Wyoming’s Miscible CO2 Enhanced Oil Recovery Potential ... miscible co2...Wyoming Enhanced and...

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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.

mailto:[email protected]

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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.

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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

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($/M

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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

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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).

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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.

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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.

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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

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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

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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.

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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.

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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


YES

NO

Policy Makersand

CO2 Devolpers

Detailed Reservoir Modeling and

Simulation

Delay...

YES

NO

Development Plan and

Detailed Economic AnalysisYES

NO Business-As-Usualor


Business-As-Usualor


Final Contractingand

ImplementationYES

NO

Delay...

Business-As-Usualor


(i) (ii) (iii) (iv) (v) (vi)

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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.

http://www.kindermorgan.com/business/co2/tech.cfm

http://www.netl.doe.gov/

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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/ .

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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.

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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

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il P

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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%

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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%

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Wasson-Denver San Andres Dimensionless Analog

Location: West TexasSource: KM San Andres Model

CO2 Injected

Water Injected

CO2 Produced Incremental Oil

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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

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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)

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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.

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Figure 7

Figure 8

12.39%

-0.25

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1.75

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2.25

2.50

Cu

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(H

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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

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d/I

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)


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

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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.

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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

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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.

http://eadiv.state.wy.us/creg/WyInsight.pdf

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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)

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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

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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

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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

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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.

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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.

http://www.ihs.com/info/cera/ihsindexes/index.aspx

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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.

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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.

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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.

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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.

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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.

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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.

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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


Hanna Basin 3 3 3 3 3 3

Laramie Basin 51 64 69 49 62 65 49 61 63


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




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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

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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.

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

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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.

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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

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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.

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41

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http://wogcc.state.wy.us/

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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.

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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.

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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.

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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.

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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.

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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.

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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%.

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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


Green River Basin 261 42 87 38 15 34


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%

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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.

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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

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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.


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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


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



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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


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



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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


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



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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



Hanna Basin 1 1 1 1 1 1 1

Laramie Basin 16 18 18 14 17 18 13 17 18



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.



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– 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



Hanna Basin 4 4 4 4 4 4 4

Laramie Basin 94 99 99 84 96 99 80 94 99


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




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– 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



Laramie Basin 15 21 23 13 19 23 13 17 22

Overthrust Belt 13 14 13 14 14


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




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– 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



Laramie Basin 90 124 129 81 109 129 81 95 126



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




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Table B - 9 KM-Morrow43


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




Laramie Basin 13 14 15 12 14 15 12 14 14



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.



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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




Laramie Basin 78 81 86 69 81 83 69 81 81



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




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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



Hanna Basin 1 1 1 1

Laramie Basin 13 14 19 12 14 19 12 14 14



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




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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


Hanna Basin 3 3 3 3

Laramie Basin 78 81 106 69 78 106 69 78 81



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

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Table B - 13 LSTP-S.Wo51


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


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



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




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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




Laramie Basin 51 64 69 49 62 65 49 61 63


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

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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


Hanna Basin 0.48 0.47 0.47

Laramie Basin 9 11 12 9 11 11 9 11 11



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

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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


Hanna Basin 3 3 3

Laramie Basin 54 67 69 52 62 68 52 61 66



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




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Table B - 17 LSTP-van ‘t Veld59


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


Hanna Basin

Laramie Basin 7 6

Overthrust Belt


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.



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71



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


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

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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


Hanna Basin

Laramie Basin 6 7 6 6 6

Overthrust Belt


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

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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


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

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APPENDIX C Field Location & Incremental Oil by Basin67

Figure C - 1 Big Horn Basin

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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.

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Figure C - 2 Green River Basin

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Figure C - 3 Powder River Basin

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Figure C - 4 Southeast Wyoming (Denver Basin, Hanna Basin, Laramie Basin, Shirley Basin)

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Figure C - 5 Wind River Basin

Wyoming’s Miscible CO2 Enhanced Oil Recovery Potential ... miscible co2...Wyoming Enhanced and...

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