Pre-Drill Stresses From Seismic For Frac Designs
Introduction
The eco-political problems of shale gas production
are well known, and the conversion of indicative
resources to realistic producible reserves applying
fraccing techniques is difficult using all known
geological data. Fraccing is essentional for
recovering unconventional reserves and poorly
understood Earth stresses in frac planning can be a
show-stopper.
Conventional versus Unconventional reservoirs
Conventional reservoirs are naturally occurring
sandstones or carbonates with porosities generally
greater than 15% having permeabilities greater
than several tens of millidarcys. Vertical wells
with standard completion methods can produce
commercial flow rates (see top left of Figure 1) and
fraccing is effectively a secondary recovery process.
Multi-mineral and cemented sandstones vary in
porosity between 15% and 5% and have very low
permeabilities, often below one millidarcy. They
require man-made stimulation to flow. Horizontal
wells access greater potential reservoir surface area
but fraccing is the necessary permeability stimulant
for unconventional reservoirs. If porosity increases
in the direction of the horizontal well (see the middle
left of Figure 1) and fracs are directed parallel with
the direction of the local maximum horizontal Earth
stress (SHmax or SHD), fraccing efficiency can be
maximised. These sands and silts and the shales
with porosities less than 5%, shown below, plus deep
coals, are increasingly referred to as unconventional
composite plays.
Shales adjacent to and sealing conventional
productive reservoirs may still have high
kreogen content having often previously sourced
hydrocarbons during the burial process. Many
shales are structurally simple, flat lying and uniform,
extending over hundreds of kilometers and can be
hundreds of metres thick. Porosity and permeability
can also be locally enhanced by natural fractures
(lower left of Figure 1) and fracs can propogate
effectively. The simple structural properties of
extensive shale basins are attributable to several
now famous US ‘shales’ such as the Eagle Ford in
Texas (see top right of Figure 1). Enormous in-place
volumes of unexpelled gas and oil have been assigned
to these unconventional units in several countries.
The recent 96% downgrade in expected oil estimates
of the rich Monterey shale in California which is also
very extensive, may be strongly interbedded with
hard chert (light, resistive bands, in lower right of
Figure 1) and may be interrupted by reverse faults
and folding which rapidly reduces frac propagation
potential and the simple structural ideal of the
fraccers.
Thus indicative resource estimates give no indication
of potentially producible commercial reserves. These
unconventional hydrocarbons have to be extracted,
and all require fraccing. This article briefly outlines
the largest rarely considered problem facing fraccers:
Earth stresses.
CONVENTIONAL
(Natural)
&
UNCONVENTIONAL
(Man-made)
RESERVOIRS
Eagle Ford
>15% Porosity
Sand
FRAC
5-15% Porosity
Silt
Natural fractures
<5% Porosity
Shale
Monterey
Figure 1. Left; diagrammatic representations of conventional (top) and unconventional reservoirs (middle and
bottom) and right; outcrop examples of unconventional reservoirs, Eagle Ford (Texas) and Monterey (California).
Structure and Stress Factors
Faults are the basis of structural geology and have
been described in terms of whether they represent
failure due to being pulled, wrenched or pushed.
Anderson (1905) described a normal fault as a subvertical offset resulting from extension or having
been pulled; a wrench fault as horizontal offset
(lateral or strike slip) resulting from extension and
compression or having been sheared (twisted); and
a reverse fault as a sub-vertical offset resulting from
compression or having been pushed (see top left of
Figure 2).
Except for some earthquake data, Earth forces are
essentially unquantified which leads to excessive
simplification and hand-waving by structural
geologists. This once caused a senior exploration
manager in Aberdeen commenting on meeting me,
that I was in a ‘specialist back-water’. Although I
was initially taken aback, he wasn’t wrong, most
structural geologists describe Earth structures
resulting from a single force (plate tectonics) in
which all the oceanic ridges ‘push’. If so, the South
Atlantic earthquake data would be represented by
pink, Anderson thrust or reverse faults circles with
black, most with opposing east-west SHD arrows
(see lower left of Figure 2). Ocean-floor spreading
data and GPS show quite clearly the gap formed at
the actively spreading oceanic ridge is simply the
site of passive infill by the upper mantle as South
America moves slowly north at 10 mm per annum
and Africa moves more rapidly northeastwards
at 25. There are another four, arguably five, global
tectonic forces ultimately controlling 99% of the
world’s hydrocarbon reserves. Can these forces be
understood and harnessed for fraccing?
Earthquake distribution rarely finds them where
a fractured well is planned, but high definition
3D seismic generally can be placed as required.
Anderson noted that ‘varieties in character
between these three (fault) types’. Predrill Stresses
International (PSI) has divided normal, wrenched
(strike slip) and reverse faults into seven in order
to extract more stress information from faults (see
the upper-middle left of Figure 2). The quality of 3D
seismic allows these ‘varieties’ to be recognised, for
example, parallel strike slip (Anderson wrench) faults
vary from compressive strike slip towards reverse
faults and, in the opposite direction, extensional
strike slip towards normal faults. PSI has patents
covering derivation of quantified stresses from
structures interpreted on seismic lines. The depths
of successive pairs of horizon structure maps are
subtracted to form a series of thickness maps or
isopachs, which, together with the interpreted
normal and reverse faults, are used by PSI’s
4DGeoStress software to map Earth stresses in threedimensions (see right of Figure 2).
Quantified stress means a horizontal well can be
planned parallel with Shmin, the direction of the
smallest horizontal component of the Earth’s stress
field (ShD), enabling fracs to be propagated at right
angles, parallel with SHmax (SHD) the direction of
extensional failure propogation, hence direction of
potentially longest frac length; no wellbore breakout
or laboratory rock property measurements are
required.
Frac Gradients
The ratio of Shmin/Load (Sh/SV) or the ‘frac
gradient’ can be extracted from the seismic and
(SH<SV)
Pull
Push
Shear
SH>SV
SV
Anderson
Stress
States
SV
SH>>SV S
V
Sh
Normal
SH
Strike Slip
Sh
st
thru
ck
Ba
SH
Sh
2θ
SH
Thrust
SV
PSI Stress States
Normal Loading
(N)
(L)
S H /S V 0.675
S h /S V 0.650
GO
SV>
SH>
Sh
0.825
0.725
SV>
Sh≥
Sh
Uplift
(U)
0.875
0.775
SH>
SV≥
Sh
Ext.
Strike
Slip
(ESS)
1.010
0.825
SH>
SV>>
Sh
1.075
0.875
Fracture Gradient
Stress Derived Area
Strike
Slip (SS)
SH>
SV>
Sh
SH Direction
Comp.
Strike
Slip
(CSS)
1.200
0.925
Reverse
(R)
1.400
1.000
SH>>
Sv≥
Sh
SH>
Sh>
SV
3.000
1.500
SH Magnitude
Sh Magnitude
STOP
Extrapolated
25mm/a
Al
EJ
10mm/a
Al
Ap
Figure 2. Left, top; diagrammatic representations of Anderson and PSI stress states and fracture gradients. Left,
bottom; reverse and strike slip stress states from earthquake focal mechanism solutions (from the World Stress
Map), and right; stress from seismic using 4DGeoStress software.
mapped within any pair of horizons. The reverse
fault areas are coloured red and wrench and normal
fault areas are green as in the traffic light sense; red
for stop (see middle left of Figure 2). This means
undesirable horizontal fractures will be formed in
red areas and desirable, reservoir-cutting vertical
fractures in green areas. There is a 3% window
between the two which serves as amber for caution.
The advantages here are profound. Not only are
detailed pressure-depth graphs generated for a well
planned in any direction or inclination, but it means
fracs can be directed and aligned vertically within
the potential reservoir units, pre-drill.
There are some 6000 line-km of 2D seismic available
from the South Australian government (DMITRE)
along with numerous 3D surveys. In 2011 PSI
interpreted an even spread of lines across the basin
and in 2013 one-fifth of the 2D lines were used to
form stress isopachs. Further lines were added in
June 2014 for the evolving non-exclusive report to
which Southwest Queensland can be added.
The frac gradient map for the South Australian part
of the Cooper Basin (see left of Figure 3) shows
the paleo North Nappamerri Trough has been
strongly compressed to red reverse faulting with
frac propagation horizontal as work is done against
the load (SV), the least principal component of
stress. Several wells have confirmed this prediction
with flows rapidly dropping below 1MMcfpd due to
no vertical splitting of the basin-centred, Permian
gas. Amber areas to the south are proportionally
too large due to the broad 2D line spacing. In other
words, the amber areas can be reduced if individual
operators wish to add extra 2D and 3D seismic to
their acreage areas, thereby making very reliable
maps with accurate red and green boundaries for
frac planning.
Faulting indicates dislocation of the rocks which,
even in shales, can be conduits for fluids to the
surface, a fact increasingly used by detractors
to oppose fraccing. Not all normal faults leak
and many reverse faults seal. These seemingly
unresolvable, unquantifiable structural factors can
be quantified by the fault seal analysis within PSI’s
software. Areas where surface faulting has become
an issue include Germany and France where there
are bans on fraccing, and in each of Poland, UK
and in the Karoo of South Africa where debate
is intensifying. The remoteness of the northern
Nappanerri Trough in Australia has not attracted
that attention. Seismic data show water and
possibly some gas expulsion up faults from the Mid
Cretaceous occurred from 50 million years ago,
but these are detached for the most part from the
Permian. It appears the operator in some countries
is going to be required to guarantee there will be no
leakage; PSI can assist, but good luck!
Global Stresses
GPS and ocean-floor spreading data show Australia
is the fastest drifting continent and has been moving
north-northeastwards in excess of 60 mm per annum
for the past 50+ million years. In doing so, Australia
has experienced an increasing Earth radius as it
approaches the Equator (see right nof Figure 3). The
Earth’s crust is essentially rigid so the response has
been to reduce the crustal curvature by compressing
the upper crust (pink) and extending the lower
crust (grey). This motion lifts the margins rather
like the flanges of a hinge. The continental margins
rise to over 2000 m on the East Coast and to 270 m
on the more distant, less weakened crust to the
West. Between these ‘flanges’ a compressional, but
sinking, ‘hinge’ area is the Cooper and the Mesozoic
Eromanga basins which, although extensively
uplifted, reach a subsea elevation of -12 m at
Lake Eyre as the lower crust concurrently extends
and sinks. The compression is strong, causing an
inversion of over 300 m of the pre-Tertiary in the
northeast Nappamerri Trough and a resulting reverse
fault stress state which predicted the lack of success
in fraccing parts of the Permian. The short yellow
bars on the upper right of Figure 3 are anticlines
and are evidence for compressional earthquakes and
surface uplift spanning the less rigid parts of the
continent.
Compres
sion
COOPER BASIN FRACTURE GRADIENTS
Cu
Extension
rva
60m
Ge
Keleary-1
Tarragon-1
oi
Paning-1
Telopea-1
Cleansweep-1
.
H
UG
O
TR
lH
eD
ecr
ig
GPS
60mm/a
h
eas
40
m
20m
Reg Sprigg-1
Moondie-1
da
tur
Beanbush-1
Pennie-1
Yanta-1
.
Lamdina-1
RA
AR
E
W
IDG
HA
Innamincka-1
.
Snatcher-1
Charo-1
Fig.11
Bookabourdie-1
Callabonna-1
Growler-1
Fly Lake-1
Kalladeina-1
TC
PA
R
Burley-1
Bulyeroo-1
ERR
M
A
PP
NA
Meranji-1
Swan Lake-1
Gidgealpa-1
Christies-1
GH
OU
R
T
Encounter-1
Merrimelia-1
Tindilpie-1
Sellicks-1
Kirby-1
Holdfast-1
Mootanna-1
I
Mcleod-1
Moomba-74 Moomba-191
Della-1
Dullingari-1
Moomba-1
Spencer-1
Tantanna-1
Big Lake-1
Wancoocha-1
A
NG
U
L
L
A
Kidman-1
PER
A
Lycosa-1
Kerinna-1
Toolachee-1
McKinlay-1
Alwyn-1
AP
Daralingie-1
Strzelecki-1
Narcoonowie-1
Reverse SH>Sh>SV
Strike S >S >S
H
V
h
Slip
Normal SV>SH>Sh
SOUTH AUSTRALIAN BORDER
Parsons-1
Wantana-1
Tirrawarra-1
GM
I
Bauer-1
Callawonga-1
Pondrinie-1
Moorari-1
>15% Porosity
Sand
30
40
50
Kobari-1
kilometres
Normal Loading
(N)
(L)
S H /S V 0.675
S h /S V 0.650
S>
V
S>
H
Sh
0.825
0.725
S>
V
S≥
h
Sh
5-15% Porosity
Aldinga-1
Davenport-1
PSI Stress States
Uplift
(U)
0.875
0.775
S>
H
S≥
V
Sh
Ext.
Strike
Slip
(ESS)
1.010
0.825
Vertical Fracs
= reservoir creation
S>
H
S>>
V
Sh
Strike
Slip (SS)
1.075
0.875
S>
H
S>
V
Sh
Comp.
Strike
Slip
(CSS)
1.200
0.925
S>>
H
S≥
v
Sh
Reverse
(R)
420000
1.400
1.000
3.000
1.500
440000
460000
480000
500000
PREDRILL
STRESSES
INTERNATIONAL
Fracture Gradient
S>
H
S>
Weena-1
h
SV
Horizontal Fracs
= uplift
Cooper Basin,
South Australia
Bellows-1
Date
: 2/07/2013 Contour Int. : 0.01 ()
Author : Sam Ekins
Project : X:/pep/pep Projects/Projects/CSP II/Cooper Stress Project/CSP 2013
Reserves
1.8 Tcf
Composite
175 Tcf (minus NE Nappamerri)
Silt
SH Magnitude
Sh Magnitude
Produced
6.9 Tcf
Unconventional
FRAC
20
T EN
Padulla-1
N
10
Tertiary Anticlines (50-0Ma)
+ Volcanic Centres
Conventional
Marsden-1
0
Stress Map
of Australia
<5% Porosity
Shale
97 Tcf
Shale
Figure 3. Left; Cooper Basin fracture gradient map derived from seismic, and right top: diagrammatic
representation of curvature reduction of the crust caused by migration of Australia towards the Equator, and
bottom; conventional reserves and unconventional producible resource estimates for the Cooper Basin, South
Australia (for details see text).
Are there any clues of fraccing success in the gas
volume numbers? The South Australian Cooper
Basin Permian has produced 6.9 Tcf of conventional
gas running up to 30% CO2 with 1.8 Tcf remaining
(see lower right of Figure 3). The US EIA states
unconventional ‘risked, recoverable shale gas’ of
97 Tcf and the South Australian state government
states 175 Tcf from the tight sands, siltstones, shales
and coals (unconventional composite plays). The
SA government, however, has recently offered
a Retention Licence for up to 15 years over the
main basin-centred gas, stress inverted, northeast
e
Ma
rc
e ll
us
Bakken
er
nt
Mo
ey
n
ia
rm
Pe
le
g
Ea
rd
Fo
focal mechanism
breakouts
drill. induced frac.
borehole slotter
overcoring
hydro. fractures
geol. indicators
World Stress Map Rel. 2005
Heidelberg Academy of Sciences and Humanities
Geophysical Institute. University of Karlsruhe
Figure 4. Significant producing unconventional shale basins of the USA overlain on the stress map (produced by
the World Stress Map project).
Nappamerri Trough tending to suggest the
conventional and unconventional composite plays
may be converging to nearer equal potential, but the
latter at a far greater cost.
The World stress Map of North America (see
Figure 4) indicates scattered thrust or reverse fault
stress states (blue circles and bars) in the eastcentral (Appalachia), the broad central and western
three-quarters has few shear (strike slip, green) and
many red normal fault stress states indicating low
horizontal compression and desirable vertical frac
reservoir potential. The far west strip (California)
has dense reverse fault stresses where local fracs
will be horizontal and unproductive, for example
affecting the Monterey which also lies within dense
strike slip green along the San Andreas Fault.
The wide expanse of low to extensional stress
states has promoted vertical fracs and excellent
unconventional production in the Bakken and Eagle
Ford. The Monterey appears to have largely dodged
the lightly compressed reverse fault bullet.
It very important to note that the strong reverse fault
associated, large anticlinal growth has been a strong
component of Los Angeles and San Joaquin basin
Monterey conventional reservoir production success,
but adverse for accompanying unconventional shale
fraccing, the latter discussed in Figure 1.
Almost all Australian earthquakes are strong reverse
fault stress states which have so far eliminated the
North Nappamerri Trough in the Cooper Basin
and reduced the South Nappamerri to a single
well reporting low flowing shale. The remarkably
extensive lower stress states of the USA are due to
differing global forces and largely to it moving at less
than one-tenth of the speed towards the Equator as
Australia, accounting for the huge difference between
the two countries’ unconventional gas and oil success
rates.
This is a broad comparison but certainly good
enough to answer the statement I have heard, ‘There
is no reason why Australia shouldn’t be as successful
as the US (in terms of shale gas potential)’. There
clearly is. A glance at the World Stress Map indicates
there are several other large and segmented, potential
trouble spots.