American Oil and Gas Reporter - September 2015 - 66

SpecialReport: Horizontal & Innovative Drilling
lationship between these two parameters
may be that the event/amplitude ratio is related to the generated fracture surface area
created during stimulation. This implies that
an open and conductive joint set is present
and mode 1 failure is fairly prevalent, explaining why the linear trends are so similar despite a bulk shift in Arootk values.
Isotope, Core And FMI Analysis

The study analyzed wellhead produced
gas using C1-C3 (methane, ethane and
propane) isotopes. Various molecular and
isotopic gas composition ratios were computed and mapped to identify trends and
anomalies. For example, the ratio of produced gas methane isotope-to-gas wetness
was mapped across the field (both values
are known to systematically increase with
thermal maturity).
Within the La Salle County field, thermal maturity increases northwest-to-southeast (downdip). While the overall downdip
maturation trend was evident in the
mapped data, there were several anomalous
areas with high ratios that corresponded to
wells drilled through large regional northeast-to-southwest normal faults.
Anomalously high mature gas also is
being produced by several wells located
within a fault block bounded by two
large northeast-to-southwest normal faults,
suggesting that high maturity gases originating outside of the Eagle Ford in the underlying Georgetown/Edwards are mobile
within the system where pre-existing normal faults are present.
Core and FMI analyses yielded insights
into natural fracture joint sets and validated the seismically resolvable features interpreted from attribute mapping (Figures
7A and 7B). A visual identification of fracture types was conducted on a continuous
150-foot cored section taken from the center of a relay ramp structure roughly 500
feet from a prominent northwest-to-southeast oriented surface attribute feature in the
field.
A total of 45 joints perpendicular or
near-perpendicular to bedding were observed. Of them, 36 were interpreted as
drilling-induced, five were high-angle
calcite cemented, and four were potential
high-angle open to partially open.
A high-resolution FMI log was acquired in the field last year in a near-vertical pilot hole that was planned to inter66 THE AMERICAN OIL & GAS REPORTER

sect one of the major regional northeastto-southwest oriented faults and reach total depth on the edge of a relay ramp structure. The main fault was crossed about 100
feet above the top of the Eagle Ford, crosscutting mixed carbonate and shale lithologies of the Basal Anacacho and Upper
Austin Chalk.
Numerous fractures were observed
adjacent to the fault. A majority of them
were healed, with extension and shear-type
fractures trending in two dominant orientations (strike 60 and 150 degrees) and generally steeply dipping (with three sets of
extension fractures dipping greater than 80
degrees, and two conjugate sets of shear
fractures dipping 60 degrees).
The dip orientations are shown as
light blue lines in Figure 7B. Within the
Eagle Ford formation, one clear fracture
was observed, interpreted to be healed and
oriented 150/88 degrees (dip direction/dip
angle), with several other possible fractures
of similar and perpendicular orientation
also visible. An intersection angle between
the borehole and fractures of less than 10
degrees implies that a large amount of correction must be applied to account for the
relatively higher expected horizontal fracture frequency/density.
Study Results

The study illustrates how numerous
datasets can be analyzed to gain insights

into the productivity impact of natural fracture/fault systems and various stress conditions in unconventional reservoir development. A fully integrated, multidisciplinary approach is needed to utilize the diverse datasets, with a continuous emphasis on the geologic context.
Routine operational datasets such as
mud gas logging and completions flowback analysis were related to specific
structural and stress field environments
within the field as delineated by high-resolution 3-D seismic attribute mapping.
Buried-array microseismic data and produced gas isotope analysis also strongly
conformed to the specific structural settings
outlined by attribute mapping. Direct visual identification of fracture types using
core and FMI log data confirmed joint orientations and types, and validated seismically resolvable features interpreted from
attribute mapping.
The findings confirm that natural fractures and differing stress conditions play
a significant role in well productivity in Eagle Ford development in La Salle County. As illustrated in Figure 8, one of the key
conclusions is a fracture classification
model characterized by three distinct
fracture types:
* Class 1, hydraulically induced fractures;
* Class 2, stratigraphically bound/confined natural fractures, and;

FIGURE 8
Fracture Classification Model
HIF -Induced Fracture
NFEF -Natural Fractures bound within the Eagle Ford
NFOZ -Natural Fractures Out of Zone

Hz Well

-Hydraulic Induced Fracture within the Matrix
-Existing Natural Fractures

Class 1
HIF>>NFEF >NFOZ

Austin Chalk
Eagle Ford

Buda
Georgetown
Edwards

Class 2
HIF≥NFEF >NFOZ

Class 3
HIF≥NFOZ >NFEF



American Oil and Gas Reporter - September 2015

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