U.S. horizontal drilling activity is booming.
From five years ago, industry estimates show a
five-fold increase to about 400 rigs per day.
These increased market pressures have stimulated
refined horizontal well data processing
techniques that reveal a world of small-scale
geologic features, like faulting, zone
undulation, and transient dip-direction
reversal. The economic results are increased
production rates from more footage drilled in
the reservoir “sweet spot” and—in some
cases—cost savings from elimination of pilot
holes.
Geosteering—the task of estimating well path
position within the stratigraphic setting and
occasionally changing the remaining planned path
accordingly—has traditionally for smaller
companies been a niche practice often handled
entirely onsite. However, more offsite oversight
is becoming the norm because 1) accelerated
production of reserves increasingly relies on
correct stratigraphic placement of the lateral;
2) the logistics of onsite-to-office data
transfer are simple with modern communications;
and 3) technical geosteering software is
available that when correctly applied enables a
quantum leap of interpretation confidence
compared to legacy geosteering methods that rely
only on drafting tools.
Technical Geosteering
Technical geosteering is a computational
signal-mapping task. Timely and depth-accurate
logging while drilling formation evaluation (LWDFE)
data is transformed—using a geometric location
estimate of a marker bed—to plot on a
representative stratigraphic type log. An
acceptable “fit” suggests a good estimate of the
marker bed location.
Gamma Ray
The most common LWDFE measurement applied to
technical geosteering is omni-directional gamma
ray. Gamma ray is chosen because of its
relatively insensitive signal response to
varying pore fluids, rock porosity, rock
permeability, and circumferential borehole
quality. Another favorable gamma ray attribute
is a short depth of investigation (e.g., 4-6
inches); with less rock “seen” by the tool there
is less chance for signal complication.
In
oil and gas geosteering applications the
measured depth (MD) frequency of gamma ray data
is typically 0.5 or 1 ft, which enables
fault-crossing recognition. Some operations rely
on focused gamma ray measurements (e.g.,
borehole high side and low side readings) to
either outright drive technical geosteering or
to augment interpretations relying primarily on
omni-directional gamma ray measurements.
3D Curved World
What complicates the software engine of
technical geosteering is addressing the fact
that both the well path (known-location) and the
payzone (unknown-location) simultaneously change
and curve in three-dimensional (3D) space. A
two-dimensional (2D) technical geosteering
analysis—one based on vertical section for
example—inherently suppresses resolution and
introduces distortion, especially with ‘3D’
wells and or ‘2D’ wells with thin payzones.
3D Technical Geosteering
In
2006, Stoner Engineering LLC developed a 3D
technical geosteering methodology that
eliminates the shortcomings of 2D analysis. Two
new geologic terms resulted from this work:
3DStratBlock and relative stratigraphic depth.
A
3DStratBlock (3DSB) is a planar surface that
mathematically represents the 3D location of a
geologic marker—usually the top of the payzone.
The target well path is at some offset distance
parallel to this marker. A 3DSB is defined with
a true dip, a true dip direction azimuth, map
coordinates corresponding to a MD along the
actual well path, and a control point true
vertical depth (TVD).
Relative stratigraphic depth (RSD) is simply a
stratigraphic distance relative to an
“arbitrary” reference point (i.e., the marker).
With respect to gamma and MD data from a logged
vertical offset well or pilot hole, with
horizontal beds, stratigraphic depth can simply
be MD. With respect to gamma and directional
survey TVD data from a directional offset well
or pilot hole, with horizontal beds,
stratigraphic depth can be TVD. If the beds are
not horizontal then TVD should be corrected with
regional dip to produce gamma versus
stratigraphic depth data. Stratigraphic depth
and gamma data, along with a reference depth
designation, produce a RSD type log.
With respect to a 3DSB however, RSD is
calculated and is the minimum 3D distance from a
respective coordinate—at a MD along the wellbore
from where gamma data was recorded—to the plane
that is the top of the 3DSB. The parameters that
define the 3DSB are calibrated to produce an
acceptable mapping of gamma data on to the type
log. When deviation becomes unacceptable, a new
3DSB is started because in most cases the
payzone has curved and or faulted.
3DSB Calibration
The most common 3DSB parameters to calibrate are
the true dip and the MD range over which the
respective 3DSB applies. After initial setup,
control point TVD only needs adjustment when a
fault is interpreted since continuity from the
prior 3DSB otherwise makes sense. True dip
direction azimuth is calibrated on the landing
to produce maximum signal expansion (“stretch”)
or maximum signal compression (“squeeze”), and
thereafter remains constant until a transient
dip-direction reversal is evidenced. When a
transient dip-direction reversal is evidenced,
which almost always occurs multiple times along
a horizontal well, the true dip direction
azimuth is simply “flipped” 180 degrees.
Thus, a 3DSB is a 3D planar location estimate of
the beds being drilled. As long as the actual
geologic structure is planar, the gamma data
will map—as calibrated via the 3DSB—on to the
type log with minimal/acceptable deviation and
therefore produces a good estimate of well path
position within the stratigraphic setting, even
though the wellbore always is curving in a
varied fashion. The 3DSB/RSD concept produces a
spatially dynamic coordinate system inherent to
the stratigraphic target.
Pilot Hole—Optional!
If
the type log “shape” is very persistent and if
regional true dips are low, often there is no
need to drill a pilot hole preceding the main
lateral because during the landing, technical
geosteering produces constant feedback about how
far the target is relative to the actual
wellbore. See Figure 1.
Some horizontal drilling operations design and
execute the landing to penetrate through most or
all of the payzone in order to confirm the gamma
signature and acquire such signal magnitude
respective to the specific gamma tool in the
bottom hole assembly. This methodology goes
hand-in-hand with a landing-derived type log.
Candidates for Technical
Geosteering
A
target zone for application of technical
geosteering evidences a formation evaluation
signal whose functional form persists aerially
and features sufficient magnitude contrast from
nearby beds. This “type log” is essential for
landing the horizontal well in the payzone.
Technical geosteering software called
SES—developed by the author—allows for derived
type logs to be created from the landing. This
allows for gamma functional form and magnitude
to play a role in calibrating future 3DSBs. A
landing-derived type log is used to geosteer the
rest of the well. See Figure 2.
Technical Geosteering Value
By
observing a cross-section of TVD versus MD that
displays the entire well path and the payzone as
defined from the 3DSBs, the best “big picture”
can be seen and drill-up/hold-steady/drill-down
planned well path revisions can intelligently be
made. See Figure 3. In practice, the number of
target changes communicated to the directional
driller can range from few to dozens. Updating
the target entails specifying inclination and
TVD at vertical section of zero.
Post-drilling application of technical
geosteering provides value by training personnel
on how to geosteer/interpret, and it produces a
most-complete understanding of the geologic
structure and actual well path / reservoir
completion. Such “in/out” understanding is often
critical for example for reservoir simulation of
wells drilled horizontally. It can also affect
completion procedures that use fracture
stimulation. The best possible geologic
interpretation can be attained after drilling
because there are no data depth-lag issues or
general human fatigue conditions that inherently
accompany live operations.
Technical geosteering is a numerical tool that
augments other data sources—akin to another
“dimension”—to assist the operator to interpret
where the wellbore is stratigraphically located.
Other data that may help with geosteering may
include multiple fluid-return-line-derived
measures, such as sample drill cuttings
analysis, gas chromatograph measurements, oil
shows, gas flare height and casing pressure in
underbalanced drilling operations, and general
rate of penetration characteristics. Most
fluid-derived measures suffer from bottoms-up
lag-time issues and relatively significant
source-depth uncertainty compared to LWDFE data.
Technical geosteering defines locally and helps
to refine globally the geologic model of the
marker bed along and nearby the actual drilled
wellbore. Small-scale geologic features—often
ignored with legacy geosteering methods that
rely only on plain drafting tools—like faulting
and zone undulation become better communicated
via the TVD versus MD cross-section displaying
calibrated 3DSBs and may help explain subsequent
production behaviors related to hydrocarbon and
or water flows, and issues related to water
sumps in wellbore low-spots.
