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262 THE LEADING EDGE April 2018 Special Section: Latin America
Microseismic monitoring of Vaca Muerta
completions in the Neuquén Basin, Argentina
Abstract
e Vaca Muerta shale oil play in Argentina’s Neuquén Basin
is ex pec ted to make a large cont rib ution to A rgent ina’s hydrocarbon
production in the future. In 2013, the U.S. Energy Information
Administration estimated that the Vaca Muerta had technically
recoverable reserves of 308 Tcf gas and 16 billion bbl of oil and
condensate, making it the third largest shale oil reservoir in the
world at that time. Wintershall Energia has been active in the
Neuquén Basin since 1994. In 2014, it acquired a controlling
interest in the Aguada Federal block with an intention to exploit
the Vaca Muerta oil shale occurrence within that block. At the
outset of its development program, Wintershall decided to incor-
porate microseismic monitoring to help understand completions
in the Vaca Muerta. Monitoring of the completion of vertical well
AF.x-1 was accomplished with a surface array. e goal of the
monitoring was to inform later decisions on horizontal wellbore
direction, wellbore and stage spacing, and landing depth. Results
of the surface array monitoring were also used in the design of a
permanent buried array intended to monitor subsequent develop-
ment wells. e buried array was installed in September 2016 and
consists of 126 stations spread at an interva l distance of approx i-
mately 500 m over an area of roughly 5 by 7 km. Each station has
geophones placed over a depth range of 20 to 50 m subsurface.
e first two horizontal development wells in the project, AF.x-4h
and AF.x-9h, were completed in late December 2016 and early
January 2017. e second set of two wells, AF.x-3h and AF.x-7h,
was completed from May to June 2017. e 4h and the 7h were
landed in the upper Middle Vaca Muerta while the 9h and 3h
were drilled about 100 m deeper, landing still in the Middle Vaca
Muerta. e lateral length of each well was approximately 1000 m,
and each was completed with 11 plug-and-perf stages. Stage
length and interval were varied along the wells to test various
completion strategies. e completions of all four wells were
successfully monitored using the buried array. ese microseismic
data provide a detailed description of the fracture network created
by the treatments. Focal mechanisms determined for the detected
ev ents have been use d to und erstand the st ress distr ibut ion in the
reservoir and to further refine the completion parameters for
future development wells.
Introduction
Oil and gas production in Argentina dates back to the early
1900 s af ter oil was discovered in 1907 near the city of Comodoro
Rivadavia, Chubut. In 2016, Argentina produced an average of
693,000 b/d of petroleum and other liquids (U.S. Energy Informa-
tion Administration [EIA], 2017) making it the world’s 26
th
largest producer. e Vaca Muerta shale oil play in Argentina’s
Neuquén Basin is expected to play an important role in future
David Curia1, Peter M. Duncan2, Michael Grealy2, Jon McKenna2, and Andrew Hill2
production. In 2013, the EIA (EIA, 2013) estimated that the
Vaca Muerta had technically recoverable reserves of 308 Tcf gas
and 16 billion bbl of oil and condensate making it the third largest
shale oil reservoir in the world at that time.
e Vaca Muerta is an Upper Jurassic to Lower Cretaceous
marine shale located in the Neuquén Basin on the eastern side of the
Andes in west-central Argentina (Figure 1). e formation outcrops
on the edges of the basin and reaches depths of approximately 2830 m
in the basin center with thicknesses ranging from 63 to 535 m. e
prospective area, including the oil-rich, condensate-rich, and dry gas
zones, is estimated to cover about 30,000 km2 (EIA, 2013).
Wintershall began its oil and gas activities in Argentina more
than 35 years ago and is the fourth largest producer. Wintershall
currently has an interest in 15 oil and gas fields in the country
and produces about 26 million BOE annually. Wintershall has
been active in the Neuquén Basin since 1994. In 2014, it acquired
1Wintershall Energia S.A.
2MicroSeismic Inc.
https://doi.org/10.1190/tle37040262.1.
Figure 1. Map showing the hydrocarbon-producing basins of Argentina with the
location of the Neuquén Basin noted.
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264 THE LEADING EDGE April 2018 Special Section: Latin America
a controlling interest in the Aguada
Federal block with an intention to
exploit the Vaca Muerta oil shale occur-
rence there.
In this article, we discuss the appli-
cation of microseismic monitoring of
both vertical and horizontal wells in
the early phases of exploration and
development of this play. In particular,
we discuss the steps that led to placing
a permanent life-of-field monitoring
array in the field, the results of monitor-
ing, and some of the initial conclusions
drawn from the data.
Early-stage field development
Wintershall’s development program
for the Aguada Federal block (Figure 2)
has been planned in four principal
project phases: (1) a technology phase
to reduce geologic uncertainty, prove
hydrocarbon flow from the reservoir,
and assess the resource with widely
spaced test wells; (2) a pilot phase to
reduce production uncertainty and to test well productivity and
effectiveness of hydraulic fracture well stimulation applied to
multiwell pads with closely spaced horizontal wells on predefined,
small acreages; (3) a predevelopment phase to reduce economic
uncertainty and demonstrate the project commerciality by continu-
ally reducing costs and increasing well productivity; and (4) a
development phase in which infill wells are completed in a manu-
facturing style mode designed to deplete the resource.
During the technical phase, Wintershall elected to monitor
the stimulation of the AF.x-1 vertical well as part of the play
as ses sment. e wel l was sti mul ated in Au gust 2 015 in fou r stages ,
penetrating the Upper, Middle, and Lower Vaca Muerta. Monitor-
ing was performed with a surface FracStar array as depicted in
Fi gure 3. e results were su fficiently compel ling t hat Winte rshal l
continued with microseismic monitoring into the technical phase
of development. e completions of four horizontal wells, located
on the same pad as the AF.x-1, were monitored from December
2016 through June 2017. Monitoring of these wells was achieved
with a permanent buried array as pictured in Figure 3.
Microseismic monitoring well AF.x-1
Microseismic monitoring is a vital part of shale exploration
and development workflows. In fact, in the prolific Permian Basin
of Texas, seven of the top 10 operators on the Midland side have
integrated microseismic into their technology portfolio as have
five of the top 10 operators in the Delaware portion. (Per
Drillinginfo.com. Top operators are defined as highest average
peak BOEPD by basin. Data for seven out of 10 in the Midland
Basin is for the period February 2016 through February 2017;
five out of 10 in the Delaware Basin covers February 2014 to
Febr ua ry 2017.)
By locating the hypocenters of the seismic signals propagating
from induced fractures or reactivated natural fractures and through
more in-depth analysis of the nature of these seismic events, it is
possible to develop a rich understanding of the geometry of the
permeability-enhanced volume created by stimulation of the well.
e results of these analyses can be used to help optimize well
placement and stimulation programs in unconventional reservoirs
(Maxwell, 2010). After considering the success of this technology
Figure 2. Wintershall (WIAR) blocks in the Neuquén Basin.
Figure 3. Location map of the stimulated wells and monitoring arrays in the
Aguada Federal block. Surface and microseismic buried array locations are shown
as orange lines and white squares, respectively. The vertical Af.x-1 well is located
at the indicated red circle. The four horizontal wells are labeled by their color.
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April 2018 THE LEADING EDGE 265Special Section: Latin America
in other plays, Wintershall decided to incorporate microseismic
monitoring into its development of the Vaca Muerta.
e completion of well AF.x-1 was monitored with a surface
array consisting of 10 lines, approximately 3 km long and of 214
channels each, placed symmetrically around the well’s surface
location as pictured in Figure 3. e station interval was 14 m.
ere were 12 geophones (conventional 10 Hz, vertical) in each
group, spaced evenly between the stations along the radial arms
of the array. e vertical well was treated in four stages over the
depth range of 2642 to 2841 m, covering the Lower, Middle, and
Upper Vaca Muerta intervals. e goal of the monitoring was to
inform later decisions on horizontal wellbore direction, wellbore
and stage spacing, and landing depth.
A surface array was selected for the monitoring for several
reasons. Available monitor wells were too far removed from the
location of AF.x-1 to be of practical use. Wintershall was interested
in determining moment tensors, failure mechanisms, and stress
distribution in the reservoir. Each of these goals was made more
feasible with a large-aperture, wide-azimuth surface array (Duncan
and Eisner, 2010). In addition, Wintershall was interested in
establishing a life-of-field permanent monitoring array over the
block at some point in the development cycle. Such a permanent
array incurs front-end costs for installation, but it then can be
used for the monitoring of many wells over the life of the field,
thereby reducing unit monitoring costs substantially while achiev-
ing the same monitoring objectives as a large surface array. Beyond
frac mapping, monitoring a large number of wells in a developing
field is beneficial for detecting production-related seismicity,
directly mapping indiv idual well dr ain age volu mes , and dete rmi n-
ing the “interconnectivity” of individual wells. Monitoring the
completions of a large number of wells under such a permanent
array can generate improvements in the accuracy of both hydraulic
stimulation design and reservoir simulation models. One goal of
the AF.x-1 surface array monitoring was to develop design param-
eters for such a permanent array.
e observations derived from the microseismic monitoring
of the AF.x-1 treatment were as follows:
•
e surface array was successful at detecting event magnitudes
in the range of −0.7 to −2.8 with a magnitude of completeness
around −1.8.
• e majority of events occurred in two clusters, one in the
Upper Vaca Muerta and one in the overlying Quintuco.
•
Few events were detected in association with the treatment
of the Lower Vaca Muerta. ere are several possible expla-
nations for this observation. First, the treatment volume
pumped into the lower stage was one-third of that pumped
into the upper. Second, the Upper Vaca Muerta and
Quintuco are known to have greater Young’s and shear
moduli, which suggests they would fail with a more “brittle”
behavior. It is possible that the Lower Vaca Muerta, being
more ductile, merely failed without microseismic emissions
in the magnitude range detected with the surface array.
ird, it is our experience that the first stage pumped into
a reservoir often will produce fewer detected microseismic
events. We believe this observation may be ascribed to the
fact that the reservoir is not yet “pressured up” at that point.
Finally, some authors (for example, Osorio and Muzzio,
2013) have reported that stress anisotropy is higher in the
Upper Vaca Muerta than it is in the Lower, suggesting
another cause for the different response.
•
ree focal mechan isms we re resolv ed. e dom ina nt mecha-
nism in the Upper Vaca Muerta was oblique slip on a vertical
plane striking at 90°. e dominant mechanism for the events
occurring in the overlying Quintuco was reverse oblique on
a 75° dipping plane striking at 35°. e third mechanism
observed was a vertical strike-slip set of fractures mostly
occurring distal to the well with a strike of 50°.
• Most events have dominantly double-couple, nonvolumetric
source mechanisms. Of the volumetric changes that do occur,
more events are apparently closing events, rather than opening.
is is interpreted to mean that the microseismic events
represent the interaction between hydraulic fractures propagat-
ing parallel to the direction of maximum horizontal stress
(S
Hmax
) and preexisting natural fractures. Microseismic events
originate where the induced fractures intersect natural frac-
tures that are well oriented with respect to SHmax.
•
e S
Hmax
or ient ation, as re vea led by event so urc e mechanisms,
is approximately east to west.
•
Taking into account the half-length of the microseismic cloud,
the indicated wellbore spacing is 150 m.
•
Taking into account the longitudinal width of the microseismic
zone, the indicated stage spacing is 75 m.
• e recommended wellbore orientation is ~N10°E based on
both the direction of event propagation and the estimate of
SHmax azimuth from the observed focal mechanisms.
•
e recommended landing zone, based on the observed frac-
turing behavior, is the Upper Vaca Muerta.
Permanent array design
Given the success with monitoring the AF.x-1 using a surface
array, Wintershall proceeded with the design and installation of
a permanent, near-surface buried array for the project’s pilot phase.
e important design considerations for the establishment of such
a buried microseismic array are as follows:
• depth of geophone placement
• individual station array configuration
• areal extent of the array (aperture)
• number of stations (fold)
Paramount to all of these decisions is the ambient surface
noise level and some knowledge of how that noise falls off with
depth (Duncan and Eisner, 2013). e monitoring of AF.x-1
already had provided a measurement of the ambient noise at the
surface and the event magnitudes that might be expected during
the treatment of the next wells. To measure the falloff of the noise
with depth, a 130 m deep well was drilled and loaded with a
vertical wireline array consisting of 10 geophones spaced 10 m
apart. Ambient noise was recorded over a 72-hour period. e
observed attenuation of ambient noise with depth is presented in
Figure 4. e root-mean-square (rms) noise at the surface had a
median va lue of 50 nm/s. e noi se was obser ved to fa ll o ff 33 d B
in the first 40 m and then 26 dB in the next 80 m.
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266 THE LEADING EDGE April 2018 Special Section: Latin America
Knowing the ambient noise falloff with depth, one can proceed
to the next step in the design process. ere is a design tradeoff
between the number of stations (fold) and the depth of each
station. e driver behind this tradeoff is the acceptable noise
level for a given target signal level. Signal-to-noise ratio (S/N) is
key to the uncertainty in location and focal mechanism estimates
for each and every event (ornton, 2012; Mueller et al., 2013).
S/N determines the effective floor in the detection level of the
array. Drilling deeper reduces the ambient noise at the receiver
(higher S/N) but increases drilling charges. Designing for more
stations (higher fold) results in a net gain in S/N through the
reduction of random noise but at the expense of drilling more
holes, needing more equipment in the field, and having more
traces to process.
e approach taken in the Wintershall array design was to
model the array response using a target magnitude of completeness
of −2.0 and a ta rget S/ N of 3:1. e falloff of signal with distance
was estimated using a Q of 40, the value of which was obtained
from vertical seismic profile work carried out in the area. With
appropriate consideration of cost-benefit tradeoffs, the final design
of the array called for 126 stations spread at an interval distance
of approximately 500 m over a roughly 5 by 7 km grid as displayed
in Figure 3. Each station consisted of three geophone pods
cemented at depths of 50, 35, and 20 m below surface resulting
in 368 seismic channels recorded at a 2 ms sampling. Each pod
consisted of six 4.5 Hz single-component vertical geophones wired
in series (Figures 5 and 6).
Microseismic monitoring wells AF.x-4h, AF.x-9h, AF.x-3h,
and AF.x-7h
e first wells of the pilot phase, the AF.x-4h and AF.x-9h,
were completed in late December 2016 and early January 2017.
e second set of two wells, the AF.x-3h and AF.x-7h, was
completed from May to June 2017. e 4h and 7h were landed
in the upper Middle Vaca Muerta while the 9h and 3h were
drilled about 100 m deeper, landing still in the Middle
Vaca Muerta. e lateral length of each well was approximately
1000 m, and each was completed with 11 plug-and-perf stages.
Stage length and interval were varied along the wells to test the
reservoir’s response to various completion design parameters.
e rms ambient noise observed on the buried array over
the 103 hours of recording was observed to be about 5 nm/s.
is is a full order of magnitude below the ambient noise observed
on the surface array. e hypocenters of the final event set are
displayed in Figure 7. During this monitoring campaign, more
seismic energy was recovered from deeper in the Vaca Muerta,
likely as a result of the increased pumping effort from the multiple
stages in the horizontal wells and the increased sensitivity of
the buried array (Figure 8). Estimated uncertainty in the event
locations as a function of S/N achieved with the buried array is
plotted in Figure 9 (ornton, 2012; Mueller et al., 2013).
Full moment tensor inversion (Aki and Richards, 1980) and
focal mechanism determination were applied to all events with
a S/N of 5 or greater (postprocessing). is resulted in 3994
distinct mechanism determinations. e three dominant
Figure 4. Noise test results showing noise reduction with depth.
Figure 5. Sketch of a buried array installation along with pictures of the sondes
and the wireless recorder.
Figure 6. Installing the buried array in September 2016.
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April 2018 THE LEADING EDGE 267Special Section: Latin America
mechanisms are an approximately vertical dip-slip mechanism
striking at 90° and two sets of strike-slip fractures, one striking
at 150° and the other at 0°. A fourth mechanism, strike-slip at
50°, as was seen during the treatment of AF.x-1, was also present
in small numbers. ese mechanisms are consistent with pub-
lished studies for the basin. For example, Garcia et al. (2013)
report that the stress regime in the Neuquén changes from
dominantly “normal” to dominantly “strike-slip” as one moves
from east to west through the basin. e Aguada Federal block
is in the intermediate or mixed zone. Bishop (2015) in work
based on wellbore breakout studies, reports that S
Hmax
in the
area strikes east to west while the minimum horizontal stress
(Shmin) strikes north to south. Bishop also reports conductive
natural fractures at 50° and 155°.
A discrete fracture network (DFN) was constructed from the
microseismic event catalog to create a more geologically reasonable
model of the fracture network activated by treatment of the wells.
Each event hypocenter, as represented by a sphere in Figure 7, is
replaced with a planar fracture element oriented with strike and
dip equal to the strike and dip of the focal mechanism estimated
for that particular event (Williams-Stroud and Eisner, 2014). e
area of the planar fracture element is calculated from the moment
magnitude of the particular event. Figure 10 displays a map and
depth section view of the DFN derived from the microseismic
monitoring of the four horizontal wells being discussed here.
e next step to be taken in the analysis and interpretation
of these data is to upscale this fracture model into a stimulated
reservoir volume (SRV) that maps the permeability enhancement
of the reservoir achieved by the stimulation. Such a volume will
be used as input to a conventional reservoir simulation to predict
production volumes and pressure drawdown distributions for
these wells over time (Shojaei and Lipp, 2016) with the caveat
Figure 7. Hypocenter locations for the final event set captured during the treatment of the four horizontal wells. (a) Map view. (b) Depth view looking west. (c) Gun barrel
view looking south. Horizon tops are shown for Upper, Middle, and Lower Vaca Muerta as well as the underlying Tordillo. Grid size in all plots is 100 × 100 m. Events are
sized by magnitude.
Figure 8. Cumulative seismic moment observed for the five Aguada Federal wells.
Note the increased depth sensitivity with the buried array (orange) versus the
surface FracStar (blue).
Figure 9. Horizontal (XY) and vertical (Z) estimated event location uncertainty as
a function of S/N during the monitoring of wells AF.x-4h, 9h, 3h, and 7h using the
buried array.
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268 THE LEADING EDGE April 2018 Special Section: Latin America
that allowance must be made for the extent to which the SRV
actually received proppant filling.
SHmax and geomechanics
Another important extension of the focal mechanism deter-
mination is to use the distribution of observed fault motions to
estimate the direction of SHmax and the ratio of principle stresses
ϕ at each point of failure as defined in equation 1:
=
2
3
()
1
3
()
, (1)
where σ1, σ2, and σ3 are the three principal stresses (Michael,
1984; Angelier, 1989).
e estimate of this ratio is made under the assumption that
the fracture slip is in the same direction as the resolved shear
stress on the fracture plane (Bott, 1959). Assuming that one of
the principal stresses is vertical and can be estimated from the
density log or other means, and that
Shmin can be estimated from a DFIT or
similar test, then the direction and value
of S
Hmax
may be calculated for every
microseismic event for which a mecha-
nism is determined (Agharazi, 2016).
Applying this analysis to the moni-
toring results of horizontal wells, we
can plot all the events on a Mohr’s circle
diagram as given in Figure 11. As the
hydraulic fracture stimulation proceeds,
the injected fluids act to increase the
pore or f ractur e pressure in the re ser voi r,
thereby reducing the net normal confin-
ing pressure until the ratio of shear stress
to net normal stress exceeds the strength
of the rock or the friction on a planar
fracture. Fractures close to this condi-
ti on are refer red to a s cr itica lly st ressed.
One can think of the hydraulic fractur-
ing process as moving the circular figure
in the plot below to the left relative to
the axes, with failure occurring when-
ever the point representing the failure
plane crosses the line of friction (Jaeger
et al., 2008).
Each of the points on the plot in
Fi gure 11 repres ents an observed micro-
seismic event from the monitoring of
the four horizontal completions. Hence,
each event represents a failure of the
rock. Points farther to the right are
harder to fracture as highlighted by the
color bands. Events plotting in the
colder colors required a higher pore
pressure to be present before
failure occurred.
A practical application of this
observation is that the Quintuco
events activated in the treatment of
AF.x-1 plot much farther to the right
th an do the events in th e Vaca Muert a.
In other words, the failure planes
excited in the Quintuco Formation
during treatment are less favorably
oriented with respect to the principal
stresses than are those observed to fail
Figure 11. Geomechanical analysis results for the microseismic events captured during the treatment of the
horizontal wells. The diagram on the left illustrates the directions determined for the three principal stresses on
a lower hemisphere polar projection. The Mohr’s circle plots on the right illustrate the relative magnitude of the
stresses at the time of failure. The horizontal axis is the net stress acting normal to the event failure plane, and
the vertical axis is the resultant shear stress on the fracture plane. The relative sizes of the principal stresses
are shown by their position on the horizontal axis. The dots represent the position of the observed event fracture
planes in this stress coordinate system. The straight lines represent hypothetical lines of friction, the ratio of
shear stress to normal stress at which failure occurs. The colors indicate the state of stress at any point in this
system with colder colors representing more stable or less likely to fail conditions. The equations illustrate how
the value of SHmax is derived in a normal faulting regime once the stress ratio ϕ has been estimated from the
focal mechanisms.
Figure 10. DFN derived from data displayed in Figure 9 using strike, dip and magnitude of the observed
microseismic events. (a) Map view. (b) Depth view looking west. Grid size is 100 × 100 m.
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April 2018 THE LEADING EDGE 269Special Section: Latin America
in the Vac a Mue rta Format ion. Very fe w Quintuco event s were
observed in the treatment of the subsequent four horizontal
wells, suggesting that during these treatments fluids penetrating
to the Quintuco did not raise the pore pressure high enough
to cause failure. Furthermore, the distribution of event orienta-
tions and their relative distance from failure or criticality
observed while treating the horizontal wells suggest an oppor-
tunity to be selective and efficient when pumping. It would
seem logical and economical to limit raising the pore pressure
to the point where events oriented perpendicular to SHmax are
triggered because they will tend to close first and make a
minimal contribution to long-term production.
Conclusion
Microseismic monitoring of the AF.x-1, AF.x-4h, AF.x-9h,
AF.x-3h, and AF.x-7h was successful in helping Wintershall
better understand and design an optimal completion strategy
for the Vaca Muerta play, Neuquén Basin, Argentina. During
the technical phase, the monitoring of a single vertical well with
a large surface array established that a surface array could indeed
detect events originating in the Vaca Muerta. e results provided
insight on preferred horizontal well orientation, spacing, and
landing zone. e data also helped establish the feasibility of a
permanent life-of-field array that was later installed during the
pilot phase of field development. A large-scale, permanent array
was desired not only for the technical advantages provided by a
large-aperture, wide-azimuth observation of the microseismic
signals, but also for the technical and budgetary advantages of
a permanent facility that would allow for the monitoring of
multiple wells at a reasonable cost.
e permanent array of 128 stations was installed in late 2016.
To date, the stimulations of four horizontal wells have been
monitored with this array. ese observations provide a detailed
description of the fracture network created by the treatments.
Focal mechanisms estimated for the detected events have been
used to understand the stress distribution in the reservoir and to
further refine the completion parameters for future wells.
Corresponding author: pduncan@microseismic.com
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