Can hydrocarbon source rocks be identified on seismic data?
Helge Løseth1, Lars Wensaas1, Marita Gading1, Kenneth Duffaut1, and Michael Springer2
1
Statoil ASA, Research Centre Rotvoll, NO-7005 Trondheim, Norway
Statoil ASA, Forusbeen 50, NO-4035 Stavanger, Norway
2
ABSTRACT
Hydrocarbon source rocks contain significant volumes of organic matter, are capable of
expelling petroleum when heated, and have produced most of the world’s known oil volumes.
Recently, source rocks have also become recognized as unconventional economic reservoirs.
Here we present a new way of identifying, characterizing, and mapping spatial distributions
and variations of thick source rocks (>20 m) that is based on seismic data only. This has a
significant impact on the prospect risk assessment of petroleum plays. Rock property studies of organic-rich claystones show that the acoustic impedance (AI), which is the product
of compressional velocity and density, decreases nonlinearly with increasing total organic
carbon (TOC) percent. Claystones mixed with low-density organic matter (TOC > 3%–4%)
have significant lower AI and higher intrinsic anisotropy than otherwise similar nonorganic
claystones. This gives the top and base source rock reflections characteristic negative and
positive high amplitudes, respectively, which dim with increasing reflection angle. In addition, the TOC profile, which is a smoothed TOC percent curve, influences the top and base
amplitude responses. An upward-increasing TOC profile has the highest amplitude at the
top, while the opposite asymmetry is observed for downward-increasing TOC profiles. By
using seismic data, we therefore can map lateral distribution, thickness, variation in TOC
profiles, and, with local well calibration, convert AI data to TOC percent. This approach to
mapping source rocks may change the way petroleum systems are evaluated.
INFLUENCE OF ORGANIC MATTER ON
ROCK PROPERTIES
The Late Jurassic Draupne (North Sea),
Spekk (Norwegian Sea), and Hekkingen (Barents Sea) Formations on the Norwegian Margin
and the Kimmeridge Clay in England are good
examples of marine source rock claystones
(Vollset and Dòre, 1984; Dalland et al., 1988;
Morgan-Bell et al., 2001; Keym et al., 2006).
Such rocks typically comprise clay minerals
A
Acoustic impedance (m/s*g/cm3)
INTRODUCTION
The petroleum system (Magoon and Dow,
1994) places the source rock as the first and
foremost element of the geological system
required to produce a petroleum play (Allen
and Allen, 2005). Recently, source rocks
have also become unconventional economic
reservoirs. A source rock contains a significant volume of organic matter and is capable
of expelling petroleum when heated. Source
rock lithologies vary across a continuum from
wholly organic sediments (coals), through
siliciclastic shales and marls, to carbonates.
This study focuses on organic-rich marine
claystones that have produced most of the
world’s known oil volumes (Klemme and
Ulmishek, 1991). The ability to identify a
source rock in the subsurface and quantify
distribution, thickness, and richness has a
significant impact on prospect assessment
and risk. Traditionally this is done by geochemical analyses of hydrocarbon or source
rock samples, but well wireline data can also
identify and give a good estimate of potential source rocks (Passey et al., 1990, 2010).
However, such analyses only give local information. A remote sensing tool that examines
the subsurface and maps the source rock
basinwide would be a better means to reveal
the hydrocarbon potential. In this paper we
describe characteristic acoustic parameters of
organic-rich claystones and associated seismic responses that allow their identification,
characterization, and mapping on seismic data.
(average 42%, minimum 20%, maximum 70%;
density 2.65–2.70 g/cm3), silt-sized quartz and
minor feldspar grains (average 39%, minimum
12%, maximum 62%; density 2.65 g/cm3), carbonate (average 5%, minimum 0%, maximum
41%; density 2.7–2.9 g/cm3), pyrite (average
13%, minimum 2%, maximum 26%; density
4.8–5.2 g/cm3), other (average 0.6%, minimum
0%, maximum 7%), and organic matter (3%–
25% total organic carbon, TOC). Compared to
surrounding nonorganic or low-organic claystones, the main difference is not the mineralogical composition but the higher content of
organic matter. In normal to rich source rocks
(TOC to 25%) the volume of organic matter is
approximately twice the TOC percent, which
is measured in weight, because the density of
kerogen (1.1–1.4 g/cm3) (Passey et al., 2010)
is roughly half the density of the mineral mass
(2.7 g/cm3). The density of kerogen is also very
low in oil and gas mature source rocks due to
as much as 50% internal kerogen porosity (Sondergeld et al., 2010). How this organic matter
influences the seismic response is described by
the acoustic parameters: compressional velocity
(Vp), shear velocity (Vs), bulk density, anisotropy, and attenuation. Our studies of cores and
well logs show that the acoustic impedance
(AI), which is the product of compressional
velocity and density, decreases nonlinearly with
increasing TOC percent (Fig. 1). Therefore,
B
10 000
10 000
8000
6000
4000
4000
0
4
8
12
16
20
Total organic carbon (wt%)
0
4
8
12
16
20
Total organic carbon (wt%)
Figure 1. A: Total organic carbon (TOC) weight percent versus acoustic impedance (AI)
plot for Metherhills Quarry well in Kimmeridge Clay in southern England (Morgan-Bell et
al., 2001). Maximum burial is ~1.5 km. TOC percent is based on geochemical analyses of
core samples. B: Similar plot for Hekkingen Formation, Barents Sea, from 9 wells at depths
between 1700 m and 2500 m. Maximum burial was ~1 km deeper. TOC percent is based
on geochemical analyses of samples of cuttings. Dotted curve in A, which shows nonlinear AI increase with increasing TOC percent, is shifted ~1000 AI units up to fit with deeper
(~1–2 km) buried Hekkingen Formation.
© 2011 Geological Society of America. For permission to copy, contact Copyright Permissions, GSA, or [email protected].
GEOLOGY,
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2011
Geology,
December
2011;
v. 39; no. 12; p. 1167–1170; doi:10.1130/G32328.1; 6 figures.
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sic anisotropy. Interbedded centimeter to meter
thick beds of variable organic content (e.g., as in
the Kimmeridge Clay Formation; Morgan-Bell
et al., 2001) may give additional anisotropy on
seismic scales (tens of meters). Calculating the
AVA response at the top source rock reflection
from an isotropic model, which only considers the AI and Vp/Vs ratio, normally only gives
a weak dimming with offset. The dimming
increases significantly if the intrinsic anisotropy
is added. Such clear dimming was found in
our studies of top source rock reflections (e.g.,
Fig. 3). Theoretical models also reveal significant dimming with offset (Carcione, 2001). We
define the significant drop in AI together with
the clear dimming of amplitude with offset as
a characteristic top source rock behavior (i.e.,
AVO class 4 seismic response) (Castagna and
Swan, 1997). A source rock interval that is
thicker than ~20 m (above tuning thickness)
will also have a distinct base source rock reflection. The increase in AI at the base gives a highamplitude positive reflection that also dims with
offset, i.e., an AVO class 1 response.
Generally, distinct AVO class 4 reflections
are not very common. Coal, which is a source
rock, has this type of reflection. We have locally
identified both shallow buried top sands and
the AI of good source rocks (TOC > 3%–4%)
is significantly lower than in otherwise similar
nonorganic claystones. The AI of source rocks
is also significantly lower than in most other
rock types. The AI contrast between nonorganic
and organic-rich claystones remains stable with
depth down to 4500 m, i.e., oil mature source
rock (Fig. 2). The top and base of thick (>20 m)
organic-rich claystones are therefore expressed
by a significant reduction and increase in AI,
respectively.
Together the Vp/Vs and the anisotropy contrasts at a rock interface determine the amount of
amplitude variation with incidence angle (AVA)
for a reflected seismic wave (Thomsen, 1993).
The intrinsic anisotropy rises with increasing
TOC percent, and in normal organic-rich claystones (TOC >3%–4% and <25%) the velocities
are significantly higher parallel to the bedding
than perpendicular to the bedding (Vernik and
Landis, 1996; Sondergeld et al., 2000). The
compressional velocity in organic-rich claystones therefore rises with increasing deviation
angle of the wells (Hornby et al., 2003). As in
the epoxy and glass experiment by Melia and
Carlson (1984), we assume that mixed layered
aggregates of acoustic soft organic matter and
acoustic harder minerals cause the strong intrin-
Depth below seabed (m)
2000
Figure 2. Acoustic impedance (AI) versus depth from
claystones in Lange, Spekk,
and Melke Formations in 12
wells from Norwegian Sea.
Total organic carbon percent
values in Spekk Formation
are calculated from well logs
(Passey et al., 1990). Organicrich Spekk Formation (green
to red) has significantly lower
AI than surrounding nonorganic claystones (blue) at
all depths. Top source rock
reflections therefore have
high amplitudes at all depths
in basin.
3000
4000
SEISMIC DATA QUALITY
In order to confidently interpret seismic
amplitudes and changes in amplitude with offset, the phase of the data must be known, the
near and far offset data must be time aligned,
and the near and far amplitudes should be
properly scaled and matched for phase and frequency. The seismic sections presented here are
zero phased. A black-blue peak reflection represents an increase in AI, whereas a red-yellow
trough represents a reduction in AI.
SEISMIC EXPRESSION OF SOURCE
ROCK
This study shows that reflections from rich
(>3%–4% TOC) and thick (>20 m) source
rocks have very high amplitudes compared to
most surrounding reflections. Top and base
source rock reflections are therefore easily
identified on seismic sections. Generally, the
amplitudes from the source rock interfaces rise
with increasing organic content (Fig. 1), assuming that there is otherwise uniform source rock
composition and there are only small variations in the embedding rocks. This is correct
as long as the source rocks are thicker than
the tuning thickness (Widess, 1973). Marro-
A
B
Sand
6000
10 000
8000
3
Acoustic impedance (m/s*g/cm )
0
10
Total organic carbon (wt%)
Sand
3.0 s
Top source rock
+
- 1 km
4000
1168
some top claystone reflections with AVO class 4
responses. Compared to top source rock reflections, these reflections have weaker amplitudes
and smaller AVA dimming. Top sand reflections also have restricted basinwide distribution
compared to source rocks. However, we have
not studied all rock types and therefore cannot
rule out that there may also be other lithological boundaries with high-amplitude AVO class
4 reflections.
3.5 s
Base source rock
Figure 3. Amplitude-balanced seismic sections showing higher amplitude on near
(A) than on far (B) stack data at top source
rock reflection (Spekk Formation). Dark gray
line shows position of well and red curve
is gamma ray log. Source rock has high
gamma ray readings, while sand has low.
Top and base sand reflections increase in
amplitude on far trace data.
GEOLOGY, December 2011
quin and Hart (2004) found that reduced layer
thickness below tuning thickness causes top
amplitude dimming for top coal reflection. A
case study of the Spekk Formation at ~4000 m
burial depth identified top source rock amplitude dimming when the thickness decreases to
<~20 m (Fig. 4).
TOC Profiles
The amount of organic matter varies across
lamina and layers in scales from millimeters to
tens of meters in most source rocks. A low frequent seismic wave is not able to reflect small
variations but responds to the averaged acoustic rock properties from intervals tens of meters
thick. The TOC profile, which is a smoothed
TOC percent curve (Fig. 5), gives a qualitative relationship between the organic content
and the associated seismic response from the
top and base source rock formation. We have
observed four typical TOC profiles. The Late
Jurassic Spekk and Draupne Formations often
have upward-increasing TOC profiles with
the highest concentration of organic matter in
the upper part, but locally a blocky pattern is
also observed. The Hekkingen Formation has
a downward-increasing TOC profile, while the
Kimmeridge Clay Formation has a ball-shaped
profile that is richest in the middle part.
Interpreting the Source Rock Interval
Lateral variations in amplitude from top and/
or base source rock layers can reflect basinwide
shifts in thickness, variations in organic concentrations, changes in TOC percent profiles,
and/or changes in embedding rocks. Changes
in embedding rocks are not discussed in detail
here, but onlapping and truncating reflections
should be mapped and correlated with shifts
in amplitude. We find it useful to first map the
source rock thickness by interpreting top and
base source rock reflections. Second, amplitude variations of both the top and base source
rock reflections are extracted. Areas where the
source rock interval decreases to less than the
tuning thickness are correlated to the reduced
amplitude strength of the top source rock reflection (Fig. 4). A uniform increase or decrease in
both top and base source rock reflections that
does not correlate with thickness variations
may reflect the average TOC percent increase
or decrease, respectively. Where the top source
rock reflection has a higher amplitude than the
base, or vice versa, this can be linked to asymmetric organic profiles, as seen for the Spekk
and Hekkingen Formations (Fig. 5). Lateral
asymmetric top and base source rock reflections
variations may reflect shifts in organic profiles.
Variations in intra–source rock reflection pattern
should be analyzed where the source rock interval is thick.
A nonlinear correlation between AI and TOC
percent is found (Fig. 1). If seismic data are
inverted to AI data it is possible to transform the
AI values in the source rock formation to TOC
percent values. However, such AI to TOC percent conversion requires good local seismic to
well calibrations both to invert the seismic data
and to establish a local AI to TOC percent relation (Fig. 6).
Løseth et al. (2011) showed that thin-skinned
gravitational gliding structures that are large
enough to be imaged on seismic data commonly
occur in organic-rich claystones. They are characteristic but not unique for this rock type. In
addition to the acoustic characteristics, the seismic identification of layer-bound thin-skinned
gravitational gliding structures may increase
the confidence in identifying organic-rich claystones.
CONCLUSIONS
Among the data types available today, the
subsurface is best imaged with seismic data, and
we have demonstrated that organic-rich claystones have characteristic seismic responses that
allow identification. Mixing kerogen into claystones gives a significant nonlinear reduction
Figure 4. Source rock
A 2.5 m
5m
17 m
27 m
38 m
66.5 m
A′
thicknesses in meters
from wells. A: Near trace
+
seismic data. B: Top
source rock maximum
100 ms
trough amplitude map.
Top source rock
Where source rock thins
N 6°40′E
below ~20 m, amplitude
38 m
dims significantly west5 m 17 m
66.5 m 10 000
ward to crest of footwall
A
where well penetrated
A′
–65°08′
27 m
2.5-m-thick source rock.
20 000
2.5 m
For thicknesses <~10 m,
Base source rock
top source rock reflec2 km 30 000
2 km
B
tion becomes weak, and
below 5 m there is no
obvious top source rock reflection. No relationship between thickness and top source rock amplitudes is observed where source rock is
thicker than tuning thickness. A−A′ shows line of seismic section.
Figure 5. Density log
TOC
TOC
RHOB
Well
TOC
Well RHOB
(ρ, g/cm3), total organic
1.95
2.95
20
1.95
2.95 0
profile
profile
carbon (TOC) log (0–20
wt%) (Passey et al. 1990)
+
+
(for B only), TOC profile,
Top
and near trace seismic
section. A: Spekk FormaSource
tion in Norwegian Sea. B:
rock
Hekkingen Formation in
Barents Sea. Smoothed
Base
TOC profile correlates
+
with seismic response
such that upward-in25 ms
0.5 km
creasing TOC profile A
has highest amplitude at top, while downward-increasing TOC profile B has highest amplitude at base. TOC profiles explain why the base
Cretaceous unconformity (common name for top source rock reflection, offshore Norway), has high amplitude in North Sea and Norwegian
Sea but low amplitude in Barents Sea. Color code and scales are same for both sections.
A
GEOLOGY, December 2011
B
1169
A) Seismic profile
+
B) AI profile
AI
10
C) TOC % profile
100 ms
-
8000
9
8
Top source rock
7
6
7000
5
4
6000
Base source rock
in AI with increasing TOC percent. Top reflections from good source rock intervals (TOC >
3%–4%) therefore have high amplitudes. Layered aggregates of organic matter cause strong
intrinsic anisotropy that results in a significant
dimming of top and base source rock reflections
from the near to the far offset. An organic-rich
(TOC > 3%–4%) and thick (>20 m) claystone
therefore has a negative top response reflection that dims with offset, while the base has a
positive response that also dims with offset. In
addition to the average organic content, the vertical stacking of the organic content, which we
smooth and call the TOC profile, also influences
the seismic response. Typical TOC profiles,
where the amount of organic matter increases
or decreases upward, are seen in the main
source rocks in the North Sea (Draupne Formation) and Barents Sea (Hekkingen Formation),
respectively. The different TOC profiles explain
why the Hekkingen Formation, which is richer
in organic matter than the Draupne Formation,
has weaker top but stronger base amplitude
reflections. Based on the established characteristics, the source rock presence, thickness,
and basinwide variations in organic content
can be mapped using seismic data. Seismic AI
data from the source rock interval can be transformed to TOC percent values where good local
well calibration can be obtained. We believe
that the findings from this study will change the
way petroleum systems are evaluated in basin
analysis studies.
ACKNOWLEDGMENTS
We thank Knut Georg Røssland, former chief geologist, Statoil ASA, who suggested the idea of studying
organic-rich claystones on seismic data. We are also
grateful to Statoil ASA for allowing the results of inhouse research to be published.
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Manuscript received 6 April 2011
Revised manuscript received 4 July 2011
Manuscript accepted 28 July 2011
Printed in USA
GEOLOGY, December 2011