Coordinated by Satinder Chopra
FOCUS ARTICLE
Fracture Detection Using 3D Seismic
Azimuthal AVO
David Gray
CGGVeritas, Calgary, Alberta, Canada
Abstract
Azimuthal Amplitude Versus Offset is a new seismic method
that is gaining popularity amongst those investigating fractured reservoirs. It is also known as AVAZ for Amplitude
Versus Angle and aZimuth, AVOA for Amplitude Versus
Offset and Azimuth and AzAVO. This paper will use the term
AVAZ.
The AVAZ method is examined using examples to determine
whether it is providing valid information about the fractures
at existing wells. It is tested in reservoir characterization to
see if it helps to predict the production rates of new wells.
This is followed by a discussion of how AVAZ can be used in
structural interpretation.
Introduction
The AVAZ method can be used to identify the presence of
fractures between well locations using wide-azimuth 3D
seismic data (e.g. Gray and Head, 2000, Hall et al, 2000, Gray
et al, 2002). Fractures are defined as cracks in rock that typically have apertures of a few millimeters or less. They usually
show little or no displacement along their faces, i.e. they are
not faults. As the fractures are so much smaller than a seismic
wave, which is typically tens of meters in length, the AVAZ
method is only capable of detecting the cumulative effect of
swarms of aligned fractures and not individual fractures.
Further, these fractures must be close to vertical. Fortunately,
these conditions frequently exist for fractured reservoirs.
In the mid 1990’s, it began to be shown that there are measurable differences in the seismic AVO responses parallel and
perpendicular to fractures, (e.g. Lynn et al 1996, Mallick et al,
1998, and MacBeth et al, 1997), suggesting that AVAZ would
be a viable technology. In the late 1990’s, AVAZ began to be
used on 3D datasets and quickly provided evidence of its
importance (e.g. Gray et al, 1999). Early work showed that the
AVAZ signal is detectable in 3D seismic, (e.g. Gray et al, 1999,
Hall et al, 2000, Jenner, 2001, and Gray et al, 2002). It has
also been shown that AVAZ results correlate to known
geology, (e.g. Gray and Head, 2000, Gray et al, 2002). Here,
examples are examined to validate that the seismic AVAZ
attribute does indeed provide additional useful information
about the fractures in a reservoir.
Following a brief discussion of the AVAZ method, this paper
examines some short case histories in which seismic AVAZ
has been used in reservoirs where geologic information is
available to check and to calibrate the AVAZ response. The
first example is from Manderson Field in Wyoming, a
Permian age carbonate reservoir (Gray and Head, 2000). The
second is from the Pinedale Anticline Field, Wyoming, which
is a Cretaceous tight sandstone reservoir that developed in a
braided stream environment (Gray et al, 2003). After establishing the validity of the AVAZ method, the question is
asked: How can geologists contribute to the interpretation of
these data? To answer this, the AVAZ analysis of the
Narraway Anticline Field in western Alberta, Canada is used.
The Narraway Anticline reservoirs of interest are Cretaceous
tight beach sandstones, (Todorovic-Marinic et al, 2004).
Method
After making some assumptions, AVAZ can be shown to be
representative of Thomsen’s (1995) crack density measurement (Lynn et al, 1996). AVAZ takes advantage of the fact that
Figure 1. Fractures respond to the seismic wave like a spring. The rock is weaker perpendicular to the fractures because the fractures respond more easily to the stress
induced by a seismic wave perpendicular to their strike (a), than they do when the seismic wave is parallel to the fracture strike (b).
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fractured rocks perpendicular to the fractures are weaker, and
therefore more compliant, than fractured rocks parallel to the
fractures. Fluid-filled fractures respond somewhat like a spring
to the seismic wave as it passes across them (Figure 1a).
Typically, for this spring-like phenomenon to be significant, the
seismic wave must hit the fractured layer at a significant angle
from the vertical. The seismic wave traveling parallel to the fractures does not encounter this spring-like behavior (Figure 1b) to
the same degree. Thus, the seismic waves striking the reservoir
from different directions see different rock properties when the
reservoir rock contains fluid-filled fractures. The AVAZ method
measures the magnitude and direction of these differences in
rock properties, which is known as seismic anisotropy.
The AVAZ technique requires wide-azimuth 3D seismic data.
Differences in AVO responses from 2D lines over known fractured reservoirs can be an indicator that the AVAZ technique will
work, but no differences do not necessarily mean that there are no
fractures; the 2D lines could simply be oblique to the fracture set.
The AVAZ technique can frequently be applied to existing 3D
seismic datasets. This is especially true for land surveys in North
America where data has been acquired with wide azimuths for
many years. Because the key factor for the applicability of AVAZ
is the azimuthal coverage, most AVAZ studies to date have been
done using land surveys with the exception of a few using OceanBottom Cables (OBC), (e.g. Hall et al, 2000 and Roberts et al,
2001). Typical marine streamer surveys are not candidates for
AVAZ analysis as they usually have narrow azimuth geometries.
The primary requirement is that some of the seismic waves hit the
reservoir at a sufficient angle from the vertical. In order to receive
resolvable signal, this should be at least 30º in the inline direction.
This is generally the case in modern surveys and is usually
achieved if the maximum shot-receiver offset is equal to the
depth of the target reservoir. For example, for a target at 9000 ft,
the maximum shot-receiver offset should be at least 9000 ft. The
wide azimuth requirement for AVAZ necessitates that some
seismic waves must hit the reservoir at a sufficient angle in the
cross-line direction. Using a surface-fitting AVAZ technique
where an equation relates the seismic amplitudes to angle and
azimuth (e.g. Rüger, 1996) allows some relaxation of the requirements in the cross-line direction, provided that the inline offset
allows for angles of at least 30°. Satisfactory results have been
achieved when the cross-line maximum offset allows the seismic
wave to strike the reservoir at 20° or greater using a surfacefitting AVAZ algorithm. The higher this angle range in the seismic
data, the better the signal-to-noise ratio will be in the AVAZ
results, provided that the assumptions of the method are met.
The assumptions typically used in modern AVAZ analysis are
the following:
1.
Small contrasts in elastic parameters, P-wave velocity, S-wave
velocity and density, between the reservoir and the
surrounding rock.
2.
Weak seismic anisotropy (Thomsen, 1986).
3.
The reservoir behaves as an Horizontally Transverse Isotropic
(HTI) medium, i.e. the reservoir contains a single set of
aligned, vertical, penny-shaped cracks.
4.
The seismic wave strikes the reservoir at small incidence
angles (<35°) from the vertical.
5.
The azimuth of the seismic wave at the reflection point is the
same as the shot-receiver azimuth.
Practically, AVAZ seems to work in the following situations:
1.
The seismic anisotropy is caused by fluid-filled fractures, i.e.
filled with brine, oil or gas.
2.
There is a single fracture set. This can come about in two ways:
a)
There is a single set of aligned vertical fractures within
one seismic superbin (approx. 100x100 m2).
b)
There are multiple fracture sets under the influence of a
stress field where the maximum horizontal stress field
is significantly stronger than the minimum horizontal
stress.
3.
There is a fracture set that is near vertical (>65°).
4.
The fractures are connected (Maultzsch et al, 2002).
In order to measure an AVAZ response, there must be some
coherent signal from the reservoir. Where there is signal continuity, the AVAZ technique works well (Soto Aguila et al, 2003). If
the signal is incoherent, then the rocks are probably so broken up
that another seismic measurement, such as signal continuity, will
give more insight into the fracture distribution.
Strong acquisition footprint can be a significant contributor to
difficulty in understanding the AVAZ result. The acquisition
footprint is an imprint of the surface geometry of shots and
receivers on the seismic data. It is most easily observed as linear
amplitude anomalies parallel to the acquisition geometry in
timeslices of the seismic dataset. Footprints can occur when shot
and/or receiver line spacings are not suitable for the target reservoir. Improper acquisition for the target reservoir can lead to
AVAZ responses showing acquisition footprints that overwhelm
the AVAZ response. Prescreening of every 3D dataset for footprint and the maximum incident angles in the inline and
crossline directions to ensure that they are suitable for AVAZ is
relatively simple and quick. This prescreening rejects those
datasets that are unsuitable for AVAZ analysis early on. I believe
that this prescreening has had a significant impact on the acceptance of the technique in the industry by significantly increasing
the proportion of successful AVAZ applications.
Examples
Examples of estimating seismic azimuthal anisotropy using the
AVAZ technique on 3D seismic data are compared to geologic
and production methods of identifying fractures that have been
used in these reservoirs. The examples are Manderson Field,
after Gray and Head (2000) and Pinedale Anticline, after Gray
et al (2003).
Manderson Field
The Manderson Field was discovered in 1951. It is located on a
sharp, asymmetric, northwest-plunging anticline. It produces oil
and gas from Pennsylvanian, Permian and Cretaceous horizons.
The most productive zone, the Permian Phosphoria, is a complex
interval consisting of a thick unit of medium-to-thick bedded,
fractured carbonate at a depth of 6500-8500ft.
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The field has several wells with cumulative production in excess
of original oil-in-place estimates. Low matrix porosity, production history and strong pressure support in these wells suggest
that oil is produced from a fracture system with significant
lateral connectivity. A wide-azimuth 3D seismic survey was shot
in 1996 to improve structural definition of the reservoir. Three
oriented core analyses, acquired between 1996 and 1998 within
the 3D-survey area, are available for comparison. Analysis of
fractures in the cores shows varied and multiple fracture orientations at all these wells.
Figure 2a shows the fracture strikes estimated from the seismic
data around the location of Well 43-33, which is the most prolific
well in the field. Having produced one million barrels of oil since
1953, it continues to produce with strong pressure support to this
day. AVAZ analysis was performed on a half-mile square around
the well location. The results show a very complex fracture
pattern. The fractures estimated using AVAZ are compared to an
analogue found in an outcrop of fractured Liassic limestone from
the coast of Wales (Figure 2b). Interestingly, the pattern of fracturing seen in the Liassic limestone is very similar to the fracturing
Figure 2. AVAZ fracture analysis results from Phosphoria limestone centered on Well 43-33 in the Manderson field (a) shows fracture complexity similar to Liassic limestone
outcrop from the coast of Wales (b) shows fracture complexity similar. Line orientation in (a) indicates fracture azimuth while line length and background color indicate fracture density. Highest fracture densities are colored blue and green. Scale 1/2 mile x 1/2 mile. Outcrop photograph courtesy of Dr. J.P. Petit.
Figure 3. a) Tensleep dolomite sand dune sequence exposed on a cliff, cutting through part of the Zeisman Dome, 10 miles SE of the Manderson Field. b) The sub-horizontal,
thin, recessed portion of the cliff at the base of the dolomitic sand dune sequence. Photographs courtesy of Golder Associates.
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estimated around Well 43 33. Therefore, this analogue may be a
useful guide for interpretation of these complex AVAZ results. The
complicated fracturing seen in this small outcrop provides confidence that the complex fracture patterns indicated by the AVAZ
fracture analysis technique at Manderson Field do indeed occur
naturally. A small fault runs from the bottom left to the top right
of the photograph of the outcrop. Fractures curl into the fault at
the top of the photograph and fractures abut against the fault at
near right angles near the center of the photograph. Similar
patterns can be seen in the lower half of the fracture analysis
around Well 43-33 (Figure 2a). Auzias et al (1997) suggest that this
complex fracturing in the Liassic limestone is due to a second
stress field applied to already fractured or faulted rock. In the case
of the Phosphoria reservoir in Figure 2a, the fractures shown by
the AVAZ analysis would therefore suggest that small-scale faults
were already present when the rocks around Well 43-33 were last
stressed. Suggestions of some of these pre-existing but sub-seismic
scale faults can also be seen in the results of the fracture analysis
in Figure 2a to the south of the well location where the fracture
strike changes abruptly. These fractures curl southeastwards into
what can now be interpreted as a fault. To the south of this interpreted fault, the fractures abut against it at right angles. This is
conspicuously similar to the photograph of fractures around a
fault in the Liassic limestone shown in Figure 2b.
Taking this analogy further, a fault can also be interpreted to the
northeast of the well location. The top of the anticline is to the
northeast of this location and it plunges to the northwest.
Therefore, if these faults are sealing, a fault trap exists within a few
hundred feet of this well location. In addition, the fractures indicated to the west of the well location are some of the largest indicated by AVAZ in the field and could be a delivery system
allowing downdip oil to be drained by this well. Thus, through
Figure 4. Dip section showing fracture strikes estimated from the seismic data around Well 43-33.
Note that fractures in the Tensleep dolomitic sand
have a consistent E-W fracture strike (green )
compared to the rest of the formations where the
majority of the fractures strike NW-SE (blue).
interpretation of the AVAZ results, a reasonable explanation for
the prolific production at this well has been described.
Figure 3a shows outcrop of the Tensleep Formation at Zeisman
Dome 10 miles southeast of the Manderson Field. Here, the
Tensleep consists of a dolomitic sand dune sequence. This formation, at the base of the dunes (Figure 3b), is a mechanically weak
rock that is much more susceptible to erosion than the rocks
above and below it. As a result, this thin interval forms a
mechanical boundary within the Tensleep that does not allow
fractures to pass through it as can be seen in Figure 3b. The AVAZ
analysis at Manderson suggests that fracturing is very complex
and it appears to be formation dependent. LaPointe (1999)
observed that the fractures here in the Tensleep are of different
orientation than most of the rest of the fractures observed in
outcrops of other formations. In these outcrops, most of the fractures are oriented NW-SE, while the fractures in the Tensleep
strike E-W. Figure 3b shows that even large fractures in the
Tensleep do not cross formation boundaries. The AVAZ analysis
of the Tensleep formation at a depth of about 7000 ft (Figure 4) is
consistent with LaPointe’s observations. It suggests that the fractures within the Tensleep at Manderson Field consistently strike
E-W, while a large proportion of the fractures in the other formations strike NW-SE. The AVAZ also indicates that the fracturing
is formation dependent, with a sharp change from NW-SE to EW striking fractures at the top of the Tensleep and then back
again to a NW-SE strike at its base. Thus, there is a good indication, from outcrop, that the seismic AVAZ fracture analysis is
detecting the correct orientation of the fractures.
Within the area of the 3D seismic survey, three oriented core
analyses were preformed to characterize fractures. These core
analyses are compared to the results derived from the AVAZ
fracture analysis to confirm the AVAZ results. Issues in core
Figure 5. a) Rose diagram from the oriented core analysis performed on Well 34-18, a gas producer, showing the distribution of all open fractures observed in the producing Phosphoria formation indicates two fracture trends centered
around 85º and 345º. In all, there were 92 fractures observed in the Phosphoria core of which 42 were open. The average
aperture of the open fractures is 0.04mm, which is in the middle of the observations from these core analyses. b) Map
of estimated seismic fracture strike and crack density map around the same well. The fracture analysis is shown over a
half-mile by half-mile area and red and yellow indicate moderate-weak fracturing throughout the mapped area.
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orientation analysis could result in error bars of up to 30º in the
fracture strike. The AVAZ seismic strike measurements are accurate to within ±11º for this survey.
Core analysis for Well 34-18 shows two predominant orientations of open fractures at 85º and 160º (Figure 5a). By comparison, the seismic fracture analysis estimates the strike of open
fractures at this location to be 90º (Figure 5b), very close to the 85º
orientation observed in the well. Moreover, this well is an excellent gas producer with moderate values of fracture density
observed in both the seismic and the core analysis (Figure 7 –
middle point). Examination of the fracture strike estimated using
AVAZ around this well suggests that two flow paths may be
converging at this location. This may be the reason this well
produces at a high rate.
Core analysis for Well 42-24 (Figure 6a) indicates 17 fractures, all
but one of which is cemented or closed, i.e. this rock in effect has
no open fractures. The seismic fracture analysis estimate also
indicates that there are no open fractures at this well location
(Figure 6b), consistent both with the well observations (Figure
6a) and the theory used to develop this technique (Thomsen,
1995). In addition, after testing no reservoir fluids, this well was
plugged and abandoned two days after drilling. Therefore, it can
be concluded that this well and the area around it effectively
have no open fractures. The potential for dry holes such as this
to be avoided is greater if seismic fracture analysis is done prior
to drilling.
Figure 7 shows the relationship between the seismic AVAZ crack
density estimate and the average aperture of the fractures
observed in the three wells that have oriented core analyses. The
results suggest that larger crack density values indicate wider
average apertures of the fractures. Using only three data points,
it is difficult to make any definitive conclusions. Still these
results are consistent with the theory that was used to develop
the AVAZ technique.
Pinedale Anticline Fractured Reservoir
Characterization
The Pinedale Anticline in Wyoming, USA, has become an area of
significant interest since the recent success of several wells that
have produced significant volumes of gas from its tight sandstone reservoirs. The Pinedale Anticline has been estimated to
contain 159 TCF of in-place sweet gas (Law and Spencer, 1989),
of which only a tiny proportion has been produced. The reservoirs of current interest in the Pinedale Anticline are the tight
sands of the Lance and Mesaverde Formations. These units were
deposited during a period of rapid sedimentation in the late
Cretaceous. Sediments were eroded off the western upland and
carried by fluvial systems flowing to the east. Lithologically, the
Lance and Upper Mesaverde consist of fluvial channel sandstones and siltstones, floodplain shales, and minor coals.
Production from these reservoirs is now possible using new
stimulation techniques developed in neighboring Jonah Field.
The best production rates appear to come from reservoirs that
have had their permeability enhanced by natural fractures.
Therefore, the ability to detect the presence of natural fractures in
the reservoir could have a significantly positive impact on the
success of future wells. The AVAZ technique has been used on 50
square miles of CGGVeritas’ 203 square mile, multi-client,
Pinedale 3D seismic survey over the Pinedale Anticline to identify the presence of these fractures. The results have been incorporated into a fractured reservoir characterization run for this
field. The reservoir characterization is shown to successfully
predict early well production, by comparison to the production
of a successful well drilled shortly after the completion of the
reservoir study.
Figures 8 and 9 show how zones of crack density can be visualized. Figure 8 shows geobodies of crack density generated
Figure 6. a) Rose diagram from the oriented core analysis performed on Well 42-24, a dry hole that produced no fluids, showing the distribution of all 17 fractures observed
in the Phosphoria reservoir formation. Only one of these 17 fractures only one is open. b) Map of estimated seismic fracture strike and crack density map around the same
well. The fracture analysis is shown over a half-mile by half-mile area and the lack of tick marks in the white areas indicates no open fractures in and around the well location.
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around the track of one of the better producing wells in the
Pinedale Anticline Field. These geobodies correlate well with the
zones where hydraulic fracture treatments have been run in the
wellbore. The location of these fracture treatments was determined from the mud log. The fracture treatments were run
where significant mud-loss occurred during drilling. It is
presumed that mud-loss measured in the mud log indicates
areas where the mud flowed into natural fractures and therefore
where the wellbore encountered these fractures. Since these
zones correlate well with the crack density geobodies, it can be
assumed that these geobodies give some idea of the fracturing in
this reservoir. Figure 9 displays a view from the north showing
Figure 7. The average aperture of open fractures as measured from core versus crack
density measured using AVAZ.
Figure 8. An example of the visualization of fracture swarms around the well track
of a productive gas well in the Pinedale Field through visualization of crack density.
Hot colors are high crack density, cool colors are moderate and low values have been
removed using the opacity editor. Hydraulic fracture treatments performed in this
part of the well indicate zones where the well probably encountered natural fractures.
the distribution of the crack density geobodies in the Pinedale
Anticline. It suggests that the bulk of the fractured zones occur to
the west (right) of the crest of the anticline. Recent drilling in
this area has produced some of the best producing wells on the
anticline to date (e.g. Gray et al, 2003). The bulk of the earlier
wells were drilled on the crest of the anticline, none of which
have produced as well as recent wells. Completion techniques
contribute to this, but these results suggest that the area just
to the west of the crest may be preferentially fractured. This is
the steeper dipping side of this asymmetric anticline with a fault
to the western side petering out to the north, all suggesting that
this is an area of significant stress. This would account for
the increase in the number and intensity of the crack density
anomalies in this area.
Recently it has become possible to incorporate AVAZ attributes
into reservoir characterization (Gray et al, 2003). This innovation
is extremely important because it allows for better determination
of fracture information between the wells and thus a better understanding of fluid flow in the reservoir. Historically, fractured reservoir characterization has been done with well information and
indirect measures of fracturing between the wells, such as curvature, distance from faults and lithology. The seismic AVAZ results
provide a direct measurement of the effects of fractures between
the wells. However, these results have been difficult to tie to well
control in the past due to the paucity of direct fracture indications
at the wells. Because of this limited well control it is difficult to
relate the seismic anisotropy measurements to the fractures.
Figure 9. View from the north end of the Pinedale Anticline using opacity to show
geobodies of high crack density (red-yellow) between the top of the Upper Lance
formation (upper horizon) and the top of the Mesaverde formation (lower horizon)
with well traces.
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Boerner et al (2003) use neural network reservoir characterization
(Ouenes and Hartley, 2000) to predict production in the Pinedale
Anticline Reservoir, incorporating the AVAZ attributes with those
mentioned above.
The neural network is used by first identifying a fracture indicator (FI) and then ranking the variety of inputs that the geoscientists and engineers familiar with the field suggest may have
influence on it. For the Pinedale Anticline Field, four-month
cumulative production is chosen as the fracture indicator. This is
the best indicator of fractures in this field due to the scarcity of
good well information on the fractures, and limited production
from the recent, better wells. The field has very few long-term
producers since it has only recently been revitalized by the aforementioned new completion techniques and the clearance of
some environmental issues. This FI correlates to Expected
Ultimate Recoverable (EUR,) a measure that is often used as a
fracture indicator (Figure 10). It also has the advantage that it
allows for the prediction of early production from a well. The
Figure 10. Correlation between four-month cumulative production and EUR.
AVAZ and other seismic attributes are used as inputs to the
neural network’s ranking process along with geologic models of
porosity, net-to-gross, and coal and the structural interpretation.
The geologic information was derived from the analysis and
interpretation of wells available in the public domain and from
interpretation of CGGVeritas’ Pinedale 3D speculative seismic
survey. The rankings of the most important of the inputs to the
neural network in predicting the FI are shown in Figure 11. The
AVAZ crack density and its envelope (Todorovic-Marinic et al,
2003) are the most important attributes in these rankings. They
are even more important than the next best ranked attributes, the
semblances, a measure of signal discontinuity, which are
commonly used for fracture detection. Additionally, it should be
noted that typical geologic indicators like slope and curvature
are only ranked 7th and 10th, with only about half the rank
correlation coefficient of the aforementioned seismic indicators.
This strongly indicates that the seismic AVAZ analysis is adding
important new information to the understanding of production
in this reservoir.
Figure 11. Neural network rankings of the relative ability of various attributes to
predict the fracture indicator in the Pinedale Anticline Field. LL indicates the interpreted depth of the top of the Lower Lance formation, ML the Mid-Lance and UL
the Upper Lance. K indicates the interpreted depth of the top of the Cretaceous.
Figure 12. On the left is the predicted FI, four-month cumulative production from the Lance formation, output of the neural network using all attributes except those from
AVAZ. High production is indicated by hot colors and low by cool colors. In the center the new well, Riverside 4-10, is added to the FI prediction. On the right is the FI is
predicted using the AVAZ attributes. The Riverside 4-10 well completed in August 2002 is highlighted as the large white circle in the upper left of each of the displays.
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On the basis of the best ranked of these attributes, multiple realizations of the FI are generated by the neural network.
Realizations were created both with and without the AVAZ
attributes, with all other attributes remaining the same.
Based on the fractured reservoir characterization, including the
AVAZ results, we predicted in July 2002 that Ultra Petroleum’s
Riverside 4-10 well, then being drilled, would be among the best
producers from the Pinedale Anticline Field (Gray et al, 2003).
An FI showing 4-month cumulative gas production of 560
MMCF (Figure 12c) was predicted. Using the attributes traditionally used to identify fractures in this reservoir, the FI prediction
indicates that Riverside 4-10 should only produce only 2 MMCF
in 4 months (Figure 12a). Riverside 4-10 had initial production
(IP) of 13.6 MMCF and in its first four months of production,
produced 461 MMCF of gas (WOGCC Riverside 4-10, 2004). The
best well in the field to date is Riverside 1-4 that produced 699
MMCF in its first four months of production (WOGCC,
Riverside 1-4, 2004). Thus the production from Riverside 4-10
confirms the neural network prediction incorporating AVAZ
showing that this would be one of the best wells in the field.
Also, the FI derived using AVAZ (Figure 12c) suggests that the
high FI indicated at Riverside 4-10 may continue to the north to
the best wells, including Riverside 1-4 just outside our study
area. This also suggests that the use of AVAZ allows for a more
accurate prediction of production.
The reason the reservoir characterization without AVAZ did not
predict the production at Riverside 4-10 can easily be understood. Since this is a relatively new field, it is undersampled by
the wells. Most of the wells drilled to date have been drilled on
the top of the anticline. It turns out that most of the wells previously drilled on the flanks of the anticline have been relatively
unsuccessful. Therefore, in any statistical analysis there is a bias
Figure 13. AVAZ crack density results along a W-E dip line intersecting the
Riverside 4-10 well location. Note the stacked large AVAZ crack density anomalies
(red) at the location of this successful well.
towards wells on the top of the structure because all previous
successful wells have been structurally high. As a result, depth
attributes are relatively important in the rankings (Figure 11).
Riverside 4-10 is located down the flank of the anticline between
its top and the fault on its western limb. This is the area that the
AVAZ analysis has identified as being more highly fractured.
Incorporation of the production from this well shifts the major
production to the west between the top of the anticline and the
western fault (Figure 12b). Through the incorporation of the
AVAZ crack density attribute, which is high in the region where
this well has been drilled, the neural network has been able to
extrapolate the successes on the top of the structure down-flank
to where this well has been drilled (Figs. 13 and 14).
AVAZ as a fracture indicator
Based on these and other comparisons of AVAZ results to
geologic indications of fractures (e.g. Gray et al, 2002), it seems
that the seismic AVAZ attributes do reflect the fracturing as
understood from geologic studies of the same rocks and formations. In addition, the AVAZ attributes seem to provide important information on the distribution of fractures between the well
locations. This information can be used to understand the reservoir, as at Manderson, and to help to predict production prior to
drilling new wells, as at Pinedale.
How can Geologists use AVAZ?
It has been shown that AVAZ technology can add significant new
information to the understanding of fractured reservoirs, but it is
not the “be-all and end-all”. There are significant issues and
assumptions that need to be addressed. First, the AVAZ attributes are indications of the change in crack density and the
Figure 14. Dip line from 3D volume after fractured reservoir characterization
showing variations of the Fracture Indicator with depth
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change in the fracture strike. Normally, it is assumed that the
overlying layer is seismically azimuthally isotropic, which it
frequently will be if it forms a seal. Geologists can help with the
understanding of whether or not this assumption and the other
assumptions used in AVAZ are reasonable for a given reservoir.
One important issue in seismic fracture analysis is that there is an
ambiguity in the AVAZ equation (Zheng et al, 2004). This can be
expressed as either a 90º ambiguity in the fracture strike or as a
sign ambiguity in the value of the change in the crack density. In
order to resolve this ambiguity additional information is
required. For example, Zheng et al (2004) used information on
the fracture strike from FMI logs to determine the correct orientation of the fractures in the reservoir in the Narraway Anticline.
Oriented core analyses, e.g. at Manderson Field, can resolve the
fracture strike ambiguity. Knowledge of where the reservoir lies
within the seismic and where the fractures start or end within the
reservoir can resolve the sign ambiguity in the crack density.
Structural geologists should be involved in the interpretation of
AVAZ results. For example, the Narraway Anticline shows
significant AVAZ anomalies on the backlimb of the thrust sheet
(Figure 15). Drilling on the leading edge of this thrust sheet has
generated wells that initially produced 2-3 MMCF/D. However,
interpretation of the AVAZ anomalies on the backlimb shows
that they correlate with the better producers in the field, with
initial production from those wells that intersect the anomalies
being an order of magnitude higher than those that don’t
(Todorovic-Marinic et al, 2004). Upon observation of these
results, Lacazette (2004a) presented a structural model, shown in
Figure 16, that offers a possible explanation for the increased
fracturing observed on the backlimb in the AVAZ attribute
(Lacazette, 2004b). This model suggests that there were two
episodes of fracturing during the evolution of this structure
which thereby reveals why more fracturing might be expected
on the backlimb as is indeed observed. Further study is required
to confirm this model and then to indicate why these fractured
zones seem to occur in pods along the strike of the structure.
Conclusions
Examples have been shown to demonstrate that crack density
and fracture strike estimated using seismic AVAZ correlates with
known fracture indicators. The AVAZ results are consistent with
core, outcrop, production, well logs and structural interpretations. Because the AVAZ records this fracture information
between the wells, it adds significant information to the interpretation of fractured reservoirs that cannot be easily obtained in
other ways. This information is not perfect and so should not be
used alone but should be included in the structural interpretation of the reservoir. R
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