t
Special section: Geoscience follow-up papers from URTeC 2013 and 2014
Marcellus fracture characterization using P-wave azimuthal velocity
attributes: Comparison with production and outcrop data
Tanya L. Inks1, Terry Engelder2, Edward Jenner3, Bruce Golob3, Jacki S. Hocum3, and Darien G. O’Brien4
Abstract
Analysis of two 3D surveys, available well data, published outcrop data and subsurface information, as well
as production data available from the state of Pennsylvania, demonstrates that wide-azimuth seismic is sensitive
to variations in fracturing at the scale of individual pads or even individual wells. These variations in fracturing
begin to explain why production varies significantly, even locally, within the Marcellus Shale gas play. Rose
diagrams from quantitative fracture analysis using azimuthal seismic velocity volumes were compared with
published data from Appalachian black shale outcrops and subsurface fracture models proposed in various
papers to validate the results from subsurface data. These analyses provided insight into the rock fabric
and the presence of systematic joints that likely affect production. There was a strong correlation between
the low anisotropy and low heterogeneity of anisotropy and high estimated ultimate recovery (EUR). Additionally, interpreted fracture trend azimuths differed between areas of larger gas EUR and areas of smaller gas EUR
as defined by decline curve analysis. Some perforations were likely to perform much better than others along
the borehole, based on observed heterogeneity in the seismic profiles and map view.
Introduction
Although it has long been understood that natural
fracture systems are essential for achieving the best
production in Marcellus Shale gas wells, methodologies
for verifying the heterogeneities in these fracture systems in the subsurface are not well understood. Analysis of wide-azimuth, P-wave seismic velocity attributes
at the reservoir level, and for specific laterals or proposed laterals, can provide this insight. The azimuthal
variation in seismic velocities is an ellipse in the horizontal plane and can be characterized by three parameters: the fast velocity (V fast ), a perpendicular slow
velocity (V slow ), and the fast velocity azimuth. From
these parameters, we can also compute the proxy for
percent anisotropy as the difference between the fast
and slow velocities normalized by the fast velocity.
Rose diagrams from quantitative fracture analysis using
azimuthal seismic velocity volumes are compared with
the published data from Appalachian black shale outcrops and subsurface fracture models proposed in various papers to validate the analysis derived from the
subsurface data. Although this velocity anisotropy,
measured as azimuthal variations in velocity, can reflect
rock fabric or stress, we show evidence that the likely
source of these anisotropies is the presence of systematic joints.
Published data and azimuthal seismic attributes
show two primary joint sets, the J1 and a J2 sets, as well
as neotectonic J3 joints that affect the Marcellus and
other Devonian shales in the Appalachian Basin (Engelder et al., 2009). Evidence suggests that in organic-rich Devonian black shale intervals including
the Marcellus, J1 and J2 joint sets formed in sediments
at or near peak burial depth as a result of anomalous
pressures generated during thermal maturation of organic matter (Lash et al., 2004). Although authors
indicate that the east–northeast to west–southwest J1
joint set is generally restricted to the black shales,
the younger north–northwest to south–southeast J2
joint set is described as being more likely to extend
out of the black shales into overlying rock. The late
cracking of oil to gas released much larger volumes
1
IS Interpretation Services, Inc., Denver, Colorado, USA. E-mail: tlinks@is-interpret.com.
Pennsylvania State University, Department of Geosciences, State College, Pennsylvania, USA. E-mail: jte2@ems.psu.edu.
3
ION GXT, Denver, Colorado, USA. E-mail: edward.jenner@iongeo.com; bruce.golob@iongeo.com; jacki.hocum@iongeo.com.
4
Solutions Engineering, Lakewood, Colorado, USA. E-mail: dgobrien@alumni.mines.edu.
First presented at the 2014 Unconventional Resources Technology Conference. Manuscript received by the Editor 26 September 2014; published
online 11 March 2015; corrected version published online 4 May 2015.This paper appears in Interpretation, Vol. 3, No. 3 (August 2015); p. SU1–
SU15, 11 FIGS., 1 TABLE.
© The Authors. Published by the Society of Exploration Geophysicists and the American Association of Petroleum Geologists. All article content, except where otherwise noted (including republished material), is licensed under a Creative Commons Attribution 4.0 Unported License (CC
BY-NC). See http://creativecommons.org/licenses/by/4.0/. Distribution or reproduction of this work in whole or in part requires full attribution of the
original publication, including its digital object identifier (DOI). Commercial reuse is not permitted. The same license does not have to be used for
derivative works.
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of gas during the period when J2 joints were propagated. Although neither contemporaneous with nor
genetically related to folding, J1 and J2 joints in black
shales within the Finger Lakes area of New York strike
approximately parallel and perpendicular, respectively,
to the Alleghanian orogenic fold axes exposed there.
Similar patterns can be seen in seismic anisotropy
for the Analog 3D survey and for the Clearfield 3D survey, to the west, in Clearfield County, Pennsylvania.
Rose diagrams from azimuthal attributes are similar
to those measured for joints in outcrop in southern New
York (Fillmore Glen State Park) and in Central Pennsylvania. The J2 azimuths dominate in areas with higher
gas estimated ultimate recovery (EUR) wells, which
is attributed to more gas generation as well as longer
joint length. High-EUR areas also have generally lower
“interval V fast velocities” and show evidence of J2 joints
well above the top of the Marcellus in Hamilton Group
gray shales. Areas with low-EUR wells have a more
dominant J1 trend as well as other scattered azimuthal
trends, along with higher anisotropy, and a higher
standard deviation of anisotropy, which suggests
greater heterogeneity. Areas showing rapid spatial
variation in the predominant azimuth of anisotropy
imply possible reservoir compartmentalization and
heterogeneities that correspond with areas of lower
production. These attributes offer a tool to high-grade
drilling opportunities and improve production estimates for Marcellus wells.
Geologic setting
The Middle Devonian Marcellus black shale was
deposited on continental crust in an interior seaway
of relatively shallow water (<200 m ¼ 656 ft), under
relatively high sea level conditions (Kohl et al., 2014).
During the Middle Devonian, a microcontinent called
Avalonia depressed the southeast edge of the Laurentia
continental margin (now the Appalachian Basin) as a
consequence of thrust loading in a highland at the
edge of the continent. This created the accommodation space, in which the Marcellus and subsequent
black shales were deposited. The seabed was depressed
below a pycnocline, which is a boundary below
which oxygenated seawater does not circulate. Organic
material, mainly from marine algae, was preserved in
this oxygen-starved environment to be buried to a depth
favorable for oil and gas generation. The Marcellus,
which is the oldest of the units in the Hamilton Group,
consists of two major cycles of organic-rich shale accumulation, with the basal portion being particularly rich.
The Marcellus and other middle Devonian black shales
in the basin are limited in extent due to the tectonically
controlled variations in relative sea level change. One
model for the development of the richest black shale
is a very rapid transgression possibly accompanying
thrust loading with disrupted river systems, reducing
sediment flux into the basin, and favoring the accumulation of rock with a high total organic carbon (TOC)
content. Eventually, river channels organized to deliver
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clastic sediments at a higher rate, thus diluting the organic content of the shale. Each of the two cycles of
black shale, the Union Springs and the Oatka Creek
members of the Marcellus Formation, is bounded above
and below by a carbonate, indicating improved oxygenation/circulation of a basin still receiving minimal
clastic influx.
The axis of regional folding in the study area is dominantly east–northeast to west–southwest (parallel to
J1), primarily as a result of slip on a regional décollement beneath the Appalachian Plateau within the Silurian salt below the Marcellus (Davis and Engelder,
1985). Additionally, younger faults, especially north–
northeast to south–southwest faults that appear to cut
section above the Tully, a carbonate that caps the Hamilton Group, may allow gas to leak from the Marcellus
reservoir. Both fault trends may affect production from
the Marcellus. They may be significant when they are
connected to fractures near the borehole and may act
to rob the stimulation by carrying fluids away from
the borehole. For this reason, most horizontal Marcellus
wells are drilled to avoid the larger faults. In the Analog
3D survey area, wells have been drilled with the laterals
north–northwest or south–southeast to be perpendicular
to the contemporary stress field, and have terminated
before reaching regional east–northeast to west–southwest-trending regional fault cuts; however, some wells
appear to have been cut by the younger faults.
A seismic cross section oriented parallel to dip is
shown in Figure 1, which displays the structural style
of the project area within the Hamilton Group and adjacent formations. This line, also nearly parallel to most
horizontal well trajectories, shows the variable thickness of the Silurian Salt below the Marcellus, which
controls much of the larger scale structuring in this part
of the Appalachian Basin. Thrust faults with a décollement in the salt, similar to faults shown in green, may be
limited to the Marcellus and lower Hamilton group.
Large faults, similar to the red faults, parallel to large
folds related to salt deformation, are avoided when Marcellus wells are drilled. Young faults (not shown) are
often parallel to dip. These faults have likely reactivated
pre-existing zones of weakness and have variable offset
at the Onondaga and Marcellus. Some have significant
offset at and above the Tully. These larger structural
features are well understood and well documented in
the literature. The focus of this paper, however, is a
study of reservoir level joints and fracturing using seismic attributes.
Even though this play is a “resource play,” this study
shows that the reservoir fracturing is heterogeneous
and that not all well locations are likely to be economic.
The Marcellus play in northern Pennsylvania and
southern New York is a “shale gas” unconventional
resource play, commonly described as having no obvious trap or seal and no water contact. Unlike the
younger units in the Hamilton Group, the Upper and
Lower Marcellus Shale contain high gamma and high
TOC facies, which generated gas just prior to and dur-
ing the Alleghanian Orogeny. These shale plays depend
on fracturing to allow mobilization of the gas during
stimulation, as they have low, poorly connected matrix
porosity.
Azimuthal anisotropy
Seismic anisotropy refers to variation in elastic wave
propagation velocity that is directionally dependent.
Conventional P-wave processing algorithms ignore azimuthally dependent NMO by assuming heterogeneous
media, resulting in a single, isotropic velocity applied
to all traces in a common midpoint (CMP) gather. As described by Tsvankin and Grechka (2011), applying a single value of NMO velocity to the whole gather in a wideazimuth 3D survey causes underestimation of velocity in
the V fast direction and overestimation of the velocity in
the V slow direction for horizontally anisotropic media. In
addition to improving the overall stack, azimuthally dependent velocity attributes can provide insight into the
anisotropy of these data, including analysis of potential
fracture trends, and reservoir heterogeneity. For the
Analog 3D project, interval V fast , interval V fast –V slow percent, and interval V fast azimuth volumes revealed significant variations in subsurface trends and heterogeneities
that have been correlated to production.
Wide-azimuth anisotropic processing corrects the
time shifts remaining in gathers that are initially migrated with the best isotropic velocity. The velocities
are obtained by a surface fitting of the observed traveltimes in offset-azimuth space using the azimuthal traveltime-velocity equation given by Grechka et al. (1999).
The azimuthal variation of NMO velocity is obtained by
first picking traveltimes and then inverting those traveltimes for the azimuthal velocity. The traveltimes
are obtained by locally windowed crosscorrelations
in the CMP-time-offset domain as summarized by Jenner et al. (2001), Jenner (2011), and described in detail
by Jenner (2001). The results are traveltime picks every
20 ms for every trace in the CMP gather, which are then
inverted in offset-azimuth space using the azimuthal
traveltime-velocity equation given by Grechka et al.
(1999). Those residual time shifts that are not corrected
by the isotropic velocity are inverted to create root
mean square (rms) velocity volumes, rms V fast , and
rms V slow . More delayed traces are those that traveled
in the “slow” velocity direction, and less delayed traces
traveled in the “fast” direction. The azimuthal position
of the maximum and minimum (fast and slow) shows
the direction of aligned geologic fabric (in the Marcellus, fracturing) as fast, if it is primarily aligned in a single direction. And rms V fast and rms V slow are defined as
the maximum velocities of an ellipse, which defines the
velocity variation with the source-receiver azimuth.
The rms calculations are similar to an average value because they represent the sum of anisotropies from the
surface. Azimuthal variations are commonly corrected
Figure 1. (a) Dip line showing the structural style of the Marcellus Analog 3D survey and (b) gamma ray and delta-time for the
reservoir and adjacent stratigraphy for two wells in the Analog 3D survey. Time and depth scales shown are relative to local datums.
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in gathers where anisotropy is present to improve the
stack; however, these data can also be used to identify
anisotropies in the geology.
Figure 2 represents an example subsurface point,
with high rms anisotropy. Consider aligned fracture systems or other aligned changes in sedimentary fabric to
be “speed bumps” for a wave traveling perpendicular to
the aligned system in an anisotropic medium. If fractures or stresses are aligned unidirectionally, the traveltime is slower for a direction that crosses the speed
bumps, and would give a V slow direction perpendicular
to the fractures or alignments. Conversely, V fast is parallel to these speed bumps. The difference between the
calculated V fast and V slow as a percentage is a proxy for
percent anisotropy. If there is low anisotropy relative to
the scatter of velocity, the difference between V fast and
V slow is small, such that the azimuth of V fast cannot be
computed accurately. As with sonic scanner data, these
azimuth values are only useful if the percent anisotropy
is calculated to be more than approximately 3%. If
anisotropy is less than 3%, azimuthal values from these
data are within the margin of error, and should not be
used to develop a proxy for anisotropy. If the difference
between V fast and V slow is large, the “sinusoid” representing velocity variation with azimuth can be calculated with confidence. Then, a proxy for anisotropy,
defined by a V fast –V slow percent greater than 3% can
delineate the azimuth of V fast with minimal error.
Interval velocities are calculated from the rms velocities using a generalized form of the Dix equation (Dix,
1955; Grechka et al., 1999). This process effectively
strips off shallow layers, removing anisotropy from
layers above the zone of interest and computing the
anisotropy between the top and the base of an interval.
Because a low dip is assumed in the calculation of the
interval velocities, areas with higher time dip gradient
were eliminated from any analyses of the data. Interval
velocity calculations are based on a window crosscorrelation calculating the time shift required for a leastsquares fit. This is calculated at every sample in a
user-defined sliding window. The result may be noisy,
so smoothing is often applied. Smoothed data may
cause artifacts in the result, especially for azimuth
calculations, so interpreters may consider using unsmoothed volumes for calculations, keeping in mind
that some data values will be anomalous due to noise.
The anomalous anisotropy values mostly occur on the
edges of the survey and in low fold areas where the azimuthal contributions to the bins are not ideal. They also
occur in fault zones where raypaths cross large discontinuities and where imaging may be poor. Because
of this organization and predictability, we determined
that unsmoothed volumes could still be used for analysis with production, where these anomalies can be
avoided.
Natural hydraulic fracturing and the Marcellus play
Natural fracture systems are essential for achieving
the best production in Marcellus Shale gas wells. Analysis of wide-azimuth, P-wave seismic velocity attributes
at the reservoir level, and for specific laterals or
proposed laterals, provides insight into these natural
fracture systems in the subsurface. Published outcrop and core data, combined
with azimuthal seismic attributes all
show two primary joint sets, the J1
and J2 sets, as well as a neotectonic
J3 set of fractures that affect the Marcellus and other Devonian shales in the Appalachian Basin. For the Devonian black
shale intervals, J1 and J2 joint sets
formed in sediments when they were
at or near peak burial depth as a result
of anomalous pressures during thermal
maturation of organic matter (Lacazette
and Engelder, 1992). The east–northeast-trending J1 joints are more closely
spaced, and best developed in the more
organic-rich black shale units (Lash
et al., 2004). Although east–northeast
joints (J1 joints) are not well developed
outside the black shale intervals, joints
(northwest-trending J2 joints) that formed
during the Alleghanian orogeny are
found throughout the Upper Devonian
shale sequence. The two fracture sets
Figure 2. Example scatter of velocities for all traces within a wide-azimuth 3D
are crosscutting within the shales,
subsurface bin. The velocity variation indicates a large anisotropy, where the rms
which is important for the optimization
V fast –V slow percent (>3% in this case) is a viable proxy for anisotropy. The
of well placement and fracking of horiazimuth of V fast , in this case, is parallel to joints that cause anisotropy in the
Marcellus.
zontal wells. The earlier J1 fracture set
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(east–northeast trending), that resulted from initial gas
perpendicular to the oroclinal fold. J1 azimuths in the
Clearfield 3D survey are similar to those in the Analog
generation, is nearly parallel to the maximum com3D study area with an east–northeast trend similar, but
pressive normal stress of the contemporary tectonic
perhaps slightly more east–west than the present-day
stress field, a coincidence.
stress direction SHMax. The systematic changing of
The J1 joint set appears to be unique to gas shales.
J2 orientation from north–northwest to west–northwest
The J2 set appears to break out of the gas shales and
shows that the azimuthal variations are not related to
populate the rock above those gas shales. The second
stress. Present-day stress has been shown to remain
joint set may appear 305 m (1000 ft) or even as much as
consistent across northern Pennsylvania (Engelder
1219 m (4000 ft) above the gas shale. We interpret this
and Gold, 2008). Thus, unless the rock fabric shows linto mean that a large enough volume of gas was generear spatial variation, the joints and fractures are the
ated, so the section above the gas shale became overlikely source of anisotropy measured by seismic azimupressured to the extent it also was hydraulically
thal anisotropy.
fractured. Therefore, the section above the gas shale became charged with high-pressure gas as well.
It is hypothesized that the variable length of J2 joints
Anisotropy and productivity from Marcellus wells
and fractures that extend into the gray shales above the
Three-dimensional azimuthal analysis gives us the
Marcellus could be related to TOC. Because the J2
subsurface information that we need to understand
joints are related to the volume of gas generation, we
the potential fracture systems within the Marcellus,
should see changes in the length and presence of J2
as well as within zones adjacent to the Marcellus.
joints across the survey area if TOC is changing, and
The results of these analyses show how azimuthal seisthe amount of gas produced was variable across the
mic velocity attributes compare with the published outsurvey. Figure 3 shows, diagrammatically, the relationcrop data describing joint and fracture orientations in
ship between J1 and J2 fractures. The J2 joints, which
and above the Devonian black shale. These data may
are Alleghanian in age and perpendicular to Alleghanian
also be used to better understand the reservoir heterogeneities that occur in the reservoir due to natural hyfolds, grew episodically during the time of maximum
draulic fracturing and tectonic stresses. With limited
gas generation. Although the J1 joint set is described
well data and production data, we cannot completely
as being more closely spaced within the black shale inevaluate all the variables that affect production from
terval, the J2 joint set, which may occur over a much
the Marcellus. We can, however, find excellent correlalarger vertical section, may be more “visible” to the seistion between published data, in particular, azimumic tool because it is longer or because it is more likely
thal analysis of joints and fractures in outcrop, and
to be mineralized. This is described in more detail in the
azimuthal data from subsurface seismic. Additionally,
analysis of rose diagrams from the azimuthal velocity
there are numerous observations showing consistency
volumes that follow.
with regard to azimuthal velocity attributes and EURs
Virtually all horizontal wells within the Analog 3D
shown from decline curve analysis.
survey area to-date have been drilled in the north–
A map of northern Pennsylvania and southern New
northwest to south–southeast direction. In the ideal
York (Figure 4) shows rose diagrams from joint analysis
case, this allows horizontal wells to cross and drain
J1 joints where they are present. Subsequent staged hydraulic fracture stimulations run east–northeast, parallel to J1,
thus cross cutting and draining J2 joints.
In spite of being perpendicular to stress,
horizontal maximum (SHMax), J2 fractures are partially mineralized, propping
open the fractures, and allowing them to
contribute significantly to drainage of
the Marcellus gas (Wilkens et al., 2014).
Black shales in outcrops within the
Finger Lakes area of New York carry
east–northeast J1 joints, and J2 joints
approximately perpendicular to the Alleghanian fold axes exposed there (Lash
et al., 2004) (Figure 4). Similarly, azimuthal analyses for the Clearfield seismic
survey, west of the Analog 3D, in Clearfield County, Pennsylvania, show that
J2 azimuths from subsurface seismic
change orientation from north–northFigure 3. Diagrammatic model showing natural hydraulic fracturing associated
with shales of the Hamilton Group.
west to west–northwest to remain
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of shales in the Finger Lakes area of New York, along
with rose diagrams calculated from the interval V fast azimuth for the middle Marcellus, Cherry Valley, for the
Analog 3D and the Clearfield 3D (all azimuths, where
anisotropy is greater than 3%, as well as with low dip
gradients). J1 joints are consistently east–northeast regardless of the fold axis. The J2 joints (Figure 4a) show
an orientation perpendicular to the Alleghanian fold
axes exposed in the Finger Lakes area (Lash et al.,
2004). In these shales, the northwest–southeast and
north–northwest to south–southeast J2 joints dominate.
The fold axes continue south into Pennsylvania, and
they show a similar trend for the Marcellus Shale.
The rose diagram for the Cherry Valley interval from
the Analog 3D survey (refer to rose diagram, Figure 4b,
right) shows azimuthal trends similar to those on the
eastern side of the Finger Lakes district. The Clearfield
survey, a large survey that lies on the oroclinal fold belt
for the Marcellus, shows a J2 azimuth (Figure 4b, left)
that changes orientation from north–northwest for the
northern part of the survey (Clearfield 3D north) to
west–northwest in the central part of the survey (Clearfield 3D central), and then to nearly east–west in the
southern part of the survey (Clearfield 3D south), staying perpendicular to structure.
Outcrops of the Appalachian Valley and Ridge contain some J3 joint sets that correlate with stress orientation diagrams from the World Stress Map (Hancock
and Engelder, 1989; Figure 5). The Tully and Upper
Hamilton Group, above the interval that is influenced
by natural hydraulic fracturing, does not show J1 or
J2 azimuths. The rose diagram calculated from the
Top Hamilton azimuths in the Analog 3D, shown in blue
in Figure 6, matches this contemporary stress field
trend, which is typically between 58° and 69° east.
For further analysis of these trends at the scale of a
single pad, we summarize what has been observed so
far on the regional scale. First, the older J1 trend, attributed to natural hydraulic fracturing, is shown to be in
the range between 70° and 77° (east–northeast) for out-
Figure 4. (a) Outcrop measurements in southern New York are compared to (b) subsurface anisotropy azimuths in northern and
central Pennsylvania. A similar trend for J2 azimuths with orientation perpendicular to the fold axis is seen in the outcrop and
subsurface data. The southernmost rose diagram in the Clearfield survey is perpendicular to the nearly north–south-trending
fold axis in central Pennsylvania. Modified from Lash et al. (2004).
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crop and subsurface data in the Analog 3D survey and
the Clearfield survey. The J2 trend, related to episodic
natural hydraulic fracturing during maximum hydrocarbon generation, is not perpendicular to the J1 trend, but
is perpendicular to Alleghanian folds, and generally
trends north–northwest in the analog survey. The younger J3 trend is shown to be between 58° and 69° (northeast), slightly more north of east than the J1 trend in this
area. The northeast azimuths captured in the shallower
Tully interval on the Analog 3D survey match very well
with World Stress Map (Heidbach et al., 2008) trends
shown in Figure 5. The Tully is well above any likely
influence from J1 and J2 natural hydraulic fractures
or joints originating in the Marcellus Shale.
Initially, the azimuth of interval V fast was extracted
for three horizons (instantaneous amplitude of interval
V fast azimuth), the Top Hamilton, the Top Marcellus,
and the Cherry Valley. Values for azimuthal analysis
were limited to areas with greater than 3% anisotropy
to insure a statistical calculation that is above the noise
level for these data. The vertical variation in azimuth
indicated by these velocity attributes match the expected results for the geologic model. The J2 azimuths,
dominant in areas with higher EUR wells, are attributed
to higher gas generation and longer joint length, as
shown in our subsurface model (Figure 3). Areas with
low EUR wells show a more dominant J1 trend, with
limited influence from J2, perhaps because the joints
are shorter where less gas is generated.
Gas estimated ultimate recovery
from decline curve forecasts
Decline curve analysis is a reservoir engineering empirical technique that extrapolates trends in production
data. The most commonly used trending equations are
those first documented by Arps (1944), who was an
American geologist that published mathematical relationships for the rate at which production from a single
well declines over time. The gas EUR assumed an
economic limit when the forecasted gas rate fell below
Figure 5. Shallow azimuths calculated for the Tully and Upper Hamilton for the Analog 3D compare with various measurements
for the present day stress field, SHMax in the northeastern part of the USA. The dominant azimuth at the Tully is east–northeast–
west–southwest, with the anisotropic proxy for fracturing or stress direction at approximately 65°, as shown by the red lines,
which fits well within the range of 58°–69° northeast, which is attributed to the contemporary stress field. Regional stress rose
diagrams modified from Engelder and Gold (2008).
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Figure 6. Example gas historic stair-step production rate profile on sixmonth intervals with hyperbolic and exponential decline curve rate forecasts
to a 20 Mscf∕day economic limit to obtain EUR for a well in the Analog 3D
survey.
Figure 7. The EUR production bubbles (size increasing with increasing EUR)
are shown over the subset area index for the Analog 3D. Note that a swath of
lower interval V fast velocity, shown within the red oval, is associated with the
area of higher EURs. The bubble size is proportional to EUR.
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20 Mscf∕day. The economic limit is the
point in time at which the production is
assumed to cease because it is no longer
economic. The EUR was determined by
adding the cumulative historical production with the forecasted cumulative production to the economic limit. Publicly
available data for historic well production for the Marcellus wells in this study
were available from the state of Pennsylvania for six-month intervals through
December 2013. To obtain a monthly
production rate for decline curve forecasting, the six-month historic production data were divided equally among
the preceding six months creating a
stair-step profile. Decline curve forecasts were made assuming that hyperbolic decline converted to exponential
decline when the instantaneous decline
rate reached 10% per year. An example
of a decline curve for a well in the Analog 3D survey is shown in Figure 6.
Estimated ultimate recovery
comparisons with seismic attributes
The EUR values for wells in the
project were used to create a bubble
map with bubbles located at the midpoint of the horizontal well trajectory,
and are corendered with Cherry Valley
V fast velocity, shown in Figure 7. No production tests or other production data
were available to determine the variability of production along the length of the
horizontal well; however, lateral lengths
are similar throughout the study area,
and all wells were drilled by the same
operator. All of the horizontal wells
were drilled after the seismic data were
acquired; thus, none of the anisotropy is
due to well stimulation. Clusters of data
were analyzed for 16 small subset areas
(white rectangles) of similar EUR, to
correlate with seismic attributes. In
map view, Figure 7 shows that the
higher EUR pads are all within the lower
velocity fairway (for amplitude extraction on the Top Cherry Valley horizon)
outlined by the red oval. It is hypothesized that the lower interval V fast velocities may be due to the presence of gas
and/or pervasive fracturing. Vertical variations in anisotropy in these subset
areas were also analyzed. The seismic
cross sections A-A′ and B-B′ shown in
Figure 7 for subset areas 1, 2, and 5 (Figures 8 and 9) show these variations.
Figure 8. The changes in azimuth are seen
for the Marcellus (Cherry Valley is a limestone
marker within the Marcellus) and intervals
above the Marcellus in the high-EUR area 1
subset. The Marcellus and 25 ms above the
Marcellus show a J2 trend, whereas 50 and
75 ms above the Marcellus show the regional
SHMax trend pointing to the present-day
maximum stress as the catalyst for this anisotropy. This northeast trend is also seen in the
Top Hamilton/Tully.
Figure 9. The lower EUR well on the left shows mixed azimuths for the Marcellus, changing to an SHMax trend in the Hamilton
group. The Marcellus has anisotropy up to 10% in this interval, as indicated by interval V f − V s , the seismic proxy for anisotropy.
The higher EUR well on the right shows a strong J2 azimuth for the Marcellus, with mixed azimuths and the J2 trend remaining in
the interval 25 ms above the Top Marcellus. The anisotropy over much of this wellbore is very low, from 0% to 6%. The shallower
part of the Hamilton group and Tully consistently shows an SHMax trend. The upper part of the Hamilton Group and Tully displays
generally higher anisotropy than shown in the Marcellus and the lower part of the Hamilton.
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For area 1, seismic cross section A-A′ (Figure 8),
rose diagrams for the Onondaga, Cherry Valley, Marcellus and 25 ms (∼61 m ¼ 200 ft) above the Marcellus
show lower anisotropy overall and an azimuth of
V fast in the J2 direction. Figure 7 shows that the interval
V fast velocity of this area is generally low. Area 1 has the
highest decline gas EURs and may be showing a strong
influence from J2 joints above the Marcellus, which
have been attributed to more prolific gas generation,
and higher TOC. From 50 ms above the Marcellus
and shallower intervals, the azimuth of V fast shows a
northeast trend, which is in the range of azimuths attributed to younger J3 stresses or fractures.
Areas 2 and 5, shown in seismic cross section B-B′
(Figure 9), have low and high EURs, respectively. Area
2 has mixed high and low velocities (instantaneous amplitude extraction calculated from interval V fast for the
Cherry Valley), and it is quite close to two significant
fault systems that may have negatively affected production. The rose diagrams calculated for the interval V fast
azimuth at the Cherry Valley in area 2 show dramati-
cally different results than in area 1. The low-EUR area
on the left side of the section shows a considerable
amount of scatter in the azimuths with J1 or J3 dominant for the Marcellus and other intervals. There is a
J2 component, but it is smaller than the J1 or J3 component. The higher EUR area on the right (area 5)
shows a strong, nearly north–south, J2 trend for the
Marcellus with minimal indication of the J1 trend.
Figure 10 shows rose diagrams from several highEUR areas. These wells show a dominant J2 azimuth.
This dominance of J2 suggests that these joints or
fractures contribute significantly to production. In this
analog area, where J2 is nearly perpendicular to the
contemporary stress field SHMax, it may seem counterintuitive that J2 fractures would be open and contribute
to production; however, closer examination of J2 fractures in core shows that these fractures are mineralized.
Wilkens et al. (2014) discuss evidence including increases in background gas concentrations while drilling, indicating that these J2 fractures are more
hydraulically conducive due to partial mineralization.
Mineralization acts to prop open the
joints or fractures and preserve porosity
as well as permeability within the fracture. Additionally, they confirm that dipole sonic logs demonstrate that where
these partially open veins are seen in
core, azimuthal shear anisotropy spikes
to values up to 10%. This observation
supports our statement that the J2 azimuths, perhaps due to higher anisotropy
from partial mineralization, dominate in
areas with higher EUR. Figure 11 shows
rose diagrams from two low-EUR areas.
These rose diagrams show numerous
azimuthal trends and a high degree of
heterogeneity that is not seen in higher
EUR areas. Although some of the areas
show a smaller (lower count) J2 trend, it
is always subordinate to other trends including the J1 and J3 trend azimuths. A
greater degree of heterogeneity also appears to be a consistent characteristic of
lower EUR areas, which have smaller
areas with a consistent azimuth, and
may also be adjacent to larger fault
systems.
Other azimuths at N30E appear to be
related to a young north–northeast to
south–southwest-trending fault system,
which dominates the eastern part of
the survey. Areas with high azimuthal
gradient (a high rate of change in azimuth) and a high calculated standard
deviation of anisotropy might also be
considered areas that are more heteroFigure 10. Rose diagrams generated for subset areas with high decline curve
geneous. There is a strong relationgas EUR consistently show a dominant J2 azimuth north–northwest to north–
ship between higher EUR and lower
northeast in trend. Some minor trends may be indicated for a lower number
of samples.
anisotropy, as well as low heterogeneity,
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which is represented by the standard deviation of
anisotropy across a subset area. In general, the highest
EUR areas have an average anisotropy of less than 5%,
with a standard deviation of less than 1.5% in the Analog
3D area.
not interconnected, so the bulk permeability of the immediate Marcellus approaches matrix permeability (Hubbert, 1957). If these joints are partially mineralized and
have a very high permeability, they still cannot leak unless interconnected (Pommer et al., 2013).
The most direct evidence that the Marcellus has
leaked over geologic time is the presence of mineralization of some, but not all J2 joints (Evans, 1995; Evans
et al., 2012). Unfilled and mineralized J2 joints are found
side by side in outcrops and core (Evans, 1994; Engelder et al., 2009). By the time of propagation of J2
joints, unfilled and mineralized, dewatering by compaction, and maturation had reduced the water saturation
of the Marcellus to an irreducible state (Lash et al.,
2004). The coexistence of unfilled and mineralized
joints indicates that capillary forces in a gas-charged
section prevented pervasive penetration of formation
water when it invaded from deeper, more porous,
and permeable beds such as the Oriskany Sandstone.
Invasion of water from below is indicated by the pres-
Discussion
In Devonian shales, a strong relationship between
azimuths derived from seismic anisotropy attributes
and those azimuths calculated from joints in outcrop
suggest that these seismic attributes are a valuable tool
for subsurface analysis of joints and fractures. Furthermore, variability in seismic anisotropy, heterogeneity,
azimuth, and velocity along individual well trajectories
indicates that the relationship between these attributes
and production are predictable despite their complexity. For the analog area, we have shown that high EUR
wells occur when a predominance of north–northwest
(i.e., J2) azimuths are indicated by seismic anisotropy,
along with lower velocity, lower heterogeneity, and
lower anisotropy. These attributes can
be used as a tool for high-grade Marcellus drilling and for designing better completions and stimulations. Potentially
lower EUR areas, with more seismic
heterogeneity, higher anisotropy, and
mixed azimuths, may be scheduled for
drilling after better locations are completed. Areas with dominant J2 azimuths
that are oriented more east–west, for example, in the southern part of the Clearfield 3D survey (Figure 4), where J1 and
J2 joints are more oblique, may point to
necessary adjustments in well trajectories for optimal drainage.
The area of our Analog 3D seismic
survey is of such a limited size (approximately 49 km2 is equal to approximately
30 mi2 ) that we presume that thermal
maturation was uniform within the Marcellus and did not cause pockets of
higher gas content. Certainly, the variation of fracture complexity is spaced at
a much smaller interval and in a much
more complex pattern than variations
in either depositional patterns or thermal
trends permit. These observations lead
to the conclusion that complex patterns
in productivity have another cause,
maybe local variation in TOC. However,
the correlation between more complex
fracturing as indicated by a heterogeneity
in azimuthal trends for anisotropy and
low EUR suggest that over the period because maturation during the Permian
there has been slow leakage of gas on
Figure 11. Rose diagrams generated for subset areas with low decline curve gas
a local scale and that the presence of a
EUR consistently show a scattered azimuth. Although the J2 trend may be
complex joint pattern was responsible.
present, the J1 trend may dominate. The scatter may be indicative of the heterogeneity of the area.
A single systematic joint set (i.e., J2) is
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attributes may require additional evaluation for Marcellus fracture identification
in western and southwestern Pennsylvania or West Virginia as the Marcellus, and
Standard
deviation of
EUR area
the Hamilton Group in general, thins. It is
average
Average V fast
Dominant
average
Average
worth considering methodologies to im(mcf) anisotropy anisotropy
Area
(velocity) azimuth direction
prove the resolution of these analyses
by sampling velocity at smaller intervals,
Area 1
5.14
4.93
1.49
Low V fast
J2
using smaller crosscorrelation windows,
Area 5
4.27
4.76
1.41
Low V fast
J2
and by using horizon-based azimuthal
Area 4
3.83
4.15
0.89
Low V fast
J2
velocity analysis. In areas with significant
Area 15
3.45
5.19
1.79
Low V fast
J2 and J1
structure, velocity attribute analysis erArea 10
2.6
5.55
1.71
Medium V fast J2 and J1
rors could be minimized by using preArea 8
2.49
4.63
1.24
Low V fast
J2 and small J1
stack depth-migrated gathers as input
Area 16
2.4
5.2
1.79
Medium V fast J2 and small J1
to the analyses.
The Analog 3D study shows seismic
Area 3
2.39
5.97
2.32
Low V fast
North–northeast
attributes that can be quantitatively anArea 9
2.21
4.99
1.22
Medium V fast J1, J2, and other
alyzed to evaluate undrilled areas of inJ2 and J1
Area 14
2.17
5.75
2.05
High V fast
terest in the Marcellus play. Table 1
Area 13
2.03
7.52
2.24
High V fast
NNE, J2
shows a summary, sorted by decreasing
Area 12
1.93
7.1
2.27
High V fast
North–northeast
EUR, for the Analog 3D area, comparing
Area 11
1.93
8.55
3.1
High V fast
J2
interval V fast –V slow percent as a proxy
Area 7
1.62
7.81
2.28
High V fast
J2, north–
for anisotropy, the standard deviation
northeast, and
of anisotropy as a proxy for heteroother
geneity, and the dominant azimuthal
Area 2
1.53
5.91
3.85
Medium V fast J1, J2, and other
component relative to EUR for each
Area 6
0.72
5.85
1.95
High V fast
J1 and J2
subset area within the Analog 3D survey. Areas with high azimuthal gradient
(a high rate of change in azimuth) and a
high calculated standard deviation of anisotropy are
ence of some mineralized J2 joints. It is likely that
considered to be areas that are more heterogeneous.
the combination of unfilled and mineralized J2 joints
There is a strong relationship between higher EUR
provides for the prolific gas production seen in the
and lower anisotropy, as well as low heterogeneity,
Marcellus.
which is represented by the standard deviation of
Slow leakage through a complex system of multiple
anisotropy across a subset area. In general, the highest
crosscutting fractures does not necessarily signal a
EUR areas have an average anisotropy of less than 5%,
rock volume that will rapidly leak stimulation fluid as
with a standard deviation of less than 1.5% in the Analog
implied by some in the literature (Warner et al.,
3D area. Using these criterion, risk is reduced in explo2012). For example, the J2 joints are more likely to have
ration plays in the northern Marcellus play. These
grown out of the Marcellus and into overlying rocks
attributes can be analyzed to prioritize a drilling sched(Engelder et al., 2009). Yet, these are the joints that
ule, and to avoid drilling potentially uneconomic wells.
seemed to have been “sealed” most effectively since
the early generation. Likewise, there is no indication
that the less economic wells in the study area have comConclusions
pletely leaked as indicated by a robust flow-back drive
The Analog 3D study shows seismic attributes that can
by high-pressure gas. This means that a relatively effecbe analyzed to evaluate undrilled areas of interest in the
tive capillary seal was maintained within the vicinity of
Marcellus play.
the Marcellus since the Permian despite a complex fracIn this study, we show that
ture pattern (Cathles, 2001). This is true even for those
wells relatively close to the zone of cross-formation
1) Regional fracture trends inferred from seismic azifaulting (Figure 1). Perhaps the effective capillary seal
muths correlate with published joint/fracture trends
might have formed as high in the section as the Tully
measured in outcrop, in other subsurface data and
Limestone; however, there is no indication of a comwith World Stress Map trends.
plete pressure breach through the Tully, even where
2) There are vertical and lateral variations in the folthere is a major disruption of bedding on the seislowing:
mic scale.
Clearly, P-wave velocity attributes provide a critical
a) azimuth,
understanding of Marcellus fractures and veins in the
b) interval V fast velocity,
northeast and north-central parts of Pennsylvania, where
c) implied anisotropy,
d) heterogeneity.
the Hamilton Group is relatively thick. These velocity
Table 1. Summary table for producing areas outlined in Figure 7
showing relationship of EUR to various azimuthal velocity attributes.
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3) Interpreted fracture trends differ between areas
with larger decline EUR and smaller decline EUR
values, making subsurface anisotropy analysis a predictive tool.
a) Higher EUR is indicated in subset areas where:
i) There is low anisotropy and low heterogeneity of anisotropy.
ii) Velocity anisotropy is less than an average
of 5%.
iii) The standard deviation of anisotropy is less
than 1.5%.
iv) The azimuth of V fast is dominantly in the J2
direction.
4) Some perforations are likely to perform much better
than others along the borehole, based on observed
heterogeneity in the seismic profiles and map
view.
5) Reservoir characterization described in the literature for the fracturing or joints induced by gas generation, specifically the J2 trend are supported by
these analyses. J2 fractures that break into the gray
shales above the Marcellus and other Devonian
black shales may give clues to the volume of gas
generated, and thus to the TOC. It has been shown
that J2 azimuthal trends, which have been attributed
to these joint/fracture trends persist above the Marcellus in areas that have higher EUR.
6) Some fault and fracture trends appear to be related
to recent fault movement, and may adversely affect
production.
Acknowledgments
We thank B. W. Horn and S. Volteranni at ION Geoventures for their support of this paper, and ION GXT
for permission to present and publish this paper. Also,
thanks go to M. Wallace, ION GXT, and K. J. McDonough for their help on various technical issues. Finally,
the authors thank IS Interpretation Services, Inc., the
Department of Geosciences, Pennsylvania State University, and Solutions Engineering for permission to publish this paper.
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Tanya Inks received B.S. and M.S.
degrees in geophysical engineering
from the Colorado School of Mines.
Since 1993, she has been providing integrated geophysical and geologic
consulting services in Denver, Colorado. She is currently involved with
projects in several unconventional
plays including the Marcellus Shale
play and the Niobrara play. She worked as a processor
for Geophysical Service Inc., and CGG prior to graduate
school, and worked for Mobil Exploration and Producing
US Inc., in Rocky Mountain and Gulf of Mexico Exploration for the first six years following graduate school. Since
1993, she has consulted for many clients, initially as the
manager of Vector Interpretation Services and later
(1998) as a partner in IS Interpretation Services Inc. In
addition to her work in the Marcellus, she has contributed
geoscientific expertise to exploration and field development projects in structurally and stratigraphically complex areas, such as the Bearpaw uplift and Disturbed
Belt in Montana, The Greater Green River, Wind River
and Big Horn Basins of Wyoming, Utah’s Uinta Basin,
the North Slope of Alaska, California’s Sacramento and
San Joaquin Basins, Oklahoma’s Arkoma Basin, as well
as international projects in Columbia’s thrust belt, Chile’s
Fell Block and Venezuela’s thrust belt. She is a longtime
member of the SEG, AAPG, DGS, and RMAG.
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Terry Engelder received a B.S.
(1968) from Penn State, an M.S.
(1972) from Yale, and a Ph.D. (1973)
from Texas A&M. He is a leading authority on the recent Marcellus gas
shale play. He is currently a professor
of Geosciences at Penn State and has
previously served on the staffs of the
US Geological Survey, Texaco, and
Columbia University. Short-term academic appointments
include those of visiting professor at Graz University in
Austria and at the University of Perugia in Italy. Other
academic distinctions include a Fulbright Senior Fellowship in Australia, Penn State’s Wilson Distinguished
Teaching Award, membership in a US earth science delegation to visit the Soviet Union immediately following
Nixon-Brezhnev détente, and the singular honor of helping W. Alvarez to collect the samples that led to the famous theory for dinosaur extinction by large meteorite
impact. He has written 160 research papers, many focused on Appalachia, and the research monograph Stress
Regimes in the Lithosphere. In the international arena, he
has worked on exploration and production problems with
companies including Saudi Aramco, Royal Dutch Shell,
Total, Agip, and Petrobras. In 2011, he was named to
the Foreign Policy Magazine’s list of Top 100 Global
Thinkers.
Edward Jenner received a B.S. in
physics with astrophysics from the
University of Birmingham, UK, and
an M.S. in geophysics from the University of Leeds, UK. Since 2002, he has
been the manager of ION’s Land Research and Development team in Denver, Colorado. After completing a
Ph.D. at the Colorado School of Mines
in 2001, he joined AXIS Geophysics and developed techniques for azimuthal velocity and amplitude variation with
offset (AVO) analyses. Since then, he has continued to focus on anisotropy, AVO, and anisotropic imaging issues for
land seismic data. In 2003, he was awarded the SEG Clarence Karcher Award for his work in the field of azimuthal
anisotropy.
Bruce Golob received a B.S. in geophysics from Bowling Green State
University and an M.S. in information
technology (dual major in database
design and object-oriented programming) from Regis University. He is a
geophysicist with ION-GXT in Denver,
Colorado, and he works as a seismic
inversion specialist, well integration,
and processing quality control resource. He also assists
clients in interpreting azimuthal anisotropy volumes
produced from wide-azimuth seismic. Before joining
ION-GXT, he worked in Denver interpreting 3D seismic
for an independent oil and gas company in the U.S.
midcontinent. He was originally hired and trained by
Amoco — working for 18 years within a team of geoscientists and engineers, generating economic drilling
prospects worldwide, his last five years with the company
working in Cairo, Egypt as senior consulting geophysicist.
He is currently a member of SEG, AAPG, DGS, and RMAG.
Jacki Hocum received a B.S. in mathematics from Arkansas State University, and after a brief stint as a high
school teacher, she began her geophysics career in 1981 at Western
Geophysical, where she processed
on- and offshore and transition zone
data from around the world, including
North America, South America, the
Gulf Coast, Alaska, and North Africa. She is a senior
processing geophysicist at ION GXT in Oklahoma City,
and she has more than 30 years of experience working
in the seismic industry. As a group leader with Western,
she was instrumental in training new processors. Before
joining GXT in 2009, she spent 10 years with ECHO Geophysical, where her role as a seismic processor has expanded to include customer support and technical
marketing. Since becoming part of the GXT team, she
has concentrated on North American processing, with
an emphasis on Niobrara and Marcellus plays. She is a
member of DGS and GSOKC.
Darien G. O’Brien received a B.S. in
petroleum engineering from the Colorado School of Mines and an MBA
from the University of Alaska. He is
the director of engineering with Solutions Engineering in Lakewood, Colorado. His technical expertise is in
domestic and international reservoir
engineering, drilling and work-over
assessments, reserves and economic evaluations, reservoir
modeling, environmental issues, and technology development. He has evaluated numerous oil and gas opportunities
throughout the country, ultimately making significant acquisition and divestiture recommendations. He has prepared independent proved, probable, possible reserve
reports for banks and investment groups, and he worked
with the U.S. Securities and Exchange Commission to obtain sanction for proved resources in emerging exploration
and resource development plays. He has been an active SPE
member throughout his career, serving as continuing education chairman for the Denver Section, SPE distinguished
lecturer, chairman of SPE’s International Continuing Education Committee, and recipient of SPE’s Regional Service
Award. He is a member of the Petroleum Technology Transfer Council’s National Board of Directors, Society of Petroleum Evaluation Engineers, and the National Society of
Professional Engineers. He is a registered professional engineer in Colorado, Wyoming, and California.
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