Page 1
draft
Wyoming’s Miscible CO2 Enhanced Oil Recovery
Potential from Main Pay Zones:
An Economic Scoping Study
Benjamin R. Cook, PhD*†
University of Wyoming
Department of Economics & Finance
Enhanced Oil Recovery Institute
November 2012
*Benjamin R. Cook, PhD, College of Business, Economics & Finance, Dept. 3985, 1000
E. University Ave., Laramie, WY 82071. Office: College of Business #379W. Email:
[email protected]
†Funding for this study was provided by the Enhanced Oil Recovery Institute (EORI),
part of the School of Energy Resources at the University of Wyoming. GIS mapping
services were provided by Klaas van ‘t Veld, Associate Professor, Economics & Finance,
University of Wyoming. Additional feedback and data support were provided by Dr.
Glen Murrell, Associate Director (EORI), Nick Jones, Senior Geologist (EORI), Vanessa
Onacki, Research Assistant, and Professor Owen R. Phillips, Department of Economics
& Finance, University of Wyoming.
Page 2
draft
2
1 INTRODUCTION
Nationally, Wyoming is the largest producer of both coal and soda ash, the 2nd
largest source of Grade-A helium, the 4th
largest source of natural gas, and
consistently ranks as the 8th
largest producer of oil.1
The majority of
Wyoming oil is produced on Federal land, with roughly half of the 12.5%
federal mineral royalty paid back to the state. There is also a 16.67% royalty
on state land mineral leases, and an additional 6% severance tax net of
royalties on all production. At the county level, these mineral properties also
pay ad valorem taxes net of royalties assessed at 100% of the prior year’s
production value. Finally, both state and local governments benefit from
mineral-related sales and use tax.
Wyoming’s economy and state & local government budgets depend heavily
on this mineral wealth. At the state level, mineral severance and royalties are
predicted to account for 51% of Wyoming’s budget, and combined mineral-
related payments account for 65% of all state/local government revenues
(CREG, 2012; Jeffries, 2012). An analysis for 2007 commissioned by the
Wyoming Heritage Foundation (WHF, 2008) attributed a full 32% of state
product and 20% of employment to the oil and gas industry. A recent study
commissioned by the American Petroleum Institute (API, 2011) found that for
2009, the oil and gas industry contribution to Wyoming as a share of the state
economy was more significant than that of any other state.
Wyoming’s reliance on mineral resources exposes the government to mineral
price swings. This is evidenced by the steep decline in natural gas prices and
the corresponding fall in Wyoming mineral revenues – overall mineral royalty
and severance revenues are projected to be 26% below their 2008 peak by
2013 (see Figure 1).
1 Coal and oil rankings come from EIA.gov production statistics. Soda ash and helium
rankings are from the U.S. Geological Survey, Minerals Yearbook, Area Reports: Domestic
2009, Volume II.
Page 3
draft
3
Figure 1 Wyoming Royalties & Severances Collections
Although Wyoming is the 8th largest domestic source of oil, annual crude
production in the state has fallen 61%, from a peak of 136 million barrels
annually in 1978 to just over 54.5 MMbbls per year in 2011 (WOGCC, 2012).
This fall in production, lower oil prices from the mid-1980s through the 1990s
and the increasing importance of natural gas reduced the contribution of crude
oil to state revenues; crude oil's share of total severance tax revenue fell from
around 40% in the early nineties to only 15% by 1999.
While diversifying Wyoming’s economy so that it is less exposed to mineral
price risk would help, the state is also pursuing other value-added activities
(such as gas and/or coal to liquids) for minerals within the state and
encouraging the development of existing resources.2
2 This is being done through legislative funding initiatives such as allocations to the School of
Energy Resources (SER) to fund research, and the creation of the Enhanced Oil Recovery
Commission & Institute (EORI).
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
Oil/G
as Price
($/M
cfe)
Ro
yalt
y an
d S
eve
ran
ce R
eve
nu
es
($M
M)
Wyoming Mineral Royalties & Severance TaxesContribution of Oil and Gas
WY Gas Prices (Mcf)
WY Crude Prices (Mcfe)
26% Drop inSeverance & Royalties by
2013
NG Severance
Oil Severance
Mineral Royalties & Severance
Sources: WY CREG (Jan. 2012)DOE-EIA Mineral Prices
Page 4
draft
4
One important channel for future development is the use of enhanced oil
recovery technology, which has the potential to deliver hundreds of millions
of barrels of additional production from existing Wyoming oil fields in the
coming decades.
Higher oil prices have already helped increase oil production in Wyoming
through the stimulation of existing resources and investments in these so-
called tertiary methods such as CO2 enhanced oil recovery (CO2-EOR). At a
broader level, growing concern about domestic energy security and CO2-
induced climate change continue to build interest in EOR, and the associated
CO2 pipeline infrastructure is seen as paving the way for larger-scale
sequestration. In addition to increasing oil production, a life-cycle analysis
that assumes the oil is burned as gasoline has found that nearly 94% of the
CO2 emissions from producing each CO2-EOR barrel are offset by the CO2
injected and sequestered during the process (Aycaguer et al., 2001).
The purpose of this study is to highlight Wyoming’s CO2-EOR potential, the
location of the most promising oil units and the CO2 supplies required to
make it happen.
2 STAGES OF OIL RECOVERY
The amount of recoverable oil as a share of the original oil in place (OOIP) is
referred to as the recovery factor (sometimes called recovery efficiency). The
initial phase of oil extraction, called primary recovery, refers to the
recoverable oil under the reservoir’s natural pressure or drive mechanism. In
primary recovery, an oil unit typically produces 5-20% of OOIP, with some
reserves yielding as much as 30% (IEA, 2005).
Secondary recovery, which usually involves the injection of water into the
reservoir, can yield an additional 10-30% of OOIP (on top of primary
recovery), depending on reservoir and development conditions (IEA, 2005).
Page 5
draft
5
Satter et al. (2008) 3
report that worldwide recovery efficiencies vary between
20-40% with a global average of 34% which is in line with the 35% reported
by the IEA. The IEA goes on to note that recovery factors above 40% usually
require a third production stage, tertiary recovery, using methods such as
CO2-EOR or other technologies such as chemical and steam flooding.
Tertiary recovery using CO2-EOR involves injecting CO2 into the oil
reservoir, and is usually done in alternating rounds (or slugs) of CO2 injection
followed by water injection. This injection pattern is referred to as water-
alternating-gas (WAG) injection, and may include a reference for the ratio of
water volume to gas volume being used. For example, a 1:1 WAG for EOR
would imply alternating between equal volumes of water and CO2.
Depending on the temperature, pressure and properties of the crude oil in the
reservoir during injection, the CO2 may be “miscible” or “immiscible” with
the reservoir oil. Immiscible flooding, while less efficient, takes place at lower
pressures and temperatures, where CO2 improves recovery by swelling the oil,
reducing viscosity, and mobilizing or displacing the lighter components of the
oil. Immiscible floods generally apply to heavier oil gravities between 13o API
and 22o API (Taber et al, 1997).
4
For reservoirs with the appropriate oil characteristics, at sufficiently high
temperatures and pressures called the minimum miscibility pressure (MMP),
the CO2 and oil become miscible after repeated contact and start to mix in all
parts (Wo et al., 2009).
Once miscibility is reached, the reservoir fluid properties become very
favorable and allow the oil and CO2 mixture to move through the reservoir
rock, thus improving recovery. Miscible flooding is done for light to medium
3 Although not mentioned explicitly, it is assumed that these figures from Satter et al. (2008)
refer to primary plus secondary recovery.
4 API gravity is a measure of how heavy or light the oil is relative to water. Higher numbers
indicate lighter oils, where 10o API and higher will all be lighter than and float on water.
Page 6
draft
6
oil gravities between 22o
API and 48o
API.5 While immiscible flooding can
improve oil recovery, the incremental oil produced can be much less than
what is possible during miscible flooding
3 CO2-EOR IN WYOMING
In 2004, the Wyoming State Legislature passed legislation establishing the
Wyoming Enhanced and Improved Oil Recovery Commission and the
Enhanced Oil Recovery Institute (EORI) at the University of Wyoming.6 The
collection and improvement of data on Wyoming oil resources has been an
ongoing part of the EORI’s broader mission to work with oil operators in the
state and maximize the potential of Wyoming’s oil resources through
enhanced recovery technologies.
Wyoming’s first experience with CO2 flooding goes back to the 1980s, when
Amoco began injecting at the Lost Soldier (see Figure 2) and Wertz fields
with CO2 from ExxonMobil’s Shute Creek Gas Plant in southwestern
Wyoming. The success of these CO2 floods at Lost Soldier and Wertz
provided strong evidence of the potential for tertiary recovery methods in
Wyoming.
To date, three additional CO2 flooding projects have come online utilizing the
CO2 from Shute Creek: Anadarko began CO2 flooding in both the Salt Creek
field and the Monell unit of the Patrick Draw field in 2003, and Devon Energy
Corp initiated CO2 flooding at the Beaver Creek Madison unit in 2008.
5 Taber et al. (1997) suggest miscible projects at greater than 22
o API, making note that
existing projects ranged from 27o
to 44o. Personal discussion with Shoachang Wo, Senior
Research Scientist at EORI, indicated that very light oils 48o API and higher are not good
candidates for miscible flooding as the CO2 is likely to displace the oil rather than mix with it.
6 Based on a recommendation from then Governor Dave Freudenthal’s Enhanced Oil
Recovery Task Force. See Wyoming Statute Title 30 Chapter 8.
Page 7
draft
7
Figure 2
More recently, significant investments have been made by Denbury Resources
Inc. to acquire oil and gas properties, develop CO2 sources, and build the 232-
mile long “Greencore Pipeline” to transport CO2 from central Wyoming
through the Powder River Basin. Denbury also entered an agreement with Elk
Petroleum Inc. to develop the Grieve Field with CO2 injection in 2012.
Through the end of 2011, the total combined incremental oil7 produced using
CO2 in Wyoming approached 86.5 million barrels. In 2011 the five oil
projects with active CO2 floods produced 7.87 million barrels of oi,l with 6.59
million directly attributed to CO2-EOR, approximately 12.1% of all 2011 WY
production supporting an estimated 1,716 jobs (Cook, 2012).
One of the first projects undertaken by the EORI was to identify Wyoming’s
total CO2-EOR potential and to get a sense of how much CO2 will be needed.
7 Incremental oil is the additional oil production recovered through injecting CO2 net of the
expected production level without CO2 flooding.
0
1,000
2,000
3,000
4,000
5,000
6,000
0
50
100
150
200
250
300
350
400
450
CO
2/N
at. Gas In
jectio
n (M
Mcf)
Oil
Pro
du
ctio
n (
1,0
00
Bb
ls)
Month-Year
Lost Soldier CO2 Units (Bairoil, WY) Monthly Oil & Pre-CO2 Decline Path
Monthly Oil Production
Pre-CO2 Decline Path
CO2/Gas Inj (Since '91)
Incremental Oil2011 = 1.3 MMstbo
Total = 44.5 MMstbo
Begin CO2 Flooding1989
Page 8
draft
8
While technically recoverable oil from the main-pay zones has been estimated
at 1.21 to 1.81 billion barrels (Wo et al., 2009), the candidate oil units must
also be economically viable. Because of the large up-front investments
required for CO2, the actual development of an oil unit depends on a number
of economic factors, ensuring that a project can raise the necessary capital and
earn a suitable return.
In association with the Department of Economics at the University of
Wyoming, an economic model was developed based on the “analog” method,
which forecasts the results of a potential project using the scaled historical
data of an existing CO2-EOR flood. The model methodology as applied to 93
units from large fields8 in the Powder River Basin (PRB) was published in
The Energy Journal (van 't Veld and Phillips, 2010) and estimated an
additional 75-256 million barrels from units able to meet a 20% rate of return
threshold.
This report builds on the prior work by updating the cost estimates and
functionality of the “CO2-EOR Analog Economic Scoping Model” and
applying it to an expanded dataset of 723 potentially miscible field-reservoir
combinations (or FRCs) in 415 oil fields. This dataset should provide a
comprehensive picture of Wyoming’s CO2-EOR potential from economically
viable miscible main-pay zones.
4 THE ENHANCED OIL RECOVERY DECISION PROCESS
Although the “CO2-EOR Analog Economic Scoping Model” allows
researchers and oil operators to quickly assess the potential EOR profitability
of an oil unit, it serves mainly as a preliminary screening tool in a multi-stage
investment and development planning process.
8 Defined as fields with at least 5 million barrels (MMbbls) of cumulative oil production.
Page 9
draft
9
A simplified illustration of the EOR development decision process is shown
in Figure 3 (from Cook, 2011). The first step is to screen oil reservoirs for the
reservoir and oil characteristics necessary for miscibility. If the geological and
petro-physical properties are suitable for EOR, then a preliminary economic
scoping of the oil unit is conducted, using a tool such as the analog model to
gauge the likelihood of CO2-EOR yielding a suitable return on investment.
The costs of these initial screening stages is relatively low compared to the
more sophisticated analysis of later development stages. Thus, before moving
too far in development planning, the investor and developer must first
consider the availability and cost of suitable volumes of CO2. Although an oil
unit may be a favorable candidate for CO2-EOR, there must be a reasonable
expectation of obtaining the necessary CO2, before further investments are
made. If the operator is unable to arrange for CO2 then plans may be shelved
indefinitely in favor of business-as-usual or investigating alternative types of
gas injection and other EOR technologies such as chemical flooding.
If it is believed that injectable CO2 can be obtained, then detailed 3D reservoir
modeling and flood simulations may be conducted to carefully assess the
CO2-EOR response and optimize the flood design. These modeling and
simulation studies help to formulate a development plan and evaluate the
project economics and risks. If the economic potential meets the developer’s
requirements then final arrangements can be made for financing the project
and ultimately implementing the development plan.
Page 10
draft
10
Figure 3 Example Decision Tree for CO2-EOR Development
Physical Screening for
Suitable Reservoir Properties
Preliminary Economic Scoping
for Profitability
Business-As-Usualor
Different EOR Technology
YES
NO
CO2 Availableand/or
Planned
Business-As-Usualor
Different EOR Technology
YES
NO
Policy Makersand
CO2 Devolpers
Detailed Reservoir Modeling and
Simulation
Delay...
YES
NO
Development Plan and
Detailed Economic AnalysisYES
NO Business-As-Usualor
Different EOR Technology
Business-As-Usualor
Different EOR Technology
Final Contractingand
ImplementationYES
NO
Delay...
Business-As-Usualor
Different EOR Technology
(i) (ii) (iii) (iv) (v) (vi)
Page 11
draft
11
5 THE ANALOG ECONOMIC SCOPING MODEL FOR CO2-EOR
A basic spreadsheet model demonstrating the analog method has been freely
available from Kinder Morgan Inc. for some time9, and van 't Veld and Phillips
(2010) extended that approach across a number of dimensions. Further still,
additional refinements and parameter updates are included for this study.
Ultimately, this revised implementation can be applied to a large number of
potential oil units and characterize incremental oil supply and CO2 purchase
demand for large regions.
The analog method itself simply creates a time line for incremental oil and CO2
flows, which are then combined with economic criteria such as and equipment
costs, CO2 purchase costs, and oil prices. The resulting capital costs and cash
flows are then used to calculate the net present value (NPV) of the project
based on a required rate of return (ROR) threshold. If the NPV of the project is
positive then, the project is considered economically viable.10
The analog approach reserves some advantages over other methods. A recent
Department of Energy study (DOE/NETL 2008) considers similar economic
factors (for a limited set of oil and CO2 prices), but employs a more data
intensive model.11
9 The Kinder Morgan Morrow and San Andres models are available at
www.kindermorgan.com/business/co2/tech.cfm. Although similar in approach, the KM model
offers limited options and other functionality compared to the UW/EORI model in this study.
10 The analog model is described with step-by-step detail in the Appendix of van ‘t Veld and
Phillips (2010) – only an overview is included here for expositional clarity.
11 The DOE report relied on the slightly more sophisticated CO2-Prophet simulation tool,
which requires detailed geological and fluid property information – thus restricting the number
of oil units with sufficient data for analysis. As reported in (ARI, 2006) the CO2-Prophet tool
was developed by Texaco Exploration and Production Technology Department (EPTD) as an
alternative to the DOE’s own CO2PM tool. Both of these software packages are freely
available from DOE/NETL: http://www.netl.doe.gov.
Page 12
draft
12
Other studies take the simpler approach of employing rule-of-thumb
multipliers and often ignore the key economic question of whether the oil unit
could profitably undertake EOR with a suitable risk-adjusted return.12
Again, at the core of the analog model is the assumption that the predicted
EOR response of each oil unit will match the scaled historical response of an
existing and mature EOR project called the “analog.” Although there are
tremendous differences across oil units in terms of geology, rock properties
and fluid properties, the method assumes that the performance of any FRC will
match that of the analog when scaled to fractions of "hydrocarbon pore
volume” (HCPV). The terms “original oil in place” (OOIP) and “hydrocarbon
pore volume” (HCPV) are used somewhat interchangeably. However, OOIP is
measured in “stock tank barrels” (stb) at the surface after the gas comes out
(the oil desaturates) with reduced pressures, and HCPV is measured as
“reservoir barrels” (rb) in the ground at reservoir temperature and pressure.13
The scaling of the analog is done by converting all units to fractions of HCPV
and describing the produced volumes as functions of the cumulative fraction of
HCPV injected. This creates a set of “dimensionless” analog curves that can be
used to predict EOR outcomes for other oil units.
By way of example, if the analog project produced 8% HCPV of incremental
oil after injecting a cumulative 200% HCP, then any FRC analyzed with this
analog is also assumed to produce 8% HCPV after injecting the same
cumulative 200% HCPV. Because the analogs are converted into
12
Holtz et al. (2001), Dahowski et al. (2005), and Wo et al. (2009) are examples of the
multiplier approach. For instance, to estimate CO2 demand in Wyoming oil basins, Wo et al.
(2009) identify suitable units based on physical screening criteria. They then assume that the
candidate projects will all inject 2.5 hydrocarbon pore volumes (HCPV) of CO2 and water with
70% of CO2 re-injected. These assumptions ignore whether the oil unit can undertake the
operation profitably and with enough return to justify the risks.
13 Converting between OOIP and HCPV is done using the reservoir “oil formation volume
factor” (FVF, >1) which is the fraction of oil shrinkage from decreasing pressure and
escaping gas when oil is brought to the surface such that OOIP = HCPV/ .
Page 13
draft
13
dimensionless space, the FRCs can differ in terms of their absolute volume of
oil in place (in barrels) and rate of water and CO2 injection (barrels or Mcfs),
but still be comparable in dimensionless space as fractions of HCPV.
5.1 ANALOG LIBRARY
The analog dimensionless-curve histories available for this study are based on
three CO2 projects: the Wasson-Denver San Andres (DSA) in West Texas, the
Postle-Morrow (PM) in the Oklahoma panhandle, and the Lost Soldier-
Tensleep (LSTP) in central Wyoming. The dimensionless data for the Denver
San Andres and Postle-Morrow come directly from the Kinder Morgan (KM)
spreadsheet models, and two versions of dimensionless data for the Lost
Soldier Tensleep were provided by Shoachang Wo (Wo et al., 2009) and Klaas
van ‘t Veld (van’t Veld and Phillips, 2010).
Along with this primary data, extended versions of the Postle-Morrow and
Lost Soldier Tensleep curves were also created by projecting the underlying
histories forward to 2.98 HCPVs of injection in order to match the
dimensionless time of the Denver San Andres unit. The incremental oil from
all seven of these potential analogs are illustrated in Figure 4, and cover three
different WAG histories from 1.87 to 2.98 HCPVs of injection and 7.75% to
17.45% incremental oil production.
The performance gap between these various projects no doubt arises from
various geological and field-development differences. For instance, the Lost
Soldier-Tensleep and Postle-Morrow are sandstone reservoirs that are typically
less responsive to EOR compared to carbonate rock as in the Denver-San
Andres. Hustad (2004) estimates that the average incremental EOR response of
sandstone is around 12% compared to 17% for carbonates. Additionally, the
LSTP is known to have fractures in the formation rock which channels the
injected fluids more directly to the production wells – bypassing contact with
some of the reservoir oil, and thus reducing the flood efficiency, perhaps in
contrast to the experience at PM or DSA.
Page 14
draft
14
Figure 4 CO2-EOR Incremental Oil Production Analogs
While the model assumptions predict that two oil units with the same exact
HCPV and injection rates will trace out the exact same incremental oil
production path, it is clear that differences in reservoir conditions and flood
design are an important consideration. here will always be some discrepancies
and uncertainty, choosing the wrong analog history can provide misleading
results. That being said, another advantage of the analog model as a
preliminary screening tool is the ability to quickly evaluate many scenarios
across different analogs and economic assumptions to characterize the range of
potential outcomes.
17.5%
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
0.20
Cu
m.
Incr
em
en
tal O
il P
rod
uct
ion
(H
CP
V)
Cum. CO2 + Water Injection (HCPV)
Dimensionless Curves (HCPV) Analog Library
Kinder Morgan San Andres (17.5%)Kinder Morgan Morrow (13.3%)KM Morrow Projected (15.3%)S. Wo, Lost Soldier Tensleep (11.1%)S. Wo, LSTP Projected (12.4%)van 't Veld, Lost Soldier Tensleep (7.8%)van 't Veld, LSTP Projected (8.9%)
11.1%
12.4%
7.8%
8.9%
13.3%
15.3%
Page 15
draft
15
WASSON-DENVER SAN ANDRES UNIT
The Wasson-Denver unit in the Permian Basin of West Texas is one of the
largest CO2 projects in the world and has been injecting CO2 since 1983. The
unit has an estimated 2.10 billion barrels of OOIP in a dolomite/carbonate San
Andres formation. The produced oil is very favorable for EOR at 33o API oil
gravity, and the unit is developed with nearly 1,100 wells (1/3rd
are injectors)
on 28,000 acres (EPRI, 1999). Based on the KM dimensionless analog history
(Figure 5), the Wasson-Denver unit has produced roughly 366 million barrels
of oil using CO2 injection (17.45% recovery factor).
According to the KM dimensionless data, the assumed injection profile
consisted of nearly 100% CO2 in the beginning of the flood before gradually
increasing the proportion of water injection to nearly 97% water in WAG by
the end of the dimensionless data.
Figure 5
17.45%
-0.25
0.00
0.25
0.50
0.75
1.00
1.25
1.50
1.75
2.00
2.25
2.50
Cu
m.
Pro
du
ced
/In
ject
ed
(H
CP
V)
Cum. CO2 + Water Injection (HCPV)
Wasson-Denver San Andres Dimensionless Analog
Location: West TexasSource: KM San Andres Model
CO2 Injected
Water Injected
CO2 Produced Incremental Oil
Page 16
draft
16
Figure 6
POSTLE-MORROW UNIT
The Postle field in the panhandle of Oklahoma began CO2 injection in 1996.
The unit has 300 million barrels of OOIP in the Upper and Lower Morrow
sandstone formations, producing lighter gravity oils (40-44o
API) (Wehner,
2009). The 26,000-acre project is developed in 80-acre 5-spot injection
patterns, and based on the KM analog (Figure 6), has produced about 40
million barrels of oil after of 1.72 HCPVs injection (13.3% recovery factor).
The underlying dimensionless injection profile suggests that Postle-Morrow
began with a 1:1 WAG of equal size slugs of CO2 and water for the first HCPV
of injection, after which the proportion of water gradually increased such that
the volume of water was 89% of WAG by the end of the analog history.
Projecting the Morrow production curve out to 2.98 HCPVs of injection
(duration of DSA analog) would suggest up to 15.25% incremental recovery –
an additional 5-6 million barrels on top of the KM curves.
15.25%
-0.25
0.00
0.25
0.50
0.75
1.00
1.25
1.50
1.75
2.00
2.25
2.50
2.75
Cu
m.
Pro
du
ced
/In
ject
ed
(H
CP
V)
Cum. CO2 + Water Injection (HCPV)
Postle-Morrow Dimensionless Analog
CO2 Injected
Water Injected
CO2 Produced
Incremental Oil
13.3%
Projected to 2.98 HCPVsLocation: Oklahoma PanhandleSource: KM Morrow Model(morscale.xls)
Page 17
draft
17
LOST SOLDIER-TENSLEEP UNIT
The Lost Soldier-Tensleep project in central Wyoming began CO2 injection in
1989, and based on a basic decline curve analysis, produced an estimated 27.6
million barrels of incremental oil through the end of 2011 – approximately
11.5% of the estimated 240 million barrels of OOIP (Cook, 2012; Brokmeyer
et al., 1996). The produced oil has an average gravity of 34o API, ideal for
CO2-EOR, and although the project is maturing, the 1,500 acre unit is currently
operating with 98 active wells (44 producers, 54 injectors) (WOGCC).
Two dimensionless curves have been reported in the literature for the Lost
Soldier-Tensleep unit: Wo et al. (2009; see Figure 7) and van ‘t Veld &
Phillips (2010; see Figure 8). While both versions are built on essentially the
same data a few underlying assumptions result in different WAG ratios and a
3-4% difference in incremental oil. In the S. Wo version of LSTP, the WAG
ratio is about 2:1 (twice as much water as CO2) compared to 1:1 in the van ‘t
Veld version – the difference likely arises from the conversion factor used to
convert CO2 volumes to HCPV. The other major difference is that van ‘t Veld
assumes the decline in secondary production would have been less severe,
resulting in less oil classified as incremental (van ‘t Veld estimates
approximately 7.75% incremental versus the 11.11% in S. Wo).
While the incremental recovery of S. Wo-curves are more consistent with the
11.5% incremental oil calculated with a basic decline curve analysis, these
analog differences highlight how the underlying assumptions of the researches
can yield slightly different results. Projecting both dimensionless histories
forward to 2.98 HCPVs of injection would yield an eventual incremental
recovery of 12.39% in the S.Wo version, and 8.85% in the van ‘t Veld version.
Page 18
draft
18
Figure 7
Figure 8
12.39%
-0.25
0.00
0.25
0.50
0.75
1.00
1.25
1.50
1.75
2.00
2.25
2.50
Cu
m.
Pro
du
ced
/In
ject
ed
(H
CP
V)
Cum. CO2 + Water Injection (HCPV)
Lost Soldier-Tensleep (S.Wo) Dimensionless Analog
CO2 Injected
Water Injected
CO2 Produced
Incremental Oil
Location: Central WyomingSource: Shaochang Wo
11.11%
Projected to 2.98 HCPVs
8.85%
-0.25
0.00
0.25
0.50
0.75
1.00
1.25
1.50
1.75
2.00
2.25
2.50
Cu
m. P
rod
uce
d/I
nje
cte
d (
HC
PV
)
Cum. CO2 + Water Injection (HCPV)
Lost Soldier-Tensleep (van 't Veld) Dimensionless Analog
CO2 & Water Injected (1:1 WAG)
CO2 Produced
Incremental Oil
Location: Central WyomingSource: Klaas van 't Veld (van 't Veld & Phillips, 2010)
7.75%
Projected to 2.98 HCPVs
Page 19
draft
19
As with the other analogs, the choice between different versions of the LSTP
dimensionless curves depends on the perspective of the researcher. The
variety of injection profiles and incremental recoveries characterized by these
different analog models allows for more flexibility in the “CO2-EOR Analog
Economic Scoping Model” and the ability to estimate a range of outcomes.
5.2 ECONOMIC ASSUMPTIONS AND DECISION CRITERIA
While the analog histories provide a way to predict the incremental oil and
CO2 production flows, whether or not a given FRC will actually undertake
EOR requires an economic decision. Including economic considerations such
as the up-front capital and operating costs of EOR allows the model to
compare the net present value (NPV) or internal rate of return (IRR) of EOR
with the baseline scenario of business-as-usual (BAU).
The net present value of continuing without EOR is
NPV bau =ptoQt
op,bau (1-t R )(1-t SP )-Co(Qtlp,bau )
(1+ r)tt=1
T bau
å (1)
and the NPV of switching to CO2-EOR is
NPVeor =
ptoQt
op,eor (1-t R )(1-t SP )- pcQtcm -C rQt
cp -Co(Qtlp,eor )
(1+ r)tt=1
T eor
å (2)
The sum of net cash flows for both BAU (1) and EOR (2) is calculated from
the start time t out to points T bau or T eor , which is the time operating cash
flow turns negative (also called the economic lifetime). The price of oil pto at
each point in time, along with each period’s oil production Qtop,bau or Qt
op,eor ,
determines the oil revenues. Subtracted from these revenues are royalty
payments t R and severance and property taxes t SP along with each period’s
operating costs.
Page 20
draft
20
In both BAU and EOR there are operating costs Co associated with each
barrel of liquid production (“lp”) composed of oil and water and denoted
Qtlp,bau or Qt
lp,eor . During the life of the EOR project much of the CO2 will
eventually be re-produced and reinjected, but at the outset most of the CO2
must be purchased; CO2 purchases net of recycled volumes are denoted as
Qtcm and charged pc per Mcf. The recycling costs C r are charged on the
volume of CO2 produced along with the oil and re-injected.
The net operating cash flows of BAU and EOR are discounted to the present
at rate r representing the operator’s assumed rate-of-return threshold for the
project. Alternatively, the stream of cash flows can be used to calculate the
IRR (the value of r for which NPV=0). Finally, undertaking CO2-EOR
involves large up-front capital investments K assumed to occur in one lump
sum at time zero (not discounted), and the economic decision criterion to
switch from BAU to EOR requires that the NPV eor > NPV bau.
Incremental Oil and CO2 Production
In equation (1) for BAU, the time path of oil production Qtop,bau for continued
water flooding is based only on the decline rate of production. In equation (2)
for EOR, each oil unit’s HCPV and injection rate is used to predict future oil
and CO2 flows – the estimated time paths of incremental oil recovery Qtop,eor
and the amount of CO2 available for recycling Qtcp – based on the selected
dimensionless analog. Once the time path for produced CO2 is determined, the
amount of CO2 actually purchased, Qtcm , can be found by subtracting Qt
cp
from the amount of CO2 injected.
Qtcp
Page 21
draft
21
Wyoming Oil Prices
Wyoming oil prices typically trade at a discount to standard WTI prices, even
after accounting for quality adjustments based on API gravity. In 2011 the
average WY domestic first-purchase price was $83.45 per barrel compared to
a W. Texas Intermediate (WTI) price of $95 – a discount of ($11.55). The
most recent prices reported by the WY Economic Analysis Division showed
even steeper discounts; compared to the May WTI of $91.09, the prices were
$65.40 for WY Sour (-$25.69) and $76.55 for WY Sweet (-$14.54).14
All oil prices entered into the scoping model are assumed to be the WTI price
and then automatically adjusted based on the API oil gravity according the
EIA 2011 domestic crude prices by gravity (EIA, 2011). Because data on
sulfur content (sweet vs. sour) was not available, a standard WY discount of
$14.54 per barrel was then subtracted to arrive at the assumed oil price
received by the oil unit. The price adjustment schedule is outlined in Table 1.
Table 1
API Oil Gravity Scoping Model Oil Price
API £ 20o pto =1.07(WTI )- $14.54
20o < API £ 25o pto =1.09(WTI )- $14.54
25o < API £ 30o pto =1.03(WTI )- $14.54
30o < API £ 35o pto =1.05(WTI )- $14.54
35o < API £ 40o pto =1.00(WTI )- $14.54
API > 40o pto = 0.97(WTI )- $14.54
14
“Wyoming Insight” June 2012 Issue, http://eadiv.state.wy.us/creg/WyInsight.pdf.
Page 22
draft
22
Table 2 Up-front Capital Investment Costs for CO2 EOR.
Cost Item Cost Estimate Notes & Source
Constructing a CO2
Processing Plant
$824,767/MMcfd of
Processing Capacity
Based on Advanced Resources International (ARI) study but
updated to 2011 using an average of the four major refinery
construction cost indexes. We assume this includes compression
that would cost $2,600/hp, based on the O&GJ estimated future
installed compressor cost report for 2010/11.
New Well Drilling
(drilling only) $302-364/ft of depth
Non-linear piece-wise function by depth. Bob King, Engineer at
World Oil Properties, Inc. updated with 2008 cost data from EIA
(2010).
Working Over and
Equipping an
Existing Producer
Well
$231,980 per well
Cleanout, acidize, and install surface and wellhead equipment.
Chuck Fox, VP, Operations & Technology, Kinder Morgan CO2
Company, LP updated with 2008 cost data from EIA (2010).
Equipping a New
Producer or
Converting another
Well to Production
$570,847 per well,
plus $35/ft of depth
Open hole, acidize, tubing with rods etc., and install surface and
wellhead equipment Chuck Fox, VP, Operations & Technology,
Kinder Morgan CO2 Company, LP updated with 2008 cost data
from EIA (2010).
Preparing and
Equipping any Well
for Injection
$257,866 per well,
plus $35/ft of depth
Acidize, special injector tubing and valves etc., and install surface
and wellhead equipment. Chuck Fox, VP, Operations &
Technology, Kinder Morgan CO2 Company, LP updated with 2008
cost data from EIA (2010).
Pipeline Costs 85, 821 Dinches0.9936614Lmiles
0.8231464PWTI0.1715248( )
Pipeline cost forecasting model estimated from O&GJ Pipeline
Economics Data. Data was adjusted for inflation to 2011 using the
O&GJ Nelson-Farrar Inflation Index.
CO2 Metering
Station $250,000 per station Personal communication with Ken Hendricks, Sr. Staff Engineer,
Anadarko Petroleum Corp. (Sept. 2011)
Page 23
draft
23
Up-front Investment Costs for EOR
The initial development costs required to prepare an oil unit for EOR can
be substantial and includes the cost of new well drilling, well work-overs,
materials and equipment used in reconfiguring wells, and the building of a
CO2 processing and recycling facility. In this study we assume that operators
purchase CO2 from a third party, but are still responsible for the cost of
building a CO2 metering station and spur pipeline to their oil unit from the
major CO2 delivery trunk pipeline. These up-front cost assumptions and their
sources are summarized in Table 2.
The cost of constructing the CO2 recycling plant is based on the maximum
volume of CO2 processed and includes the compression required to meet the
reservoir injection pressure. In a 2006 assessment of CO2-EOR in the Rocky
Mountain region by Advanced Resources International (ARI) it was assumed
that the recycling plant cost $700,000 per MMcfd of capacity – adjusting this
number for inflation to the end of 2011 gives a current figure of
$824,767/MMcfd of capacity.
For simplicity, this study assumes that each oil unit is responsible for a CO2
metering station costing $250,000 plus the cost of a 5-mile spur pipeline. The
actual cost of this spur pipeline depends on the pipe diameter determined by
the throughput of CO2 and is also adjusted to the price of oil assumed for the
beginning of the project.
K
Page 24
draft
24
The pipeline costs are therefore determined by the following equation:
(3)
where is the total cost of the spur line, is the pipe diameter in
inches, is the length of the pipe in miles (5-miles in this case) and
is the WTI price of oil at the beginning of the project.
The well drilling and completion costs make up the remainder of K. The
model assumes that 80% of surface acreage is covered by well patterns
consisting of one producer and one injector well, and the number of patterns
required is determined by the maximum well-pattern spacing being assumed.
If the number of existing wells falls short of the number required, then new
wells are drilled at an average cost of $316 per foot. Adapting an existing
producer for CO2 costs $231,980/well and preparing new producers costs
$570,847/well plus $35/ft of depth. All injector wells, whether new or
existing, are assumed to cost $257,866/well plus $35/ft of depth to prepare
them for CO2 injection.
Some adjustments are made to these cost estimates based on the price of oil
assumed at the beginning of the project. All of the well costs are assumed to
be tied 1-to-1 with percent changes in the starting price of oil from a base
price of $100 per barrel, the pipeline equation accounts for the starting oil
price directly, and all other capital costs are tied 0.20-to-1 for percent changes
in the starting oil price from a base of $100 per barrel.15
15
The correlation between drilling costs and other capital costs are based on relationships
evaluated in Cook (2011).
C pipe = 85,821[Dinches0.9936614Lmiles
0.8231464PWTI0.1715248 ]
C pipe Dinches
Lmiles PWTI
Page 25
draft
25
Table 3 Ongoing Operating Costs for BAU and EOR.
Cost Item Cost Estimate Notes & Source
Royalty Rates
12.5% Base Fed. Royalty
5.25% Override
16.67% State Royalty
18.75% Private Royalty
The State and Federal rates are set by policy. The override
rate on federal leases is set to bring the total rate to 17.75%,
in-line with a study of such rates in Montana. The 18.75%
private rate is based on a recent lease contract between
Laramie County and Anadarko Petroleum Corp.
Severance Taxes 6% Most Leases
8.5% Tribal Leases Set by Wyoming state policy.
Ad Valorem (Property) Tax 5.9% to 7.2% Varies by County. Mineral property is assessed at 100% of
the value of prior-year production.
CO2 Purchases $0.50/Mcf Delivery Charge,
plus 1.0% to 2% of Oil Price
van ‘t Veld, K. and Phillips, O.R. (2009)
DOE/NPOSR (2006)
CO2 Processing Plant Operating Costs
Maintenance & Labor = $92 per hp-yr
Electricity =
6.02 cents per kWh =
$421.40 per hp-year
Assumes the plant is powered by purchased electricity based
on 7,000 kWh per horsepower. Electricity rate is the WY
average industrial purchase price.
Other Total Liquid Production Costs $0.65/barrel BAU
$0.72/barrel EOR BAU is based on EIA (2010) and EOR is assumed 10%
higher by Chuck Fox, VP, Operations & Technology, Kinder
Morgan CO2 Company, LP. Other Well Operating Costs
$38,828/well-yr BAU
$42,710/well-yr EOR
Page 26
draft
26
Operating Costs for BAU and EOR
The royalty, severance, property-tax and operating-cost assumptions are
summarized in Table 3. The royalties are estimated based on the share of prior
production coming from federal, tribal, state and private mineral leases. Ad
valorem taxes in Wyoming for mineral properties are assessed at 100% of the
production-value, with the exact rate determined by the primary county
location of the oil unit, and severance taxes are 6% across the board.
The operating costs of labor, maintenance, and power for the injection and
production equipment are charged at $38,828/well-year plus $0.65 per barrel
of liquid produced under water flooding, and are assumed to be 10% higher
for EOR ($42,710/well-year plus $0.72 per barrel of liquid).
The operating costs for the CO2 processing facility are based on the
horsepower rating of the facility. Labor and maintenance are estimated at
$92/hp annually, and the electricity is estimated at 7,000 kWh/hp and charged
6.02 cents per kWh.16
As with the capital costs, some adjustments are made to the labor,
maintenance and electricity costs based on a simple correlation with the
assumed oil price. The model is calculated on a quarterly basis, and based on
the assumed oil price in each quarter these costs are adjusted 0.20-to-1 for
percent changes from a base price of $100 per barrel.
The purchase of CO2 for injection into the oil reservoir constitutes a
substantial and ongoing operational expense. For projects purchasing CO2
from a third party, and depending on the source of the CO2, the operator will
pay a $0.50-$1.00/Mcf delivery charge plus 1.3-2.6% of the current oil price
(van ‘t Veld, K. and Phillips, O.R., 2009; DOE/NPOSR, 2006).
16
Based on the May 2012 Wyoming industrial average price of electricity, “Electric Power
Monthly, July 2012, With Data for May 2012,” EIA.gov.
Page 27
draft
27
In the case of vertically integrated operators who own their CO2 resource, the
internal cost (what they charge themselves as an accounting basis) is perhaps
closer to the delivery charge.
In this study several different CO2 pricing scenarios will be considered, all of
which will assume a $0.50/Mcf delivery charge plus 1.0%, 1.5% or 2.0% of
the oil price.
Many of the cost estimates are based on data collected in 2003 from industry
contacts. According to the IHS Upstream Capital and Upstream Operating
Cost Indexes these cost levels peaked in 2008, and are only now starting to
return to their pre-recession levels.17
Each cost item was therefore adjusted to
2008 using the comparable cost categories detailed in the EIA “Oil and Gas
Lease Equipment and Operating Costs 1994 through 2009”.18
5.3 VISUALIZING THE MODEL RESULTS
The application of the analog model for oil and CO2 flows and the resulting
cash flows are projected on a quarterly basis so that the optimal stopping point
for CO2 flooding can be calculated down to a 3-month period. It is helpful to
consult a visual representation of the model results to get an idea of what is
going on inside the model.
The Grieve-Muddy oil unit, operated by Denbury Resources and Elk
Petroleum, is located in central Wyoming and slated to begin CO2 flooding by
the end of 2012. Because Grieve-Muddy has been extensively considered for
CO2-EOR (see Wo et al., 2008; Mullen, 2008) it serves as a useful example.
17
http://www.ihs.com/info/cera/ihsindexes/index.aspx
18 This series has now been discontinued by the EIA, so all future cost updates will have to
rely on a different indexing method.
Page 28
draft
28
The oil unit has an estimated OOIP of 67 MMbbls, and has produced 29.9
MMbbls of oil19
(36o API oil gravity) with a successful water flood.
By way of example, consider the assumption that the project is developed in
50-acre well patterns (one injector plus one producer), injects water and CO2
at 15% HCPVs/year, pays $2.70/Mcf for purchased CO2 (~40 MMscfd
initially) and faces a WTI oil price of $110 per barrel. While previous studies
have assumed an incremental recovery of 18-20 MMbbls under gravity-stable
CO2 flooding, the scoping model assumes more conservative results under
WAG flooding.20
Applying the projected version of the Lost Soldier-Tensleep
(S.Wo) analog to predict the results at Grieve would assume 12.4%
incremental oil recovery, or roughly 8 MMbbls.
Under this scenario, Grieve-Muddy would require approximately $60 million
in up-front capital for wells, equipment, a 5-mile spur pipeline and a CO2
recycling facility. The project would purchase 52.6 Bcfs of CO2 to produce
8.05 MMbbls over 14 years and yield $247.7 million in pre-tax profits - an
estimated IRR of 52%.
The annual oil revenues, operating costs and net cash flows are shown in
Figure 9 and the incremental oil, CO2 injected and CO2 purchased are shown
in Figure 10.
19
Based on figures reported by Chris Mullen (2008) presenting on behalf of Elk Petroleum.
In the scoping analysis for this report, the more conservative estimate of 26.6 MMbls was
used as reported in the IHS Rocky Mountain Production database.
20 Gravity-stable flooding is typically applied in steeply sloping and/or domed oil reservoir
formations where gravity can be used to improve the efficiency of the CO2 flood.
Page 29
draft
29
Figure 9
Figure 10
($80)
($60)
($40)
($20)
$0
$20
$40
$60
$80
$100
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
Cas
h F
low
s ($
Mill
ion
s)
Project Term (Years)
Oil Revenues, Operating Costs & Net Cash FlowGrieve-Muddy Example
Net Cash Flow
Operating Costs
Gross Oil Revenue
$60 Million Upfront Capital Costs
14.25 Years$247.7 Million Pre-Tax Profit
52% IRR on Project
0
2
4
6
8
10
12
14
16
0.00
0.20
0.40
0.60
0.80
1.00
1.20
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
CO
2 Flo
ws (B
cf)In
cre
me
nta
l Oil
(Mm
stb
o)
Project Term (Years)
CO2 Injected/Purchased and Incremental OilGrieve-Muddy Example
Inc. Oil (Mmstbo)
CO2 Injected (Bcf)
CO2 Purchased (Bcf)
Purchased CO2 falls as CO2 is recycled an re-injected.
Page 30
draft
30
6 DATA
Data on depth, temperature and API oil gravity for nearly every FRC in
Wyoming were first used to screen for miscible oil gravities in the
neighborhood of 22o
to 48o API.
21 Second, estimates of minimum miscibility
pressure (MMP) and fracture pressure were used to ensure that MMP is lower
than the reservoir fracture pressure to ensure the unit can safely and legally
achieve MMP. Only those FRCs that appeared to satisfy these requirements
were kept in the sample.
Lastly, only fields with at least one FRC meeting a cut-off near 450,000 bbls
of cumulative production were kept in the sample. While many FRCs below
that cut-off are included, it is only because they are located within fields with
at least one FRC meeting this requirement. This cut-off was chosen because
98% of WY oil production has been from FRCs with more than 450,000 bbls
of production, and such smaller reservoirs rarely have enough potential
recovery to justify the up-front capital costs of CO2-EOR.
The final dataset for this study contains the necessary inputs for the scoping
model, and is meant to provide a comprehensive view of WY’s CO2-EOR
potential, containing information on 723 oil field-reservoir combinations
(FRCs) in 415 oil fields.
The assembled data on each FRC describe the geology, oil characteristics, oil
production, water injection history, and the number, type and status of
existing wells. The sources used were the Wyoming Geological Association
Symposium and Field Reports (WGA), the Department of Energy and
National Energy Technology Laboratory (DOE/NETL) TORIS data, the
Wyoming Oil & Gas Conservation Commission (WOGCC), and IHS data for
the Rocky Mountain region (IHS).
21
There were 39 FRCs between 20-21.9o API and 20 FRCs between 48.1-49.5
o API that were
included because of their larger size or by being part of a field with other more favorable
FRCs.
Page 31
draft
31
Collectively, this dataset represents over 4.9 billion barrels of cumulative oil
production from an estimated 13.9 billion barrels of original oil in place
(OOIP). These 415 oil fields have roughly 7,119 active production wells,
1,734 active injection wells, and another 6,255 available well bores.
A more detailed description of the dataset is provided in Appendix A.
7 WYOMING INCREMENTAL OIL & CO2 PURCHASE DEMAND
The total economically recoverable oil and the associated CO2 purchased
demand are estimated by applying the scoping model to all 723 FRCs in the
dataset and summing the results from units earning a minimum 20% IRR.
Because the results vary depending on the underlying assumptions (analog
and incremental recovery, minimum well spacing, injection rate, oil prices,
CO2 prices) a broad range of scenarios are considered. For simplicity, a
baseline scenario is defined to serve as a reasonable middle-of-the-road
benchmark result.
The “baseline” results are calculated using the Lost Soldier-Tensleep (LSTP-
S.Wo) analog with a projected 12.4% incremental oil recovery after 2.98
HCPVs of injection, 50-acre well-patterns (consisting of one injector and one
producer), and 15% HCPVs of injection per year (~20 years). The baseline
results also assume that CO2 purchases are tied to the WY oil price at $0.50 +
2% of the oil price per Mcf. This “baseline” of 12.4% incremental was chosen
to be in line with the Hustad (2004) average of 12% recovery for sandstones.
Wyoming’s estimated CO2-EOR incremental oil recoverable under this
baseline scenario ranges from 897 to 1,053 MMbbls, at WTI oil prices of $80
to $140 per barrel, with 101-170 different FRCs meeting the 20% IRR
threshold. The associated volume of cumulative CO2 purchases required by
those FRCs ranges from 4.9 to 6.5 Tcfs of CO2, at prices of $2.10-$3.30/Mcf.
Page 32
draft
32
In terms of location, 57-65% of this incremental oil is projected to come from
oil fields in the Big Horn Basin, followed by the Powder River Basin with 17-
26%, the Wind River Basin with 10-11%, the Green River Basin with 5% and
a few projects in other areas. The “baseline” results for incremental oil are
reported in Table ,4 and CO2 purchases are reported in Table 5.
Clearly there will be substantial variations in the results achieved by each
project, but to get a sense of the plausible range of outcomes, the calculations
are also provided for 144 different scenarios organized under two different
development profiles: 50-acre well-patterns with 15% HCPV/year injection
(~20 years), and 80-acre well-patterns with 12.5% HCPV/year injection (~24
years). For each well-development profile the results calculated consider all
four of the analog models, WTI oil prices of $80, $110, and $140 per barrel,
and CO2 contracts of $0.50 plus 1%, 1.5% and 2% of the oil price.
The incremental oil and CO2 purchases for these scenarios can be found in
Appendix B. Incremental oil recovered ranges from a low of 234 million
barrels all the way up to 1.8 billion barrels, and the volume of CO2 purchased
ranges from 2.0 to 10.2 Tcfs.
Page 33
draft
33
Table 4 LSTP-S.Wo22
– Total Incremental Oil Produced (MMbbls): 50-Acre Pattern, 15% HCPV Inj/Year
BASELINE
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl23 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 620 636 650 613 630 643 608 625 632
Denver Basin 0.83 0.84 0.82 0.84 0.82 0.83
Green River Basin 48 50 52 32 49 50 30 49 50
Hanna Basin 0.47 0.48 0.47 0.47 0.46 0.47
Laramie Basin 9 11 12 9 11 11 9 11 11
Overthrust Belt 10 9 9
Powder River Basin 179 230 251 165 223 239 145 213 234
Wind River Basin 108 115 118 107 110 117 106 109 116
Statewide Total 964 1,044 1,094 927 1,025 1,072 897 1,008 1,053
# of Units (20% IRR) 115 154 189 110 146 176 101 140 170
22
Lost Soldier-Tensleep dimensionless curves from Wo et al. (2009) projected forward to 2.98 HCPVs of cumulative production.
23 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 34
draft
34
Table 5 LSTP-S.Wo24
– Cumulative CO2 Purchase Demand (Bcfs): 50-Acre Pattern, 15% HCPV Inj/Year
BASELINE
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl25 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 3,533 3,760 3,928 3,433 3,646 3,803 3,353 3,553 3,668
Denver Basin 5 5 5 5 4 5
Green River Basin 296 317 336 156 307 321 144 304 310
Hanna Basin 3 3 3 3 3 3
Laramie Basin 51 64 69 49 62 65 49 61 63
Overthrust Belt 87 79 76
Powder River Basin 1,007 1,345 1,505 907 1,284 1,409 781 1,205 1,353
Wind River Basin 608 686 721 593 628 696 576 612 677
Statewide Total 5,496 6,179 6,652 5,137 5,934 6,381 4,903 5,741 6,153
# of Units (20% IRR) 115 154 189 110 146 176 101 140 170
24
Lost Soldier-Tensleep dimensionless curves from Wo et al. (2009) projected forward to 2.98 HCPVs of cumulative production.
25 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 35
draft
35
7.1 INCREMENTAL OIL & OIL PRICES
As the price of oil goes up, so do the number of oil units that can profitably
undertake CO2-EOR. This relationship is illustrated in Figure 11, which
shows Wyoming’s incremental oil potential at WTI oil prices from $40 to
above $230 per barrel and assuming the CO2 contract is $0.50 plus 2% of oil
per Mcf.
For each individual analog curve, roughly 90% of the oil possible under each
recovery profile can be realized at WTI oil prices of $140 per barrel – the vast
majority of projects meeting the 20% threshold are online at that point. Even
so, the range of incremental oil possible in the state depends largely on the
average incremental oil recovery factor. At $140 oil, the recovery potential
could be as low as 569 million barrels with 8.9% recovery, or as high as 1.8
billion barrels with 17.4% recovery.
Figure 11
*All analogs assume 2.98 HCPVs of injection and CO2 at $0.50 + 2% of oil per Mcf.
$40$50$60$70$80$90
$100$110$120$130$140$150$160$170$180$190$200$210$220$230$240$250
WTI
Oil
Pri
ce (
$ p
er
bar
rel)
Cumulative Economic Incremental Oil (Mmstbo)
Cumulative Economic CO2-EOR Incremental OilWyoming's Miscible Main Pay Zones
25-Acre Wells, 15%HCPV/Year40-Acre Wells, 12.5%HCPV/Year
LSTP-van 't Veld*8.9% Inc. Oil
LSTP-S.Wo*12.4% Inc. Oil
KM-Morrow*15.3% Inc. Oil
KM-San Andres*17.5% Inc. Oil
High-Baseline$140 WTI Oil
1,053 MMstbo
Low-Baseline $80 WTI Oil
897 MMstbo
Mid-Baseline $110 WTI Oil
1,008 MMstbo
Page 36
draft
36
7.2 CO2 DEMAND, SUPPLY & PRICES
While typical purchase contracts for CO2 are tied to oil in the range of 1-2%
of the oil price according to industry participants, there appears to be a
disconnect between the pricing expectations of oil operators and the cost of
bringing new supplies of CO2 online. While there are clearly promising CO2-
EOR targets across Wyoming at current oil prices, these projects are
constrained by the availability of CO2. To date, the only source of CO2 in
Wyoming has been the ExxonMobil Shute-Creek helium and gas plant whose
entire CO2 supply is already spoken for.
Denbury Resources Inc. is aggressively developing additional CO2 supplies in
Wyoming from the gas facilities at Riley Ridge near Shute Creek and also in
Lost Cabin at the mouth of their Greencore pipeline in central Wyoming.
These sources of CO2 separated from conventional gas streams are much
cheaper than post-combustion capture at power plants or other manufacturing
facilities. Denbury follows a vertically integrated model by primarily owning
their own CO2 sources, and reports an internal accounting charge of $0.20-
$0.44/Mcf at $60 per barrel oil (Blincow, 2012). Such prices represent a
substantial discount to what would be charged in a conventional third-party
purchase contract with a delivery charge plus an additional 1-2% of oil price.
Current Wyoming CO2-EOR operators have indicated that a CO2 price tied at
2% of oil ($2-$2.50/Mcf at $100/barrel) would be considered “way too
high”.26
However, CO2 prices below $2/Mcf stand in stark contrast to capture
costs approaching $95/tonne (~$5/Mcf) from power plants (EPA, 2010).
26
Personal discussion with participants at EORI’s 6th
Annual CO2 Conference held in Casper,
WY July 11th
-12th
, 2012.
Page 37
draft
37
Commenting on the price of CO2 from the supply-side perspective, developers
of the first planned commercial-scale “clean coal” power plant in Texas with
CO2 capture for EOR have said that “without DOE support, no CCS power
plant would be economic…at ‘2% of crude’ – yet CO2 seems to be worth
more” (Ford, 2012).27
With CO2 representing a substantial operating cost for oil developers, the
higher the price, the fewer economic oil units there will be, and the lower the
demand for CO2. This CO2-price-versus-demand relationship is illustrated in
Figure 12, which shows the demand for CO2 using the “baseline” analog
curve and assuming CO2 prices from $0 to above $7/Mcf.
Figure 12
*Assumes LSTP-S.Wo analog projected to 2.98 HCPVs of injection and CO2 at $0.50 + 2% of oil per Mcf..
27
Presentation by Jim Ford, Vice President of Summit Power Group, Inc. which is developing
the first commercial-scale “clean coal” plant with CO2 capture for EOR in the Permian Basin.
$0.0
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
$3.5
$4.0
$4.5
$5.0
$5.5
$6.0
$6.5
$7.0
$7.5
$8.0
CO
2 P
rice
($
/Mcf
)
Cumulative CO2 Purchased (Bcf)
Cumulative CO2 Purchase DemandWyoming's Miscible Main Pay Zones
LSTP-S.Wo* (25-Acre Wells,15% HCPV Inj/Yr, 12.4% Inc. Oil)
Low-Baseline$2.10/Mcf CO2
4,713 Bcfs897 MMstbo
$80 WTI Oil $110 WTI Oil $140 WTI Oil
Mid-Baseline$2.70/Mcf CO2
5,667 Bcfs1,008 MMstbo
High-Baseline$3.30/Mcf CO2
6,032 Bcfs1,053 MMstbo
Anthropogenic$5.00/Mcf CO24.4 to 5.5 Tcfs
834 to 992 Mmstbo
Page 38
draft
38
While the demand for CO2 is clearly lower at higher CO2 prices, if WTI oil
prices are above $100 per barrel there is still substantial incremental oil
potential at “anthropogenic” CO2 prices in the $4-$6/Mcf range. If CO2 were
charged a flat $5/Mcf, there may be 94 to 144 separate Wyoming oil units still
able to meet a 20% IRR at oil prices from $110 to $140 per barrel. These units
would produce 834 to 992 MMbbls of incremental oil, and be purchasng 4.4
to 5.5 Tcfs of CO2.
7.3 WYOMING’S CO2-EOR DEVELOPMENT LANDSCAPE
The geographic locations of Wyoming’s potentially economic CO2-EOR
fields are shown in Figure 13 with the size of each circle corresponding to the
relative amount of additional oil possible. Larger views of each individual
basin are also supplied in Appendix C.
To supply CO2 to the existing projects in the Green River, Wind River and
Powder River Basins, the current pipeline infrastructure starts with the Exxon
pipeline from the Shute Creek plant. The route proceeds northeast above
Green River and Rock Springs before eventually transitioning to an
Anadarko-operated line west of Casper and terminating at the Salt Creek field.
Denbury is slated to complete their 232-mile Greencore pipeline by the end of
2012, starting at Lost Cabin in central Wyoming. The route initially travels
southeast before following the Anadarko line up past Salt Creek and
extending northeast near Gillette and into Montana.
While the 340 MMcf per day available from Exxon is fully subscribed, the
new Denbury pipeline will eventually have a capacity of 725 MMscf per day,
which should allow for significant volumes to be made available in the
Powder River Basin. While the Big Horn Basin holds the majority of
Wyoming’s CO2-EOR potential, and preliminary pipeline planning appears to
be underway, there has yet to be CO2 infrastructure put in place.
Page 39
draft
39
Rank Field Basin
1 Oregon Basin BHB
2 Elk Basin BHB
3 Grass Creek BHB
4 Garland BHB
5 Frannie BHB
6 Byron BHB
7 Hartzog Draw PRB
8 Winkleman WRB
9 Salt Creek PRB
10 Lance Creek PRB
11 Steamboat Butte WRB
12 Big Sand Draw WRB
13 Bonanza BHB
14 Sussex PRB
15 Brady GRB
16 Rock River LB
17 Raven Creek PRB
18 Genrock South PRB
19 Murphy Dome BHB
20 GEBO BHB
21 Big Muddy PRB
22 Labarge GRB
23 McDonald Draw GRB
24 Ryckman Creek OTB
25 Hamilton Dome BHB
26 Grieve WRB
27 Timber Creek PRB
28 Black Mountain BHB
29 North Fork PRB
30 Elk Basin South BHB
31 Golden Eagle BHB
32 Coyote Creek PRB
33 Meadow Creek PRB
34 Sussex West PRB
35 Cole Creek WRB
Figure 13 Wyoming Location & Incremental Oil from Potentially Profitable Oil Fields
BHB
PRB
WRB
GRB
DB LB
HB
OTB SB
Page 40
draft
40
8 CONCLUSION
In the coming, decades Wyoming is positioned to benefit greatly from
enhanced oil recovery technologies such as CO2-EOR and stands to recover
100’s of millions of barrels of additional oil from otherwise maturing fields.
With both existing and planned CO2 projects within the state, there has been
an influx of capital investments, mineral royalties, severance and ad valorem
taxes flowing into state and local budgets and the overall state economy.
In order for Wyoming to realize its CO2-EOR potential, new supplies of CO2
will need to be forthcoming, and pipeline delivery infrastructure will have to
be expanded into the Big Horn Basin. These efforts will require industry
professionals, investors, and public agencies to work together with a common
vision of Wyoming’s EOR landscape to harness the state’s mineral wealth in
an economically and environmentally responsible way.
Page 41
draft
41
REFERENCES
API (2011). Study commissioned by the American Petroleum Institute, prepared by
PriceWaterhouseCoopers LLP, “The Economic Impacts of the Oil and Natural Gas
Industry on the U.S. Economy in 2009: Employment, Labor Income and Value
Added” (2011). Available online at
http://www.api.org/~/media/Files/Policy/Jobs/EconomicImpacts_of_Industry_on_U
S_Economy_in_2009.ashx
ARI (2006). Advanced Resources International, “Basin Oriented Strategies for CO2 Enhanced
Oil Recovery: Rocky Mountain Region”. Prepared for U.S. Department of Energy,
Office of Fossil Energy - Office of Oil and Natural Gas. Available online at
http://www.fossil.energy.gov/programs/oilgas/publications/eor_co2/Rocky_Mountai
n_Basin_Document.pdf
Arps, J. J. (1945). “Analysis of Decline Curves”. Transactions of the American Institute of
Mining, Metallurgical and Petroleum Engineers 160: 228-247.
Aycaguer et al. (2001). Aycaguer, Anne-Christine, Miriam Lev-On, and Arthur M. Winer.
2001.“Reducing Carbon Dioxide Emissions with Enhanced Oil Recovery Projects:
A Life Cycle Assessment Approach.” Energy Fuels 15 (2) (March 1): 303–308.
Blincow, Mike (2012). “Denbury Resources, Inc.” Presented at the 6th Annual CO2
Conference, Casper, WY, July 11th 2012. Slides available online at
http://www.uwyo.edu/eori/resources/co2conf_2012_agenda.html
Brokmeyer et al. (1996). Brokmeyer, R. J., D. C. Borling, and W. T. Pierson (1996). “Lost
Soldier Tensleep CO2 Tertiary Project, Performance Case History: Bairoil,
Wyoming.” Paper # SPE 35191
Cook, Benjamin R. (2011). “Essays on Carbon Policy and Enhanced Oil Recovery”, PhD
Dissertation, Economics, University of Wyoming.
Cook, Benjamin R. (2012). “The Economic Contribution of CO2 Enhanced Oil Recovery in
Wyoming's Economy”, University of Wyoming, Center for Energy Economics &
Public Policy (CEEP) Working Papers & Reports. Available online at
http://www.uwyo.edu/cee/working-papers.html
CREG (2012). Wyoming Consensus Revenue Estimating Group (CREG), “January 2012
CREG Forecast for FY2012-FY2016”. Available online at
http://eadiv.state.wy.us/creg/GreenCREG_Jan12.pdf
Dahowski et al. (2005). Dahowski, RT, JJ Dooley, CL Davidson, S Bachu, and N Gupta.
“Building the cost curves for CO2 storage: North America”. IEA Greenhouse Gas
R&D Programme.
DOE/NETL (2008). “Storing CO2 with Enhanced Oil Recovery”. Washington, D.C.:
Department of Energy, National Energy Technology Laboratory. Available online at
http://www.netl.doe.gov/kmd/cds/disk44/D-CO2%20Injection/NETL-402-1312.pdf
DOE/NPOSR (2006). “National Strategic Unconventional Resource Model: A Decision
Support System”. U.S. Department of Energy, Office of Petroleum Reserves, Office
of the naval Petroleum and Oil Shale Reserves (DOE/NPOSR), Washington, DC.
DOE/TORIS. “Computer Software & Databases”. Washington, D.C.: Department of Energy,
National Energy Technology Laboratory (NETL). Available online at
http://www.netl.doe.gov/technologies/oil-gas/software/database.html
Page 42
draft
42
Doublet et al. (1994). Doublet, L. E., P. K. Pande, T. J. McCollum, and T. A. Blasingame.
“Decline Curve Analysis Using Type Curves--Analysis of Oil Well Production Data
Using Material Balance Time: Application to Field Cases”. Presented in the
International Petroleum Conference and Exhibition of Mexico.
EIA (2010). “Oil and Gas Lease Equipment and Operating Costs 1994 through 2009”.
September 28, 2010. Washington, D.C.: DOE, Energy Information Administration.
EIA (2011). “Domestic Crude Oil First Purchase Prices by API Gravity”. Washington, D.C.:
DOE, Energy Information Administration. Available online at
http://www.eia.gov/dnav/pet/pet_pri_dfp3_k_a.htm
EPA (2010). “Report of the Interagency Task Force on Carbon Capture and Storage.”
Environmental Protection Agency, Washington, D.C. Available online at
http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-Force-Report-
2010.pdf
EPRI (1999). “Enhanced Oil Recovery Scoping Study”. EPRI, Palo Alto, CA: 1999. TR-
113836. Prepared for EPRI by Advanced Resources International, Inc.
Ford, Jim (2012). “The Texas Clean Energy Project (TCEP)”. Presented by Jim Ford, Vice
President of Summit Power Group, Inc., 6th Annual CO2 Conference, Casper, WY,
July 11th 2012. Slides available online at
http://www.uwyo.edu/eori/resources/co2conf_2012_agenda.html
Holtz et al. (2001). Holtz, Mark H., Peter K. Nance, and Robert J. Finley (2001). “Reduction
of Greenhouse Gas Emissions through CO2 EOR in Texas.” Environmental
Geosciences, 8(3): 187–199.
Höök, Mikael (2009). “Depletion and Decline Curve Analysis in Crude Oil Production”.
Licentiate Thesis, Uppsala University.
Hustad, CW (2004). “Large-scale CO2 sequestration on the Norwegian continental shelf: a
technical, economic, legal and institutional assessment”. Oslo: Norwegian Research
Council.
IEA (2005). International Energy Agency, “From Resources to Reserves: Oil & Gas
Technologies for the Energy Markets of the Future” (2005). Paris, France:
OECD/IEA.
Jeffries (2012). Presentation by Brian Jeffries, Executive Director of the WY Pipeline
Authority (WPA) May 15th, 2012. Data Source: WY Dept. of Revenue, Fiscal Year
2010 Data. Slides available online at
http://www.wyopipeline.com/information/presentations/2012/Wyoming%20Pipeline
%20Corridor%20Initiative%20copy.pdf
Kinder Morgan (KM). Kinder Morgan CO2 Scoping Models, Rena Koinis, Morrow
(modified in 2000) and San Andres (modified in 2001). Available online at
www.kindermorgan.com/business/co2/tech.cfm.
Mullen, Chris (2008). “Grieve Field, Natrona County, WY CO2 Potential”. Presented at the
2nd
Annual CO2 Conference, Casper, WY, July 2008. Slides available online at
http://www.uwyo.edu/eori/resources/08co2conf.html.
Satter et al. (2008). Satter, A., G. M. Iqbal, and J. L. Buchwalter. “Practical Enhanced
Reservoir Engineering: Assisted with Simulation Software” (2008). Pennwell Corp.,
Tulsa, Oklahoma.
Page 43
draft
43
Taber et al. (1997a). Taber, JJ, FD Martin, and RS Seright. “EOR screening criteria revisited-
Part 1: Introduction to screening criteria and enhanced recovery field projects”. SPE
Reservoir Engineering 12, no. 3: 189-198.
———. (1997b). “EOR Screening Criteria Revisited? Part 2: Applications and Impact of Oil
Prices”. SPE Reservoir Evaluation & Engineering 12, no. 3: 199-206.
van 't Veld, Klaas, and Owen R. Phillips (2009). “Pegging Input Prices to Output Prices in
Long-Term Contracts: CO2 Purchase Agreements in Enhanced Oil Recovery”.
Working paper, available online at
http://www.uwyo.edu/owenphillips/papers/co2pegging071509.pdf
———. (2010). “The Economics of Enhanced Oil Recovery: Estimating Incremental Oil
Supply and CO2 Demand in the Powder River Basin”. The Energy Journal, 2010,
vol. Volume 31, issue Number 4, pages 31-56.
Wehner (2009). “A CO2-EOR Update from No Man’s Land – Challenges & Successes”.
Presented by Scott C. Wehner, Whiting O&G Company, at the 2009 CO2 Flooding
Conference in Midland, Texas December 10th
-11th
, 2009.
WHF (2008). Study commissioned by the Wyoming Heritage Foundation, prepared by Booz
Allen Hamilton Inc., “Wyoming Oil and Gas Economic Contribution Study” (2008).
Available online at http://westernenergyalliance.org/wp-
content/uploads/2009/05/WYHF_O_G_Economic_Study_FINAL.pdf
WOGCC (2012). Wyoming Oil & Gas Conservation Commission (WOGCC), State
Production, http://wogcc.state.wy.us/, accessed July 2012.
Wo et al. (2008). Wo, S., Yin, P., Blakeney-DeJarnett B. and Mullen, C.: “Simulation
Evaluation of Gravity Stable CO2 Flooding in the Muddy Reservoir at Grieve Field,
Wyoming”, SPE 113482, presented at the 2008 SPE Improved Oil Recovery
Symposium held in Tulsa, Oklahoma, April 19-23, 2008.
Wo et al. (2009). Wo, S., L. Whitman, and J. Steidtmann. “Estimates of Potential CO2
Demand for CO2 EOR in Wyoming Basins”, SPE 122921, presented at the 2009 SPE
Rocky Mountain Petroleum Technology Conference held in Denver, Colorado,
USA, 14–16 April 2009.
Page 44
draft
44
APPENDIX A Wyoming Miscible CO2-EOR Oil Dataset
The Wyoming miscible CO2-EOR oil dataset contains the necessary inputs for
the WY CO2-EOR Economic Scoping Model, and is meant to provide a
comprehensive view of WY’s CO2-EOR potential. The dataset was built
mainly from public data resources with information on 723 oil field-reservoir
combinations (FRCs) in 415 oil fields (Table A - 1).
All 723 FRCs were pre-screened for miscibility potential similar to the 97
Powder River Basin FRCs analyzed in van ‘t Veld & Phillips (2010) and the
197 state-wide FRCs analyzed in Cook (2011). In contrast to the previous
work, this new dataset includes all potentially miscible units in Wyoming,
rather than being restricted to major basins and fields with 5 MMbbls of
cumulative production.
The collected and estimated data on each FRC describes the geology, oil
characteristics, oil production, water injection history, and the number, type
and status of existing wells. Average values by basin for select FRC
characteristics in the dataset are reported in Table A - 2. The primary data
sources used were the Wyoming Geological Association Symposium and
Field Reports (WGA), the Department of Energy and National Energy
Technology Laboratory (DOE/NETL) TORIS dataset, the Wyoming Oil &
Gas Conservation Commission (WOGCC), and IHS data for the Rocky
Mountain region (IHS).
Collectively, this Wyoming dataset represents over 4.9 billion barrels of
cumulative oil production from an estimated 13.9 billion barrels of original oil
in place (OOIP). These 415 oil fields have roughly 7,119 active production
wells, 1,734 active injection wells, and another 6,255 available well bores.
Although some FRCs are relatively small and unlikely to be profitable when
considered alone, they are included due to the possibility of sharing facilities
with their larger neighbors.
Page 45
draft
45
In cases where multiple observations were found for the same variable, the
sources were either averaged or prioritized based on the age of the observation
and/or perceived reliability of the source. Although every effort was made to
collect data for each variable, there were inevitably missing values that had to
be estimated. A description of each critical variable, the priority ranking of
data sources, and the estimation method used to infill missing data is provided
in Table A-3.
A.1 Physical Screening Criteria
Even before assembling all of the necessary data elements for the economic
analysis, two criteria for rock and fluid properties were used to pre-screen
FRCs for CO2 miscibility potential: (1) oil gravities around 22-48o API, and
(2) minimum miscibility pressure (MMP) below fracture pressure.
Various screening criteria are reported in the literature, such as in Diaz et al.
(1996) and Taber et al. (1997a; 1997b). Taber et al. suggest that FRCs should
be sandstone or carbonate rock with porosity >7%, permeability >10 md,
depth >2,500 ft, and average oil gravity of at least 22o
API. The primary
reasons for the depth and oil gravity limits have to do with the conditions
required for miscibility, namely sufficient pressure and temperatures as well
as the required carbon-chain composition found in light to medium-weight
crude oils.
Preliminary data on depth, temperature and API oil gravity on nearly every
FRC in Wyoming were used to first screen for miscible oil gravities in the
neighborhood of 22o
to 48o API.
28 Secondly, multiple estimates of MMP and
fracture pressure were derived using the range of assembled values for
temperature, oil gravity and depth. In order to be “miscible,” the MMP must
be lower than the fracture pressure of the FRC’s cap rock to ensure the
28
There were 39 FRCs between 20-21.9o API and 20 FRCs between 48.1-49.5
o API that were
included because of their size or by being part of a field with other more favorable FRCs.
Page 46
draft
46
reservoir can safely and legally operate, and only those FRCs that appeared to
be able to satisfy this requirement were kept in the sample.
Normally a third criterion is used, requiring that an FRC have water flood
experience, but this dataset makes no such restriction. A successful water
flood serves as an engineering and economic screen to ensure the FRC is
suitable for flooding, however the presence of water flooding is only noted in
the data without excluding potentially miscible non-water flooded FRCs.
A.2 Estimating Original Oil in Place (OOIP)
Estimating OOIP and forecasting future oil production flows is a critical
component of oil-field development decisions, and the analog model converts
OOIP into HCPV in order to forecast the incremental oil produced.
According to Satter et al. (2008, p.72), the primary method used by 95% of
US oil fields to forecast oil production is “decline curve analysis,” as most are
too small to warrant the cost of sophisticated reservoir modeling. Whether the
oil production potential is identified by decline curve analysis, volumetric
estimates or computer modeling, it is often the case that these results and
other reservoir specific data are kept confidential and not readily available to
the public.
Absent proprietary data or the resources required to carry out detailed
modeling studies on hundreds of units, it becomes necessary for researchers to
characterize each FRC and approximate the feasible range of OOIP estimates
using minimal and possibly noisy data. While some estimates of OOIP are
available in the WGA publications and DOE-TORIS database, it is unclear
how those estimates were determined, and how dated they are, and which
reservoirs are included.
Page 47
draft
47
In order to maintain consistency across the entire database used in the
economic scoping, the OOIP for each FRC was estimated using the
cumulative oil reported by the IHS database and decline-curve analysis on the
WOGCC monthly production data. Because production data is readily
available for nearly all oil units, the decline analysis is preferred to the
volumetric approach, which requires more detailed data observations that are
simply not available for many FRCS.
The oil-production decline path is first used to estimate the ultimate oil
recovery of a project, and then OOIP can be calculated based on assumed
recovery efficiency “i.e.” what percentage of OOIP is ultimately recoverable.
The basic calculation for OOIP would then be as follows:
URR
OOIP = RF
where
URR = ultimate recoverable reserves, stock tank barrels
RF = recovery factor, % of original oil in place.
Calculating ultimate recovery using decline-curve analysis involves plotting
the oil-production history, estimating the rate of production decline to forecast
the future production path, and then adding the remaining recoverable oil to
the existing cumulative recovery. The advantage of decline-curve analysis
using the actual production history is that the method is more or less
independent of the geological uncertainties or engineering choices (Doublet et
al. 1994). These factors come back into play however when trying to
determine the recovery factor (or recovery efficiency), which is the % of
OOIP represented by that ultimate recovery figure. Indeed, the oil’s fluid
conditions, the reservoir’s rock properties, and surface well development are
all considerations for recovery efficiency.
Page 48
draft
48
Decline Curve Analysis for Ultimate Recovery
The three types/shapes of mathematical decline curves commonly used for
analyzing crude production are exponential, hyperbolic, and harmonic, as
proposed by Arps (1945). Following Höök (2009), this study has adopted the
exponential decline curve out of simplicity, and because it yields more
conservative estimates of ultimate recoverable reserves (URR).29
Under the
assumption of an exponential decline, the URR is calculated as follows:
0 0
0
00
URR Q
Q
tq e dt
q
(4)
where
0
0
Q cumulative oil recovered, stb
last oil production level, stb/month, and
monthly exponential decline rate, fraction/month
q
The cumulative recovery and level of oil production in the last month ( 0q )
were determined using production data from the IHS, WGA and WOGCC
data sources. However, the constant monthly decline rate ( ) had to be
estimated by hand, based on a visual analysis of the OGC’s monthly
production history. While this makes the decline-rate estimates subject to the
individual judgment of the researcher, technical issues make it difficult to
29
A detailed overview of the mathematical properties of all three types of decline can be
found in Chapter 11 of Satter et al. (2008). The exponential decline characteristic of
underestimating URR is mentioned as a disadvantage by Höök (2009), but is attractive here
by being a more conservative estimate. The hyperbolic and harmonic curves are able to
generate flatter curves in the tails, which can be common in mature, depleted fields that are
waterflooding in secondary recovery.
Page 49
draft
49
calculate these rates in a purely computational fashion. These include
interruptions and outliers in the data series arising from reporting issues,
periods of well maintenance or other operational issues. Thus, it is up to the
researcher to visually examine the production history and fit an exponential
declin-curve to the data that seems representative of the unit’s decline rate.
Except for oil units with limited oil production since 1978 both the author and
one to three other research assistants independently estimated the decline
rates. Finally, a point estimate of the decline rate was obtained by averaging
the decline estimates across researchers for each FRC. To ensure conservative
estimates of URR, these average decline rates were also truncated at a
minimum rate of 0.32% per month to match the 3.9% production-weighted
annual decline rate of giant land-based oil fields as reported in Höök (2009).
Lastly, for FRCs with insufficient data or unidentifiable decline rates, the rate
was merely assumed to be 50% per month, two remaining months of
production, as they are already depleted to their economic shutdown point.
Recovery Factor (RF)
Having determined URR with decline analysis, the remaining consideration
for estimating OOIP is the recovery factor (RF): the percentage of OOIP
represented by URR. As mentioned earlier, the RF for primary recovery is
between 5-20%, and the global average of mature fields under both primary
and secondary recovery is about 35%. The American Petroleum Institute
(API) and others have published correlation equations for estimating RF;
however, these calculations typically involve detailed data on oil fluid
properties, gas-oil ratios, initial and terminal reservoir pressure, etc. ARI
(2006) was faced with similar data limitations and used a simple linear
regression of known recovery factors on oil gravity as a way to estimate
unknown RFs. The ARI equation, RF = (Oil Gravity + 5) /100 , would give
fairly high estimates of RF in many cases.
Page 50
draft
50
For example, IEA (2005) says that achieving RFs above 40% usually requires
advanced techniques, but the ARI equation would produce these estimates for
all oil gravities of 35o
API and higher. While recovery factor is positively
related to oil gravity (high oil gravity is associated with lighter oils, which are
easier to recover), the relationship is unlikely to be linear in most cases.
Water production and injection history along with information from the
WOGCC and WGA publications were used to determine whether each FRC
had engaged in a secondary (waterflood) production stage. In order to produce
conservative estimates of OOIP, and absent accurate estimates of RF for all
oil units, it was assumed that oil units still producing in the primary recovery
stage have an RF of 25%, and that fields producing in the secondary recovery
stage have an RF of 40%.
Page 51
draft
51
Table A - 1 Selected Data Statistics
Wyoming Basin Cumulative
Production (MMbbls)
Number of
Oil Fields
Field-Reservoir
Combinations
(FRCs)
FRCs with Water
Injection
FRCs
w/Natural
Water Drive
FRCs w/o
Injection or Water
Drive
Big Horn Basin 2,168 47 136 74 40 22
Denver Basin 29 7 10 6 1 3
Green River Basin 261 42 87 38 15 34
Hanna Basin 1 1 1 0 1 0
Laramie Basin 53 4 11 7 3 1
Overthrust Belt 20 2 2 0 1 1
Powder River Basin 1,960 282 400 240 65 95
Wind River Basin 419 30 76 25 26 25
Totals 4,910 415 723 390 152 181
Table A - 2 Average Values of Select Data by Basin
Wyoming Basin Depth (ft)
Min.
Miscibility
Pressure (psi)
Net Oil Pay
Thickness (ft) Temperature (F)
Oil Gravity
(API)
Monthly Production
Decline Rate
Big Horn Basin 5,753 2,069 122 122 29 3.78%
Denver Basin 8,001 1,988 251 158 36 2.28%
Green River Basin 6,841 1,641 240 152 43 2.51%
Hanna Basin 7,239 1,634 20 145 41 1.44%
Laramie Basin 3,741 1,515 39 111 35 1.45%
Overthrust Belt 11,160 1,513 87 148 46 2.30%
Powder River Basin 7,865 2,225 52 159 34 1.84%
Wind River Basin 6,687 1,847 100 136 34 2.85%
All FRCs 7,170 2,070 94 148 34 2.39%
Page 52
draft
52
Table A - 3. Relevance and Estimation Method for Selected Data Components
Data Point Relevance Data Sources (ranked) Missing Data/Estimation Method
Decline Rate of Oil
Production
(fraction per month)
Used for OOIP estimation
and existing production
path.
WOGCC
Each decline rate was estimated by multiple researchers
fitting an exponential decline curve to the WOGCC
production data and then averaged.
Original Oil in Place
(OOIP, stb)
Can be used to calculate
HCPV, and thus the EOR
response.
Decline Curve Analysis
using IHS and WOGCC
production data.
The monthly production decline and IHS cumulative
production were used to determine ultimate recovery.
OOIP was estimated assuming a 40% recovery factor for
secondary recovery projects and 25% for primary only.
Water Injection History /
Water Drive Status
Used to estimate the
recovery factor and
injection rates.
WOGCC and WGA Data
Water production and injection history, FRCs identified as
secondary recovery by the WOGCC, and WGA
information on drive mechanism.
Average Net Pay
Thickness (ft)
Can be used in the
volumetric calculation of
HCPV.
(1) DOE TORIS (2) IHS
Perforations (3) WGA
Estimated values based the average difference between
upper and lower well perforations in the IHS data.
Reservoir Surface Area
(acres)
Can be used in the
volumetric calculation of
HCPV, and determines the
number of wells required.
IHS Well Locations
Surface areas for each FRC were estimated based on the
surface locations and coverage of existing wells using the
IHS latitude and longitude coordinates.
Reservoir Temperature (oF)
Used to calculate MMP
and the CO2 Formation
Volume Factor (BCO2).
(1) DOE TORIS (2) WGA
(3) EORI Database
Missing values estimated from geothermal gradients on
the four major basins using a linear regression of
temperature on depth. Smaller basins were estimated as
the median of the large basin gradients.
API Oil Gravity Used to screen for miscible
oil characteristics.
(1) WOGCC (2) DOE
TORIS (3) IHS
Average oil gravity for post-78 production was available
in WOGCC data for 721 of the 723 FRCs. The remaining
2 FRCs had gravity recorded in the IHS data.
Page 53
draft
53
Data Point Relevance Data Sources (ranked) Missing Data/Estimation Method
Depth (feet)
Used to estimate drilling
costs, fracture pressure and
in some cases temperature.
Average depth of wells in the
IHS production data.
Fracture pressure was estimated using the average depth of
the upper well perforations, and drilling costs are based on
the average total depth.
Minimum Miscibility
Pressure
(MMP, psi)
The minimum reservoir
operating pressure to
ensure CO2 miscibility.
Correlation Estimates Estimated from oil gravity and reservoir temperature using
an API correlation equation for MMP.30
Fracture Gradient
(psi/ft of depth)
MMP must be less than
fracture pressure .
WOGCC Fracture Gradient
Program where available.
Missing fracture gradient values were assumed to be the
average value of 0.68.
Oil Formation Volume
Factor (FVF, Bo, fraction )
Used to convert between
surface barrels (stb) and
reservoir barrels (rb).
(1) DOE –TORIS (2)
Correlation Estimates Vasquez-Beggs correlation.
CO2 Formation Volume
Factor
(CO2-FVF, BCO2, rb/Mcf)
Used to convert reservoir
barrels of supercritical CO2
into Mcfs.
Equation of state (EOS) Calculated using the Span-Wagner Equation of State
(EOS) for CO2 based on reservoir temperature and MMP.
Historical Injection Rates
(barrels/well-month)
Can be used to estimate
feasible injection rates. IHS monthly water injection
Estimated as the median of an FRCs water injection
history. Substantial variability in these histories.
Well Counts
Used to determine drilling
required and well-based
capital and operating costs.
WOGCC Well Status Active producers, injectors, shut-in wells and temporarily
abandoned wells were included.
Lease Ownership &
County Location
Used to estimate royalties
and property taxes. WOGCC Mineral Types Average of other units in the field.
30
0.870220.744206 4.688927399358
15.988API
MMP Temp
Page 54
draft
54
APPENDIX B Basin Level Scoping Results by Analog Model
Table B - 1 All Analogs – Total Incremental Oil Produced (MMbbls): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl31 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 302-907 421-943 446-957 290-904 399-938 436-951 178-894 386-937 415-943
Denver Basin 0-1 1-1 0-1 0-1 0-1 0-1
Green River Basin 6-48 19-74 31-81 6-48 11-74 21-80 6-30 11-73 19-76
Hanna Basin 0-1 0-1 0-1 0-1 0-1 0-1 0-1
Laramie Basin 0-16 0-18 7-18 0-14 0-17 6-18 0-13 0-17 0-18
Overthrust Belt 0-14 0-14 0-14
Powder River Basin 35-318 70-406 119-436 20-278 61-363 97-419 20-217 45-346 68-387
Wind River Basin 40-160 69-171 78-173 39-159 53-166 71-173 31-154 46-164 67-167
Statewide Total 383-1,449 579-1,627 681-1,681 356-1,402 524-1,560 631-1,657 234-1,309 488-1,538 569-1,593
# of Units (20% IRR) 34-145 78-208 114-249 26-125 62-186 92-232 16-100 54-169 78-203
31
Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 55
draft
55
Table B - 2 All Analogs – Cumulative CO2 Purchase Demand (Bcfs): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl32 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 2,895-
5,042
4,188-
5,134
4,513-
5,196
2,750-
5,022
3,906-
5,106
4,336-
5,166
1,636-
4,955
3,730-
5,101
4,070-
5,122
Denver Basin 0-7 6-7 0-7 0-7 0-7 0-7
Green River Basin 23-249 155-484 337-523 23-249 66-484 179-511 23-116 64-477 153-486
Hanna Basin 0-4 0-4 0-4 0-4 0-4 0-4 0-4
Laramie Basin 0-94 0-99 66-99 0-84 0-96 63-99 0-80 0-94 0-99
Overthrust Belt 0-125 0-125 0-125
Powder River Basin 317-1,825 669-2,268 1,202-
2,420
172-1,560 572-2,035 940-2,323 168-1,200 410-1,933 645-2,148
Wind River Basin 379-882 687-953 781-961 368-878 507-899 702-961 289-854 424-886 653-899
Statewide Total 3,615-8,095
5,699-9,071
6,905-9,334
3,313-7,793
5,051-8,631
6,220-9,195
2,115-7,205
4,629-8,501
5,522-8,764
# of Units (20% IRR) 34-145 78-208 114-249 26-125 62-186 92-232 16-100 54-169 78-203
32
Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 56
draft
56
Table B - 3 All Analogs –Total Incremental Oil Recovered (MMbbls): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl33 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 378-915 436-953 447-964 348-909 426-939 438-956 183-897 403-935 430-954
Denver Basin 0-3 0-4 0-4 0-4 0-4 0-4 0-4
Green River Basin 6-48 17-74 32-88 6-42 16-74 29-77 6-24 8-50 17-76
Hanna Basin 0-1 0-1 0-1 0-1 0-1 0-1
Laramie Basin 0-15 6-21 7-23 0-13 6-19 6-23 0-13 0-17 6-22
Overthrust Belt 0-13 0-14 0-13 0-14 0-14
Powder River Basin 50-357 124-450 155-530 41-313 115-434 139-465 30-273 89-401 122-454
Wind River Basin 50-159 71-169 75-175 40-157 69-165 72-171 31-146 59-165 70-167
Statewide Total 484-1,498 655-1,685 716-1,799 435-1,434 632-1,649 684-1,710 249-1,354 560-1,571 646-1,691
# of Units (20% IRR) 41-152 97-214 128-260 33-124 86-193 113-236 19-100 60-173 98-215
33
Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 57
draft
57
Table B - 4 All Analogs – Cumulative CO2 Purchase Demand (Bcfs): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl34 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 3,624-
5,122
4,330-
5,233 4,536-5,294
3,315-
5,086
4,160-
5,159
4,353-
5,240
1,691-
5,008
3,891-
5,135
4,214-
5,233
Denver Basin 0-21 0-21 0-21 0-21 0-21 0-21 0-21
Green River Basin 22-258 138-489 344-590 22-214 124-489 311-496 21-85 40-258 132-489
Hanna Basin 0-4 0-4 0-0 0-4 0-4 0-4 0-4
Laramie Basin 0-90 63-124 74-129 0-81 57-109 65-129 0-81 0-95 62-126
Overthrust Belt 0-126 0-126 0-126 0-126 0-126
Powder River Basin 458-2,029 1,214-
2,538 1,572-3,007 367-1,773
1,111-
2,441
1,385-
2,599 253-1,535 839-2,254
1,187-
2,535
Wind River Basin 481-886 705-943 754-993 370-872 670-904 713-951 288-819 560-904 684-908
Statewide Total 4,585-
8,407
6,449-
9,476
7,280-
10,165
4,073-
8,026
6,121-
9,253
6,827-
9,565
2,253-
7,527
5,331-
8,671
6,279-
9,442
# of Units (20% IRR) 41-152 97-214 128-260 33-124 86-193 113-236 19-100 60-173 98-215
34
Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 58
draft
58
Table B - 5 KM-San Andres35
– Total Incremental Oil (MMbbls): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl36 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 907 943 957 904 938 951 894 937 943
Denver Basin 1 1 1 1 1 1
Green River Basin 48 74 81 48 74 80 30 73 76
Hanna Basin 1 1 1 1 1 1 1
Laramie Basin 16 18 18 14 17 18 13 17 18
Overthrust Belt 14 14 14
Powder River Basin 318 406 436 278 363 419 217 346 387
Wind River Basin 160 171 173 159 166 173 154 164 167
Statewide Total 1,449 1,627 1,681 1,402 1,560 1,657 1,309 1,538 1,593
# of Units (20% IRR) 145 208 249 125 186 232 100 169 203
35
Permian Basin Denver San Andres dimensionless curves from the Kinder Morgan spreadsheet models.
36 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 59
draft
59
Table B - 6 KM-San Andres37
– Cumulative CO2 Purchases (Bcfs): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl38 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 5,042 5,134 5,196 5,022 5,106 5,166 4,955 5,101 5,122
Denver Basin 7 7 7 7 7 7
Green River Basin 249 484 523 249 484 511 116 477 486
Hanna Basin 4 4 4 4 4 4 4
Laramie Basin 94 99 99 84 96 99 80 94 99
Overthrust Belt 125 125 125
Powder River Basin 1,825 2,268 2,420 1,560 2,035 2,323 1,200 1,933 2,148
Wind River Basin 882 953 961 878 899 961 854 886 899
Statewide Total 8,095 9,071 9,334 7,793 8,631 9,195 7,205 8,501 8,764
# of Units (20% IRR) 145 208 249 125 186 232 100 169 203
37
Permian Basin Denver San Andres dimensionless curves from the Kinder Morgan spreadsheet models.
38 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 60
draft
60
Table B - 7 KM-San Andres39
– Total Incremental Oil (MMbbls): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl40 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 915 953 964 909 939 956 897 935 954
Denver Basin 3 4 4 4 4 4 4
Green River Basin 48 74 88 42 74 77 24 50 76
Hanna Basin 1 1 1 1 1 1
Laramie Basin 15 21 23 13 19 23 13 17 22
Overthrust Belt 13 14 13 14 14
Powder River Basin 357 450 530 313 434 465 273 401 454
Wind River Basin 159 169 175 157 165 171 146 165 167
Statewide Total 1,498 1,685 1,799 1,434 1,649 1,710 1,354 1,571 1,691
# of Units (20% IRR) 152 214 260 124 193 236 100 173 215
39
Permian Basin Denver San Andres dimensionless curves from the Kinder Morgan spreadsheet models.
40 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 61
draft
61
Table B - 8 KM-San Andres41
– Cumulative CO2 Purchases (Bcfs): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl42 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 5,122 5,233 5,294 5,086 5,159 5,240 5,008 5,135 5,233
Denver Basin 21 21 21 21 21 21 21
Green River Basin 258 489 590 214 489 496 85 258 489
Hanna Basin 4 4 4 4 4 4
Laramie Basin 90 124 129 81 109 129 81 95 126
Overthrust Belt 126 126 126 126 126
Powder River Basin 2,029 2,538 3,007 1,773 2,441 2,599 1,535 2,254 2,535
Wind River Basin 886 943 993 872 904 951 819 904 908
Statewide Total 8,407 9,476 10,165 8,026 9,253 9,565 7,527 8,671 9,442
# of Units (20% IRR) 152 214 260 124 193 236 100 173 215
41
Permian Basin Denver San Andres dimensionless curves from the Kinder Morgan spreadsheet models.
42 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 62
draft
62
Table B - 9 KM-Morrow43
– Total Incremental Oil (MMbbls): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl44 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 785 804 815 782 795 812 779 795 809
Denver Basin 1 1 1 1 1 1
Green River Basin 61 63 67 40 63 64 37 63 64
Hanna Basin 1 1 1 1 1 1
Laramie Basin 13 14 15 12 14 15 12 14 14
Overthrust Belt 12 13 12
Powder River Basin 262 302 350 224 289 313 191 279 299
Wind River Basin 136 144 148 136 140 148 134 139 143
Statewide Total 1,257 1,341 1,409 1,194 1,304 1,364 1,153 1,292 1,330
# of Units (20% IRR) 128 167 209 118 152 186 101 142 168
43
Postle-Morrow dimensionless curves from Kinder Morgan projected forward to 2.98 HCPVs of cumulative production.
44 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 63
draft
63
Table B - 10 KM-Morrow45
– Cumulative CO2 Purchases (Bcfs): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl46 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 4,377 4,428 4,468 4,364 4,381 4,447 4,345 4,381 4,431
Denver Basin 6 6 6 6 6 6
Green River Basin 410 414 435 212 414 414 184 414 414
Hanna Basin 3 3 3 3 3 3
Laramie Basin 78 81 86 69 81 83 69 81 81
Overthrust Belt 108 116 108
Powder River Basin 1,502 1,713 1,969 1,258 1,641 1,763 1,065 1,582 1,682
Wind River Basin 758 808 829 758 770 829 745 763 779
Statewide Total 7,125 7,562 7,912 6,661 7,297 7,654 6,409 7,231 7,397
# of Units (20% IRR) 128 167 209 118 152 186 101 142 168
45
Postle-Morrow dimensionless curves from Kinder Morgan projected forward to 2.98 HCPVs of cumulative production.
46 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 64
draft
64
Table B - 11 KM-Morrow47
– Total Incremental Oil (MMbbls): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl48 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 790 805 827 785 805 819 784 801 810
Denver Basin 3 3 3 3 2 3
Green River Basin 61 64 65 38 64 65 38 62 65
Hanna Basin 1 1 1 1
Laramie Basin 13 14 19 12 14 19 12 14 14
Overthrust Belt 12 12 12 12 12
Powder River Basin 301 365 391 269 343 375 238 317 350
Wind River Basin 137 144 150 134 144 146 126 140 146
Statewide Total 1,302 1,408 1,467 1,237 1,384 1,439 1,199 1,336 1,401
# of Units (20% IRR) 138 178 216 118 168 195 104 150 179
47
Postle-Morrow dimensionless curves from Kinder Morgan projected forward to 2.98 HCPVs of cumulative production.
48 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 65
draft
65
Table B - 12 KM-Morrow49
– Cumulative CO2 Purchases (Bcfs): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl50 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 4,390 4,427 4,543 4,359 4,427 4,480 4,359 4,403 4,433
Denver Basin 18 18 18 18 12 18
Green River Basin 410 420 420 195 420 420 195 410 420
Hanna Basin 3 3 3 3
Laramie Basin 78 81 106 69 78 106 69 78 81
Overthrust Belt 108 108 108 108 108
Powder River Basin 1,731 2,060 2,192 1,514 1,937 2,101 1,334 1,796 1,960
Wind River Basin 758 805 849 741 801 808 704 767 808
Statewide Total 7,366 7,922 8,240 6,879 7,788 8,045 6,661 7,466 7,832
# of Units (20% IRR) 138 178 216 118 168 195 104 150 179
49
Postle-Morrow dimensionless curves from Kinder Morgan projected forward to 2.98 HCPVs of cumulative production.
50 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 66
draft
66
Table B - 13 LSTP-S.Wo51
– Total Incremental Oil (MMbbls): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl52 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 620 636 650 613 630 643 608 625 632
Denver Basin 0.83 0.84 0.82 0.84 0.82 0.83
Green River Basin 48 50 52 32 49 50 30 49 50
Hanna Basin 0.47 0.48 0.47 0.47 0.46 0.47
Laramie Basin 9 11 12 9 11 11 9 11 11
Overthrust Belt 10 9 9
Powder River Basin 179 230 251 165 223 239 145 213 234
Wind River Basin 108 115 118 107 110 117 106 109 116
Statewide Total 964 1,044 1,094 927 1,025 1,072 897 1,008 1,053
# of Units (20% IRR) 115 154 189 110 146 176 101 140 170
51
Lost Soldier-Tensleep dimensionless curves from Wo et al. (2009) projected forward to 2.98 HCPVs of cumulative production.
52 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 67
draft
67
Table B - 14 LSTP-S.Wo53
– Cumulative CO2 Purchases (Bcfs): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl54 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 3,533 3,760 3,928 3,433 3,646 3,803 3,353 3,553 3,668
Denver Basin 5 5 5 5 4 5
Green River Basin 296 317 336 156 307 321 144 304 310
Hanna Basin 3 3 3 3 3 3
Laramie Basin 51 64 69 49 62 65 49 61 63
Overthrust Belt 87 79 76
Powder River Basin 1,007 1,345 1,505 907 1,284 1,409 781 1,205 1,353
Wind River Basin 608 686 721 593 628 696 576 612 677
Statewide Total 5,496 6,179 6,652 5,137 5,934 6,381 4,903 5,741 6,153
# of Units (20% IRR) 115 154 189 110 146 176 101 140 170
53
Lost Soldier-Tensleep dimensionless curves from Wo et al. (2009) projected forward to 2.98 HCPVs of cumulative production.
54 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 68
draft
68
Table B - 15 LSTP-S.Wo55
– Total Incremental Oil (MMbbls): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl56 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 626 644 655 618 637 646 611 629 640
Denver Basin 2.41 2.45 0.82 2.43 0.81 2.40
Green River Basin 47 51 52 30 50 51 29 49 51
Hanna Basin 0.48 0.47 0.47
Laramie Basin 9 11 12 9 11 11 9 11 11
Overthrust Belt 9 9 9 9 9 9
Powder River Basin 226 280 305 203 263 298 186 249 281
Wind River Basin 109 115 118 108 114 117 100 112 115
Statewide Total 1,017 1,114 1,154 967 1,085 1,136 935 1,059 1,110
# of Units (20% IRR) 129 175 199 119 167 191 108 154 182
55
Lost Soldier-Tensleep dimensionless curves from Wo et al. (2009) projected forward to 2.98 HCPVs of cumulative production.
56 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 69
draft
69
Table B - 16 LSTP-S.Wo57
– Cumulative CO2 Purchases (Bcfs): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl58 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 3,676 3,924 4,097 3,570 3,804 3,933 3,486 3,691 3,820
Denver Basin 14 15 5 15 5 14
Green River Basin 292 332 345 147 326 337 144 311 328
Hanna Basin 3 3 3
Laramie Basin 54 67 69 52 62 68 52 61 66
Overthrust Belt 81 84 79 82 79 81
Powder River Basin 1,319 1,684 1,873 1,155 1,563 1,794 1,048 1,456 1,669
Wind River Basin 631 703 743 620 682 721 570 661 689
Statewide Total 5,971 6,804 7,230 5,543 6,521 6,952 5,301 6,264 6,671
# of Units (20% IRR) 129 175 199 119 167 191 108 154 182
57
Lost Soldier-Tensleep dimensionless curves from Wo et al. (2009) projected forward to 2.98 HCPVs of cumulative production.
58 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 70
draft
70
Table B - 17 LSTP-van ‘t Veld59
– Total Incremental Oil (MMbbls): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl60 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 302 421 446 290 399 436 178 386 415
Denver Basin 1
Green River Basin 6 19 31 6 11 21 6 11 19
Hanna Basin
Laramie Basin 7 6
Overthrust Belt
Powder River Basin 35 70 119 20 61 97 20 45 68
Wind River Basin 40 69 78 39 53 71 31 46 67
Statewide Total 383 579 681 356 524 631 234 488 569
# of Units (20% IRR) 34 78 114 26 62 92 16 54 78
59
Lost Soldier-Tensleep dimensionless curves from van ‘t Veld & Phillips (2010) projected forward to 2.98 HCPVs of cumulative production.
60 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 71
draft
71
Table B - 18 LSTP-van ‘t Veld61
– Cumulative CO2 Purchases (Bcfs): 50-Acre Pattern, 15% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl62 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 2,895 4,188 4,513 2,750 3,906 4,336 1,636 3,730 4,070
Denver Basin 6
Green River Basin 23 155 337 23 66 179 23 64 153
Hanna Basin
Laramie Basin 66 63
Overthrust Belt
Powder River Basin 317 669 1,202 172 572 940 168 410 645
Wind River Basin 379 687 781 368 507 702 289 424 653
Statewide Total 3,615 5,699 6,905 3,313 5,051 6,220 2,115 4,629 5,522
# of Units (20% IRR) 34 78 114 26 62 92 16 54 78
61
Lost Soldier-Tensleep dimensionless curves from van ‘t Veld & Phillips (2010) projected forward to 2.98 HCPVs of cumulative production.
62 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 72
draft
72
Table B - 19 LSTP-van ‘t Veld63
– Total Incremental Oil (MMbbls): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl64 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 378 436 447 348 426 438 183 403 430
Denver Basin
Green River Basin 6 17 32 6 16 29 6 8 17
Hanna Basin
Laramie Basin 6 7 6 6 6
Overthrust Belt
Powder River Basin 50 124 155 41 115 139 30 89 122
Wind River Basin 50 71 75 40 69 72 31 59 70
Statewide Total 484 655 716 435 632 684 249 560 646
# of Units (20% IRR) 41 97 128 33 86 113 19 60 98
63
Lost Soldier-Tensleep dimensionless curves from van ‘t Veld & Phillips (2010) projected forward to 2.98 HCPVs of cumulative production.
64 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 73
draft
73
Table B - 20 LSTP-van ‘t Veld65
– Cumulative CO2 Purchases (Bcfs): 80-Acre Pattern, 12.5% HCPV Inj/Year
CO2 Contract $0.50 + 1.0% $0.50 + 1.5% $0.50 + 2.0%
WTI Oil Price/bbl $80.00 $110.00 $140.00 $80.00 $110.00 $140.00 $80.00 $110.00 $140.00
~WY Oil Price/bbl66 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96 $65.46 $95.46 $125.96
~CO2 Price/Mcf $1.15 $1.45 $1.75 $1.48 $1.93 $2.38 $1.81 $2.41 $3.01
Big Horn Basin 3,624 4,330 4,536 3,315 4,160 4,353 1,691 3,891 4,214
Denver Basin
Green River Basin 22 138 344 22 124 311 21 40 132
Hanna Basin
Laramie Basin 63 74 57 65 62
Overthrust Belt
Powder River Basin 458 1,214 1,572 367 1,111 1,385 253 839 1,187
Wind River Basin 481 705 754 370 670 713 288 560 684
Statewide Total 4,585 6,449 7,280 4,073 6,121 6,827 2,253 5,331 6,279
# of Units (20% IRR) 41 97 128 33 86 113 19 60 98
65
Lost Soldier-Tensleep dimensionless curves from van ‘t Veld & Phillips (2010) projected forward to 2.98 HCPVs of cumulative production.
66 Assumes an average discount of $14.54 to WTI. Slight differences will occur between individual FRCs after adjusting for API oil gravity.
These slight differences also hold for the ~CO2 price, which is tied to the oil price.
Page 74
draft
74
APPENDIX C Field Location & Incremental Oil by Basin67
Figure C - 1 Big Horn Basin
67
All GIS maps were generated by Klaas van ‘t Veld, Associate Professor, Economics & Finance,
University of Wyoming utilizing CO2-EOR scoping results supplied by the author.
Page 75
draft
75
Figure C - 2 Green River Basin
Page 76
draft
76
Figure C - 3 Powder River Basin
Page 77
draft
77
Figure C - 4 Southeast Wyoming (Denver Basin, Hanna Basin, Laramie Basin, Shirley Basin)
Page 78
draft
78
Figure C - 5 Wind River Basin