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 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 tolerances2) 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.
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.
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.
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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.
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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.
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:
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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.
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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.
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.
Coordinating with Mudloggers
Mudloggers can verify lime
zones, mineralogy changes such as the presence of pyrite, and note changes in
samples. Gas shows can verify a zone when it is uncertain which lobe is being
drilled. Mudlogs and geosteering cross-sections can be combined to analyze the
hydrocarbon or natural fracture qualities of different parts of a reservoir. On
occasion one may correlate a gas show with a zone that is not usually a good
gas bearer or in a zone that has been drilled horizontally in the same well
with lesser shows. Such gas shows suggest that a gas-bearing fracture may have
been crossed. Of course, one should rule out changes in mud properties
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.
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.