American Oil and Gas Reporter - September 2015 - 61

SpecialReport: Horizontal & Innovative Drilling
by dividing total gas by the drilling rate of
penetration and applying a Fourier transform scan line analysis. These results were
correlated to the mapped structural features.
Examples of large gas kicks or well
control issues were evident in 10-15 percent of total wells. Commonly, large gas
kicks were two to four times higher than
background gas readings, and in some cases, involved long periods of mud circulation, surface gas flaring, and well shut in.
In a majority of these cases, well paths traversed seismically resolvable northwestto-southeast features within interpreted relay ramp structures. In a few instances,
well paths crossed northeast-to-southwest features within steeply dipping monocline features.
Figure 3 is an overhead view (the top
of image is north) of four horizontal
wells drilled through a moderately dipping
northwest-to-southeast fault feature associated with a relay ramp structure. Three
of the four wells were drilled slightly underbalanced, allowing for pronounced
gas kicks. The top right inset image
shows that a gas kick of 8,000 units
caused one of the wells to be shut in and
then circulated out to flare for an extended time.
Correlating gas ratios (i.e, gas wetness)
to mapped structural features proved difficult, but in all instances, variations in gas
wetness ratios corresponded to wells that
drilled through major regional northeastto-southwest seismically resolved normal
fault features. When crossing these features, many ratios indicated decreased gas
wetness, which corresponds to a gain of
light ends and/or loss of heavy ends. The
former is interpreted to be the main reason for this observation, with regional normal fault systems creating the necessary
pathways for highly mobile lighter hydrocarbons (methane) to migrate from deeper stratigraphic sources.
In outcrop studies, fracture measurements along a traverse line can be analyzed
using a Fourier transform to infer the relative intensities (amplitudes) and frequencies of natural fracture sets. This technique was adapted by using normalized total mud gas as the scan line input for the
Fourier transform. The analysis differentiated two main subsets of wells: those with
several dominant (high-intensity/ampli-

tude) frequencies below 0.02 cycles/foot
(specifically at 0.0125 and 0.006), and
those with unresolved frequencies below
0.02 cycles/foot.
From the subset of wells with dominant
frequencies below 0.02 cycles/foot, 80and 160-foot fracture frequencies could be
calculated. Comparing this with seismically resolved features was difficult, since in
most cases, seismic features occurred at
frequencies several times larger (5001,000 feet). Nonetheless, the paths of all
wells with resolvable frequencies below
0.02 cycles/foot traverse identical seismic
features to wells that encountered large gas
kicks.
Completion Flowback Data

The produced water flowback dataset
consisted of all producing horizontal
wells with similar completion designs, allowing a wide range of produced water
salinities and oil-gas-water ratios (OGWRs) to be observed throughout the
field. When cross-plotted, observed salinities and OGWRs developed a boomerangshaped (hyperbola) pattern. This
"boomerang curve" shows that wells with
high OGWR follow a decreasing salinity
path (15,000 to 7,500 ppm Cl), wells with
moderate OGWR have the lowest salini-

ties (less than 7,500 ppm Cl), and wells
with low OGWR follow an increasing
salinity path (7,500-25,000+ Cl).
The three OGWR/salinity relationships are denoted as regions in Figure 4 using flowback data from new wells E and
F. Interestingly, the boomerang pattern is
mirrored when flowback OGWR is plotted against estimated ultimate recoveries.
This observation is profound, suggesting
that routine flowback information can be
used as an early indicator of long-term well
productivity.
In addition, OGWR/salinity relationships correspond to three distinct groups
of wells located within varying inferred
structural features. High-OGWR/highsalinity wells reflect those drilled in transfer zones with regional dip and limited or
no relay ramp features. ModerateOGWR/low-salinity wells are located in
relay ramp areas with counter-regional
(southwest dip) and seismically resolved
S Hmin parallel faults/fractures. LowOGWR/high-salinity wells are those in
which some portion of the well path
drilled through large regional (SHmax)
faults/fractures.
The connection between variations in
flowback water salinity and interpreted
structural features enforces that early-time

FIGURE 3
Mud Gas Analysis of Four Horizontal Eagle Ford Wells
Dip Azimuth (deg)
2.00

Gas kick 5,302u, +2,000u
background @ 12.1ppg MW

Shut in well, 8,000u
kick, mud up to 12
ppg
No kicks
reported, MW
12.8 ppg
Shut in well, gas kick
@12.4 ppg MW,
open to gas buster

Source: Three-D seismic data owned by Global Geophysical

SEPTEMBER 2015 61

American Oil and Gas Reporter - September 2015

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