PESA Qld Breakfast 22 May 2014
Shale oil – what does it
take?
David Lowry
www.lowryresources.com.au
Source rock issues:
Total Organic Carbon
Hydrogen Index
Maturity
Kinetics
Thickness
Porosity
Fraccing Issues
Poissons Ratio, Youngs Modulus
Reservoir/seal couplets
Resource Estimates
Exploration in Australia
Source rock issues:
Need a good source rock
Initial Total Organic Carbon
Initial Hydrogen Index
> 4%
(my impression)
> 400
Obtain from RockEval pyrolysis.
Preferably core, or at least hand-picked cuttings.
Regular cuttings likely to be full of cavings and may steer
you away from a good source rock
Source rock issues:
Need a rich source rock
Initial Total Organic Carbon
Initial Hydrogen Index
> 4%
(my impression)
> 400
mg HC generated from 1 g
Organic Carbon at full maturity
1000 mg Organic Carbon ~ 1200 mg kerogen
Immature
Fully mature
600 mg Oil & Gas
Source rock issues:
Need a rich anoxic source rock
Pyrite
Lamination (no bioturbation)
Good preservation of organic matter
because no scavengers
(my impression)
Immature
Fully mature
Source rock issues:
Need a rich mature source rock
Maturity
0.8% — 1.1% Ro
Estimating maturity
Vitrinite reflectance – traditional but very likely suppressed in
oil-prone shale.
VIRF or FAMM - good
TMax from RockEval – good for Proterozoic rocks; but
suppression
Modelling – good if heat flow and stripping histories are
known; good for mapping; can use old wells but need some
calibration.
Source rock issues:
Need to know your kerogen kinetics
How easily does your kerogen crack?
Track change in oil/gas ratio with maturity
Use A and E parameters to model maturity
Source rock issues:
Thickness
Thickness: the thicker the better. Minimum 30 m?
volumetrics; engineering; seismic
Source rock issues:
Porosity
SEM with ion milling
Porosity: Organic porosity important at Ro ~1%
Generation can also fracc the shale, giving permeability
Source rock issues:
Porosity
Jarvie ,2012
10% TR
80% TR
0%
14%
Fraccing Issues
Poissons Ratio, Youngs Modulus
Reservoir/source couplets
clay rich, ductile
Slatt, 2013
cemented by silica, calcite or
dolomite. Good to fracc
Optimum: interbedded reservoir/source ouplets
Oil generated= Thickness (m)
x initial TOC
x initial Hydrogen Index
x Transformation Ratio
Available Oil in place =
Thickness (m)
x initial TOC
x initial Hydrogen Index
x Transformation Ratio
— Adsorbed oil
— Migrated oil
Recoverable oil
x Recovery factor
Resource Estimates
Resource calculation
TOC. In anoxic marine source rock, uranium is adsorbed on the organic
matter. Gamma Ray log roughly proportional to TOC
Image deleted; data not
yet open file
Cluff, 2012
Problem of adsorption
Kerogen adsorbs early-formed oil. Not available for
migration into pores and fractures
Pepper & Corvie (1995) estimate: 100 mg oil / g organic C
Suppose HI source rock is 500 and
take particular Ro/TR kinetics
curve.
At Transformation Ratio 0.2,
kerogen will have generated 500 x
0.2 = 100 mg oil / g TOC
Just at start of expulsion at Ro
0.84%
To quantify expulsion, need to quantify kinetics and
initial HI
Image deleted; data not
yet open file
Recovery Factors for shale oil
Look to US experience
Evaluating production potential of mature us oil, gas shale plays. Oil & Gas Journal 12/03/2012
Eagle Ford fairway
Recovery Factors for shale oil
Oil & Gas Journal 12/03/2012
US Energy Information Administration 2013. Based on U.S. shale
production experience, ...... the recovery factors for shale oil range
from 3 percent to 7 percent of the oil in-place with exceptional cases
being as high as 10 percent or as low as 1 percent.
http://www.eia.gov/analysis/studies/worldshalegas/
Recovery Factors for shale oil
Oil & Gas Journal 12/03/2012
Recovery Factors for shale oil
Oil & Gas Journal 12/03/2012
Study the core as source
Rock Eval, RockEval on extracted samples, extract GCMS;
Py-GC, Bulk and MSSV multicomponent kinetics, FAMM or
VIRF, SEM with ion milling, clay XRD.
Study the core as reservoir
Mechanical properties, helium porosity, MICP, % carbonate,
Dean-Starke saturation; dipole sonic log, image log
A lot more science is needed than in conventional exploration.
Companies will need staff with strong skills in the theory and
practice of geochemistry and rock mechanics.
Australia Shale oil: McArthur Basin
Barney Creek Fm (1.6 Ga) & Velkerri Fm (1.4 Ga)
Barney Creek Fm
Velkerri FM
HI 1000
Tmax
Crick et al., 1988
Who are the
players?
Permits held/applied for
by Armour Energy
Southern McArthur Basin
Northern Georgina Basin
Imperial O&G (Empire
Energy)
Tamboran Resources.
Farmed out to Santos
Falcon O&G
Beetaloo Sub-basin.
No obvious burial
since Cambrian;
chance of
overpresssuring is
limited
Law et al., 2010
Relatively simple structure;
source rocks in both gas
and oil window
2011
Shenadoah-1
flowed wet
gas from
Velkerrie
Pangaea O&G
Southern Georgina Basin
Baldwin-2Hst1 August 2011 875
m in Arthur Creek Hot Shale.
Oct 2012 fracc; casing failed
MacIntyre-2H June 2012 1080
m in Arthur Creek Hot Shale.
Oct 2012 9 stage fracc. Testing
suspended (H2S)
Owen-3H August 2011 966 m in
Arthur Creek Hot Shale. Oct 2012
10 stage fracc; recovered fracc
fluids but no hydrocarbons
Buru Energy is major
player in Canning Basin
Ordovician Goldwyer
Fm recognised as major
shale oil opportunity
NE
SW
New Standard Energy
holds a large area
New Standard;
ConocoPhillips &
Petrochina farming in
X
X
Hess – formerly
Kingsway
X
Perth Basin. Hovea Mbr of Kockatea
Shale (Earliest Triassic)
AWE active exploration for tight gas. Four vertical wells
stimulated. Arrowsmith-2 5 stage fracc.
22 bbl
Eromanga Basin. Toolebuc Shale
Early Cretaceous
Exoma & CNOOC drilled a dozen
wells on the Maneroo Platform.
Maturity not quite high enough
Elsewhere Toolebuc is
largely immature; need to
find an area with high heat
flow and deep maximum
burial
PESA Qld Breakfast 22 May 2014
Shale oil – what does it
take?
Exceptional geology; lots of money
David Lowry
www.lowryresources.com.au