Presentation Identifier (Title or Location), Month 00, 2008

Petrophysical Characterization of the

Marcellus & Other Gas Shales

Daniel J. Soeder, NETL, Morgantown, WVPresentation for PTTC/DOE/RSPEA Gas Shales Workshop, 28 Sep. 2011

AAPG Eastern Section Meeting, Arlington, Virginia

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Petrophysics Physical properties of rocks

Wireline well log measurements

radioactivity, density, conductivity, sonic velocity

links between well logs and geology

Measurement of reservoir rock and fluid transport

properties (core analysis)

porosity, pore volume compressibility, capillary entry

pressure, pore size distribution

permeability/relative permeability, flowpath aperture,

flowpath tortuosity, reaction to stress

links between core analysis and petrography

classically designed for conventional reservoirs;

added challenge in shale.

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Gas Shale Geology Sedimentary rock formed from mud

Composed of fine-grained material: clay,

quartz, organic matter, and other minerals.

Clay-rich shales are fissile: split into thin sheets

Shale can be silty or calcareous, and grade into

other lithologies (siltstone/limestone)

Shale types: organic-rich (black) and organic

lean (gray or red)

Shale porosity ~ 10%, permeability is very low.

Pore spaces between grains are small.

Gas occurs in fractures, in pores and adsorbed

or dissolved onto organic materials and clays.

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Marcellus Shale in Hanson Quarry, NY

Oatka Creek Member

Cherry Valley LS

Union Springs Member

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WV 6 7355.2 Organic-rich black shale100 m

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Woody

organic

10 m

Pyrite >

Parallel clay flakes

Microfracture

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Nanoporosity in Shale

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Petrophysics of Shale Shale grain size is very small: silt sized quartz grains,

clay flakes, organic matter. Small grains = small pores

Pores in shale are flat, slot-like structures, supported

by asperities or surface roughness, versus triangular

pores supported by round grains.

Small pores are easily plugged by liquids held under

high capillary pressures

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Pore Geometry and Drawdown Stress The linear shape of slot pores is more strongly

affected by narrowing under stress than

triangular pores.

Asperities in slot pores are easily crushed

during high net stress excursions, and do not

recover the pore shape, resulting in

hysteresis.

Slot pore behavior under increased net stress:

greater mean aperture (smaller pores closed)

greater flowpath tortuosity (loss of inter-connectivity)

result: lower permeability

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DOE Eastern Gas Shales Project 1976-1992

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EGSP Cored Well Locations38 total, including 3 wells in the Antrim

Shale of the Michigan Basin, and one

well in the New Albany Shale of the

Illinois Basin

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Appalachian Basin Stratigraphy

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IGT Core Analysis 1982-89 Institute of Gas Technology in Chicago (now GTI) had a

contract to perform tight sand core analyses for DOE

Multiwell Experiment (MWX) in Colorado.

A high-precision, steady-state gas permeameter and

porosimeter was developed for this work, called the

Computer Operated Rock Analysis Lab, or CORAL

The CORAL used temperature control to produce a gas

reference pressure stable to ~1 part in 500,000

Gas flow through cores was measured by differential

pressure build-up in calibrated downstream volumes

Actual flow sensitivity was as low as 10-6 standard cm3

per second

Pore volumes under net stress were measured using

Boyles Law to an accuracy of 0.01 cm3

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IGT Core Apparatus (CORAL)

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Permeability

Henry Darcy: 19th Century French hydrologist defined the basic

parameters for water; some modifications needed for gas

Flow is controlled by permeability of the porous medium, x-s area,

pressure drop, fluid viscosity and flowpath length:

Q = kA (P/ L); to solve for permeability: k = L (QA/P)

In the lab, L and A are properties of the sample, is a property of the

measuring fluid, P is controlled, and we measure Q.

Akin to electrical conductivity, in that some materials allow fluids

to pass through more easily than others

Ohm's law: I = U(1/R): current = voltage divided by resistance

Basic permeability unit: darcy = 1 cp fluid flowing at 1 cm3/sec

under 1 atm P per cm length, through a cross-section of 1 cm2

millidarcy = 10-3 darcy: conventional oil & gas reservoirs

microdarcy = 10-6 darcy: tight sands, coal, some shales

nanodarcy = 10-9 darcy: some coals, many shales

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Pulse versus Steady State Joel Walls under Amos Nur at Stanford University developed a

pulse technique for low permeability rocks

Stanford Rock Physics Project in 1982

Used decay of pressure pulse to calculate permeability

Fast, commercial technique, currently in use

Phil Randolph at IGT stood by a modification to the steady

state technique for research purposes

Temperature control gave stable reference pressure

Adjustments to stress, fluid redistribution, adsorption and other

subtle phenomena could be measured over time

Slow technique; days to weeks to collect data

Side by side comparison for GRI showed similar performance

on dry rock

Steady state more accurate for relative permeability to gas under

partial liquid saturations

Pulse technique much faster

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IGT CORAL Operations

Modification of CORAL for Devonian shale analyses:

1) Reconfigured air circulation for better temperature stability

2) Improved digitizing resolution with new data logger

3) New temperature control algorithm to minimize overshooting

the desired setpoint.

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Shale Petrophysics in the 1980s

Only 5 cores out of 38 EGSP wells penetrated to the

Marcellus Shale

DOE funded EGSP core analysis at the Institute of

Gas Technology (now GTI) in Chicago 1982-84

EGSP cores had deteriorated, leading to challenging

sample selection

Samples analyzed were 7 Ohio Shale cores, and 1

Marcellus

Ohio Shale contained oil; difficult gas measurements

Marcellus Shale had strong sensitivity to net stress

Marcellus had very strong adsorbed gas component

Permeability of all shales very low, but measureable

New analyses planned to follow up on earlier results

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EGSP WV-6 Well and Core (MERC#1) Photographed in 2011

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Ohio Shale Gas Permeability

100 nanodarcies >

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Marcellus Shale Gas Permeability

Gas slippage in tight rocks.

Klinkenberg correction:

K = k x 1+b/P

where b is the Klinkenberg

coefficient (slope)

Effect of net stress: 2x net

stress = 2/3 reduction in

permeability (19.6 d at 3000 psi net PC; 6 d at 6000 psi net PC

Derived parameters:

Flowpath aperture

Flowpath tortuosity

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Gas Pore Volume in Marcellus

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Gas Content of Marcellus Shale

1980 NPC estimates for shale: 0.1 to 0.6 scf

gas/ft3

1988: IGT core analysis: 26.5 SCF/ft3 at

3500 psi reservoir pressure; GIP= 3693

TCF; 10% recoverable = 369 TCF

2002: USGS Open-File Report 2006-1237:

Marcellus has 2 TCF of recoverable gas.

2008: Engelder and Lash: Marcellus has

500 TCF of GIP, with 50 TCF recoverable.

2009: Engelder revised this to 363 TCF

recoverable.

2011: USDOE - Energy Information

Administration using 410 TCF recoverable.

USGS estimate is 84 TCF recoverable.

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IGT Data - Circa 1988

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Marcellus Gas Production

Mitchell Energy adapted new technology for

economic production of shale gas in the 1990s

directional drilling, laterals & light sand fracs

Barnett Shale in Ft. Worth Basin, Texas

Range Resources, Renz #1 well, October

2004, Washington County, PA;

Trenton-Black River Limestone original target

recompleted vertically in Marcellus Shale

light sand frac; IP 300 MCFD

Range Resources, Gulla #9 well, 2005

"Barnett" type - drilled horizontally

slickwater frac completion; IP 4 MMCFD

3157 Marcellus Shale wells drilled in PA

between January 2008 and June 2011

Energy value of U.S. natural gas may equal

twice the oil in Saudi Arabia.

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NETL Petrophysical Analyses

Precision Petrophysical Analysis Laboratory (PPAL)

Constructed in a lab at the Petroleum and Natural Gas

Engineering Department at West Virginia University

Student access (esp. international students)

PNGE expertise to analyze and model the data

Facilities accessible for 24-hour operations

Based on IGT's CORAL design, but smaller footprint

with improved sensor electronics, greater degree of

computer control, and only 2 coreholders instead of 4.

Design capabilities of 10,000 psi confining pressure,

1500 psi pore pressure, and 30 psi differential pressure

Flow differential pressure sensors 0.5 psid full scale

Porosimetery differential sensor 0.5 psid; displacement volume

calibrated t