AbstractThe current state of the art understanding of shale gas plays is based on �eld data from one or two areas and very limited core data. A common viewpoint is the “sweet spot” for shale gas production is at thermal maturities in the gas window. This is based on the sharp drop in Barnett Shale productivity at the northwestern end of Newark East �eld, near the 1.2% Ro line. The explanation is: 1) insu�cient gas is generated at lower maturity levels to �ll the shale; and 2) oil in the pore system blocks the movement of gas. Both lab data and modeling suggest substantial gas is co-generated with oil and data from low maturity shale gas plays suggest shales can become fully saturated with gas down to the base of the oil window. Relative permeability has never been measured in shales and this idea is based on analogy to conventional reservoirs.

A second common notion is gas is stored as both a free gas phase and as an adsorbed phase on kerogen or clays. We determine e�ective porosity using helium and subtract this from a total sorption isotherm to determine the partitioning between free and adsorbed gas. Because helium is a much smaller molecule than methane, the helium porosity is certainly greater than the pore space available to methane and consequently the adsorbed frac-tion will be underestimated and porosity overestimated. This problem was never seen in sandstones because the pore sizes are so much larger than the molecular sizes of the gases.

The third major problem is transport mechanisms. Most companies view shales like extremely tight sandstones where mass transport through micropores and tiny pore throats move gas from the matrix to fractures to the well bore. Measured matrix permeabilities of shales range from 500x10-6 mD to 1x10-9 mD. Considering its molecular size and the fact that all shales must contain some capillary bound water, the e�ective permeability to methane is probably still lower. This suggests there must be a di�ferent pathway that allows methane to move from the shale matrix into fractures. We may think we understand how gas moves through shale, but hard data are lacking.

1. There is more gas generated at low thermal maturities than you think.

2. Gas shales may not need to reach the gas window to completely charge the system with methane; all available storage sites could be filled by peak oil generation.

3. Cracking liquid hydrocarbons to gas will not add to the gas retained in the source rock itself if it is already fully saturated with methane. Oil cracking probably results in substantial explusion of gas from the source rock.

4. We could be overestimating effective porosity to methane in shales because of the way we perform routine core analysis. The problem propagates to log models when we calibrate our log calculations to core.

5. If we overestimate porosity, then the partitioning of gas between porosity and the adsorbed state is wrong and we do not compute gas-in-place correctly. Potentially, the error is large.

6. Effective permeability to methane in shales is extremely low- far lower than required to explain the flow rates we observe in many shale plays. Perhaps gas is not moving through pores and pore throats in a manner analo-gous to sandstone reservoirs and measured permeabilities are misleading.

7. We need to rethink the entire process of methane charge, storage, and transport in these ultra-low permeability rocks if we expect to effectively explore for new resources.

Key take-home points of this poster presentation:

“Paradigms?We ain‘t got no paradigms.We don’t need no stinking paradigms!“

“Paradigms?We ain‘t got no paradigms.We don’t need no stinking paradigms!“

Robert M. Clu�, The Discovery Group Inc., Denver, ColoradoKeith W. Shanley, The Discovery Group Inc., Denver, ColoradoMichael A. Miller, BP America Production Co., Houston, Texas

Three things we thoughtwe understood about shale gas,but were afraid to ask . . .

FEET

0 53,278

PALO PINTO PARKER TARRANT

WISEJACKDENTON

GOR=50

GOR=5000

Montgomery et al, 2005

Isoreflectance map, Fort Worth basin and Bend Arch region. Contour interval R0 = 0.2%. Data from Humble Geo-chemical Services, Inc. Map interpreta-tion modified from Pollastro et al. (2004a).

Cardott, 2006

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Heating Rate = 5°C/m.y.Surface Temp. = 15°C

S.R. Age = 80 Ma

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Kerogen Hydrocarbons Hydrocarbons-to-Gas Vitrinite Reflectance

Kerogen to Oil-Gas Cal. Oil-to-Gas TR Cal. Sum Cal.%VR (alt.y-axis)

Calculated Rates ofKerogen and Oil Conversion

using a 1°C/m.y. constant heating rate model

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1701501301109070 190

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0.75% Vitrinite Reflectance

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37%47%

3%

Jarvie, 2004

Kerogento

Hydrocarbons

CumulativeHydrocarbons

Oilto

Gas

Jarvie, 2004

Lewan, 2002

Statement of the problemn It is widely held that a vitrinite re�ectance (Ro) of 1.2% or higher is required

for signi�cant shale gas production (Jarvie, 2004) n The northwest limit of Newark East �eld (Ft Worth basin Barnett play) approxi-

mately correlates to the base of the gas window and a sharp drop in GOR.

n Reduced gas productivity north of this line is thought to re�ect a three-phase relative permeability e�ect “blocking” gas movement through the shale.

So what?n Are thermogenic shale gas plays

delimited by a 1.2% Ro line?

Discussion pointsn Kinetic modeling and hydrous pyrolysis experiments indicate substantial gas is generated in the oil window (Ro 0.6 –

1.0%), with liquid hydrocarbons. 80% of the total gas has been generated by an Ro of 1.2%. n Oil cracks to gas at higher thermal maturities than 1.2% Ro, and is insigni�cant until 2.3% Ro or higher (20% transforma-

tion ratio) (Lewan, 2002). This is higher than the maximum Ro of 1.9% attained in the Ft Worth basin Barnett play (Montgomery et al, 2005), but within the range of the Arkoma basin Woodford play (Ro 0.5 to 4.85%; Cardott, 2006).

n Desorbed gas data in low maturity plays such as the New Albany (Illinois basin) and Ohio Shale (Appalachian basin) are close to saturated gas values. Su�cient gas is co-generated with oil to �ll the shale to capacity prior to entering the gas window.

n To our knowledge no relative permeability measurements in shale have been reported.

What is the timing of gas charge andhow mature does a shale need to beto “�ll up the tank”?

CH4He

As pore throats approach the mo-lecular diameter of methane, helium might pass into adjacent pores where methane is blocked. A layer of bound ions makes the constriction still tighter.

Relative sizes of helium and methane molecules based on Van der Waals radii. Helium will fill small interstices in the po-rosity that are unavailable to methane.

Adsorbed gas vs. free gas example

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total sorption7% porosity, free gas7% porosity, adsorbed gas2% porosity, free gas2% porosity, adsorbed gas

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depth = 1500 ftpressure = 650 psimatrix density ~ 2.65 g/c3Gc at 0% TOC = 4.3 scf/tonimplied effective porosity = 0.8%

example data from Reeves, 2000, West Coast PTTC presentation

Discussion pointsn Plug porosities are less than as received or “gas-�lled”

porosity, which are less than crushed rock dry poros-ity.

n Molecular size of helium is <60% that of methane.

n Shales have high bound water content and extreme-ly small pore throats.

n Cross-plots of TOC vs. desorbed gas typically inter-sect 0% TOC axis at a low GIP value, implying small e�ective methane porosity in absence of kerogen.

So what?n Play concepts de�ned by free gas are directly related

to porosity estimates.

n If we overestimate porosity and the free gas compo-nent, we are underestimating adsorbed gas.

Statement of the problemn Most workers view gas shales as a triple porosity system: gas in pore space (aka free gas or compression gas), adsorbed

gas on clays and kerogen, and absorbed (solution) gas in the kerogen or bitumen. n Partitioning between these three storage sites is determined by conventional porosity measurements and adsorption iso-

therm experiments. n Core porosity is used to calibrate log models with typical values in the 0.5 to 10% range.

n Core porosity is determined through Boyles Law using helium as the penetrant gas. Samples are crushed and sieved to reduce the diameter of the particles that helium has to penetrate for valid porosity measurements. The e�ect of the ir-regular particle surfaces on the measured porosity is small.

n Helium is a small molecule (D ~ 2.5 Å; Van der Waals b = 0.0237 L/mol ) and can pass through ultra-small pore throats that may not be accessible to larger molecules such as methane (D ~ 4.3 Å; Van der Waals b = 0.04278 L/mol).

n Helium determined porosity is potentially greater than the e�ective methane porosity (Bustin et al., 2006). This is analo-gous to total porosity vs. e�ective porosity in log analysis.

n The magnitude of porosity overestimation depends on pore size distributions which are poorly constrained. The porosity error could exceed a factor of 2X.

How is methane stored in shales?The nature of porosity

1 2 3 4

Measured Shale Properties

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Proprietary Data

Barnett Simulation (GRI 96/305)

FMC 78 (GRI 95/496)

FMC 69 (GRI 95/496)

Rocky Mountain Low-permeability Reservoirs - Relative Permeability to Gas(adjusted for overburden stress and corrected for slippage) (n = 681)

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y = 30.368x - 38.064

R2 = 0.9925

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plug permeability 16 µDcrushed rock matrix permeability 6 nDplug porosity 1.3%"gas filled" porosity 4.33%total porosity 5.55%

KRG @ 4000 NOB

Byrnes data

modified from Shanley et al., 2004

Gas3D models2000 ft horizontal well with multiple fracs

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Basic model parameters300 ft zone heightXf = 400 ftfrac spacing 25 to ~200 ftKfrac = 30 mDporosity = 2%drainage area 55 ac

20 yrs

Frac model2000 foot horizontal leg10 to 80 fractures with Xf = 400 ft, K frac = 30 mDcross fractures parallel to horizontal well 400 ft on either side of wellrectangular drainage area 2640 ft x 900 ft = 55 net acresmatrix permeability varied between runs

40 fracs, 0.1 nD

80 fracs, 0.1 nD

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10 fracs, 500 nD

40 fracs, 0.1 nD

80 fracs, 0.1 nD

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10 fracs, 500 nD

Statement of the problemn Permeability in shales is thought to be analogous to very tight sandstones.

n Plug permeabilities are too small to measure, desorption vs. time plots yield apparent e�ective permeabilities of 10’s of nanoDarcies (nD), and pulse decay permeabilities on powdered samples (“GRI method”) range from 1E-6 to 1E-15 D (1 μD to 1 femtoDarcy), with an average near 1E-11 (10 pD).

n Single-well numerical modeling requires gas permeabilities 2 to 4 orders of magnitude greater than observed to match �ow rates and ultimate recoveries in the Barnett Shale.

So what?n Some other, higher permeability pathway through

shale seems necessary.

n Conventional air permeability measurements are not meaningful.

n “Net pay” could be less than we think and only those portions of the shale section with “high” permeability (in a relative sense) are contributing.

n Characterizing the extent of the feeder fracture system might be critical.

Discussion pointsn The volume expansion of liquid oil to gas through

thermal cracking has been invoked as a mechanism to create a pervasive microfracture network. This net-work might explain the high deliverability of shales such as the Barnett (Ft Worth basin) and Woodford (Arkoma basin).

n Microfracture-like features are observed in thin sec-tion, but the low measured plug permeabilities do not support the presence of pervasive microfracture networks.

n The logical disconnect between absolute permeabil-ity and productivity is only made worse by relative permeability in water wet shales.

n Some have proposed di�usive �ow (e.g. Knudsen dif-fusion) is more important than mass �ow, but be-cause gas di�usion is expected to be slower this idea is usually discounted.

How does methane move through shales?The nature of permeability

REFERENCES CITEDBustin, R Marc, Ross, D., and G. Chalmers, 2006, Rethinking methodologies of characterizing gas in place in gas shales (abstract): AAPG Annual Mtg,

Houston, http://www.searchanddiscovery.com/documents/2006/06088houston_abs/abstracts/bustin.htm

Cardott, B., 2006, Frontier gas-shale plays of Oklahoma: presentation at Mid-Continent Coalbed Methane and Gas Shale Symposium II, Tulsa, Oct. 23rd, http://www.ogs.ou.edu/pdf/Oklahoma_Gas%20Shales_2006_CMB_Symposium_Modi�ed.pdf

Hill, N.C, and D.E. Lancaster, 1995, Reservoir characterization of the Clough area, Barnett Shale, Wise County, Texas: Gas Research Institute topical report GRI-96/0305, 52 p.

Jarvie, D.M., 2004, Evaluation of hydrocarbon generation and storage in the Barnett Shale, Ft Worth basin, Texas: Special BEG/PTTC presentation, www.humble-inc.com, 116 p.

Lewan, Michael D., 2002, Fundamental issues on thermogenic gas generation from source-rock maturation and reservoir-oil cracking: Rocky Mountain Association of Geologists, Innovative Exploration Concepts conference, Oct 1st.

Montgomery, S.L., D.M. Jarvie, K.A. Bowker, and R.M. Pollastro, 2005, Mississippian Barnett Shale, Fort Worth basin, north-central Texas: Gas-shale play with multi-trillion cubic foot potential: AAPG Bulletin 89, 2, 155-175.

Pollastro, R.M., R.J. Hill, D.M. Jarvie, and C.Adams, 2004a, Geologic and organic geochemical framework of the Barnett-Paleozoic Total Petroleum System, Bend arch-Fort Worth basin, Texas (abs.): AAPG Annual Meeting Program Abstracts 13, A113.

Reeves, S.R., 2000, Shale gas exploration at the Red Dog mine, Alaska: West Coast PTTC presentation, http://www.westcoastpttc.org/presentations/99-00/030300/06-Reeves.pdf

ResTech Houston, Inc., 1996, Development of laboratory and petrophysical techniques for evaluating shale reservoirs: Gas Research Institute �nal report GRI 95/0496, 286 p.

Shanley, K.W., R.M. Clu�, and J.W. Robinson, 2004, Factors controlling proli�c gas production from low-permeability sandstone reservoirs: implications for resource assessment, prospect development, and risk analysis: AAPG Bulletin 88, 8, 1083-1121.