Discussion of North American Natural Gas Development 

and Documentation of the Gas Resource Base Included 

in ICF Modeling Work for EPA 

ICF International 

August 31, 2010 

The objectives of this paper are to present recent trends in North American gas 

resource development, to document the development of the ICF North American 

gas resource base used in the recent EPA modeling and forecasting. 

Unconventional Gas Development in the U.S. 

Unconventional (low permeability) reservoirs now account for about one-half of 

U.S. gas production. For decades, conventional high permeability gas 

reservoirs were developed in regions such as the Gulf Coast, Gulf of Mexico, and 

the Mid-Continent. However, recent decades saw a sharp decline in onshore 

new field discoveries, and well recoveries were declining. The deepwater Gulf of 

Mexico was the only bright spot in the Lower-48 for new conventional 

discoveries. 

However, North America has vast deposits of in-place unconventional natural 

gas resources in the form of tight (low permeability) gas, coalbed methane (coals 

where the coalbed is both the source and reservoir for gas), and shale gas 

(organic shale formations where the shale is both the source and reservoir for 

gas). These resources are now being extensively developed and U.S. 

production is increasing. Shale gas has now emerged as a major, long-term 

energy resource due to the widespread occurrence of high quality organic shales 

in the U.S. and Canada. 

Shale gas production in the U.S. dates to the 1800s with the early development 

of the Appalachian Devonian Shale in West Virginia, Kentucky, Pennsylvania, 

and New York. This eventually involved the drilling of thousands of shallow low 

productivity vertical wells where production in many cases was unrecorded. The 

wells were often stimulated with explosives. 

The 1980s saw the development of the Michigan Basin Antrim Shale. This was 

also the time of the initial development of the Barnett Shale in the Fort Worth 

Basin of North Texas – a play that was to expand into, by most definitions, the 

largest and most prolific natural gas play in U.S. history. 

Tight gas sandstone production in the U.S. dates to the 1940s with the 

development of the San Juan Basin in northwestern New Mexico and 
2 

southwestern Colorado. Tight gas reservoirs were also developed starting in the 

1950s and 1960s in Appalachia. 

Coalbed methane production in the U.S. began in a significant way in the 1980s 

with the Fruitland coalbeds of the San Juan Basin in New Mexico and Colorado. 

Coalbed methane production in the San Juan increased rapidly in subsequent 

years, reaching 2 Bcf per day (Bcfd) by 1995. The Alabama Warrior Basin 

coalbed methane production also started in the 1980s and saw more modest 

growth to about 300 million cubic feet per day (MMcfd). Then came the 

development of the Powder River Basin in eastern Wyoming. Production from 

that play started in the mid-1990s and achieved one Bcfd by 2003. Coalbed 

methane production also started in Alberta several years ago and production now 

exceeds 650 MMcfd. 

Recent Trends in Gas Production 

Figure 1 summarizes the recent trends in Lower-48 unconventional gas 

production. The production rate has increased from 1,000 Bcf per year to almost 

10,000 Bcf per year since 1970. Overall, most of the growth has been in tight 

gas. However, shale gas has accounted for much of the recent growth. 

Figure 1: Lower-48 Unconventional Gas Production 

0

2,000

4,000

6,000

8,000

10,000

12,000

19701972197419761978198019821984198619881990199219941996199820002002200420062008

Bcf Per Year

Coalbed

Shale

Tight
3 

The U.S. currently has five large-scale, active shale gas plays. These are the 

Barnett Shale of North Texas, the Fayetteville Shale in Arkansas, the Woodford 

Shale in eastern Oklahoma, the Haynesville Shale of northern Louisiana and 

East Texas, and the Marcellus Shale in Appalachia. 

Other Lower-48 shale plays with increasing activity include the Eagle Ford shale 

along the Texas Gulf Coast, the Woodford Shale in western Oklahoma, the 

Bossier in Louisiana, and several Rocky Mountain formations including the 

Gothic Shale in the Paradox Basin. The Bakken oil shale play in North Dakota is 

experiencing rapid development. A portion of the Fort Worth Barnett play is 

being developed for crude oil as well. 

In Canada, active shale plays include the Horn River Basin, the Cordova 

Embayment, and the Montney siltstone/shale in BC. Eastern Canada has seen 

exploration activity in shale formations in New Brunswick and Nova Scotia. 

Figure 2 focuses on U.S. shale gas production. This chart illustrates the 

tremendous growth in gas production from the Fort Worth Barnett Shale. While 

production growth from the Barnett is slowing, other shale gas plays such as the 

Fayetteville, Haynesville, and Marcellus are growing rapidly. 

Figure 2: Lower-48 Shale Gas Production 

0

500

1,000

1,500

2,000

2,500

3,000

2000200120022003200420052006200720082009

Bcf per Year

N. LA and E. TX

Mid-Continent

Fort Worth Basin

Michigan-IL

Appalachia
4 

Recent Trends in Drilling Activity 

Over the past decade, gas well completion activity in the U.S. has shifted heavily 

toward unconventional gas development. The initial surge was in the Fort Worth 

Basin Barnett Shale and in tight gas development in the Rockies and Texas. 

Within the past few years, operators have been able to use the technology 

developed for the Barnett Shale to open new shale plays around the country. 

Activity has surged, particularly in North and East Texas, Oklahoma, 

Pennsylvania, and Arkansas. 

Recent activity peaked in 2008 but declined greatly in late 2008 and 2009, with 

the onset of the recession. In 2010, activity has rebounded, but overall rig counts 

at a level of about 1,500 rigs are only about two-thirds of prior levels. 

Perhaps the most significant aspect of rig activity has been the shift away from 

vertical drilling to horizontal and directional drilling. This trend is illustrated in 

Figure 3. Currently, over two-thirds of rig activity is directed toward either 

horizontal or directional drilling, while only one-third is vertical drilling. Horizontal 

wells are mostly shale gas wells and directional wells are mostly tight gas wells. 

Figure 3: Recent Rig Activity Trends 

U.S. Rig Activity by Type - Vertical vs. Horizontal (Baker-Hughes)

0

200

400

600

800

1,000

1,200

1/4/20083/4/20085/4/20087/4/20089/4/2008

11/4/2008

1/4/20093/4/20095/4/20097/4/20099/4/2009

11/4/2009

1/4/20103/4/20105/4/20107/4/2010

Rigs

Vertical

Directional

Horizontal

Also, a recent trend that has emerged in 2010 is a greatly increased emphasis on 

crude and natural gas liquids production from several unconventional plays. 

These include the Bakken oil shale in North Dakota, the Eagle Ford shale in 

south Texas, the oil portion of the Barnett, and the Granite Wash tight sand play.
5 

ICF Gas Resource Base Analysis 

ICF has been involved in North American gas and oil resource base studies for 

over 20 years. The work has included resource assessment, characterization, 

and economic analysis, and has included both conventional and unconventional 

resources and modeling. In the early years, unconventional gas assessments 

relied heavily upon published information from the U.S. Geological Survey, which 

has assessed many tight gas and coalbed methane plays, and some shale plays 

and this effort is onging.1 ICF developed a map-based cell structure to compile 

information on depth, well recovery, production parameters, drilling costs, and 

operating costs. 

Starting about 2005, ICF began studying several of the major U.S. shale gas 

plays in detail. This included geologic mapping of play area, depth, organics 

maturity, and thickness. We determined basic shale volumetrics, and by using 

relationships derived in part from the Fort Worth Basin Barnett Shale, ICF 

developed estimates of gas in place and recovery for the major plays. This 

information was collected on the basis of 36 square mile units or “townships.” 

Within the past two years, ICF has employed more sophisticated approaches to 

shale and tight gas assessment. These involve geographic information systems 

and detailed mapping. In addition, new models have been developed to 

approach the resource assessment using reservoir engineering methods and 

accounting for recovery as a function of well spacing. With shale and tight gas 

plays in particular, any comprehensive analysis must account for infill drilling 

potential and the characteristics of the reservoir that control well recovery as a 

function of well spacing. Over 30 plays have been evaluated by using this 

approach. The resource base assumed for the EPA modeling is a modified 

version of that developed in this recent ICF work. 

Figure 4 shows the supply regions for this study. Table 1 summarizes the 

resource base assumptions used in the model. The Lower-48 conventional 

resource is 313 Tcf, the recoverable shale gas resource base is 921 Tcf, tight 

gas is 321 Tcf and coalbed methane is 74 Tcf. Canadian shale gas is assessed 

at 509 Tcf. 

It should be noted that ICF’s assessment of Marcellus Shale potential has been 

reduced as applied in the EPA modeling from the original geologically-based 

analysis because of the potential for reduced access due to state regulations. In 

general, ICF believes that industry will experience more difficulty in accessing 

portions of the Marcellus than has been the case with plays such as the Barnett 

and Fayetteville. 

 

1 U.S. Geological Survey National Oil and Gas Assessment, 2010 

http://energy.cr.usgs.gov/oilgas/noga/
6 

Table 2 compares the shale gas resource base assumptions for the EPA work to 

other significant assessments in recent years. The first column of the table 

documents the ICF shale gas resource. While the individual play assessments 

are not shown here, the regional comparisons are shown. All of the plays listed 

in the table are included in the current ICF assessment. 

An important observation from this table is that with the past few years, many 

new shale plays have been added to the assessment. Thus, the changes from 

older assessments involve both changes within plays and the addition of new 

plays. To a large extent, the number of successful new plays being announced 

has declined over the past year, although recently Encana announced a new 

shale play in the Michigan Basin - the Collingwood Shale. In the Rockies, 

technologies are currently being developed that will likely unlock a number of 

shale plays. The Colingwood and these potential new plays from the Rockies 

have not been included in the ICF resource assessment because they are so 

recent. 

Figure 4: ICF Supply Regions Map 
7 

Table 1: ICF Resource Base Assumptions for EPA Modeling 

Lower 48 Resources

Total

Offshore Conventional

Conventional Shale Tight Coalbed Total Non-Associated associated

Northeast 15.4 254.8 33.7 9.5 313.4

Gulf Coast 133.9 433.1 59.6 4.3 630.9 

Midcontinent 54.4 133.9 4.6 9.6 202.5

Southwest /1 19.2 61.3 6.1 0.0 86.6

Rockies/Williston 84.0 37.9 205.1 49.8 376.8

West Coast 6.4 0.3 11.5 0.7 18.9

L-48 Total 313.3 921.3 320.6 73.9 1,629.1 137.1 145.1 1,911.3

Alaska Resources 153.6

Total U.S. 2,064.9

Canada Resources

Western 121.4 508.8 10.3 27.4 667.9

Eastern Offshore 71.8

Mackenzie Delta 32.9

Total Canada 154.3 508.8 10.3 27.4 71.8 8.1 780.7

Onshore Non-associated Other 
Table 2: ICF Gas Resource Base Assumptions for EPA Modeling 

Tcf recoverable

2010 2009 2008 ICF INGAA 2008 

ICF Assessment ICF Foundation PGC 2009 2002-08 2010 

Region Basin for EPA Assessment Assessment Assessment EIA USGS ARI 

United StatesAppalachia Appalachian Vertical Low Pressure 17.0 30.6 (with Marcell.) 13.1 12.2 

Appalachian Marcellus 289.7 63.0 228.0 38.3 not assessed 200.0 Appalachian Huron 20.0 20.0 (with Marcell.) not assessed not assessed not assessed wNY Utica not assessed not assessed (with Marcell.) not assessed not assessed not assessed ntotal 245.3 326.7 113.6 228.0 51.4 12.2 200.0 

Texas and LA Haynesville Shale 102.2 31.0 112.3 71.6 not assessed 130.0 Gulf Coast Bossier Shale not assessed not assessed (with Haynes.) not assessed not assessed not assessed

Eagle Ford Shale not assessed not assessed 24.5 not assessed not assessed not assessedPearsall Shale not assessed not assessed not assessed not assessed not assessed not assessedTotal 433.1 102.2 31.0 136.8 71.6 0.0 130.0 

Warrior Basin Floyd and Conasauga Shales not assessed not assessed not assessed not assessed not assessed not assessed Michigan- MIchigan Antrim 4.0 4.0 5.9 10.0 7.5 not assessed Illinois Illinois New Albany 3.2 3.2 5.4 3.1 3.8 not assessed 

Cincinnati Arch 2.3 2.3 not assessed 1.1 0.0 not assessedtotal 9.5 9.5 9.5 11.3 14.2 11.3 

North Texas Fort Worth Barnett 46.3 107.4 107.0 59.3 59.7 26.2 39.0 Mid-Continent Arkoma - Arkansas Fayetteville 86.3 58.0 110.5 29.2 not assessed 50.0 

Arkoma - Oklahoma Woodford 61.9 53.0 (with Fayette.) 19.7 not assessed 34.0 Arkoma Moorefield (AR) not assessed not assessed (with Fayette.) not assessed not assessed not assessed nArkoma Caney (OK) not assessed not assessed (with Fayette.) not assessed not assessed not assessed nAnadarko Woodford not assessed not assessed 2.1 not assessed not assessed not assessed nCentral OK Fold Belt Woodford not assessed not assessed not assessed 7.1 not assessed not assessed ntotal 133.9 148.2 111.0 112.6 56.0 84.0 

Permian Basin Barnett Shale 10.0 10.0 3.9 not assessed 35.1 not assessed 

Woodford Shale with Barnett with Barnett with Barnett not assessed not assessed not assessedtotal 15.0 10.0 10.0 3.9 0.0 35.1 

Williston Williston Niobrara with tight with tight not assessed 3.9 not assessed not assessed 

Williston Bakken Oil Play not assessed not assessed not assessed not assessed not assessed not assessed total 1.9 0.0 0.0 0.0 3.9 0.0 

Rockies Green River Vermillion Baxter Shale not assessed not assessed not assessed not assessed not assessed not assessed

Green River Hilliard Shale not assessed not assessed not assessed not assessed not assessed not assessedGreen River Lewis and Mowry with tight with tight not assessed not assessed not assessed not assessed Paradox Gothic Shale 1.0 1.0 not assessed not assessed not assessed not assessed nParadox Cane Creek Shale not assessed not assessed not assessed not assessed not assessed not assessedUinta Mancos Shale not assessed not assessed 60.2 not assessed not assessed not assessedSan Juan Lewis with tight with tight 4.5 10.5 not assessed not assessed Denver Niobrara with tight with tight not assessed not assessed not assessed not assessed Raton Basin Pierre 2.0 2.0 not assessed not assessed not assessed not assessed ntotal 36.0 3.0 3.0 64.7 10.5 0.0 

Pacific Onshore San Joaquin Basin McClure 0.3 0.3 0.3 not assessed not assessed not assessed not assessed nOther 0.0 0.0 0.0 0.0 0.0 Lower 48 total 921.3 707.3 385.4 616.6 267.2 84.8 453.0 Alaska not assessed not assessed not assessed not assessed not assessed not assessed nU.S. total 707.3 385.4 616.6 267.2 84.8 453.0 
9 

Another aspect of the ICF resource assessment work involves crude oil and 

natural gas liquids. The volume of natural gas liquids that is produced with the 

gas can have a major impact on economics. This is evidenced by the shift 

toward liquids-rich plays this year. The ICF analysis has included a map-based 

analysis of gas “wetness” in major shale plays that is a function of shale gas 

“maturity.” Interestingly, the analysis shows that the U.S. has a very large 

volume of undeveloped crude oil and NGLs that are associated with 

unconventional shale and tight gas plays. 

Producer Expenditure Trends 

While the total number of gas wells currently being completed is much lower than 

it was in 2007 and 2008, industry outlays are very high because of the increased 

capital cost per well. Each horizontal shale well may range in cost from $2 to 

$10 million or more, depending on the location and well configuration. This well 

cost is many times that of a conventional vertical gas well along the Gulf Coast or 

in the Mid-Continent. The higher cost is due to several factors, including the 

drilling of the horizontal lateral and the cost of stimulating the well, which may 

require up to ten or more fracture stages. 

The annual Oil and Gas Journal survey of upstream industry expenditures has 

documented a huge increase in outlays in recent years. 2

 For example, upstream 

U.S. expenditures were approximately $292 billion in 2008. This compares to 

only $84 billion in 2004. Most of the increase was due to higher drilling and 

completion outlays. Much of the increased activity in shale well development has 

been undertaken by the Top 20 E&P operators in the U.S. since significant 

capital outlays are required for shale well development. Many of those operators 

have continued to increase their expenditures for shale well development despite 

significant downturn in the prices for natural gas during the past couple years. 

 

2 Oil and Gas Journal, March 1, 2010.