Geosteering Issues in Structurally
Challenging Areas of the Marcellus Shale Play By Kent C. Stewart – Geologist –
Blue Dragon Geoscience, LLC
My Background with Horizontal Wells
I have steered over 130 horizontal wells personally and
analyzed over 200 horizontal wells. My first encounter with a horizontal well was as a
mudlogger in a gas storage field in 1996, then as a geologist during a coal bed
methane project in 2001.
Geosteering in the Marcellus
can be challenging due to the structural geology. High dips, tight folding, and
offset faulting are quite common, especially in areas near the overthrust. In
general, each well and each area is unique. Below is a guide to geosteering the
Marcellus Shale.
Middle Devonian Geology
Most drilling areas seem to
be characterized by folding, which can be closely spaced. Other areas have
mostly small offsetting faults that are not typically detected on seismic,
especially 2D seismic. Most areas are bounded by larger fault/fold zones
characterized by high dips and large offsets that are prominent on seismic and
can be mapped for considerable distances. Recent research indicates that Acadian Middle Devonian structure is controlled by detachment zones floored in the Silurian salts.
Geosteering Goals
Geosteering in these areas of
high dips and variable structure invokes the need to balance the two main
mandates of the geosteerer:
1) to keep the
wellbore smooth and straight by staying within predetermined dogleg tolerances
2)
to stay in, or very near, the target interval
In most cases the wellbore smoothness
integrity is paramount, as difficulty in running casing can occur if there is
too much up and down and high doglegs in the hole. This situation is even more
precarious when there are turns and back-curves in the curve which tend to
increase torque and drag. This is more of a problem where the TVD is shallower,
as there is less string weight with which to push casing. One way to favor
wellbore smoothness is for the directional drillers to combine slides for
inclination changes with slides needed for azimuth correction, so that overall
sliding is minimized. Preparing for expected upcoming structural changes in the
lateral can be key to keeping the wellbore free of too many inclination changes
and high doglegs.
Tolerances
1) maximum inclination – this is particularly important for updip. Some MWD
tools will slip out of their sleeve at high inclination angles if not equipped
with a way to hold in the tool. Inclinations above 95-96 deg can be enough to
cause problems if future or recent past inclinations are 10 deg or more the
other way as is the case with folding. Dip changes from 5-6 deg up (95-96 deg) to
5-6 deg down (84-85 deg), within short VS intervals, are fairly common in the
Middle Devonian of Northeast Pennsylvania. High inclinations may be required to
avoid cutting into the Onondaga, usually due to unexpected high dips, and
should be decided on the basis of well parameters and expected future dips.
What the maximum updip or downdip inclination in a well should be depends on
the geology, the length of the lateral, and torque/drag issues encountered
during drilling.
2) maximum dogleg – dogleg tolerances may vary according to areas,
well depths (TVD), drilling parameters , and casing difficulties. An example of
a narrow dogleg tolerance would be 2 deg/100ft. It may not be possible to stay
within this tolerance as doglegs with full rotation (no sliding) can be this
much or larger on occasion. 4 deg/100ft should be fine in general and
3deg/100ft should be sufficient in areas where difficulty in running casing has
been encountered, or where needed pad drilling variance, or need to save
vertical section warrants a smoother borehole.
Landing the Curve
Lateral length in these wells
is often constrained by the distance between the larger fault zones. These fault
zones trend along strike at more or less regular intervals. The faults zones
are avoided due to issues of frack propagation as well as the obvious issues of
the difficulty of staying in or even near the target interval due to the very
high dips and offsets. There is also the possibility of losing mud or even lost
circulation issues associated with the fault zones. In order to increase vertical section, it is sometimes
necessary to drill the curve within the highly dipping zones and land the well near
where the dips level out. This brings further geosteering challenges. It is
often difficult to predict an accurate dip until the well gets laid out flat.
This is due mostly to the influence of the stratigraphic differences between
the well and the control well. Changing the landing point due to unexpected
dips can be a problem, especially in updip wells, if the landing point needs to
come up. This is less of an issue in downdip wells or if the landing point
needs to come down. So-called “soft landing” a little above the planned target
interval is generally a good strategy, especially in updip wells. When the
wellbore inclination reaches about 60-65 deg, the dip should be accurate enough
to make landing point changes, although at those angles there is a limitation
to how much landing point change can be made. Directional drillers should be
aware of stratigraphic intervals in certain areas where build rates can be hard
to maintain and attempt to stay at or above the plan line until the zone is
passed. This, of course, depends on what bend of motor is in the hole. Another concern with landing is to try to avoid a dip in the landing where the well is landed too low then immediately brought up. Directional drillers like to land the curve and wait a while to see what will happen in rotation. Often the inclination comes up in rotation. This can inadvertently add to the trough, or dip at the base of the curve.
Geosteering Strategies
1)
Soft-landing – especially in up-dip wells – in updip wells it seems best to plan landing at the
top of the target interval or a little above it. Higher than expected dips can and do occur.
2)
Anticipating known dip changes or fault offsets – where dip changes are known from offset wells
and/or suspected from seismic, it is possible to optimize in or near-target
footage by anticipating these changes. This is done by going to the top or
bottom (or above or below) the target interval and allowing the changing dip to
bring the bit back into the center of the target interval.
3)
Keeping in mind the pre-drill geology predicted from
seismic and structure maps – it is
important to keep this in mind even if one part of the well did not match the
expectations from seismic and/or mapping as the seismic may simply be skewed in
terms of vertical section, or different dips than predicted from seismic.
Below is an example of a geosteering strategy drilling through multiple closely spaced folds. In order to keep the borehole straight and smooth in this 6000 ft lateral section the upcoming structures were anticipated and doglegs were kept to a minimum.
Below is another example of steering strategy where there are closely-spaced folds. This is in an area of very fast drilling.
Long laterals especially need to keep the priority of well bore smoothness. Below is an example.
Pre-drill Geology
The pre-drill geology is very
important to accurate landing of curves and drilling of the lateral section. If
possible, a seismic line with interpretation should be available for the
geosteerer. A geophysicist or geologist should be able to make general
predictions concerning the expected dips, where dip changes should occur in
terms of vertical section, the expected landing point, and where faults might
occur in the well. From my experience, landing point is best predicted on the
basis of offset wells and structure maps, with seismic as a support. Again from
my experience, the general shape of the seismic is usually correct but
predicted dips and position of dip changes may be off considerably. Such
problems may have to do with acquisition, processing, and/or interpretation of
the seismic section. Old 2D seismic lines may miss very large faults. In areas
where there are high dips, it may be difficult to predict the geology close to
the larger faults, even with structural maps. Good well control is the best
predictive tool. Seismic positioning relative to the well can also be a factor
that leads to less predictability.
Post-drill Geology
It is especially important to
compare geosteering cross-sections to seismic line interpretation so that those
interpretations can be adjusted for future wells. This is important in terms of
observed dips and VS position of structures. These sections can also help with
detailing structure maps.
Target Interval Selection
There are several possible reasons for selecting a target interval. TOC, gas content, clay content, silica content, and best zone for optimal fracture propagation, are among these reasons. From a geosteering standpoint, the target interval is ideally one where there is discernible variation in the gamma curve. See example below:
Lithology Issues
ROP variations in the
Marcellus between hot gamma black shale and clean gamma limestone stringers can
be extreme. When drilling horizontally near dip, the bit can be deflected off
of the limestone contact. This can be desirable at times if the bit stays in
the adjacent hot shale at higher ROP and can rotate holding the same dip. This
can occasionally backfire if the bit digs into the limestone and tracks along
another bed boundary within the limestone. If it is desired to cut through the
limestone, it is most effective to do so at a variance from dip, preferably
starting at least a few feet above or below the limestone, depending on which
way one intends to go.
In some areas, there may be
zones of varying thickness within the target interval that drill faster than
others. One may attempt to stay in these zones. We have found some that are
only 1 or 2 ft thick, so are not so easy to stay within. In areas of slower
drilling, it may be a good idea to seek these zones.
Pyritic or other mineralized
zones may cause some problems with bit wear but these seem to be inconsistent.
Since there are many factors that can affect ROP, it is often not easy to
determine.
Drilling in the hotter,
softer shales, may bring on issues of hole integrity. The characteristics of
the cuttings should be watched. Not letting mud weight drop in these zones is
more important. Maintenance sweeps may be needed more frequently in these
sections.
Working with Parallel Offset
Horizontal Wells
Ideally, it is desirable to
drill horizontal wells in such a sequence that one well offsets the previous
one, is parallel, has a similar VS start, and is similarly perpendicular to
strike of the faults – which happens to be generally perpendicular to maximum
principle stress direction in Appalachian Basin Middle Devonian – which is
convenient in this respect. Sometimes the wells will be a little bit oblique to
being perpendicular to fault/fold and structural strike, so that once
anticlines and synclines can be matched, the VS of the offset can be shifted to
match the well being drilled in order to predict upcoming structures. This has
worked very well in my experience. Sometimes there will be significant
differences in parallel offsets as the following examples show but much of the
time the differences tend to be nearer to the major faults.
Multi-Well Pad Planning
Considerations
One potential problem with
drilling the curve in or near one of the large fault zones is the potential for
the predicted leveling out of dip to be further out than expected. This could
occur due to seismic displacement issues. This could result in less of the
lateral being drilled in the reservoir and/or target interval. Such a problem
could be exacerbated on a multi-well pad.
If possible, it is best to
first drill the wells in each direction on a multi-well pad that have the least
amount of swing-out so that the exact geology can be worked out in a well with
no swing-out. This makes it easier for the directional driller to focus on
following the plan rather than having to deal with landing point changes in
addition to turning out and horizontal. Once the geology is well worked out, it
is easier to drill the swing-out wells.
Criteria for Target Changes and
Inclination Changes
This can vary according to
operator parameters. Typically any landing point changes should be discussed
with operator geologists and approved by drilling staff as well. Small changes
in recommended inclination may be at the discretion of the geosteerer. Larger
changes, preferably delineated ahead of time, should be discussed. These larger
changes could be 1, 2, 3, or 4 deg depending on the area, the target thickness,
the dip, the operator preference, etc. The operator should have a general
protocol for inclination changes.
Directional Drilling
It should be noted that
different directional drillers have different styles of drilling. Thus, it is
often helpful when the geosteerer and the directional drillers are in tune with
one another and discuss often the upcoming rotations and/or slides. Effective
and clear communication is essential.
Correlation Difficulties and Gamma
Issues
Sometimes there will be
correlation mistakes and difficulties. There may be situations where there are
two or more possible correlations. This may be due to poor gamma quality,
‘look-alike’ gamma lobes, or unexpected geology, such as fault offsets or
unexpected strong dip changes. In these cases it is often best to wait before
reacting too strongly. Gamma zones can look different when they are drilled at
different angles and ROPs. Sometimes a lime stringer may thicken or thin
further out in the lateral. Gamma values may differ in the same stratigraphic
zone when penetrated in different places along the lateral. Zones may be masked
with poor quality gamma or gamma “spiking”. Certain markers may be sometimes
present and sometimes not present, which can make correlation difficult. Such
situations should be noted and collated for each micro-area. Fast drilling can
reduce gamma quality since it reduces the amount of samples the gamma gets over
a given measured depth section. If a gamma tool is switched out during drilling
there can be differences between the two tools which are difficult to reconcile
until enough stratigraphic section is drilled to do so.
Updating Estimated Formation Tops
It is important to update any
changes in estimated formation tops during the drilling of the curve. This may
be relevant to the mud engineer since mud weight may be increased at a certain
formation top. This also allows the directional drillers to be ready for zones
which have different ROPs and different build rates.
Stoner Engineering (SES) Software
This software, and others
like it, allows one to quickly examine different correlation scenarios. One can
make various plots in various ways. One can utilize different control wells
simultaneously without much difficulty. While vertical control wells make
better control wells overall, one can also utilize TVD logs of offset
horizontal wells, at least through nearly all of the curve to landing, in most
cases. This can be an advantage where vertical control wells are farther away. The
log matching algorithms of SES can be manipulated and examined quickly in order
to get the most likely interpretation.
D-Plot Software
This is a simple plotting
software that ties in to Excel. This makes it convenient for presentation and
for comparing and shifting parallel offset horizontal wells. SES software also
makes good cross-sections, but it is tied in to the gamma so much that small
thickness differences between the well being drilled and the control well can
skew the dips, especially in short sections. I have found it better to keep a
plot with less overall data points, but with more definite data points, in
order to get an accurate avg. dip over longer VS intervals.
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