assigned a 98% success rate for reserve appreciation and 78% for
undiscovered gas.
Table 3-4
Drilling Success Rates in Model
Current technology basis
playcd
play_name
resource
3701A
3701A
3701B
3701B
3701C
3701C
3701D
3701D
3701E
3701E
3701Z
3701Z
3702A
3702A
3702B
3702B
3702C
3702C
3702D
3702D
3702Z
3702Z
3703
3703
3704A
3704A
3704B
3704B
3704C
3704C
3704D
3704D
3704Z
3704Z
3705A
3705A
3705B
3705B
3705Z
3705Z
3706
3706
3707A
3707A
3707B
3707B
3707Z
3707Z
3708
3708
3709
3709
37401
37401
37402
37402
37403
37403
Rock Springs Uplift - Tertiary
Rock Springs Uplift - Tertiary
Rock Springs Uplift - Upper K
Rock Springs Uplift - Upper K
Rock Springs Uplift - Lower K
Rock Springs Uplift - Lower K
Rock Springs Uplift - J thru Perm
Rock Springs Uplift - J thru Perm
Rock Springs Uplift - Penn
Rock Springs Uplift - Penn
Rock Springs Uplift - Misc.
Rock Springs Uplift - Misc.
Cherokee Arch - Tertiary
Cherokee Arch - Tertiary
Cherokee Arch - Upper K
Cherokee Arch - Upper K
Cherokee Arch - Lower K
Cherokee Arch - Lower K
Cherokee Arch - JR and older
Cherokee Arch - JR and older
Cherokee Arch - Misc.
Cherokee Arch - Misc.
Axial Uplift
Axial Uplift
Moxa Arch - Tertiary
Moxa Arch - Tertiary
Moxa Arch - Upper K
Moxa Arch - Upper K
Moxa Arch - Lower K
Moxa Arch - Lower K
Moxa Arch - J thru Penn
Moxa Arch - J thru Penn
Moxa Arch - Misc.
Moxa Arch - Misc.
Basin Margin Anticline - Tertiary - Upper K
Basin Margin Anticline - Tertiary - Upper K
Basin Margin Anticline - Lower K
Basin Margin Anticline - Lower K
Basin Margin Anticline - Misc.
Basin Margin Anticline - Misc.
Subthrust
Subthrust
Platform (Eastern Basin) - Cretaceous
Platform (Eastern Basin) - Cretaceous
Platform (Eastern Basin) - Pre-Cretaceous
Platform (Eastern Basin) - Pre-Cretaceous
Platform (Eastern Basin) - Misc.
Platform (Eastern Basin) - Misc.
Jackson Hole
Jackson Hole
Deep Basin
Deep Basin
Cloverly-Frontier Tight 0-14999 Ft
Cloverly-Frontier Tight 0-14999 Ft
Cloverly-Frontier Tight 15000-16999 Ft
Cloverly-Frontier Tight 15000-16999 Ft
Cloverly-Frontier Tight 17000-18999 Ft
Cloverly-Frontier Tight 17000-18999 Ft
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
success rate table.xls
success rate
0.873
0.697
0.873
0.697
0.873
0.697
0.873
0.697
0.873
0.697
0.873
0.697
0.727
0.581
0.727
0.581
0.727
0.581
0.727
0.581
0.727
0.581
0.727
0.581
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.852
0.680
0.852
0.680
0.852
0.680
0.892
0.712
0.784
0.626
0.784
0.626
0.784
0.626
0.892
0.712
0.892
0.712
0.978
0.781
0.978
0.781
0.978
0.781
6/19/02
Table 3-4
Drilling Success Rates in Model
Current technology basis
playcd
play_name
resource
37404
37404
37405
37405
37411
37411
37412
37412
37413
37413
37414
37414
37415
37415
37421
37421
37422
37422
37423
37423
37431
37431
37432
37432
37433
37433
37441
37441
37442
37442
3750
3750
3751
3751
3752
3752
3753
3753
3754
3754
3755
3755
Cloverly-Frontier Tight 19000-20999 Ft
Cloverly-Frontier Tight 19000-20999 Ft
Cloverly-Frontier Tight 21000+ Ft
Cloverly-Frontier Tight 21000+ Ft
Mesaverde Tight 0-8999 Ft
Mesaverde Tight 0-8999 Ft
Mesaverde Tight 9000-10999 Ft
Mesaverde Tight 9000-10999 Ft
Mesaverde Tight 11000-12999 Ft
Mesaverde Tight 11000-12999 Ft
Mesaverde Tight 13000-14999 Ft
Mesaverde Tight 13000-14999 Ft
Mesaverde Tight 15000+ Ft
Mesaverde Tight 15000+ Ft
Lewis Tight 0-9999 Ft
Lewis Tight 0-9999 Ft
Lewis Tight 10000-11999 Ft
Lewis Tight 10000-11999 Ft
Lewis Tight 12000+ Ft
Lewis Tight 12000+ Ft
Fox Hills-Lance Tight 0-9999 Ft
Fox Hills-Lance Tight 0-9999 Ft
Fox Hills-Lance Tight 10000-11999 Ft
Fox Hills-Lance Tight 10000-11999 Ft
Fox Hills-Lance Tight 12000+ Ft
Fox Hills-Lance Tight 12000+ Ft
Fort Union Tight 0-9999 Ft
Fort Union Tight 0-9999 Ft
Fort Union Tight 10000-11999 Ft
Fort Union Tight 10000-11999 Ft
Rock Springs Coalbed
Rock Springs Coalbed
Iles Coalbed
Iles Coalbed
Williams Fork Coalbed
Williams Fork Coalbed
Almond Coalbed
Almond Coalbed
Lance Coalbed
Lance Coalbed
Fort Union Coalbed
Fort Union Coalbed
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
rgrowth
undisc
success rate table.xls
success rate
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.978
0.781
0.900
0.900
0.900
0.900
0.900
0.900
0.900
0.900
0.900
0.900
0.900
0.900
6/19/02
Ultimate Recovery per Completion
For each unit of analysis, EEA estimated ultimate recovery per completion. The data
source for the analysis of historical well recoveries is the IHS completion level production
database. EEA uses an algorithm to estimate remaining reserves and ultimate recovery of
oil and gas. The procedure involves analysis of historical annual production, published
state level reserves, and a conversion to dry marketable gas. For conventional plays, EEA
developed completion recovery estimates through analysis of the historical data. For tight
and coalbed plays, EEA used information published by the USGS or NPC.
Heating Content of Gas
EEA maintains a U.S. gas composition database developed by us for the Gas Technology
Institute (formerly GRI). This information was originally compiled at the well sample
level and includes information on Btu content, as well as the mole percentage of
hydrocarbon and non-hydrocarbon components including C1, C2, C3, C4, C5+, CO2, N2,
and H2S.
3. Discounted Cashflow Model
The economic analysis of Green River Basin oil and gas resources is based upon a
discounted cash flow model developed by EEA. Input into the spreadsheet includes
assumptions for drilling and completion costs, stimulation costs, geological and lease costs,
completion oil and gas recoveries, production parameters, drilling success rates, taxes, rate
of return criteria, and expected Btu content and gas composition.
Resource Cost Example
An example gas resource cost calculation is presented in Table 3-5. The example well
costs and production shown in the table is for a completion in the Lower Cretaceous on the
Moxa Arch. The resource scenario is the NPC Advanced Technology Case.
The economic analysis calculates two measures of resource cost:
•
resource cost in $/MMBTU
Table 3-5
2
Cost Indicies
Well
1.051
ROW =
30
NPC-inspired Advanced Technology Case
Equipment
1.000
Increment=
0
O&M
1.000
Other
1.017
Greater Green River Basin
Moxa Arch - Lower K
- Gas Wells New Fields/ERM
WELL CASHFLOW:
13-Jun-02
12:48 PM
(2000 DOLLARS)
REGION # =
DRILLING DEPTH =
DRILLING INTERVAL =
$/FT SUCC WELL =
$/FT DRY HOLE =
$/SUCC WELL =
$/DRY HOLE =
STIMUL $/WELL =
EQUIP/W =
O+M/YEAR =
G&G /WELL =
LEASE/WELL =
OVERHEAD,G+A% =
COST AND FINANCIAL ASSUMPTIONS
7
9,918
SEV & AD VAL TAXES =
6
ROYALTY =
74.9
AFTER-TAX, REAL ROR =
52.3
INFLATION =
742,432
Variable O&M =
518,712
SUCCESS RATE =
309,979
MMcf/COMPLETION =
37,500
BTU/CF GAS =
26,500
CONDNSTE (BBL/MMcf) =
25,422
MMBtu/COMP. =
50,844
BOE/COMP. =
16.0%
COMPLETIONS/WELL =
@ 1 COMP.
PER WELL
$2.58
$2.20
$/MCF RAW GAS:
$/MMBTU GAS & LIQUIDS:
DEPREC.
260,230
YEAR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
RevenueFa1.918
moxa_DCF_example.xls
INTANG.
829,682
GNP
DEFLATOR
1.000
1.025
1.051
1.077
1.104
1.131
1.160
1.189
1.218
1.249
1.280
1.312
1.345
1.379
1.413
1.448
1.485
1.522
1.560
1.599
TAX SCENARIO
DELIVERABILITY
C1 =
C2 =
K=
R=
B=
Q1 =
Q2 =
13.0%
12.5%
6.3%
2.5%
0.00
83.6%
1,583
1,139
7.711
TAKES =
1,856,065
320,011 succ rate func.
1.2 depletion function
(655,448)
14,570
14,215
13,868
13,530
13,200
0
0
0
0
0
0
0
0
0
0
0
0
0
0
WRITE OFF SCHEDULES
DEPREC.
INTANG.
TAX =
0.14
0.700
ITC =
0.25
0.060
0.17
0.060 INTG % =
0.13
0.060
0.11
0.060
0.10
0.060
0.10
0.000
adv tech scaling factors:
success rates
1.07
drilling costs
0.95
100%
1.00
1.00
RESOURCE COST RESULTS
INVESTMENT COST RESULTS
@ AVRG COMPS.
MILLION DOLLARS:
$508.28
PER WELL RESERVE
Trillion Btu:
760.58
$2.15 ADDITIONS Million BOE:
131.13 Million BOE NWI*:
$1.83
Gas Bcf:
648.87
Liquids MMbbl:
DOLLARS/BOE NWI*:
$4.43
DEPLET.
91,261
EXPEN.*
307,295
TOTAL
1,488,467
AFTER TAX ANNUAL
(249,300)
19,041
12,632
9,424
7,780
6,900
6,732
0
0
0
0
0
0
0
0
0
0
0
0
0
0.010
0.059
0.420
0.000
1.100
0.059
0.130
(88,916)
3,310
2,454
1,904
1,526
1,253
1,049
892
768
668
586
518
461
412
371
335
304
277
253
232
GAS
PROD
(MMCF/Y)
(233,656)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(18,550)
(1,227,321)
18,372
10,751
6,646
4,286
2,803
(10,769)
(17,658)
(17,782)
(17,882)
(17,964)
(18,032)
(18,089)
(18,138)
(18,179)
(18,215)
(18,246)
(18,273)
(18,297)
(18,318)
135.6
196.2
149.1
118.6
97.4
82.0
70.4
61.3
54.1
48.2
43.4
39.3
35.8
32.9
30.3
28.1
26.1
24.4
22.8
21.4
SUM=
NPV=
(1,430,307)
(1,228,800)
1,317
913
0.83
0.58
GAS
VALUE
($/MCF)
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
2.58
30.0%
0.0%
70.0%
114.74
5.00
*NWI=net working interest
NET REV
A.T.
NET A.T.
CASHFLOW
182,458
264,050
200,634
159,553
131,084
110,360
94,697
82,506
72,786
64,884
58,352
52,874
48,225
44,239
40,787
37,775
35,126
32,783
30,695
28,826
(1,044,863)
282,421
211,385
166,199
135,370
113,164
83,928
64,848
55,004
47,001
40,387
34,842
30,136
26,101
22,608
19,560
16,880
14,510
12,398
10,508
342,386
(0)
6/19/02
•
finding and development costs in $/BOE
The resource cost is the selling price required at the wellhead to compensate producers for
their investments, operating costs, taxes, royalties, and cost of capital.
The finding and development cost is the total investment divided by the reserves added, on
a net working interest basis. It excludes operating costs, taxes, royalties, and the cost of
capital.
The resource cost is the discounted cost of the reserves expected to be produced by an
average completion in each subplay and resource category (reserve growth or
undiscovered). The cost is expressed both in dollars per Mcf of gas and dollars per MMBtu
of gas and liquids. The investment required to develop the reserves includes the full cost of
a successful well and equipment plus the additional costs of dry holes drilled during field
development. The success rate and corresponding dry hole frequency are based on EEA
analysis of IHS drilling history data.
The key variables that affect the drilling and completion costs are the depth of the well and
the artificial stimulation (hydraulic fracturing) costs. Drilling costs in this subplay are
estimated to be $74.90/foot for a successful well and $52.30/foot for a dry hole. Artificial
stimulation cost is $310,000. Equipment cost is estimated to be about $37,500. Geologic
and geophysical expenses ($25,000 per well) and leasing expenses ($51,000 per well) also
are added to the cost of the wells. Annual operating and maintenance expenses are
estimated at $26,500.
Financial assumptions include severance and ad valorem taxes, royalty rate, required aftertax rate of return, and an inflation rate in order to express future cash flow in constant
dollars. The federal and state income tax rate for this analysis is assumed to total 30.0
percent. No investment tax credit is assumed available. Depreciable capital investment
includes all tangible equipment and 30% percent of intangible drilling costs. The
remaining 70 percent of intangible drilling investment is expensed in the first year of the
project as indicated in the write-off schedule table. Drilling and completion costs are
assumed to be 70 percent intangibles.
Production from each completion is characterized by a total reserves volume (1,583 MMcf
in this example), Btu content of the dry hydrocarbon gas, condensate yield, and average
annual takes. A deliverability forecast in the form of a hyperbolic decline curve is used to
flowstream production over the life of the well. The variable "completions/well" indicates
the average number of completions a well in this basin will have over its life.
The resource cost of gas in each subplay and resource category is estimated by calculating
the present value of all investments and expenses after taxes and dividing by the present
value equivalent of the production flowstream to yield costs in $/Mcf. The well in this
example is assumed to cost $742,434 if successful. Depreciable items (30 percent of the
successful well cost plus equipment) are $260,230. Intangible investment (70 percent of
the successful well costs plus any stimulation expenses) are $829,682. Investments
qualifying for cost depletion (G&G lease acquisition, including that portion applicable to
dry holes) are $91,261. Expense items (dry hole costs plus overhead) are $307,295. Total
investment for this project is $1,488,467.
The cashflows resulting from each category are shown under each column for the years 1 to
20. It is assumed that all investments are made in year 1. Investment expenditures produce
negative cashflow while tax savings result in positive cashflows. For example, net
cashflow for year 1 under depreciable items is $-249,300. This is made up of $-260,230 for
expenditures for depreciable items plus +10,930 for the tax savings from depreciation. The
tax savings from depreciation is the product of the investment amount times the portion
written off in the year times the tax rate ($260,230 x .14 x .30 = $10,930). For year 2, the
entire cashflow for depreciable items stems from the tax savings adjusted for inflation
($260,230 x .25 x .30/1.025 = $19,041).
The total expenditures for intangibles are $829,682. This consists of 70 percent of the
completed well cost plus the stim cost ($742,432 x .7 + $309,979). Intangibles are written
off on the schedule shown under the "tax scenario" portion of the spreadsheet. In this
scenario, 70 percent is written off in the first year for a tax savings of $174,233 ($829,682 x
.7 x .30). Thus, the net cashflow for this category is $-655,448 ($-829,682 + $174,233).
Total expenditures for depletables are $91,261. This figure represents the total G&G and
lease costs allocated to each successful well. The total includes the portion of costs
associated with dry holes. The figure of $91,261 is derived as follows: (Total G&G and
lease costs)/(Drilling success rate). In this case, $91,261 = $76,266/0.836. The year 1
cashflow from depletables is $-88,916. This figure includes a tax writeoff based on the
quantity of gas produced in each given year. ($91,261 - ($91,261 x (135.6 MMcf / 1583
MMcf) x .30) = - $88,916)
The total "expensed" category is $307,295. This figure represents dry hole costs plus
overhead. A fraction of the costs for each dry hole is allocated to each successful well
based upon the drilling success rate. An overhead component of drilling and equipping
costs also is included in the "expensed" category.
An important assumption made in the model's treatment of income tax effects is that there
exist sufficient income against which writeoffs can be taken in the year in which they first
are available. For instance, in the spreadsheet, a deduction of $36,432 ($260,230 x .14) is
taken for depreciation in the first year. This results in a tax savings of $10,930. If, for
some reason, a company making the investment had no taxable income in that year, this
deduction would not reduce its taxes in that year. Instead, the deduction would contribute
toward a tax loss for that year. In many instances, such a tax loss would be carried forward
into a future year and would reduce the company's income taxes for that year. The net
effect would be to reduce the present value of the deduction by postponing the deduction to
a future year, where it would be more heavily discounted. For this reason, the model might
overstate the tax benefits for companies experiencing low taxable income.
The present value after tax of all investments and expenses is $-1,228,800 assuming an
after-tax real rate of return of 6.3 percent. Table 3-6 shows the origin of the 6.3 percent
Table 3-6
Weighted Average Cost of Capital
INCOME TAX RATE:
INFLATION:
30.0%
2.5%
Calculation of Real After-Tax Discount Rate
CAPITALIZATION
NOMINAL
AFTER-TAX REAL, AFTERRATIO
RATE
RATE
TAX RATE
DEBT
60.0%
7.0%
4.9%
2.3%
EQUITY
40.0%
15.0%
15.0%
12.2%
10.2%
8.9%
6.3%
Cells in yellow are carried forward to "Main" sheet
rate of return value. It is based upon a capitalization ratio of 60 percent debt and 40 percent
equity. This ratio results in a nominal rate of 10.2 percent, an after tax rate of 8.9 percent,
and a real after tax rate of 6.3 percent.
The present value equivalent of the well's production flowstream is 913 MMcf. The
resource cost of this production is, therefore, the present value of expenses divided by the
present value of production adjusted for royalties, severance taxes and income taxes, which
is equal to $2.58/Mcf of raw gas. If the Btu value of lease condensate production is
included, the resource cost of the total hydrocarbon production from this one-completion
well is $2.20/MMBtu. Since an average well in this subplay contains 1.2 gas completions
per well, the proper resource cost for the gas is $2.20 / 1.2 = $1.83/MMBtu. It is the latter
cost adjusted for completions per well that is used in the economic analysis.
Table 3-5 also shows the finding and development cost. This is presented in the section on
the right side of the table titled "Investment Cost Results." In this example, the finding and
development cost is $4.43 per BOE, net working interest. The $4.43 is the investment
divided by the net working interest BOE ($508.28 / 114.74 million BOE). As mentioned
above, the finding and development cost excludes operating costs, taxes, royalties, and the
cost of capital.
4. Modeling of Resource Depletion
The DCF spreadsheet models the effect of resource "depletion" on well recovery and
drilling success rates. As a basin is developed through time, well recovery tends to
decline because the better areas are developed first. Drilling success rates also decline
through time as the exploration targets become smaller and more difficult to find.
1. Well Recovery Depletion
The DCF model includes a range of well recoveries for each subplay and resource type
(reserve growth or new fields), with each well recovery representing one-tenth of the
potentially productive wells that could be drilled in that play. Each well recovery is also
associated with a volume of oil or gas potential. Thus, for a particular subplay, there is a
range of resource quality and costs. This approach to resource cost analysis is closer to
what is observed in gas productive basins, and provides a more representative supply
curve.
Conventional and Tight Old Fields
Table 4-1 summarizes the approach and data sources used to evaluate well recovery
depletion. EEA developed separate analysis of old field and new field well depletion
effects. For old (existing) conventional structural fields, EEA used an analysis of reserve
appreciation developed for the 1999 NPC study. In that analysis, trends in historical gas
well recovery were evaluated by region and well "vintage" or year of completion. These
well recovery trends were used in the NPC study to assess remaining reserve appreciation
potential. The basis for this approach is that well recoveries in old fields decline through
time as the resource becomes depleted. At some point, well recoveries are too low for
economic development. That point represents the point of exhaustion of the reserve
appreciation resource. By evaluating the decline in well recovery, the NPC approach
was evaluating resource depletion.
Table 4-1
Well Recovery Depletion Analysis
Green River Basin Study
Resource
category
Soure of depletion
information
Old Fields
Conventional structural
NPC Vintage well recovery analysis
Tight
NPC Vintage well recovery analysis
Low BTU
no depletion - all of the area is within a one large structure
New Fields
Conventional structural
HSM new field characterization
Tight
NPC "selectability" assumption
Low BTU
HSM new field characterization
Coalbed
EEA judgement (NPC assumption was for no selectability)
depletion_summary.xls
6/19/02
EEA used the Rocky Mountain NPC analysis to evaluate old field well recovery
depletion for the Green River Basin. Resource depletion was evaluated separately for
structural plays and tight plays.
The depletion assumptions for old fields currently in the model are documented in Table
4-2. The three categories of old fields are "structural," "tight," and "low BTU." The
table presents the depletion information on the basis of well recovery relative to the initial
wells drilled. For example, under the column "structural old fields," if the initial well
recovery is 1.00 Bcf, the first group of wells (decile) has that recovery. The next group
of wells has a well recovery of 0.866 MMcf (or 0.866 times the initial recovery). If the
initial well recovery is 2.00 Bcf, the second decile recovery is 1.73 Bcf.
Low-Btu Old Fields
For Low-Btu old fields, it is assumed that there is no depletion because this resource base
represents a single large structure on the Moxa Arch.
Structural New Fields
For new field well depletion, EEA used different methods, as shown in Table 4-1.
Approaches included the use of the Hydrocarbon Supply Model (HSM) information,
NPC assumptions, and EEA judgement.
The Hydrocarbon Supply Model contains a characterization of undiscovered fields for
each region and depth interval. Each region contains a distribution of new fields for each
of 20 USGS field size classes.
The new field exploration process in an area increases geologic knowledge through time
as parts of the basin are condemned and other areas are identified as having potential.
During the early stages of exploration, many larger fields are found because they are
easier to find. As exploratory drilling continues, it becomes more concentrated in parts of
the basin with known accumulations, and new fields become smaller. The number of
fields of a given size discovered with an increment of drilling declines through time.
Table 4-2
Resource Depletion Functions (Recovery of productive wells)
First row represents intial well recovery and subsequent rows represent the well recovery for
each additional increment (decile) of wells
selectability
resource type
Structural
old fields
decile
1
2
3
4
5
6
7
8
9
10
resource_depletion.xls
1.000
0.866
0.751
0.650
0.563
0.488
0.423
0.366
0.317
0.275
Tight
old fields
1.000
0.890
0.791
0.704
0.626
0.557
0.496
0.441
0.392
0.349
Low Btu
old fields
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
Structural
new fields
1.000
0.790
0.631
0.522
0.447
0.392
0.350
0.317
0.288
0.264
Tight
new fields
1.000
0.866
0.825
0.801
0.781
0.766
0.752
0.738
0.727
0.719
Low Btu
new fields
1.000
0.790
0.631
0.522
0.447
0.392
0.350
0.317
0.288
0.264
CBM
new fields
1.000
0.925
0.903
0.889
0.878
0.870
0.862
0.854
0.848
0.843
6/19/02
The HSM employs a modified "Arps-Roberts" find rate equation to model the
relationship between exploratory drilling and new field discoveries. The HSM
exploration process predicts the number of fields of each size class in each depth interval
found by an increment of exploratory drilling.
The find-rate process that is modeled in the Hydrocarbon Supply Model is - in effect - an
analysis of resource depletion on a field size basis.
The process of new field depletion is associated with a corresponding decline in average
well recovery. (Smaller fields tend to also have poorer well recovery). The well
recovery information in the HSM was used in the current study to evaluate resource
depletion for new fields in the Green River Basin
The current depletion assumptions for new fields are also documented in Table 4-2. The
fourth column shows the relationship used for structural new fields.
Tight New Fields
The NPC study included a statistical analysis of "selectability" or resource depletion for
tight gas wells. Low selectability means that the producer can only poorly target the
better areas first, while high selectability means that the better areas can be found first.
The tight new fields depletion function shown on Table 4-2 is based upon the
selectability analysis of the NPC study.
Low Btu New Fields
Low Btu new fields are assumed to have the same depletion function as conventional new
fields.
Coalbed New Fields
The new field coalbed depletion function on the table is set as low selectability, based
upon EEA judgement. The NPC assumption was for no selectability.
2. Drilling Success Rate Depletion
Through time, the average drilling success rate in new fields declines as the resource
becomes depleted. This is primarily the result of a decreased ratio of development to
exploratory drilling with time. As new fields become smaller, the ratio of development to
exploratory wells declines, resulting in a lower overall success rate.
The impact of depletion on new field drilling success rates are shown in Table 4-3. The
factors shown in the column are the adjustors used to modify the initial new field drilling
success rate for subsequent drilling increments. The drilling success rates for other
categories of resources (old fields, tight, coalbed, and low Btu) are constant in the model.
Table 4-3
Success Rate Adjustors - New Field Exploration
decile
factor
1
2
3
4
5
6
7
8
9
10
resource_depletion.xls
1.00
0.87
0.76
0.68
0.62
0.57
0.54
0.51
0.49
0.47
6/19/02
5. Results
1. Comparison of Supply Curves
Table 5-1 and Figures 5-1 and 5-2 present the results of the economic gas study on the
basis of total gas supply for the three scenarios. The curves include all undeveloped
resources for each scenario on the basis of wet total gas. Not shown are oil volumes or
barrels of oil equivalent (BOE). (Supply curves for oil and BOE are included in the
spreadsheets).
Table 5-1 summarizes the results of the three scenarios. Volumes of economically
recoverable gas are shown for wellhead prices from $1.00 to $10.00 per MMBTU. Also
shown is the total resource base and the percentage of technically recoverable wet gas
that is economic to develop at each price.
Figure 5-1 presents the supply curve comparison through a resource cost of $20 per
MMBTU and Figure 5-2 shows a detail of the supply curves through $10 per MMBTU.
Note that each subplay in the basin may be represented by multiple resource cost values
due to the application of depletion functions and the separate economic analysis of
reserve growth and undiscovered resources.
The curves show that in all three scenarios, a large percentage of the technically
recoverable resource is available at a resource cost of $5.00 per MMBTU or lower.
In the USGS scenario, 59 percent of the resource is available at $5.00, while the NPCinspired scenarios range from 51 to 65 percent.
2. Sensitivity to Selectability
As discussed in a previous section, well recovery resource depletion or selectability is
accounted for in the economics model. The model contains EEA's evaluation of the
impact of depletion on well recovery.
Table 5-1
Summary of Results - Green River Basin Study
Economically Recoverable Gas at Selected Prices
Total Wet Gas
Scenario
A
USGS -Based
Tcf
Scenario
B
NPC -Inspired
Current
% of total
Tcf
Scenario
C
NPC -Inspired
Advanced
% of total
Tcf
% of total
$/MMBTU
$1.00
1.4
1.0%
0.5
0.4%
4.6
3.0%
$2.00
25.5
18.4%
14.1
11.1%
39.4
25.9%
$3.00
62.0
44.7%
43.0
33.8%
63.2
41.5%
$4.00
74.3
53.6%
54.7
43.0%
86.0
56.5%
$5.00
81.6
58.9%
64.9
51.0%
98.6
64.7%
$6.00
93.1
67.2%
88.0
69.1%
121.9
80.0%
$7.00
103.7
74.8%
94.6
74.3%
127.2
83.5%
$8.00
112.3
81.0%
100.8
79.2%
130.6
85.8%
$9.00
121.1
87.4%
108.2
85.0%
134.1
88.0%
$10.00
121.7
87.8%
109.8
86.3%
138.6
91.0%
152.3
100.0%
total
results table.xls
138.6
127.3
6/25/02
Figure 5-1
Total Gas Supply Curves for Three Scenarios
Green River Basin (Wet Gas Basis)
Through $20 per MMBTU
160,000
140,000
NPC - Inspired
Advanced
120,000
BCF
100,000
USGS - based
80,000
NPC - Inspired
Current
60,000
40,000
20,000
0
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00 $12.00 $14.00 $16.00 $18.00 $20.00
$ per MMBTU
compare_curves2.xls
6/25/02
Figure 5-2
Total Gas Supply Curves for Green River Basin
Through $10 per MMBTU
160,000
140,000
NPC - Inspired
Advanced
120,000
BCF
100,000
80,000
USGS - based
60,000
NPC - Inspired Current
40,000
20,000
0
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$ per MMBTU
compare_curves2.xls
6/25/02
An important issue in the economic analysis of Rocky Mountain gas resources is the
impact of exploration technologies that affect industry's ability to target the better areas
first. Well recoveries within a given tight gas play or sub-play can vary greatly,
depending upon factors such as natural fractures and depositional trends. Industry has
shown some ability to target the better areas first, and this is reflected in EEA's depletion
assumptions in the model. However, future technology could greatly improve industry's
ability to target these better areas. This would have the impact of making more gas
available at lower cost.
One way to look at this is the potential impact of so-called "perfect selectability" on the
Green River resource economics. Perfect selectability is the theoretical ability to
perfectly target the "sweet spots" in the tight gas reservoirs. As part of the NPC studies,
EEA evaluated tight gas well recovery statistics to determine the variability in well
recoveries by groupings or cohorts of ten percent of the wells. The current Green River
Basin model was modified to assume that initial exploration efforts yield an average
recovery equal to the best 10 percent of the underlying well distribution. (See footnote
on how to do this in the model). The results were then compared to the EEA case to
determine the sensitivity.
The results of the analysis are presented in Table 5-2. The table shows the difference in
the supply curves with the currently assumed selectability and perfect tight gas
_________________________________
The specification of selectability for tight gas can be changed by going to the "Main"
worksheet. Scroll over to the right to column "DI," which contains the selectability codes
for each subplay. In this column, replace each value of 5 with a value of 17. This will
assign perfect selectability to the tight gas subplays. The selectability functions are
included in the table titled "Resource Depletion Functions" at cell AD 320.
selectability for Scenario C (the NPC Advanced technology). At a wellhead price of
$3.00 per MMBtu, an additional 24 Tcf of gas would become economic with perfect
selectability. This shows that the supply curve is changed so that much more of the
resource is economic at lower prices. The average cost of the resource is still the same,
but by being able to target the best locations first, more of the gas is made economic at
$3.00.
Table 5-2
Effect of Selectability on Resource Economics
Scenario C (NPC Advanced)
Resource
Cost
$/MMBtu
selectability.xls
Original
Supply
Curve
(Tcf)
Perfect
Selectability
Curve
(Tcf)
Difference
(Tcf)
$3.00
63.2
87.3
24.1
$4.00
86.0
99.7
13.7
$5.00
98.6
107.3
8.7
6/26/02
6. References
American Petroleum Institute, "API Joint Association Survey on Drilling Costs -1998,"
API, Washington DC.
American Petroleum Institute, "Quarterly Completion Report," API, Washington, DC.
Barlow and Haun, 1994, "Accessibility to the Greater Green River Basin Gas Supply,
Southwest Wyoming," Barlow and Haun, Inc., Casper Wyoming, prepared for Gas
Research Instiute, Chicago, IL, GRI report no. 94-0363.
Energy Information Administration, 2002, "Oil and Gas Lease Equipment and Operating
Costs - 1986 through 2000," DOE/EIA - 0185 (2000), December 2001.
Gas Technology Institute, 1999, "Chemical Composition of Discovered and Undiscovered
Natural Gas in the United States," GTI Report 98/0364, May 1999.
Gas Technology Institute, 2001, "GTI's Gas Resource Database," GTI publication 01/0136,
CD-ROM, GTI, Chicago, Il.
IHS Energy Group, 2002, IHS Well History Database, IHS Energy Group, Houston, TX.
IHS Energy Group, 2002, IHS Oil and Gas Production Database, IHS Energy Group,
Houston, TX.
National Petroleum Council, 1999, "Meeting the Challenges of the Nation's Growing
Natural Gas Demand," NPC, Washington, D.C.
Potential Gas Committee, 2000, "Potential Supply of Natural Gas in the United States,"
PGC, Golden, Colorado, (Colorado School of Mines).
U.S. Geological Survey, 1995, "1995 National Assessment of United States Oil and Gas
Resources," U.S. Geological Circular 1118, and CD- ROM publications DDS-30 and DDS36.