A Comparative Study of North America's Largest Shale Gas Reservoirs

Recent estimates of recoverable gas from unconventional shale reservoirs in the US exceed .5 qcf (quadrillion cubic feet) (USGS 2009) with potential for another .1 qcf in Canada (NEB). North American shale gas reservoirs currently rank as 6 of the largest 22 global gas fields, based upon estimated recoverable reserves, with average recovery factors of about 20%. Innovations in horizontal well drilling and completions, supported by 3D seismic, microseismic, FMI/FMS and other measurements, are unlocking North American gas supplies for the decades ahead. However, volatile commodity markets and dramatic variability in well production rates make economic shale gas production a challenge. This large well production variability, even within the same field, challenges our intuition about the simple, consistent nature of shale formations and the gas within.

With a motivation to understand why "all gas shales are not created equal" – Transform Software and Services performed a study integrating published data, type logs, accessible seismic and microseismic data along with 5 years of experience across most significant North American shale gas basins. Our tabulation of shale gas reservoir characteristics and well log analysis highlights key production differentiators.  Eighteen different reservoir properties were compared across eight major North American shale reservoirs: Marcellus, Eagle Ford, Haynesville, Horn River, Barnett, Utica, Woodford, and Bakken in an attempt to determine reservoir similarities and difference as well as what factors most influence reservoir production. 

Article Navigation:
1. Shale Reservoir Summaries - Profiles, maps, settings, stratigraphy, and well log crossplots
        1. Barnett - Fort Worth Basin
        2. Eagle Ford - South Texas
        3. Haynesville - Texas/Louisiana
        4. Horn River - N.E. British Columbia
        5. Marcellus - Appalachia
        6. Bakken - Williston Basin
2. Shale Reservoir Comparison - Crossplots and analysis of shale reservoir characteristics
3. What We Learned - Reservoir similarities, differences, and what makes a good shale gas reservoir?
4. Transform Software and Shale Gas Reservoirs - Products, services, and research

Barnett - Fort Worth Basin

Reservoir Profile

Age: Mississippian, 340 MYA
Lithology: Siliceous Mudstone
Total Area Size (sq mi): 50,000
Total Gas (tcf): 327
GIP (bcf/sq mi): 150
Producable Gas (tcf): 50
Depth (feet): 7,500
Thickness (feet): 300
Horizontal Well Cost ($M): 2.8
Average EUR: 2.65
Pressure (psi): 4,000
Temperature (F): 200
Ro: 2.0
TOC (%): 4.5
Porosity (%): 6.0
Matrix Permeability (nD): 250
Pressure Gradient (psi/ft): .526
Clay Content (%): 45
Silica/Calcite/Carbonate (%): 55
Adsorbed Gas (%): 35

Reservoir Summary

Any understanding of shale gas reservoirs must start with the pioneering work of Mitchell/Devon in the Barnett Shale of the Fort Worth Basin in North/Central Texas. Beginning with vertical wells and a visionary concept in 1981, the Barnett has become the proving ground for efficient horizontal well drilling and multi-stage completions. With USGS estimates of 327 tcf of gas in place and 50 tcf recoverable, the Barnett has emerged as the benchmark for all shale gas plays. While reservoir properties range considerably, the Mississippian Barnett Shale averages 300 feet in thickness, at an average depth of about 7500 feet, with average porosities of 6% and low permeabilities of 250 nanodarcies. Average well production reaches 2.65 bcf, with initial production rates of up to 13 mmcf per day. Seismic data is generally of moderate quality, but is essential for tracking the key bounding horizons and identifying karst "collapse chimneys" which degrade individual well production. Also worth noting is that vitrinite reflectance averages 2% in the Barnett, but drops to the "oil window" in the northern basin.

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Eagle Ford - South Texas

Reservoir Profile

Geologic Age: Cretaceous, 100 MYA
Lithology: Bituminous Shales
Total Area Size (sq mi): 1,350
Total Gas (tcf): 84
GIP (bcf/sq mi): 200
Producable Gas (tcf): 9.0
Avg. Well Depth (feet): 11,500
Thickness (feet): 250
Horizontal Well Cost ($M): 4.8
Average EUR: 5.5
Pressure (psi): 5,200
Temperature (F): 335
Ro: 1.5
TOC (%): 4.5
Porosity (%): 11
Matrix Permeability (nD): 1,100
Pressure Gradient (psi/ft): 0.65
Clay Content (%): 8.0
Silica/Calcite/Carbonate (%): 87
Adsorbed Gas (%): 20
Average IP: 6.2

Reservoir Summary

One of the newest shale gas plays is the Cretaceous Eagle Ford, located in South Texas. It is early for USGS gas estimates, but individual wells are expected to produce 5.5 bcf, from depths of about 11,500 feet and 250 foot formation thickness. Typical porosities of 11% and permeability in excess of 1 microdarcy are bringing on wells at initial production rates in the mid-teen mmcf per day. Seismic and microseismic data is of excellent quality in the Eagle Ford play and is useful for drilling and completions planning.

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Haynesville - Texas/Louisiana

Reservoir Profile

Age: Upper Jurassic, 170 MYA
Lithology: Argillaceous/Calcareous
Total Area Size (sq mi): 9,000
Total Gas (tcf): 717
GIP (bcf/sq mi): 175
Producable Gas (tcf): 251
Avg. Well Depth (feet): 12,000
Thickness (feet): 225
Horizontal Well Cost ($M): 7.0
Average EUR: 6.5
Pressure (psi): 8,500
Temperature (F): 340
Ro: 2.2
TOC (%): 3.0
Porosity (%): 6.0
Matrix Permeability (nD): 658
Pressure Gradient (psi/ft): .95
Clay Content (%): 27
Silica/Calcite/Carbonate (%): 53
Adsorbed Gas (%): 18
Average IP: 10

Reservoir Summary

The Jurassic Haynesville(/Bossier) tight gas formations of Eastern Texas and Western Louisiana has become a "star" of US unconventional resources - with USGS estimates of ~720 tcf total gas and ~250 tcf producable. While deeper (~12,000 feet) and thinner (~225 feet) than the Barnett, the Haynesville has seen outstanding initial productions rates in excess of 30 mmcf per day and estimated ultimate well recoveries of 6.5 bcf. Higher porosities, approaching 9 %, and moderate permeabilities of about 650 nanodarcies, couple with pressures in excess of 8000 psi to drive good well performance. Deeper wells and both high temperature (~340 deg F) and high pressure environments result in horizontal well costs in the range of $7M, well over twice the cost of Barnett wells.

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Horn River - N.E. British Columbia

Reservoir Profile

Age: Upper Devonian, 370 MYA
Lithology: Brittle Shale
Total Area Size (sq mi): 5,000
Total Gas (tcf): 370
GIP (bcf/sq mi): 150
Producable Gas (tcf): 47
Avg. Well Depth (feet): 8,800
Thickness (feet): 450
Horizontal Well Cost ($M): 7.0
Average EUR: 7.5
Pressure (psi): 4,800
Temperature (F): 160
Ro: 2.5
TOC (%): 2.5
Porosity (%): 3.0
Matrix Permeability (nD): 230
Pressure Gradient (psi/ft): 0.6
Clay Content (%): 30
Silica/Calcite/Carbonate (%): 70
Adsorbed Gas (%): 34
Average IP: 7.3 

Reservoir Summary

In contrast to the Marcellus, the Horn River Basin is located at the most northern extreme of the Canadian province of British Columbia - approximately 750 miles north of the US border of Washington State. The Horn River is also unique in that it contains multiple prospective shales including the Carboniferous- Devonian Muskwa, Otter Park, Klua and Evie formations. Prospectivity of these formations vary across the Horn River Basin, leading to alternating or combined completions across the play. The Canadian National Energy Board estimates that the Horn River contains 370 tcf of total gas, 47 tcf of which is recoverable. The Horn River is a reasonable facsimile of the Barnett, with similar porosities and permeabilities and well depths of about 8800 feet and pay zone thicknesses of 450 feet, on average. Initial production rates are approaching 20 mmcf per day in the best wells, although it is early to estimate initial decline rates and overall well recovery levels.

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Marcellus - Appalachia

Reservoir Profile

Age: Middle Devonian, 385 MYA
Lithology: Argillaceous Mudstone
Total Area Size (sq mi): 95,000
Total Gas (tcf): 1,500
GIP (bcf/sq mi): 200
Producable Gas (tcf): 356
Avg. Well Depth (feet): 7,000
Thickness (feet): 350
Horizontal Well Cost ($M): 3.5
Average EUR: 3.75
Pressure (psi): 4,000
Temperature (F): 130
Ro: 1.25
TOC (%): 3.25
Porosity (%): 8.0
Matrix Permeability (nD): 1,000
Pressure Gradient (psi/ft): 0.4
Clay Content (%): 50
Silica/Calcite/Carbonate (%): 50
Adsorbed Gas (%): 50

Reservoir Summary

If size and location matter, then the Middle Devonian Marcellus of the Appalachia may be the gem of all shale gas plays. Covering an area of about 100,000 square miles and spanning Pennsylvania, the Virgnia's and parts of New York State, the Marcellus is the largest of the identified North American shale gas plays, underlying the largest gas market. The USGS estimates a total of 1500 tcf of gas in place in the Marcellus, with about 350 tcf being recoverable. Comparable to the Barnett in depth (~7000 feet) , thickness (~350 feet) and porosity (~8%) - permeabilities reaching 1 microdarcy are driving early estimated recovery of 3.75 bcf per well. Initial production rates have reached nearly 25 mmcf per day, with faults, fractures and variable shale and carbonate lithology driving considerable variability in well production.

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Bakken - Williston Basin

Reservoir Profile

Age: Uper Devonian/Lower Mississippian, 360 MYA
Lithology: Sandstone/Siltstone/Carbonite
Total Area Size (sq mi): 200,000
Total Gas (tcf): 945.10
GIP (bcf/sq mi): 28.30
Producable Gas (tcf): 20.66
Avg. Well Depth (feet): 10,000
Thickness (feet): 150
Horizontal Well Cost ($M): 5.5
Average EUR: 1.41
Pressure (psi): 5,600
Temperature (F): 140
Ro: 0.9
TOC (%): 10.0
Porosity (%): 5.0
Matrix Permeability (nD): 10,000
Pressure Gradient (psi/ft): 0.5
Clay Content (%): 5.0
Silica/Calcite/Carbonate (%): 95
Adsorbed Gas (%): 0.0

Reservoir Summary

The Mississippian/Devonian Bakken formation is predominantly a low-permeability oil reservoir, with associated gas, spanning North Dakota, Montana and the Canadian provinces of Saskatchewan and Manitoba. The USGS estimates the Bakken holds in excess of 300 billion barrels of oil, with about 3.65 billion barrels being recoverable. The formation is typically 150 feet thick, at depths of nearly 10,000 feet, while porosities range around 7% and permeabilities are about 75 microdarcies. On average, wells are projected to produce 500,000 total barrels of oil. Horizontal wells are multi-stage completions are essential for economic production in the Bakken, with microseismic measurements supporting generally north/south well orientations.

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Shale Reservoir Comparisons

A detailed search of USGS and other sources revealed key reservoir parameters for North American shale gas plays.  Data crossplots highlight key similarities and differences between shale gas reservoirs.  Figure 1 shows a map of North American shale gas reservoirs where the red circles represent gas in place for each of the major reservoirs in this study.  Figure 2 shows the gas in place rankings of the eight reservoirs with the Marcellus and Eagle Ford ranking first with an average of 200 bcf/sq mi.  Figures 3 and 4 show the average well depth and thickness of the different reservoirs.  Wells in the Haynesville (12,000 ft) and Eagle Ford (11,500 ft) are typically the deepest while the Marcellus (350 ft) and Barnett (300 ft) have the greatest thickness.

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Crossplotting the characteristics of the shale gas reservoirs against gas in place illustrates the relationship between each attribute and the gas production of the reservoir.  Eighteen different characteristics were analyzed, the following nine crossplots represent the most meaningful results with the number in the upper left representing the correlation between the attribute and GIP.

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What We Learned

What Matters Most?

Tbe results of the shale reservoir crossplots reveal that thickness (.842), permeability (.679), porosity (.637), temperature (.562), adsorbed gas (-.435), and vitrinite reflectance (.404) have the highest correlation to gas in place production.  These characteristics seem to be the greatest contributors to what makes a good shale gas reservoir.

Reservoir Similarities

• Most shale basins fall in the Devonian-Mississippian fairway
• Economic shale reservoirs range between 150-450 feet
• Devonian-Mississippian shale reservoir wells average 7,000-10,000 feet
• Commercial shale basins generally range between .2 and 1.1 microD
• Shale plays are generally gas-focused
• Shale plays generally have a single economic target

Reservoir Differences

• Some of the best shale gas basins are Mesozoic and lie on the younger side of major thrust belts (Eagle Ford, Haynesville)
• Some of the best shale gas basins have deeper well depths of 10,000-13,000 feet (Eagle Ford, Haynesville)
• Increasingly, shale plays are being developed as joint gas/oil assets (Barnett, Eagle Ford)
• Shale plays range from relatively flat with minimal faulting (Haynesville) to highly faulted and structural (Woodford, Marcellus, Eagle Ford) to other features like karst collapse chimneys (Barnett)
• Some shale plays have multiple, adjacent levels for development (Bakken)
• Difference in thickness, permeability and porosity drive gas-in-place differences between shale gas plays

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Transform Software and Shale Reservoirs

This study was performed using seismic, microseismic, well log, and crossplot analysis tools available in Transform's TerraSuite software package.  Whether it is fracturing in the Woodford, karst collapse chimneys in the Barnett, natural fracturing in the Marcellus, or clay/silica content in many places - Transform's seismic, microseismic, and data analysis tools have proven invaluable for companies involved with shale gas reservoir production.  As a result, Transform software is currently used in many of North America's top shale gas reservoirs.

Learn more about Transform's Software Suite, Interpretive Services, and work in the Barnett.  Also, contact us for a list of references or questions: This e-mail address is being protected from spambots. You need JavaScript enabled to view it .

Acknowledgements

• Huge thanks to anonymous data donors and bp, Devon, CGGVeritas, and Global Geophysical Services
• Many sources were used for data in this study including USGS, NEB, GSC, BCEM, WVGS, Hart's Unconventional Gas Center, American Oil and Gas Reporter, Oil and Gas Journal, and more

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