Read, and answer 3 quistions, summarizing what you have read.URTeC: 2670034
Sampling a Stimulated Rock Volume: An Eagle Ford Example
Kevin T. Raterman*1, Helen E. Farrell*1, Oscar S. Mora1, Aaron L. Janssen1, Gustavo A.
Gomez1, Seth Busetti1, Jamie McEwen1, Michael Davidson1, Kyle Friehauf1, James
Rutherford1, Ray Reid1, Ge Jin1, Baishali Roy1, Mark Warren1.
Copyright 2017, Unconventional Resources Technology Conference (URTeC) DOI 10.15530/urtec-20172670034
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Austin, Texas, USA, 24-26 July 2017.
The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper
have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is
subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not
necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited.
In 2014 ConocoPhillips drilled the first of five deviated wells in DeWitt County, Texas, in order to sample the
rock volume adjacent to a horizontal Eagle Ford producer prior to and immediately following hydraulic
stimulation. The design, execution and results of the pilot will be described, with particular emphasis on the
data acquisition program, which included core, image log, microseismic, DTS/DAS, and pressure data. The
observed reservoir state preceding and following hydraulic fracturing will be discussed from an integrated
perspective, emphasizing geologic, geophysical, reservoir engineering and completions related observations.
The notion that hydraulic fractures in the subsurface are complex is not new (Mahrer et al., 1996, Mahrer, 1999,
Cipolla et al., 2008). Fracture complexity has been proposed as one of the causes of high treating pressures and
several studies have sampled complex hydraulic fractures. The most notable of these are hydraulic fracture corethrough projects (Warpinski et al., 1993, Fast et al., 1994, Branagan et al. 1996) and hydraulic fracture mine back
endeavors (Warpinski and Teufel, 1987, Warpinski 1991). In these studies, multiple hydraulic fractures were
encountered close to each other and fracture deflections and branching at geological heterogeneities, such as natural
fractures and bedding surfaces, were described. The observations from mine back data and hydraulically fractured
vertical wells indicate that simple bi-wing fractures are not the norm in nature. By extension, this is likely the case
for multi-stage horizontal wells completed in shale. Shales are more mechanically anisotropic than the sandstones
previously studied and thus should be more likely to develop complex fracturing. With the maturation of
microseismic imaging, the premise of complex fracturing has been reinforced (Walker et al., 1998, Fisher et al.,
2002, Maxwell et al. 2002, Cipolla et al. 2008). In these, and other published case histories, microseismic event
maps generally reflect a diffuse cloud that is typically interpreted as the result of fracture complexity.
Accepting fracture complexity as the norm can be justified, but the practical necessity is that this complexity must
be translated into the reservoir-modeling domain such that spatial drainage can be adequately delineated and longterm production predicted. In the context of completion and well spacing and stacking decisions, business demands
that an adequate assessment of well performance be made early in the field development cycle. To account for the
growing evidence of fracture complexity, the engineering community has migrated from uniform planar fracture
models that are embedded in a homogeneous matrix to SRV (Stimulated Rock Volume) models wherein some
portion of the matrix surrounding the fractures is assigned permeability uplift. In some instances, the fracture
complexity has been explicitly expressed in the form of fracture network or discrete fracture models. Frequently, the
latter are tied to guided mapping protocols that seek to associate reactivated natural fractures and bed boundary
partings with microseismic events. Although there is a certain appeal to this progression of models because it
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embraces fracture complexity as the causal agent for permeability uplift, the models themselves remain largely
uncalibrated by direct observations of fracture density and far field spatial pressure response to drainage. These are
critical to accurately assess spatial drainage.
In 2014 ConocoPhillips undertook a piloting effort to reduce these uncertainties. The pilot design relied heavily on
spatial sampling adjacent to an Eagle Ford horizontal producer, both before and after hydraulic stimulation, to
characterize the state of hydraulic fracturing. Remote monitoring by microseismicity and Distributed Acoustic and
Temperature Sensing (DAS/DTS) were an integral part of the design. Furthermore, the design employed multiple
pressure gauges to monitor the spatial progress of depletion with the intent to tie production performance to
observed fracture characteristics. This paper details both the operational issues of executing the pilot and the
characteristics of the hydraulic fractures that were sampled.
Figure 1: Location map
Figure 2: Eagle Ford type log showing gamma ray colored by volume carbonate and calculated bulk volume hydrocarbon. Also shown are the
location of producer, P3, and well S1 pressure gauges, G1-7.
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Pilot Design
The test area is in ConocoPhillips’ Eagle Ford acreage in north, central De Witt County Texas (Figure 1). The pilot
consists of 4 producers, P2, P3, P4 and P5 landed at the same level in the Cretaceous Lower Eagle Ford, one vertical
far field pressure monitoring well, and 5 deviated observation wells to characterize the stimulated rock volume at
different locations adjacent to one of the stimulated producers, the P3 well. The wells were drilled in 2014 and 2015
adjacent to an existing producer, P1. The pilot area is structurally quiet with beds dipping gently to the southeast at
3° without seismically mappable faulting. The local stratigraphy of the Eagle Ford in this area is shown in Figure 2.
The Eagle Ford is overlain by the Austin Chalk and underlain by the Buda Limestone. The Lower Eagle Ford
consists primarily of thinly interbedded organic marl, marly limestone and limestone beds. The Upper Eagle Ford in
this area is a calcareous mudstone. The pilot was placed in the lower Eagle Ford section.
The 4 producers were drilled from a single pad, down dip, parallel to bedding in a fan-shaped arrangement with
well-spacing being approximately 400 ft. at the heel and 1,200 ft. at the toe (Figure 3). All were landed at the same
stratigraphic depth, approximately 70 ft. above the Buda Limestone. The P3 well was instrumented with fiber optic
cables for bottom hole pressure and Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing
(DAS) for monitoring during completion and production. The P2, P4 and P5 were not instrumented down hole, but
were monitored at the surface.
Figure 3: Pilot well lay-out, map view
Three data wells were drilled next to P3 (Figure 3). S1 is a vertical well drilled approximately 615 ft. to the
southwest of P3. A standard log suite was acquired to establish stratigraphy for geosteering. Additionally, the
Borehole Acoustic Reflection Survey (BARS™) and Next Generation Imager (NGI™) logs were obtained for
fracture characterization. S1 was designed for simultaneous pressure and microseismic monitoring. Fiber optic cable
was installed on casing for monitoring DTS/DAS and reservoir pressure throughout the Eagle Ford interval and into
the Austin Chalk (Figure 2). During the stimulation of P2 and P3, geophones were placed in this well as part of a
dual well microseismic acquisition. The S2 and S3 wells were landed about half way along P3 to sample the SRV in
the central-to-toe region, adjacent to stages 1 – 7. S2 was drilled before the hydraulic stimulation of the producers to
characterize the native state of fracturing in the pilot area. It is 30 ft. TVD above and approximately 200 ft.
southwest of the P3. Lateral length is 1,270 ft. Two hundred feet of three-inch diameter horizontal core and an FMIHD™ log were taken in this well. S3, which was sidetracked three times, was used to sample the SRV at different
spatial locations around P3 post-stimulation. Cuttings were collected and examined for the presence of proppant in
all post-stimulation wells. The sidetracked laterals are 1,300 to 1,700 ft. long. Pipe conveyed FMI-HD™ image logs
were run in all sampling wells for fracture characterization. The original S3 wellbore was parallel to, 30 ft. TVD
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above, and 70 ft. northeast of the P3, and 360 ft. of three-inch diameter, horizontal core was taken from this well.
After logging, the lateral was cemented and abandoned using a disposable tubing string. This drilling and
abandonment procedure was repeated for S3_ST01 and S3_ST02. ST01 was drilled at the same stratigraphic level as
the original S3 lateral. The sidetrack initiated approximately 130 ft. northeast of the producer and sampled outward
to 360 ft. from P3. The second and third sidetracks landed approximately 210 ft. to the northeast and 100 ft. above
P3 and both crossed above it. ST02, remained 100 ft. above the producer along its entire length with a TD
approximately 105 ft. southwest of the producer, whereas ST03 cut down through the section, crossed 56 ft. above
the producer to a TD approximately 30 ft. below and 250 ft. to the southwest of P3. 120 ft. of three-inch diameter
core were taken from ST03, roughly 40 ft. above the core taken in the original S3 lateral. The S3_ST03 well was
cased and cemented to serve as a long-term far-field pressure monitoring well. Twelve externally mounted pressure
gauges were installed along the length of the lateral. Distances from gauge to the P3 producer ranged from 50 to 280
Pilot field operations took place in two phases over two years. In the first phase, the producers and sample wells S1
and S2 were drilled and completed. The producers were then stimulated and put on production for one month before
sample well S3 was drilled. Phase 2 consisted of the 3 sidetracks from S3 and was performed after a year of
Execution of this pilot raised four significant operational challenges. These challenges were: precise well location
and collision avoidance; a multipurpose mud system; horizontal coring; and pressure gauge installation and
A rotary steerable drilling system along with In Field Ranging (IFR) was used to reduce well location uncertainty.
Surveys at 10 ft. intervals were calculated while drilling and through the cored sections after coring. Additionally,
vertical well position was known accurately from the uniform stratigraphy using MWD gamma ray to geosteer the
well. This, along with the tendency for the bit to follow bedding, meant that the S2 core cut just 15 inches of section
along its 200 ft. length. A passive ranging system was used to ensure that ST03, which passed closest to the
producer, did not intersect it.
The mud system offered three challenges. 1) There was a strong preference to drill and core the Eagle Ford with an
oil based mud system which conflicted with the need to use a water-based fluid for FMI-HD™ acquisition. 2) Post
stimulation, a heavy mud weight was required for well control. 3) A bridging mud was needed to limit mud invasion
into hydraulic fractures and potential damage to the producer. The first item required that the oil mud system be
swapped after coring or reaching TD to a similarly weighted water-based system. The water-based mud was
formulated with high (120,000 – 140,000 ppm) chlorides optimized for the FMI-HD™ imager. Image logs showed
no perceptible difference in quality between the sections drilled with OBM or WBM. It is believed that the WBM
filtrate readily penetrated the fractures providing sufficient resistivity contrast with the formation regardless of the
initial fluid used in drilling. For items 2 and 3, a 16 ppg. mud was chosen to reduce well control risk in S3, which
was drilled while the formation was still over pressured from the stimulation by as much as 4 ppg. The mud was
additionally designed to bridge and seal any low-pressure fractures that the wells might encounter. To gain operation
experience with the heavier mud, the mud system was also used to drill and core the pre-stimulation well, S2. In this
case, the well was overbalanced with respect to initial reservoir pressure. Both the S2 and S3 were free of drilling
problems and had excellent, round boreholes without washouts. The later sidetracked laterals, which were drilled in
Phase 2, used a lower mud weight. The hole quality was not as good, with some washouts and sticking of the FMIHD™ encountered.
ConocoPhillips had not attempted horizontal coring in the Eagle Ford before this project. Core jamming and core
erosion problems were encountered during the pre-stimulation S2 coring. It appeared that the mud was unable to
flow out of the core barrel resulting in high pressures within the barrel and premature downhole failure of the
pressure relief valves in the inner core barrel. This resulted in core and inner core barrel erosion and, in one case, a
dropped core. These problems were solved with the coring vendor by modifying the core barrel design to ensure
flow out of the top of the coring assembly. Coring in S3 and S3 ST03 was uneventful with 100% recovery in runs of
up to 120 ft.
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The final operational challenge was pressure gauge installation in S1 and S3 ST03 (Figure 2 and 4). Both wells
employed cemented casing with externally mounted fiber optic pressure/temperature gauges. In S1, the 7
pressure/temperature gauges were installed from just above the Buda Formation up into the lower Austin Chalk
using the cement annulus as isolation. Each gauge was in a casing mounted carrier connected by a snorkel tube to an
externally mounted perforating gun assembly. After deployment, the guns were fired outward to connect the
pressure gauges to the formation. Unfortunately, while all 7 gauges remained functional, only 3 were successfully
hydraulically connected to the formation. Inadequate charge size and charge degradation due to high formation
temperatures were thought to be responsible. Consequently, to ensure pressure connectivity and gauge isolation in
S3 ST03, the 12 gauges were installed and cemented on the outside of the casing, but ported internally. After the
casing was cemented, the fiber optic cable was mapped using tele-coil and a custom designed oriented tele-coil
bottom hole assembly (BHA) was used to perforate the casing away from the cable and connect to the formation.
Gas-tight bridge plugs separated gauge/perforation pairs, and perforations were situated in areas with a good cement
bond. All gauges are currently functioning and reading independent pressures indicating a successful installation.
Figure 4: Well paths showing hydraulic fractures as white discs. Cored intervals are shown in pink. Pressure/temperature gauge location in S3
shown by red circles Yellow filled log on P3 is Scandium RA tracer log. Blue discs show locations of iridium RA tracer from offset producer P2.
The order of completion was as follows: the toe-ward portion of P5; followed by zipper fracking the adjacent
portions of P5 and the shortened well, P4; P2; and P3. The perf. and plug completion design was essentially
common to all wells. Cluster spacing was 47 ft. between, with five evenly spaced clusters per stage. A limited entry
design was employed. The total fluid volume was sized per treated lateral length at 21 bbl./ft. The injected fluid
sequence consisted of an acid and linear gel pre-flush pad, followed by proppant slurry in a 30 # guar borate gel
carrier fluid. The slurry was flushed with linear gel and slick water. Approximately 1,500 lbs./ft. of proppant was
injected at a maximum rate of 55 BPM. The proppant concentration ranged from 0.5 PPA to 4 PPA; 40/70 white
sand was followed by 30/50 white sand.
Some completion details differed for well P3 due to the need to avoid perforating the casing-deployed fiber optic
instrumentation. Specifically, cluster spacing was not always constant (43 to 47 ft.) and the perforations were phased
180 degrees opposed to the fiber optic cable. Each of the 14 stages for well P3 was monitored via DTS and DAS to
estimate fluid injection volumes at the cluster level.
Injected fluid and proppant volumes were traced for P2 and P3. Each stage adjacent to the planned sampling well
trajectories (stages 1 -7) employed a unique oil and water phase tracer. For non-adjacent stages a single tracer per
every two stages was utilized. The service provider specified sampling and analysis protocols. Radioactively tagged
40/70 proppant was introduced in all stages for both wells. Well P2 was tagged exclusively with an iridium dopant;
well P3 employed a scandium tag. Approximately twice the normal concentration of tagged proppant was injected to
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ensure that detectable radioactivity would persist some months after the completion. This duration for decay was
estimated to coincide with the drilling of the first sampling well offset to P3.
Completion operations were effectively trouble-free throughout. The notable exception was stage 1 of well P3.
Extremely high treating pressures were experienced which could not be remediated by acidizing or re-perforation.
Consequently, limited fluid volumes were injected into this stage without proppant.
Completion Monitoring
The multiwell stimulation was monitored by various means including: dual well microseismic; continuous
distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) in P3; and pressure response in
multiple gauges in S1 and P3.
Borehole microseismic was recorded during stimulation of the P2 and P3 using high temperature borehole
geophones clamped to the inside of casing in vertical monitor well S1 and through the build section of a horizontal
monitor well S2. Both arrays consisted of twelve geophones spaced at 100 ft. intervals. In the vertical monitor well,
the bottom geophone was placed 100 feet above the top of the Buda and the array extended vertically 1100 ft. All
geophones were at or above the level of the producers. Downhole conditions of 325°F exceeded the rated maximum
temperature/pressure conditions for the geophone arrays and thus, geophones were often replaced.
In all, 26 of the 28 stages in P2 and P3 were microseismically monitored from at least one of the monitoring wells
and the events from six stages in P3 closest to the sample wells were recorded on both arrays. Industry standard
event detection and location routines were used to obtain robust dual well location solutions for the 6 stages
offsetting the sample wells, and a combination of single and dual well solutions were obtained for the remaining
stages. These differences in microseismic acquisition and processing, led to variation in the completeness of event
detection and the accuracy of event location over the monitored area; however, the greatest confidence in event
locations were assigned to the immediate pilot study area.
Vertically, half of the microseismic events are contained within an interval from 15 ft. below to 115 ft. above the P2
and P3 wells. A lack of events in the Buda suggests this formation behaved as a barrier to downward fracture
propagation. The density of microseismic events are greatest at the wellbore and decrease spatially away from the
stimulated well (Figure 5). Stage event patterns ranged from linear to dispersed.
Figure 5: Map view and cross-section view of microseismic events
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The central stages of the laterals show NE/SW trending linear event clustering features which extend over 1,000ft
from the stimulated wells and cross P1, P2 and P3. This clustering is perpendicular to the minimum horizontal insitu stress and is thus parallel to the predicted plane of hydraulic fracturing. The linear event clustering features are a
result of events recorded during multiple stages and sometimes consisted of co-located events from both the P2 and
P3 stimulation. When the microseismic events are examined stage-by-stage it is apparent that, in some stages, events
occur both up- and down-hole of the stage being stimulated. A significant amount of microseismic activity recorded
during the stimulation of the P2 was located along the P1 well, which had been stimulated and produced for one year
prior to pilot activities. Note that few microseismic events were recorded in the heel and toe areas of P2 and P3. The
lack of events in the heel region is likely the result of poor geophone location for imaging this area. Considering
observations from previous microseismic surveys that consistently show a high level of activity in the near wellbore
region, the paucity of events in the toe region of P3 is more puzzling.
Microseismic events also extended to the S1 well, which has a vertical pressure gauge array and is 615 feet from P3.
As Figure 6 indicates, the recording of microseismic events positioned within 100 feet of S1 preceded and persisted
throughout the pressure response registered in the three gauges successfully connected to the reservoir (G3, G5 and
G6). The absolute maximum-recorded pressure in the connected gauges exceeded the minimum stress of 11,960 psi
estimated by DFIT from an adjacent well. Hence, it is interpreted that a hydraulic fracture or fractures intersected or
were proximal to S1. Significantly, the pressure event is associated with a compressional heating event recorded in
all 7 gauges. Given that the magnitude of heating was similar in gauges 1 through 6, it is likely that the fracture
extended throughout the Eagle Ford interval.
Figure 6 also shows the DAS response at the S1. The DAS signal is highly sensitive to temperature and mechanical
strain changes. In this instance, the fiber was used to analyze the strain response at S1 imparted by stimulating the
P3. The first DAS arrival is consistent with the first recorded local microseisms in time and depth. Subsequent DAS
arrivals agree spatially and temporally with recorded pressure and temperature events, which were interpreted above
as fracture arrivals. Given that it provides precise position data, the spatial resolution of fracture height is extended
to the base of the Austin Chalk at the S1 location.
Figure 6: Microseismic and pressure at S1
The DAS fiber in P3 was also used to analyze strain changes during the stimulation of the adjacent producers. The
fiber is mechanically coupled with the formation, thus strain rate along the P3 wellbore during hydraulic fracturing
of the offset producers can be calculated and tied back to formation deformation. Where the fiber is in the path of a
hydraulic fracture, it is extended. On either side of the hydraulic fracture, the fiber and coupled formation are
compressed, or stress shadowed. This is illustrated in Figure 7 that shows an example of a recorded signal at P3
during stimulation of an offset producer. In this figure, the red signal denotes fiber extension and blue denotes fiber
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compression. The response in the offset well correlates with the fluid and proppant injection timing. A set of
extension signals interpreted to be ‘new fracture opening’ (in red) are observed within a short delay of onset of
pumping, which is surrounded by the compression signal from the stress shadowing of the formation. The signal is
reversed when pumping stops resulting in ‘fractures closing’ (in blue) surrounded by a relaxation of stress in
surrounding formation. The location and number of fracture hits observed can be correlated back to the perf clusters
for each stage on the stimulation well to provide information on SRV geometry (Figure 8). Note that some of the
fractures extend for 1,500 ft. The absence of signal from the toe stages of P5 is because these stages were not
Figure 7: Strain rate in S3 from DAS during stimulation of offset producer
Figure 8: Cross well DAS response indicating that some fractues extend 1,500 ft.
The DTS/DAS interpretation of the injected fluid distributions at the cluster level for well P3 is shown in Figures 9
and 10. All clusters in each stage produced a measurable amount of acoustic energy throughout the time of pumping.
This was the first qualitative indication that all clusters initiated fracturing and took a meaningful amount of fluid
volume during the stimulation. Figure 9B, in which acoustic energy is plotted against time, shows an example of the
DAS data from stage 5. The red/yellow colors in the figure represents the high acoustic intensity recorded from the
DAS at each of the 5 cluster locations. The acoustic energy varied somewhat with time, but was continuous
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throughout the pumping of the stage. DTS interpretation (Figure 10) showed cooling across all clusters, which
supports the DAS conclusion that all clusters took fracture fluid. In Figure 10, where temperature is plotted against
time, the red color indicates higher temperatures and blue lower temperatures. Each stage can be identified in depth
by the horizontal dashed lines representing the plug depths. The lowest temperatures recorded were at the depths of
the perforation clusters associated with the stage being pumped. In Figure 10, multiple stages show cooling below
the plug that is intended to provide hydraulic isolation from the previously pumped stage. In 10 of the 13 stages
monitored, fluids were leaking below the plug and stage isolation was not complete.
The DAS data was also used in a quantitative sense to interpret plug leakage and injected fracture fluid (slurry)
volumes by cluster. In this proprietary method, it is assumed that the DAS intensity is a measure of the flow volume
through each perforation. The results from stages 2-8 are shown in Figure 9A. While it verified that all clusters took
meaningful amounts of fracture fluid, the quantitative analysis showed that the distribution of slurry volume into
each cluster is uneven with clusters taking from 33 to 142% of the targeted cluster volume. This analysis also
indicated that, for the entire wellbore, fluid loss through the plug ranges from zero in three stages, to small in four
stages, to approximately 500 bbl. or 10% of the total pumped volume in six of the stages.
Figure 9: DAS injection monitoring
Figure 10: DTS injection monitoring
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Hydraulic Fracture Description
When interpreting the hydraulic fracture pattern within the SRV it must be noted that, except for the toe-ward end of
ST03, all the wells cut the SRV above the level of the stimulated producer, and all cores were acquired above the
level of the stimulated wells. Despite sampling over 7,700 continuous feet of the SRV volume, the overall geometry
of the SRV remains statistically under-sampled with key areas immediately adjacent to and below the producer
being completely unsampled.
In this study, it was necessary to distinguish between hydraulic, natural and drilling induced fractures. In most cores,
identification of natural and drilling induced fractures is relatively routine using fracture mineralization, surface
markings, and orientation and form with respect to the core axis (Kulander et al.1990). However, in the absence of
natural fracture mineralization or a distinct difference in orientation, hydraulic and natural fractures can be hard to
distinguish. To characterize the natural fracturing in this area, which was unknown, a pre-stimulation, baseline core
and image log were acquired. Well S2, was drilled at the same stratigraphic depth and just 270 ft. along strike from
S3, the first post-stimulation sample well.
The pre-stimulation S2 core was taken with a mud system that was significantly over balanced. This resulted in the
formation of many drilling induced fractures in the core and borehole wall perpendicular to the wellbore. In the core,
these were identified primarily by the presence of distinct surface arrest lines that initiated a few millimeters from
the edge of the core and typically wrapped around the upper, but occasionally also the lower, half of the core (Figure
11A). These drilling induced fractures were present in every foot of the S2 core. They were also abundant in the
image log from the well. The 200 ft. of core from S2 contained just 4 natural fractures. The natural fractures are not
mineralized and trend NE/SW with 75 – 80° dips to the SE. The image log from the vertical S1 well contained a
single natural fracture within the Eagle Ford and it parallels the S2 fractures. This paucity of fracturing supported the
belief that the pilot was placed in an area without faulting and with very limited natural fracturing. These natural
fractures differ in orientation from the drilling induced fractures by just 10 – 15°. This similarity in orientation
caused challenges to fracture classification from the image logs alone and was a factor in angling the later Phase 2
sidetrack wells away from the principal stress direction to create a larger angular difference between the fracture
types and facilitate their identification in the image logs. Although the 4 cored natural fractures were interpreted to
be un-mineralized, a hydraulic origin could not be absolutely eliminated. Well P1, the original well on this lease,
which is approximately 1,300 ft. to the northeast and well within the DAS recorded envelope for cross well events,
was completed a year prior to pilot operations. Therefore, the fractures could also be hydraulic in origin from well
Figure 11: Fractures in core A) Drilling induced. B) – F) hydraulic
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The cores from S3 and S3 ST03 contained many hydraulic fractures and far fewer drilling induced fractures. Both
wells were drilled with mud much closer to the formation pressure and no stress indicators such as breakouts or
drilling-induced tensile fractures were observed. The hydraulic fractures have the following characteristics: unmineralized; oriented NE/SW transverse to the well; steeply dipping; planar with, when present, surface markings
indicative of extensional or hybrid origin; and non-uniformly spaced. The case for a hydraulic origin is deductive.
First, these fractures were not present in the baseline core just 270 ft. away and in this structurally quiet area it is
unlikely that hundreds of natural fractures would form along trend over such a short distance. Second, they are
aligned with both present day stress and the linear event clusters seen in the microseismic; thus, they parallel the
anticipated hydraulic fracture direction. Third, surface features, such as arrest lines and plumose features, indicate an
extensional or hybrid (mixed-mode) origin. Finally, embedded proppant was found on the surface of two of the
hydraulic fractures. Although a reactivated natural fracture origin cannot be eliminated, it is much less likely.
Examples of these fractures are shown in Figure 11. Figure 11B-D show typical surfaces of hydraulic fractures and
Figure 11E-F shows the fractures in profile where their southeasterly dip can be seen.
While the hydraulic fractures are generally planar, their surfaces may be smooth (Figure 11B, rough, ridged (Figure
11C) or occasionally stepped (Figure 11D). Fracture surface roughness is affected by lithology. The fractures within
the organic marl beds are generally extremely smooth whereas those in the more calcareous layers display small
ridges parallel to bedding and may have arrest lines or plumose features indicative of upward and lateral fracture
propagation (Figure 11C). Surface features indicating shear are absent. The cores contain examples of the hydraulic
fractures being refracted at bedding surfaces and of bent arrest lines (Figure 11C) and one hydraulic fracture has a 3mm. step where it crosses a bedding surface (Figure 11D). Ridges and steps in the hydraulic fracture surfaces have
implication for proppant transport and settling and fracture permeability preservation during pressure draw down.
Both in core and image logs, it was observed that multiple, usually two or three, hydraulic fractures often develop in
close association, where their orientations differ by 5 – 20° and they diverge with a projected line of intersection, or
branch line, just outside the core or borehole wall (Figure 12). The common occurrence of these doublets and triplets
along the length of the wells indicates that hydraulic fracture branching may be widespread. Branching along with
the observed influence of bedding surfaces on hydraulic fracture propagation leads to the postulation that the
mechanical stratigraphy resulting from interbedded organic marl and stiffer limey beds is in part responsible for
much of the observed fracture complexity and the large number of fractures encountered. Other natural
heterogeneities in the formation, likely also impact fracture complexity.
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Figure 12: Hydraulic fractures in close association. 12A showing dipping fractures in core. 12B showing the same section of CT image as an
unwrapped circumferentail image. 12C showing 18 ft. section of FMI-HD™ image log containing several fracture doublets and triplets showing
up as dark sinusoids across image.
The core adjacent to the hydraulic fractures is intact, with no visible or microscopic evidence of off-fracture damage
that might enhance matrix permeability. This was supported by SEM mapping and steady state core plug
permeability measurements from both the pre- and post-stimulation cores that were acquired from the same
lithologic interval. In the post-stimulation case, plugs were acquired proximal and distal to hydraulic fracture faces.
Regardless of origin, these samples showed no statistical difference in microscopic structure or measured
The 3 cores were oriented using the bed orientation from the image logs, apparent bedding orientation in the core,
and the borehole orientation. Core and image log fracture orientations are the same. Hydraulic fracture orientations
are shown in Figure 13. The hydraulic fractures form a parallel set striking N060 °E and dipping 75 – 80° SE. The
strike and dip both have a ± 20° range, some of which can be ascribed to the accuracy of the core orientation
method, but much of which is real and can be seen in continuous sections of core. This hydraulic fracture strike was
anticipated and is consistent with the local in-situ stress field. The 75- 80° dip of the fractures indicates that either
these fractures are not pure opening mode but hybrid mode 1-2, or the in-situ principal stresses are rotated away
from vertical/horizontal. A small sub-set of the fractures, especially in the shallower wells ST 02 and ST 03 dip to
the northwest. It is unclear whether these fractures are more highly influenced by branching or splaying
mechanisms, influence from local mechanical heterogeneities, or operational stress perturbations.
Figure 13: Hydraulic fracture orientation from image logs
The distribution of hydraulic fractures along the wellbores is non-uniform. In both post stimulation cores, the
hydraulic fractures form swarms, in which many fractures are spaced a few inches apart and are separated by lengths
of core with several feet between fractures (Figure 14). The FMI-HD™ image log data, which were of good to
excellent quality, were also used to analyze the spatial distribution of hydraulic fractures within the SRV. The best
quality FMI-HD™ logs were taken in S3 where, over the cored section, each hydraulic fracture in the core could be
correlated to a fracture in the image log. The image log, however, did not resolve closely spaced fractures and
showed some stretch and compression compared to the core. Nevertheless, a high degree of confidence was
established in the image log interpretation such that dipping hydraulic fractures could be distinguished from drilling
induced fractures which were perpendicular to the well trajectory. Interpretation of the image logs from the
URTeC 2670034
sidetracks, especially the ST03, was more challenging due to higher borehole rugosity and tortuosity that resulted in
tool sticking and short sections without interpretable images.
Figure 14: Hydraulic fracture swarm. 14A) Core photograph. 14B) Unwrapped circumferential CT scan of cored section 14C) FMI-HD™ image
of cored section and 14D) showing one hydraulic fracture swarm consisting of 22 fractures in a 20 ft. section of the well
S3 and its sidetracks sampled adjacent to stages 1 – 7 in the P3 producer. Thus, they sampled the rock volume
stimulated by 30 perforation clusters. The number of hydraulic fractures interpreted in the image logs is shown in
Table 1 and far exceeds one per perforation cluster. To investigate the spatial characteristics of the SRV the
hydraulic fracture density is presented in simple histograms (Figure 15) where the fracture count in a 50 ft. window
is displayed. Even at a bin size of 50 ft. the hydraulic fracture intensity is non-uniform. These plots show that
overall hydraulic fracture intensities are highest in S3 and ST03 and lower in ST01 and ST02, which are drilled
further out laterally and higher above the producer respectively. Fracture intensity decreases in ST01 at a measured
depth of 14,750 ft., which is 40 ft. above and 270 ft. laterally offset from the stimulated well. While the upper few
hundred feet of ST02 shows fracture densities similar to S3 and ST03, the toe-ward 2/3 of the well has much lower
intensities even where the well crosses 100 ft. directly above the producer. Thus, while some hydraulic fractures
extend well beyond the sampled area, hydraulic fracture intensities decrease more rapidly with height than with
lateral distance. This implies that the SRV is considerably wider than it is tall.
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Figure 15 Hydraulic fracture distribution. “P3” marks location the well crosses above the P3 producer
Table 1: Number of Hydraulic Fractures from Image Log Interpretation
S3 ST01
S3 ST02
S3 ST03
Length of Image Log (ft.)
# of Hydraulic Fractures
The RA tracer log from P3 indicates that proppant was well distributed amongst clusters at the source location
(Figure 4). To determine proppant distribution in the sample wells, a two-part proppant study was performed. First,
cuttings were collected at a 20 ft. interval throughout the drilling and coring of the sample wells. The samples were
washed, dried and sieved through a 70-mesh screen to remove fine particles and then were examined visually and
the abundance of proppant grains was estimated semi-quantitatively. The samples containing proppant for all 4
post-stimulation wells are tabulated in Table 2. The shallowest proppant grain was encountered in S3 ST02
approximately 120 ft. TVD above the producer. Proppant was much more abundant in S3, which is the lateral that is
consistently closest to the producer, where proppant was detected in 76% of the cuttings samples. Conversely, just
5% of the cuttings samples in ST01, which is the shallowest well at 100 ft. above the producer, contained proppant.
Table 2: Proppant Grain Distribution in Cuttings Samples
S3 ST01
S3 ST02
S3 ST03
# Samples
% Containing >1 Proppant Grain
The second part of the proppant work involved visual inspection of the surface of each cored fracture for sand gains
and proppant indentations. All mud and debris from the fracture surfaces were collected for laboratory analysis.
Small numbers of proppant grains were found on many hydraulic fracture surfaces. In S3, at least one grain of
proppant was recovered from 25% of the fracture surfaces, whereas in the ST03 core just 3 fractures contained
proppant (5%). It is unknown whether these sand grains were in-situ or had been washed into the hydraulic fractures
along with drilling mud. Only two cored hydraulic fractures had sand grains embedded on their surfaces (Figure 16),
one was in S3 and the other in ST03. Embedment pits in the surfaces of these two fractures, along with the presence
of many sand grains, indicated that the proppant was in-situ and had not been washed in with the mud system. An
estimate of the thickness of the proppant pack was not possible given the mud invasion. The presence of proppant in
the cuttings and core confirms that the wells sampled some portion of the propped SRV and the proppant is more
abundant at the S3 location than in wells drilled further from the producer.
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Figure 16: Proppant embedment A) Sand grains on surface, B) Embedment pits C) Fracture in core
Fracture Characteristics Discussion
The observations from this pilot lead to a new and different understanding of the SRV. At least in this area, it is
concluded that reservoir permeability enhancement in the SRV results principally from hydraulic fractures and that
matrix damage is extremely limited or absent. Hydraulic fractures are numerous, widespread, closely spaced,
steeply dipping, and branch. Most form a near parallel set. Hydraulic fracture surfaces are rough and may step where
they cross bedding planes. Proppant emplacement, at the sampled locations, is sparse. Some hydraulic fractures are
very long and extend well beyond the sampled area. The limited spatial data indicates that hydraulic fracture
intensity decreases more rapidly with height than with lateral distance and that the SRV volume in this area could be
on the order of two to three times as broad, laterally, as it is tall. This shape is generally consistent with the shape of
the microseismic event cloud.
The broadly parallel nature of hydraulic fractures and their large number indicates that SRV permeability is likely to
be highly anisotropic on a reservoir scale. The rugosity of the hydraulic fracture surfaces will influence both
proppant transport and settling. The sparsity of proppant, especially at more distant locations in the SRV, indicates
that fracture permeability and its preservation during pressure draw down may be spatially heterogeneous.
These findings are very different from the simple view of the SRV that are commonly modeled or predicted with
current fracture models. The absence of proppant on most of the hydraulic fractures indicates that proppant
emplacement is quite different from idealized transport model predictions. The apparent side-by-side propagation of
closely spaced, near parallel hydraulic fractures also differs from the output of currently accepted fracture models
and may call into question the role of stress shadowing in hydraulic fracture propagation. Stress shadowing may
have contributed to non-uniformity, but did not cause fractures to turn severely or fully inhibit the propagation of
closely spaced fractures.
The relationship between fracture density and cluster spacing was investigated by calculating a Gaussian Kernel
Function, with a bandwidth of 6 feet, from the S3 well. Fourier spectral analysis was applied to determine the
periodicity of densely spaced fractures or swarms. Data adjacent to stages 1 through 7 of well P3 were analyzed.
Stages 3, 4, and 5 exhibit a signal with a swarm spacing of 45 feet (Figure 17). The average cluster spacing was 47
feet. Stage 1 was not expected to show a strong dependence because this stage was not completed. Hence, 3 of 6
completed stages reflect a positive correlation of swarm occurrence with treated cluster spacing projected from the
adjacent stimulated well, whereas 3 do not.
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Figure 17: Fourier Analysis. Stages 3, 4 and 5 exhibit strong periodicty of 45 ft.
Understanding the relationship between the observed hydraulic fractures and microseismic events was complicated
by the different scale at which the two measurements are recorded and the discrete nature of both events. A
probability density function of the discrete location of both was calculated using the approach of Silverman (1986),
which results in a smooth distribution using a Gaussian Kernel (Figure 18). To determine the bandwidth for
construction of the density estimates, the method of Sheather and Jones (1991) was adopted. The relationship
between the two measurements was determined by cross plotting and computation of a Pearson correlation.
The correlation of microseismic events to sampled hydraulic fracture density are summarized in Table 3 and Figure
18. Although multiple combinations of microseismic attributes and fracture characteristics were examined, only a
few showed any degree of correlation. The total hydraulic fracture population associated with wellbores S3,
S3_ST01 and S3_ST03 showed none to moderate positive correlation to microseismic event density; notably, these
correlations improved when the hydraulic fracture population was restricted to include only shallowly dipping
fractures (
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