A Short History of Geosteering

A Short History of Geosteering – by Kent C. Stewart, Geologist, Blue Dragon Geoscience, LLC

My first experience with a horizontal well was in a gas storage field in 1996 where I was a mud logger. This was a well in the Oriskany Sandstone near Charleston, West Virginia. The targeted part of the porous sandstone was clean, well rounded, and well sorted, and fairly unconsolidated. We got to take samples from a shale shaker, which was rare in those days in Appalachia. Drilling was very slow when we got horizontal so we took samples every two feet. We were especially making note of a glauconitic zone of characteristic green color. We correlated this zone to a soft spot of high ROP just above the main porosity zone. We were helping to steer the well by noting the recurring presence of this zone and the clean sand below it. However, after a few days of this very slow drilling we saw no glauconite and no clean sand but a more consolidated finer grained sand. We were out of the porosity zone. Apparently, the main geologist who had come from Texas had miscalculated the dip. Because of this the project was scrapped since at the time short-radius horizontal drilling was less flexible in changing inclinations. The goal of the project was to increase deliverability from the storage field in times of high winter demand. They sought deliverability from these horizontal wells of up to 50MMFC per day. Horizontal wells can especially increase deliverability late in the storage draw season when volumes and pressure in the storage reservoir are lower. This well did not succeed due to inadequate steering but others in the field did. Other advantages of horizontal wells in gas storage fields include the ability to develop less favorable parts of the reservoir, reduce the level of base gas required to pressure the working gas, fewer surface sites, and less pipe and surface equipment.

In the late 1980’s the Cretaceous Austin Chalk was a big play in Texas and Louisiana. Vertical drilling made occasional good wells but there were also many dry holes. Lateral drilling through the reservoir was quite successful in some fields but less so in others. It was thought that lateral wells could better connect with the natural fracture networks which had a strong vertical component. Eventually these wells came to be often steered with gamma ray in the new technique of logging-while-drilling (LWD), or measurement-while drilling (MWD). Incidentally the source of Austin Chalk oil is now thought to be the prolific Eagle Ford Shale below it, although it was once thought to be self-sourced. Some of the horizontal gas wells in the deeper Austin Chalk trend in Texas had phenomenal production, some exceeding 50MMCF per day in line. During this time period the first company devoted to geosteering as a specialty, Horizontal Solutions International (HSI), came about in the mid-1990’s. 

Horizontal drilling of coal bed methane wells became common in the late 1990’s and early 2000’s. CBM wells in the Appalachian Basin were drilled on air, mainly in order to de-gas the coals before mining the same seams. Drilling was very fast as coals are quite soft relative to the rock around them. This contrast is an advantage to geosteering as the bit tends to stay in the soft rock and deflect off of the hard rock. Even so, properly orienting the motor was still important to staying in the coal. In coal, in the absence of MWD gamma one can steer on the basis of ROP. Samples can also help and with coal, even looking at the color of what it coming out of the flow line can verify if the bit is in the coal or not. I was able to work for a short-time on-site at one of these wells in 2001 learning a bit of geosteering by using Excel worksheets of survey data and calculating dips. The main issue when the bit exited the coal bed was simply to determine whether it was above or below it. If there was a contrast in rock above and below that was certainly preferred to a transition into similar rock character in terms of ROP, gamma, and samples.

Beginning in late 2005 the company I was working for decided to try a Devonian Lower Huron Shale well in Southern Ohio drilled with stiff foam, which proved to be a mistake. Vibrations affected the tools which could not get good reliable survey and gamma readings. We sent the data to a geosteering specialist via email who then sent back an interpretation. This continued as we drilled horizontal wells in the Marcellus Shale beginning in 2006. I would correlate and steer with paper logs. After a certain amount of time I was able to rather routinely contradict some of the interpretations of our specialist. I then devised a way to present the data graphically. It was fairly accurate but tedious and slow. Soon thereafter the company acquired licenses for Stoner Engineering geosteering software (SES). I was now able to utilize it for faster correlations and perhaps more importantly in the structurally complex Marcellus, to test several different correlation scenarios quickly and determine the correct one. We no longer needed our specialist. By the late 2000’s geosteering had become well established in the shale plays and the structural, depositional, and petrophysical variations of each play were becoming apparent. With better well control the regional and local dips were getting a little more predictable but in some plays like the Niobrara, Woodford, Marcellus, and others, small faults undetectable by seismic resolution had to be interpreted by the geosteerer, typically after a significant amount of section had been drilled past the fault. In addition since the survey and gamma are typically close to 50 ft. behind the bit this means that by the time the post-fault correlation could be determined some hole was necessarily drilled out of zone before adjustments could be made. In some cases it was worse in the Marcellus as high dips, sometimes very high dips up to 45 degrees, could be encountered near reverse faults, or high-angle thrusts. These zones were typically avoided but sometimes they were not seen on old 2D seismic and sometimes the curve was drilled in the fault zone to try and maximize lateral well length between the large fault zones. This made geosteering quite challenging at times as unexpected dip changes and folds were not uncommon. Some plays and areas of plays are relatively calm geologically. In those areas it is of course easier to maximize in-target footage even in small target windows.

By 2007 around 400 rigs were drilling horizontally in multiple shale plays: mainly the Barnett, the Bakken, the Bossier and Haynesville, the Fayetteville, the Woodford, and the Marcellus. The Niobrara, Eagle Ford, Mississippi Lime, SCOOP, STACK, Tuscaloosa Marine Shale, Utica-Point Pleasant, Burket, and multiple Permian plays would come later. Dr. Mike Stoner, the creator of SES software defined some of the terms and parameters of “technical geosteering.” One is the idea of Relative Stratigraphic Depth (RSD) which he defined as “stratigraphic distance relative to an “arbitrary” reference point [or marker bed]” This software and others can stretch or squeeze a gamma or other MWD log section to match a control well TVD log and/or the adjusted TVD log just landed in the well being drilled. No software can be perfect as it difficult to account for changes in stratigraphic thickness of different zones over the length of a lateral, for deflection off hard zones which can temporarily distort the inclination and make it appear that the dip has changed, and differences in gamma character due to inadequate sampling rates as a result of very fast drilling. A good geosteerer can see through these issues and adjust accordingly, thus optimizing the effectiveness of the software.

   

By around 2010 geosteering had taken four main forms which it retains today. 1) Dedicated geosteering centers were established where geologists typically work 12-hour shifts, sometimes on multiple wells. The expense of the software made this economic as software license keys could be optimized. 2) There was on-site geosteering, sometimes combined with mudlogging. As access to software increased and geosteering was in demand more geologists were learning geosteering, some while learning mudlogging. This was probably not wise at the time as that is lot to manage for a young geologist, although there are likely some outfits that with experience do fairly well at it now. Some plays are better geosteered on-site. One is perhaps the Bakken as I have heard but I have no experience with it. Plays where gamma is less distinct and where ROP and samples are more definitive, are probably good candidates for on-site geosteering. 3) Remote, or off-site geosteering has also been a successful format. The advantages to remote geosteering include avoiding travel expenses and travel times, avoiding another body on location, and avoiding the distractions of the rig environment. With WITSML well information systems such as Pason, all of the important parameters of the well can be monitored in real-time from anywhere. The phone app makes it very portable as well. 4) In-House geosteering has some advantages if the geologist is involved in updating structure maps, isopach maps, and in well-planning. Due to the necessity of 24-hour coverage it also requires a remote geosteering component and so is similar to contracting out the work. Sometimes in-house geologists will follow along geosteering along with field or remote geosteerers for duplicate coverage and cross-checking, which is not a bad idea in structurally complex plays. 

Other potential innovations involve utilizing resistivity logs where gamma ray is indistinct or has very little variable character. Another is the technique of chemostratigraphy – correlating geochemically by powdering samples to determine elemental constituents by XRD/XRF (X-Ray diffraction and X-ray fluorescence). While this is potentially useful in some circumstances it is also slow and not very amenable to being useful at current ROPs. The technique itself is quite useful and probably has better application to compare wells after they are drilled. Another method is detailed Mass Spectrometry to tag specific mud gas signatures to specific zones. Yet another technique that may have niche applications in complex trapped conventional reservoirs, offshore reservoirs, and faulted unconventional reservoirs is seismic-while-drilling (SWD). The main goal of SWD is to image what is ahead of the bit. Schlumberger has used the technique quite a bit but not much is known about its success rate. I had heard years ago of the idea of using resisitivity to see ahead of the bit when attached to a BHA close to the bit. if I recall correctly it was because it penetrates deeper than other logs and can be pointed ahead of the bit. Another new technique I just read about is Baker's VisiTrak which utilizes "extra deep reading azimuthal resistivity..," in combination with omnidirectional sensors (360deg) that can image bed boundaries up to 100ft ahead of the bit. The sensors are very close to the bit attached to the BHA with a rotary steerable motor.

All geosteerers make correlation mistakes from time to time. The likelihood of making a mistake can be influenced by several factors: gamma quality, look-alike zones, unexpected large dip changes, and most commonly – similar gamma character above and below a known well-correlated zone. More well control leads to refined structure maps and thus better predictability of regional dip. Pad wells drilled parallel are typically easiest to steer but can have some variability. Some of that variability has to do with whether the wells are drilled perpendicular, oblique, or parallel with regional dip, as well as changes in structure. Distance from the control well is important as thickness changes relative to that well can be significant. This is more common in the curve which traverses more stratigraphic distance than a target window. It can also be a factor in the target interval but there is usually not more than a foot or two variation. Even so this can be a factor when drilling a small target window in areas of depositional thinning on marine shelves. Sometimes deflections off of hard zones or depositional variations can look like small faults or sometimes they may actually be small faults. Thus, I think it is difficult to determine for sure if offsets less than about 3 feet or so are actual faults or false faults. If a similar offset is encountered near the same VS in one or more parallel well(s) then it is more likely a fault. In such cases the actual orientation (azimuth) of the fault can be determined. If a large gas show is encountered without changing zones and without changes in mud properties (weight, viscosity, water loss, cuttings size and shape) then it is possible that a significant gas-filled fracture was encountered.

There are also some psychological and communication issues in geosteering. Since the process of geosteering involves frequent interpretation of data in constantly changing conditions that may require adjustments there are times when correlations are uncertain and tentative. Communicating degree of certainty is important. Considering reliability of regional dip is important as well. From my experience it is best to have frequent contact with the directional drillers, MWD personnel, and sometimes the Drilling Engineer, and occasionally the mudloggers for sample and gas verifications, either in person, by phone, or through email. Email is usually fine but if drilling out-of-zone seems possible then a phone call or two can be warranted. Some directional drillers have particular styles of drilling and don’t like to change inclination. Dog-legs need to be considered. Tolerances and protocols for changing inclination and by how much need to be discussed. Structurally complex areas can make such required communication more frequent than one might like but sometimes that is the nature of the beast.

  

Geosteering results can be used to determine the amount of what I call primary reservoir access (PRA), which is access to the most desirable reservoir rock. If that rock is “hot” shale then footage and percentage of the wellbore in the hot shale can be calculated. In some source-rock mudstone reservoirs there are thin beds of varying gamma and interbedded limestones even in small target intervals. In such cases one may determine what I call – relative optimized reservoir access (RORA)– which is basically how much of the wellbore is in the best part of the target interval. Primary reservoir access (PRA) can be compared to the microseismic delineation of stimulated reservoir volume (SRV). With microseismic studies thin stratigraphic intervals defined by geosteering correlations can be compared in terms of induced fracture propagation, tendency for frac height growth, and frac half-length. Target intervals can be tweaked or optimized on the basis of such studies.

                  

Perhaps the most desirable setup for geosteering, though exceedingly rare, would include gamma ray and resistivity logs, both very close to the bit with a rotary steerable to keep the well from moving up and down too much through the formation. Plays with faults and/or high dips are most amenable to having gamma MWD and surveys close to the bit in order to minimize out-of-target drilling. SES software has improved over the years and now incorporates a nice cross-section feature that accommodates mud logs, ROP logs, and other data. It can also accept the grid data that makes up structure maps and seismic sections. Newer geosteering programs like ROGII’s StarSteer can accommodate seismic lines, image logs, and other nice graphical features.

Another current issue with the ubiquity of multi-pad wells is wells with large turn-outs for proper spacing. This can create some distortions during drilling of the curve but they are typically quite manageable. A related issue is the need the change azimuth to keep required spacing from an unleased property. Yet another is to avoid so-called “no tag zones” near lease lines. This is an issue in Pennsylvania where the base of the Marcellus target zone may be a mere two feet from a no-tag zone (Onondaga Limestone) although the true rationale for this rule is impractical and potentially unfairly punitive to an oil and gas operator, especially if an unexpected fault, dip, or inclination would occur.
    

Horizontal and directional wells requiring some degree of geosteering are also utilized in deep geothermal drilling, where MWD tools and mud motors need to be able to endure high temperatures for long periods. The deep, high temperature/high pressure Haynesville Shale and Bossier plays and other oil and gas plays also require HPHT tools. Geosteering would also be required in carbon sequestration wells where horizontal wells increase both the CO2 injectivity and the CO2 storage capacity of deep brine reservoirs. Horizontal drilling for near-surface pipeline and utility road and stream crossings generally don’t require geosteering, although soil horizons and rock bed dips and boundaries should be known and documented. 

Most recently, as the oil & and gas industry has been contracting due to low commodity prices and increased efficiency, the need for day-rate field and operations people has been reduced. This has created an overhang of qualified field people that will likely stick around to some extent even as prices recover. Thus there is now much competition in terms of people and price. Success rates driven by experience and effective workflows are very important in tight margins.

References:

Geosteering Keeps Drillers on the Right Track – by Louise S. Durham, in A.A.P.G. Explorer, Dec. 2012

Technical Geosteering Finds the Sweet Spot – by Dr. Mike Stoner, in E & P Magazine, November 2007, pgs. 71-77

Carbon Dioxide Injectivity in Brine Reservoirs Using Horizontal Wells – multiple authors, National Energy Technology Lab – U.S DOE

ENEL’s Experience With Directional Geothermal Wells – by Bianchi, Quintavalle, and Rossi (Italy)

Horizontal Drilling Used in Gas Storage Programs – by Young, McDonald, and Shikari (Gas Research Institute), in Oil & Gas Journal, April, 5, 1993

Geosteering as Research – by Louise S. Durham, in A.A.P.G. Explorer, Dec. 2013

Seismic While Drilling Moves Closer to Reality – by David Brown, in A.A.P.G. Explorer, Dec. 2013

VisiTrak Services May Eliminate Need for Pilot Wells in Wellbore Placement - by Alex Endress, in Drilling Contractor, drillingcontractor.org, 2016

Guide to Geosteering Series - Parts 1,2,3, and 4 - by Patrick Tobin, posted in OilPro, Feb., 2016

Dip Distortion in Geosteering Due to Stratigraphic Thinning or Thickening Relative to Control Wells

Dip Distortion in Geosteering Due to Stratigraphic Thinning or Thickening Relative to Control Well(s)

Dip distortion due to stratigraphic thinning or thickening relative to control well(s) is common when geosteering wells. Distorted dip may be misinterpreted as a structural anomaly. It may look like a small fault or fold in graphic format when matching up gamma. A tell-tale sign of thinning is dip distortion every time the particular section is cut. The direction of dip change (up or down) should be opposite when cutting down section compared to the direction when cutting up section.

Geosteering programs will distort the dip automatically with thickness differences relative to control well(s) unless the dips are manually adjusted. If dips are not manually adjusted, the TVDs given at the MDs in those sections will not be correct. Such TVDs should not be used in subsequent structure mapping.

Thickening relative to control well(s) is harder to detect and may manifest as more section running along with dip in the particular section than otherwise would be the case.

Deflection of the bit off of hard zones can also cause dip distortion, often of a similar magnitude. However, this is not accompanied by cutting through section but by changing inclination due to deflecting. In deflection the inclination is often unexpected and it is likely that the inclination is distorted rather than the dip, although it is typically assumed that it is dip distortion since that is how the geosteering program must interpret it. On this basis it should be relatively easy to distinguish between the two. Of course, sometimes there may be genuine structural changes due to small faults so that the expressed dip is real. Folds typically show as folds with no dip distortion.

Below is an SES example of dip distortion. Here it looks like the clean limey section in the target interval is thinned relative to the control well. It will be noted that when cutting down through that section the dip was distorted up and when cutting up through the section the dip was distorted down. This occurred multiple times.