WHAT IS GEOSTEERING?
Geosteering is a practice specific to high-angle and horizontal (HAHZ) wellbore
drilling. A good "early"
historical perspective of horizontal drilling is published in Journal of Petroleum Technology,
July 1999, pages 20-24, titled "Horizontal and Multilateral Wells: Increasing Production and
Reducing Overall Drilling and Completion Costs";
part of a series sponsored by Society of Petroleum
Engineers (SPE) Foundation. The
link to its pdf now requires SPE
membership or $$$. :-( On a lighter note, the American
Association of Petroleum Geologists presents with
Like Landing in Fog."
Horizontal drilling in the USA became a niche practice during the
1980s and was only applied in certain fields and areas. During the 1990s the
average fraction of drilled oil & gas wellbores that were horizontal at total depth ("horizontally TD'd") was
7%. 2004 was the first year the average weekly fraction was
10%. Wells horizontally TD'd first exceeded vertical+directional in March 2010. Not long
thereafter the fraction hit 60% in May 2012 and 70% in October 2014. Finally, 80% was first tagged in February 2016.
As-of November 2018, the fraction of wellbores horizontally TD'd is ~86%, according to Baker Hughes
Rig Count data.
Geosteering in general is drilling a
horizontal wellbore that ideally is located within or near preferred layers of rock.
As interpretive analysis performed while drilling or
after drilling, geosteering determines and communicates a wellbore's stratigraphic depth location
in part by estimating local geometric bedding structure. Early geosteering was performed mostly
as inference from cuttings
samples, paper well logs, structure maps, rough sketches, and 2D trigonometry. Modern geosteering
normally incorporates more sources of information and insight from now-evolved quantitative correlation methods. Ultimately, today's
geosteering provides explicit approximation to the location of nearby geologic beds in relation to a wellbore or
coordinate system, and as such, helps to explain rock/wellbore completion and subsequent oil/gas/water/frac fluid-flow
observations from or into rock.
GEOSTEERING - DIFFERENT QUANTITATIVE APPROACHES
Quantitative geosteering analyses often follow one of two fundamental technical
approaches. Along the horizontal wellbore path, one approach effectively assumes the vertical
formation-evaluation (FE) well log profile is known while the other approach effectively assumes that the
stratigraphic FE well log profile is known. Regardless of approach, normally one or very
few sparsely-distributed control well logs from non-horizontal wellbores exist in the direct drilling vicinity, and, the absolute 3D
coordinate locations of control information are blurred within ellipsoids of uncertainty from directional survey "errors".
In many commercial oil and gas horizontal well geologic settings, stratigraphic
thickness is relatively more stable than vertical thickness along the horizontal wellbore path because
bedding dip changes and faults are crossed.
By definition, bed vertical thickness
depends on dip (initially unknown) AND stratigraphic thickness at the map location of interest, and furthermore is complicated when considering attributes of true dip
versus apparent dip and the fact that—incidentally and/or purposely—real 3D wellbore paths always turn left or turn right in map view. In
numerous structurally-complex (i.e., dip-varying) geologic settings over typical horizontal wellbore lengths, stratigraphic
thickness may actually be effectively constant or its thickening/thinning tendencies known with sufficient
certainty. In the cross-section below the wellbore turns right about 40 degrees azimuth after
landing and true stratigraphic thickness (TST) throughout is fully constant for all layers while true vertical
thickness (TVT) is of course dip-dependent and thus varies. In other words, TVT will almost always vary because
dip almost always varies; but the same is not necessarily true for TST.
For these technical reasons and in general when trying to approximate structure/dip, analyzing FE data at the local horizontal well
level in the stratigraphic depth domain is
superior than in the vertical depth domain (DVerticalDepth
≠ DStratigraphicDepth) and performing 3D-math geosteering logic is
superior than projecting into a 2D vertical plane (DMeasuredDepth
GEOSTEERING with help from AZIMUTHAL MEASUREMENTS
Primary geosteering interpretation value deriving explicitly
from azimuthal LWD signal is evidenced when high-side and low-side average value readings are
sufficiently different while the wellbore is approaching/crossing a bed boundary
with suitable signal contrast between the adjacent beds. From observing this very progression AND with certainty of
immediately-prior wellbore stratigraphic location, it may for example be determinable that
a wellbore is scraping/leaving a zone via its top or its base. Imaging is not required to extract this
interpretation value from the data but imaging may be visually preferred and is efficient at
presenting such LWD signal when available.
Bed dip estimation directly from azimuthal imaging relies on
multiple hole/tool assumptions and thereby introduces parameters needing tuning and/or conjecture. At least two such parameters are
actual hole size at MD (e.g., from a caliper log) and "electrical penetration depth"
at MD, which are unknown with sufficient accuracy
to be independently illuminating. In general with all else equal, adding more degrees of freedom that require
tuning ≠ less bed dip uncertainty. In other words, if quantitative dip estimation from azimuthal imaging
is able to provide interpretation assistance, the stratigraphic picture is already clear from applying the
fundamental correlation logic described above. Circular results aren't breakthroughs.
However, to be clear, azimuthal LWD signal can at times/depths reduce
uncertainty and be "leaned-on" to make smarter steering bets regarding probable geologic structural realities.
LWD TOOL MODEL-BASED GEOSTEERING
LWD tool-dependent "model-based geosteering" as a
practical/non-academic geologic interpretation benefit is highly debatable. Too much of
what the analyst can't know with certainty—or indeed is intended to be discerned—must be assumed, creating a major circular
result. Non-uniqueness and non-practical complexity abounds and much regarding extremely pertinent parameter values such as
true stratigraphic thicknesses, bed dip, and petrophysical properties at MD and at different radii of investigation,
unfortunately, are unknown with insight-producing certainty.
3D SEISMIC/GRID MODEL-BASED GEOSTEERING
Geologic structure models have value and purpose but if
were dependably 3D-accurate at horizontal wellbore stratigraphic drilling scale—somewhere between core and vertical-wellbore—you wouldn't be reading this page and there wouldn't be
>20 geosteering software offerings. Drillers would very much rather "just" drill geometry and can do so
well, but operators know the less-expensive "geo-blindfolded" approach does not maximize the economic value of fluid flows from horizontal
wellbores. Small-scale rock/wellbore understandings matter and the relevant $64000 questions cannot be answered
or accurately predicted from large-scale models alone.
3D structure models often
look neat as pixels on screens but the typical
extreme sparseness of hard data samples means its
structural uncertainty is beyond that which is
required for commercially successful geosteering.
Nature is less-often smooth and predictable and so
decisions based on actual "in the rough" observations prevail over
In practice and excluding a simple local TVD bulk-shift or having external controls points located very
closely nearby the subject HAHZ wellbore, adding structural control points located from behind
the drill bit and re-gridding the full-field 3D structure model does not materially improve the level
of certainty regarding drillable structure directly ahead of the drill bit. In uncommon data-rich situations and in particular geologic
settings, grid data may efficiently communicate
predicted zone thinning/thickening tendencies and major structural attributes but because
small-scale dip is also unknown, significant uncertainty surrounds bed thickness insight able to be gleaned from analyzing horizontal wellbore data.
Please see "Geosteering Trade Secrets" chapter in
SES User Manual for much more discussion.
To be clear, full-field 3D models can at times/depths
generally constrain structural estimates and provide rational fall-back options when "current"
data analysis situations are ambiguous. However, a real risk of materially using 3D models when geosteering is over-relying on preconceived
expectations instead of best-analyzing the actual data as they are.
NO SUBSTITUTE FOR 'G&E' INTELLIGENCE
For any and all geosteering interpretation approaches, what's precisely known is limited and sporadically
located along the wellbore path. Last but not least, there certainly is no substitute for geologic and engineering
intelligence—of the area and of the beds being drilled—on the ultimate ability to approximate reality sufficiently well to make informed geosteering
and directional steering decisions.
The following article written by Dr. Mike Stoner was published in E&P Magazine, November 2007,
pages 71-77, titled "Technical Geosteering Finds the Sweet Spot".
Click here to view it with larger figures.
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
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 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.
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.
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
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.
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.
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.
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
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
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.
‡This sentence is better as: "True dip direction
azimuth is typically set from knowledge gleaned from
a contour map over the drilling area, and thereafter
remains constant until a transient dip-direction
reversal is evidenced."
The preceding article written by Dr.
Mike Stoner was published in E&P Magazine, November 2007,
pages 71-77, titled "Technical
Geosteering Finds the Sweet Spot". Click here to view it with