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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
2
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.
3
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.
4
Marcellus Shale in Hanson Quarry, NY
Oatka Creek Member
Cherry Valley LS
Union Springs Member
5
WV 6 7355.2 Organic-rich black shale100 m
6
Woody
organic
10 m
Pyrite >
Parallel clay flakes
Microfracture
7
Nanoporosity in Shale
8
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
9
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
10
DOE Eastern Gas Shales Project 1976-1992
11
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
12
Appalachian Basin Stratigraphy
13
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
14
IGT Core Apparatus (CORAL)
15
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
16
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
17
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.
18
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
19
EGSP WV-6 Well and Core (MERC#1) Photographed in 2011
20
Ohio Shale Gas Permeability
100 nanodarcies >
21
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
22
Gas Pore Volume in Marcellus
23
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.
24
IGT Data - Circa 1988
25
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.
26
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