An interview with Doug Voegtlin

INTERVIEW COORDINATED BY SATINDER CHOPRA

“It is important to find challenge, purpose and fulfillment in your work.”

Doug Voegtlin is an accomplished geophysicist whose career spans more than three decades across the Canadian oil and gas industry. A graduate in geophysics from the University of Alberta, he began his journey at a time when seismic interpretation relied heavily on hands-on analysis of paper sections and field experience. From early summer student roles at Dome Petroleum and Home Oil to leadership positions with companies such as Apache Canada, Compton Petroleum, Velvet Energy, and Westbrick Energy, his professional journey reflects continuous growth, adaptability, and technical excellence.

Over the years, he played key roles in seismic interpretation, exploration planning, prospect generation, and geophysical leadership across a variety of conventional and unconventional resource plays. Known for his practical approach, openness to innovation, and strong technical judgment, he earned the trust of colleagues, management, and industry partners alike, eventually rising to the role of Chief Geophysicist and later serving as a trusted technical advisor.

His career story is also one of mentorship, resilience through industry cycles, and a deep passion for understanding the subsurface, qualities that continue to shape his perspective on geophysics and exploration today.

Doug, could you share an overview of your educational background and walk us through your professional journey? What were the key turning points that led you from an early-career geophysicist to the roles of Chief Geophysicist and Technical Advisor?

My educational journey began with an interest in teaching physics, mathematics, and physical education. However, after realizing there was an oversupply of education students, I shifted into general science. My introduction to geophysics came through engineering roommates who mentioned summer jobs in the field. Since I had always enjoyed mathematics and physics, geophysics immediately appealed to me, and I transferred into the program. I graduated with a B.Sc. in Geophysics from the University of Alberta in 1989.

My professional career started as a summer student at Dome Petroleum, where I was first exposed to seismic interpretation under the mentorship of Peter Vodak. A second summer position at Home Oil further strengthened my technical skills in seismic interpretation and prospect evaluation. Following an industry downturn, I joined Dekalb Energy as a geophysical technician, where I gained hands-on experience managing seismic data and eventually advanced to a junior geophysicist role. During this period, mentors such as Barry Flavelle encouraged me to gain field experience and understand seismic acquisition firsthand.

A major turning point in my career came in the early 1990s when Apache Canada acquired Dekalb. With only four years of experience, I unexpectedly found myself leading the geophysical function, managing budgets, seismic planning, and technical presentations. That experience accelerated my professional growth and gave me confidence in both technical and leadership responsibilities.

I later joined Remington Energy and then Compton Petroleum, where I expanded both my technical and managerial expertise. At Compton, my work on the Basal Quartz play and my willingness to critically evaluate new technologies strengthened my reputation within the industry. Eventually, I was appointed Chief Geophysicist.

Later in my career, I joined startup ventures including Oban Energy and Velvet Energy, where I helped build exploration portfolios and guide key technical decisions. My final corporate role was with Westbrick Energy before its acquisition by Vermilion Energy.

Looking back, my progression into leadership was never something I specifically planned for. Instead, it came naturally through consistently earning the trust of colleagues, contractors, and management by being technically reliable, open to learning, and willing to take responsibility.

You have dedicated your entire career to geophysics discipline. What originally drew you to geophysics, and what has sustained your passion for it over the years?

My original draw to geophysics was to have a career that involved both mathematics and physics. Over the years, several key elements have sustained my passion for the field. The first is, I genuinely enjoy the mental challenge of solving problems. Early in my career at Dekalb, a geophysicist told me, “The seismic line you are looking at now has been looked at by many geophysicists at multiple companies. Your job is to find what they have missed.” That mindset stayed with me because it captures the essence of exploration, a constant challenge to see beyond the obvious. Besides, I have always been very team-oriented, whether in sports or at work. Interpreting seismic data is ultimately a collaborative puzzle; it requires integrating your geophysical insights with the structural models and engineering data provided by your peers. The ultimate testing of the team’s collective results comes with drilling, delivering a tangible outcome, rather than just theoretical.

Finally, I am driven by the ability to visualize and reveal what is hidden. It is exceptionally rare in any profession to be the first person in the world to do something. However, when you acquire 3D data over a previously unshot area, you are quite literally the first person in the world to visualize that part of the Earth. Having that window into the subsurface is simply a privilege.

Looking back across your career, what would you say have been your primary aspirations and defining motivations as a geophysicist?

My primary motivation has always been to bring forward as complete and accurate an understanding of the subsurface as is possible. I have a compelling internal drive to understand the geological configurations and make sense of what is hidden beneath the surface. Besides interpretation, I am passionate about educating those within the organization and outside the geophysics discipline on the value of seismic. Over the years, I have presented a lunch-and-learn talk entitled “Geophysics: what does Doug do anyway”. It has been incredibly rewarding to have the marketers, accountants, and engineers, all thank me for demystifying seismic data and giving them a clear, practical understanding of what a seismic section represents and how we interpret it.

You have a reputation for creative problem-solving. Could you share a few instances where thinking outside the box directly influenced a project’s outcome or drove business success?

When I started with Compton Petroleum, I was assigned an area south of Calgary and told that I would need to pick four Mississippian locations and two Crossfield (Wabamun) locations within the following year. This was part of a farm-in land earning deal with Exxon Mobil on their fee lands. As I had never worked in that area before, it presented an interesting opportunity. The area was covered by a reasonably good 2D seismic grid, and the seismic structures were sizeable. Water, however, was expected to be an issue as the Mississippian section was not situated in a deep basin setting and the majority of gas had migrated through prior to the structuring. I reprocessed a seismic line that crossed several known Mississippian wells, including one that was structurally high and productive. What became clear was that the time high did not correspond to the actual depth high. I worked with a processor (Judy Leah, who remained my preferred processor until her retirement) to address this problem. We investigated anisotropy effects, experimented with velocity variations, and explored multiple processing approaches, yet getting the correct structural positioning for the Mississippian proved to be difficult. Ultimately, by studying what I would call the ‘template line’, I recognized a consistent relationship between the true structural high and a deeper feature that was offset from the seismic time high. The test locations were selected based not on apparent seismic time highs but at a certain distance from deeper structural features that actually appeared lower on the seismic data. The first well was drilled and encountered gas, as did the subsequent three wells. They had bottom water as the trapping area was small, however they all were high in a regional setting so proved the method effective.

The Crossfield play presented a completely different challenge due to the high H2S content and no production within 30 miles of the farm-in lands. I could not identify anything compelling at the Crossfield level; however, I recognized an interesting feature in the Upper Wabamun interval, just above the Crossfield. Drilling confirmed a porous Upper Wabamun section. This zone had a significant gas show while drilling, although completion issues limited the result. Interestingly, the Upper Wabamun was sweet, while the zone 40 m below it was highly sour, which was a fascinating geological contrast. One of these farm-in wells ended up going through an interesting feature just above the Mississippian and encountered a gas charged previously known but not intensely mapped Basal Quartz zone. The Basal Quartz focus for Compton really began after that.

What innovative ideas or leading-edge technologies have you introduced or championed throughout your career that significantly impacted exploration, interpretation, or drilling success?

As you can appreciate, the evolution from pencil crayons and paper sections to today’s digital technologies has created many opportunities to champion innovation in geophysics. At Dekalb, I convinced the management to purchase a digi-rule to replace traditional timing rulers. This may not sound particularly significant today, but at the time the horizons were being picked manually and isochron values calculated by hand, so the associated man-hours accumulated very fast. I prepared a document outlining the expected time-to-payout for the investment, which was very well received.

Later, Apache introduced a Landmark workstation into the Calgary office. A technician was hired to load the tapes for interpretation. The system crashed continually and with technical support in Houston, the experience often became an exercise in frustration. The only fun part was to be able to call technical support and say, “Houston we have a problem”. It did however allow geoscientists a vision of what was to come.

I believe the most important idea I have championed owes some credit to Scott Jamieson. I remember a CSEG talk he gave where he discussed using offsets to evaluate sand reservoirs. From that point onwards, for at least the last 25 years, I have consistently requested near (0-15 degree), mid (15-30 degree), and far (30-45 degree) offset volumes for every seismic dataset I have processed. I have also encouraged the geophysicists I have worked with to adopt the same practice. Many geophysicists I have worked with, as well as many exploration VPs have been amazed at how different those offset volumes can appear and how much additional geological insight they can provide.

From a software perspective, I have always been a big proponent of using seismic attribute analysis feature identification. The ability to correlate waveforms, manipulate frequency content, color blend volumes, and crossplot many of the derivative products allows differentiation within one offset and among multiple offset volumes.

More recently, machine learning has become another valuable tool. The sheer amount of data that can be integrated to derive correlations is impressive. And once meaningful correlations are identified, predictive maps and related products can also be generated as follow-up deliverables.

Your expertise spans an impressive range of Western Canadian play types, including the Basal Quartz, Montney, Notikewin, Ellerslie, Rock Creek, Swan Hills, and Duvernay. Which of these did you find to be the most technically challenging, and why?

The Ellerslie interval in the deep basin, where I was working, could be quite challenging. This was the primary play that Velvet initially focused on, and one of the key difficulties was that four different sands could occur at the same stratigraphic level. One was Ostracod, two were Ellerslie, and the fourth was Jurassic. In addition, multiple unconformities could either prevent deposition of a prospective sequence from below or remove it from above through erosion. Coal could also be interspersed in the erosional lows. Complicating matters further, the overlying section contained coals within channels (geologically interesting) in the Wilrich, and coals and channels in the Falher. The reflection off the Rock Creek interval below could also vary with porosity and thickness changes within that zone.

In view of these complexities, the development of a good geologic model was critical. I was fortunate to work closely with Ian Collar, who was not only highly skilled with log analysis but also had a strong interest in core interpretation. The model took a few years to fully develop, and we would work closely when selecting drilling trajectories. I remember talking to a geophysicist at Conoco who told me that they viewed the zone as too risky due to the nature of the play. I simply viewed that as opportunity as Velvet had become comfortable with the play.

What made this play somewhat unique is that it was difficult to make a good large-area map as many of the zones around the Ellerslie could change the seismic character, making regional consistency difficult. In addition, establishing a dependable datum was a challenge as the closest reliable horizons were Viking or Wabamun.

As I have mentioned previously, I spent considerable time examining logs and since the Viking and Wabamun were good picks, I wanted to determine if they would be reliable enough to calculate a datum from. One of the first things I look for in an area is a good datum to work from. After compiling a spreadsheet of formation tops from numerous wells, it turned out that the Ellerslie was close to halfway between the Viking and Wabamun horizons. I therefore added the horizons together, divided by two, and called the resulting horizon, ‘Half’.

To test whether this horizon could serve as a valid stratigraphic datum, I generated several slices from different attribute volumes both above and below it. The resulting layers confirmed that it was indeed a reliable marker. Some of the most striking 3D seismic images I have generated came from the erosional system filled by the Ostracod interval. The ability to predict both the erosional geometry as well as the porosity within the Ellerslie became critical for location selection and drilling decisions.

At the time, Vermilion was our partner on many wells, and their geophysicist, Dennis, someone I had previously played hockey with, was closely involved in the area. I explained to him how I arrived at my marker, and years later when Westbrick was being sold to Vermilion I mentioned the Half horizon, again. The response was, “so that is where that horizon came from”. I also knew that Dennis had generated an inversion over the Ellerslie interval, and I became interested in performing an inversion study myself, partly because I recognized that this was an area where I had limited hands-on experience. I negotiated a short-term license and took the appropriate software training course. The inversion project covered about 50 sections, and it took me a month to edit the logs and generate my inversion result which was focused on a region around my Half horizon. I was pleased with the result as it gave a match that was 95% + for accuracy of wells. I showed the VP at the time who compared it to my interpretation based on offsets. Unfortunately for me, my offset-based interpretation that I had previously done was almost an overlay of the inversion result. So, while I wanted to improve my inversion skills, the conversation essentially concluded with, “If you can already generate this map from offsets, why would we purchase the software?”.

Given your extensive experience, could you estimate how many wells or drilling locations you have directly selected or high-graded over your career? Furthermore, what has been your estimated success rate, particularly on prospects where advanced seismic interpretation and AVO analysis were critical to the risk-mitigation process?

These are approximate numbers, but I would estimate that I have been involved in roughly 500-600 wells, with 95% of them drilled deeper than 2000 m TVD. Approximately, half of these wells were horizontal. In terms of success rate, the vertical wells were successful approximately 85% of the time, while the horizontal wells had a success rate closer to 95%. I can recall only two instances where a vertical well successfully intersected the target zone but was subsequently found to be depleted due to production from another well located as much as four miles away. Both of those wells were drilled on 2D seismic data, so recognizing that connection prior to drilling was not straightforward. Angle-stack volumes have been used in many ways for 400 of these wells and have played a significant role in both prospect evaluation and drilling decisions.

Your technical contributions at one of your previous companies significantly advanced the Basal Quartz play, ultimately transforming the organization’s market value. Could you walk our readers through the specific technical workflow you utilized to identify and successfully de-risk that play?

That play proved transformative not only for Compton but for my own personal development as well. As I recall the sequence of events, the first step involved recompleting an existing well in the Basal Quartz (BQ) zone. The next well was the one I mentioned previously, originally drilled for the Mississippian, which encountered a porous BQ sand accompanied with a big gas show on penetration. I was subsequently asked if I believed the BQ trend could be mapped seismically, and I let them know I thought it could.

Shortly thereafter, a 3D seismic survey was planned jointly with Exxon Mobil over much of Township T17-18, Range 29W4M, which represented the mapped geologic fairway. A few more wells were drilled for which I recommended getting dipole information on as many of them as possible as I had recently completed Fred Hilterman’s “Seismic Amplitude Interpretation” course and wanted to apply some of those concepts. When the AFE for the seismic program was structured with Exxon Mobil, I discussed the processing strategy with their geophysicist, and we purposefully excluded processing costs from the joint AFE. Our agreement was that we would independently process data at our own selected processor and swap volumes. I still believe that this can be a valuable practice because reviewing alternative processing approaches often provides useful insights at relatively little incremental cost.

Post processing, I began detailed interpretation. I noticed from well logs that the sands, particularly the thickest sands, removed a section of the shale below. As an aside, I spend a great deal of time examining logs and tried to keep the Gamma Ray character of most wells within a 3D survey in mind during interpretation. I looked at the different offset volumes and after picking the Mississippian peak on all of them, I noticed the near offset volumes had a somewhat diminished peak under the thicker BQ sand wells. I then modified the frequency of the volume to optimize that difference visually.

An amplitude extraction was generated over the target window throughout the 3D volume, followed by first, second, and third order residual calculations. I may have also applied a phase rotation to maximize the result. Once the residuals were calculated, most of the sand trend became clearly visible. The far angle volume was used to predict porosity within that trend. Together with the geophysicist at Exxon Mobil, we also decided to run an offset VSP on an upcoming well. Fortunately, the well ended up being one of the thickest we had drilled to that point, making it a good template for offset work as well as calibrating any possible multiple contamination.

An interesting result emerged from a well located within a structural low that, although subtle, was still mappable on seismic. That low preserved oil within the middle of the gas field. Although the oil accumulation was not commercially producible, the result demonstrated the trapping influence of these subtle lows, which we avoided in the future. I do not recall the total gas ultimately booked to the play, but I remember estimates into the hundreds of BCF.

You have successfully developed productivity maps by integrating production data with seismic attributes. Could you explain the mechanics of one of these workflows and discuss the ultimate reliability and predictive power of the resulting maps?

When working the Ellerslie play at Velvet Energy, a question arose regarding which fracture stimulation method was providing the best production results. The issue was a bit contentious, as low-productivity wells often trigger the typical debate between geology and engineering. In general, three scenarios can explain poor well performance:

i. A poor reservoir with an ineffective frac

ii. A good reservoir with an ineffective frac

iii. A poor reservoir with an effective frac

Geology provides a strip log, or a visual record of the subsurface geology penetrated by a well, while engineering provides frac data, or behaviour of the formation under immense hydraulic stress. My thinking at the time was that well locations were being selected based on seismic interpretation. Assuming that seismic data were effectively identifying porous Ellerslie reservoir volumes, and if each horizontal well was encountering a different amount of reservoir quality rock, then attributes extracted around the horizontal borehole should correlate with production and provide a reasonable prediction of expected performance.

To test this idea, I requested six-month gas production data from an engineering colleague. I specifically chose gas production because oil production data from competitor companies can sometimes be less reliable for comparison purposes. The production figures represented the first six months of actual production rather than a calendar-based six-month period. By using our own and competitor wells, I assembled a dataset of more than 40 wells for analysis. My goal was to apply machine learning, but I wanted to begin with regression analysis to make sure there was a meaningful correlation, or else machine learning can turn apples into oranges. Attributes were generated for three angle volumes as well as the full volume. For each well, an attribute interval was summed within 100 m, 150 m, and 200 m of the lateral borehole along its entire length. These attribute measurements were then compared to six-month gas production values.

The regression analysis showed a meaningful correlation, which justified proceeding with machine learning. Some areas of the 3D were noisy, so those wells were left out of the training. A subset of wells was used, and the overall correlation was quite high. After multiple runs with varying blind well validation sets, the results showed that the wells that had only a slickwater component underperformed the production expectation from seismic while those that had a crosslink gel component performed as expected. I gave a lunch hour presentation on this to the geoscience and engineering groups. So, the value of the workflow was not only that it could give a reasonable production estimate, but that it also could aid in the understanding of the effectiveness of a frac.

Over a career spanning nearly 37 years, how have you seen seismic interpretation technology evolve, moving from manual horizon timing and paper-based isochron calculations to modern interactive platforms and machine-assisted workflows?

This question makes me smile a little bit as memories flood in.

To provide a little perspective, when I started in interpretation, seismic sections were labelled either normal or reverse polarity. Synthetic seismograms were printed on clear film at 7.5”/second and hung from racks. These displays typically consisted of both normal and reverse polarities for five different sets of bandpass frequencies. To use them, you would take one of these from the rack, overlay your section, and try to match the phase and the frequency. This allowed us to determine if normal polarity on the section was truly normal, reverse, or in the case of vibroseis data, sometimes 90 degrees out of phase. Once you determined the correct frequency and polarity, you would photocopy the synthetic, color it, apply tape, cut it out on a light table or cutting pad on your desk, and tape it into place on your section at the top of the synthetic so you could lift it to see the traces underneath. You would annotate the distance to the well from the line and draw on the appropriate well symbol. The original film version of the synthetic was then returned to the rack.

For colouring, we used erasable colour pencils, which made it easier to fix interpretation blunders, or prisma colour pencils, which offered more vibrant colours to follow your horizons. Horizons had designated colours across the company; for example, the Halfway formation was a yellow trough with an underlying red peak, the Mississippian was blue, and the Devonian was purple. If you wanted a model made, that had to be sent to a specialized group, a request that was not made very often.

Maps came directly from the drafting department, and all interpretations were marked on them as well. Clear overlays were placed on these maps that could then be taken from a seismic anomaly map to a geology map. You would manually mark line intersections and well intersections on seismic lines to tie them together and continue your correlation. Well logs were also entirely paper-based and stored in a library. Consequently, requesting well logs for an area often meant filling the top of one of the desks with containers of logs which could be pulled out to view the zone of interest. Zone depths were calculated manually using the log curves and the Kelly Bushing (K.B.) from the header. If you wanted to build a cross section, you had to either photocopy the logs (if you were a geophysicist) or print them with a microfiche reader (if you were a geologist). Then you would splice them together on your chosen datum.

With the advent and regular use of workstations, basic interpretation of events and generation of maps became a straightforward exercise. Generating synthetics and tying multiple 2D lines to the same phase became a mathematical manipulation (a grid balancing act) that the machine could handle automatically. Models became easy to generate, providing reasonable estimates of seismic signature. Furthermore, 3D volume rendering and time slicing opened a completely new world to those of us who had previously used paper sections. These images literally revealed subsurface pictures that had never been seen before. Drilling success ratios increased dramatically with the advent of 3D data and workstations. The amount of work expected from a single person also rose dramatically.

Modern interactive tools provide the ability to analyze staggering amounts of data relatively quickly. Attributes, inversions, predictions, 4D differences, rock physics, machine learning, and AI offer multiple avenues to pursue. Today, it is often possible to approach a geoscientific problem from two different angles, using one to check the other. A recent article in The Leading Edge illustrated this beautifully, demonstrating that machine learning can yield essentially the same result as a deterministic inversion. When multiple independent methods converge on the same result, the likelihood of the interpretation being correct increases significantly.

An important step is to try any new method on a dataset where the answer is already known. If the output on a simple well-constrained model is incorrect, it is far easier to evaluate than if it was a complex example. This verification is important because with fast-paced digital solutions, interpreters spend far less time looking at the actual seismic data than they do looking at the resultant maps, which can lead to costly errors. I have personally witnessed million-dollar drilling decisions made on severely flawed maps.

Ultimately, independent of technology, the key is to understand the limitations of your data before generating derivative products. Furthermore, if the geology does not match the output seismic product, or the seismic product fails to accurately predict future well outcomes, then the model must be corrected and the error in the workflow determined. Products that only match historical data but lack predictive capability for future wells are rarely useful.

Successful asset development relies heavily on cross-functional collaboration. What key lessons have you learned from integrating geophysical data with geology, engineering, land, and executive management teams during development planning?

This question can take multiple paths depending on the asset stage, and it is also play dependent. For this context, I am assuming the ongoing development of a semi-conventional play.

In general, management teams need to set the strategic direction at the beginning of a project, review the outcomes at the end, and limit their intervention during the execution phase. The more autonomy a development team, consisting of geology, geophysics, engineering and land professionals (assuming a competent, experienced group), has during execution, the better and possibly more creative the results will be.

One of the key lessons in asset development is that your interpretation, whichever form it takes, needs to align with the geology first. If the geology and geophysics disagree, the well logs are not going to change as they are truly your control points. Until the geological and geophysical models are fully aligned, it is pointless to waste the team’s time on drilling locations that may not be valid. Once G&G are aligned, the focus should shift to integrating engineering and land data. If, from an engineering perspective, the economic and uneconomic wells look identical to you, you must learn how to differentiate them or adjust your risk profile accordingly. Operationally, it is wise to select twice the number of drilling locations than your budget allows, assuming that land deals will need to be finalized, and then have the Land department pursue the necessary pooling agreements. The deals that take the longest may never close, or they may extend beyond your allotted timeframe, which is why if you need to drill two wells, you should advance four.

Finally, develop good relationships with your team, that trust becomes invaluable. If you have joint-ventures, maintain good relationships with them as well. Going out for lunch as a group and collaborating openly can save a significant amount of time in trying to reach a consensus on a drilling location.

In your opinion, what distinguishes a purely technically interesting anomaly from a commercially viable drilling opportunity, and how can geophysicists train themselves to bridge that gap more effectively?

One of the best courses I took in university was PE 564 (Petroleum engineering well logging). This was a mandatory course for petroleum engineers as well as the geophysics students. The reason I mention this is that whenever I identify an anomaly on seismic data, my first step is to check if a well has penetrated it and thoroughly analyze the log before consulting the geologist. I have routinely recommended a course like this for summer students, as having a strong working knowledge of well logs has been invaluable throughout my career.

In terms of interpretation, I have also found that seismic anomalies that shift in time over varying offsets, and disappear or appear depending on the offset, are typically good targets to map out. Examples of this include porosity variations within the Ellerslie, Notikewin, and Bluesky formations, as well as Mississippian subcrop porosity. Conversely, large, beautiful structures can hold little value if their structural timing is wrong. It is essential to generate multiple time slices to map out the thicks and thins, and then rigorously investigate the underlying geological causes for those variations. Some features will be clearly obvious while others remain subtle, yet both can be viable targets.

I am also a strong believer in utilizing seismic templates. If you have seismic line over a producing well for a zone you are chasing, it removes all doubt as to what the seismic expression should look like. After that, modify the frequency and examine the angle stacks over the well to look for diagnostic changes. Often, isolating an ideal frequency band and offset range is what is needed to optimize the visibility of a reservoir zone.

Could you share a few of your most memorable professional success stories from the various companies you have served throughout your career?

Generating the Basal Quartz fairway map for Compton was a major highlight of my career, as it provided the company room to grow for the next few years. The geologists I collaborated with there (Marc Junghans and Norm Hopkins), were talented, and became close friends, which made for a highly enjoyable and productive work environment.

Figuring out the stratigraphic intricacies of the Ellerslie formation at Velvet, once again alongside a talented geologist, allowed the company to strategically acquire land, grow production, and construct a processing plant. Establishing this strong, reliable production base within the Edson area set the company up perfectly to later venture into Montney land acquisition and drilling.

While at Remington, I was asked to evaluate a farm-in opportunity targeting the Swan Hills formation at Karr. Having never interpreted that specific zone before, I was excited for the challenge. I spent about a week on the interpretation and presented my results to Doug Pruden who was the Chief Geophysicist at Remington. He reviewed my methodology, liked the approach, and Remington decided to drill the well. At the time the major operator whose land we were farming into showed very little reef build on their maps where my location was selected, which admittedly made me a bit nervous. However, the well ended up intersecting all seven stages of build up and the cored interval had some sizeable porosity filled with drilling mud. While I cannot remember the production results, the personal affirmation was that the reef model was validated.

When I started at Westbrick, I was told the team needed help identifying the Notikewin on seismic. I let them know that would not be a problem. Around that time, they were drilling a deep horizontal Wilrich well that intersected a Notikewin channel right where I had just purchased a 3D dataset and was getting it reprocessed. The active well was set to reach total depth (TD) on a Monday, after which the rig was set to immediately spud a second well from the same surface pad. I received the reprocessed 3D data, which covered a bit over a township in size, on Thursday morning. I interpreted the volume that afternoon, compiled a 40-page PowerPoint presentation on Friday morning, and presented it in an impromptu Friday afternoon technical meeting with popcorn and beverages for anyone who wanted to attend. During that meeting, the leadership team made the definitive decision to change the trajectory of the next well off the pad to target the Notikewin anomaly I had just mapped. The well was a success and became the first Notikewin well the company ever drilled, firmly solidifying the idea that 3D seismic could successfully image these channels. Westbrick’s ability to pivot that quickly was one of its greatest organizational strengths, and in hindsight, it was a vote of confidence in my work.

Another memorable moment from Westbrick involved a consulting geophysicist who had been with the company for quite a while, and whom I had previously worked with briefly at Compton. Following our initial Notikewin success, management approved a budget for him to reprocess a large merge of multiple 3D volumes, a dataset where he had been trying to resolve the Notikewin on for years. When the reprocessed data arrived, I offered him a few workflow suggestions, and he began his interpretation. A few days later, he came to my office door with a big smile on his face, as he was finally able to clearly image the Notikewin channel and confidently select a drilling trajectory. Seeing that smile was incredibly rewarding. He retired later that year, exactly as he had planned, leaving on a high note.

What stands out as the most complex or stubborn technical problem you have ever tackled, and how did you resolve it?

Multiples generated from coals, particularly close to or overlapping your zone of interest, can be particularly problematic. When the velocity of the multiple is too close to the primary reflection, separating the two becomes extremely difficult. I sometimes “cheat” by extrapolating the seismic character from one side of the affected area to the other, assuming the distance is small. This approach was particularly effective for the Wilrich coal multiple near the Ellerslie interval. I also applied similar techniques to features affecting the Rock Creek reflections. Another way to partially mitigate these issues is by examining different frequency ranges across various offset volumes. However, if the multiple amplitude is large, even frequency and offset discrimination may provide limited improvement.

Navigating a 37-year career in a cyclical industry is a major achievement. Beyond adapting to technological shifts, what is your “secret” or piece of advice for surviving and thriving over the long term in the seismic industry?

First and foremost, it is important to find challenge, purpose, and fulfillment in your work. Stay curious, have a desire to work as a team, learn from others, and educate yourself throughout your career. A willingness to take on new roles, a desire to mentor or help others, and admit when you are wrong are also invaluable. Maintaining integrity in anything you do is equally important. Your co-workers, partners, and contractors will recognize and respect honesty, professionalism, and consistency over time. Finally, it is important to enjoy the journey. Have fun, high five people at work and learn to laugh.

Let me pose a philosophical question: It is often said that “sometimes when you are in the midst of things, you don’t see them clearly; stepping back and assessing them rationally is the way to go.” How does this sentiment resonate with you, particularly when applied to your professional life and technical decision-making?

I have found that my natural inclination is to take a new 3D volume and analyze it as many ways as possible, as quickly as possible. Over time, I have learned that a methodical approach, one that focuses on building a coherent, geologically consistent interpretation, ultimately produces better results. It does not take that much longer; it simply requires me to slow down my initial impulse and proceed more deliberately.

Another practice that has proven helpful, particularly on challenging plays, is stepping away from a problem for a period and then revisiting it with fresh eyes. This can often provide a different perspective or an alternative approach. I may also spend time reading on similar plays or methods that could provide additional insight. For many years, I kept a quote attached to my monitor that read “Never give up, Never, Never, give up, Never, Never, Never, give up”. I really don’t like it when a play “hides” from me. At times there are also plays which do not resolve over time or don’t exist where you are looking, and at a certain point you must be willing to accept it.

From a broader career perspective, I still rethink decisions I have made in the past. Sometimes we are faced with multiple good choices neither of which is wrong. If you examine your professional life and see it is impacting your personal life, then understanding that one is a career and the other is life becomes important. I have talked to multiple people who have asked the question “Who am I when I don’t do what I do anymore?” They are stepping back, assessing, and are concerned. Also, if you step back and find you are no longer enjoying what you are doing, it may be time to seek a change. Life is too short to spend every day going somewhere you no longer want to be.

How do you like to unwind outside of work? Do you find any interesting parallels between your personal hobbies and your professional approach to scientific problem-solving or teamwork?

As a leisure activity, I enjoy reading. My interests range from science fiction, which is welcome escapism, to books that focus on exploring how the human mind works, a subject which I find fascinating. I also enjoy reading philosophy and apologetics, both of which challenge my thinking while helping me better understand and solidify my beliefs.

For sports, I enjoy hockey, slo-pitch, and golf, though you will rarely see me golfing alone, as I am more team-oriented.

During the COVID period, I developed new hobbies, including woodworking, welding, and 3D printing. These pursuits bring out my creative side, as I will draw designs to be built with pencil and paper or for the 3D printer using a CAD program.

As a group activity, I also sing in a choir. Again, this is a team activity as every voice and part needs to come together for the desired result.

If I am to summarize the above, I like to think deeply on a topic, enjoy challenging myself, want to be part of a team, compete, and love it when everything works together in harmony.

Finally, what words of advice or encouragement would you offer to the new generation of geoscientists who are just beginning their careers in our profession?

Be curious and inquisitive. Do not be afraid to ask questions or ask for help when needed. Take the time to learn some fundamentals from other disciplines, specifically geology and engineering. Talk to your geologist often and learn from each other. Your partnership will drive the play.

Whenever possible, network with people, and build relationships within your organization. Ask your colleagues about their current roles or experiences and career paths. Most people are quite willing to spend time talking to someone who genuinely wants to learn about them or from them. Something as simple as smiling and greeting people in the hallway can have a positive impact on workplace culture and help create a more welcoming environment.

Spend time understanding how the seismic signature varies from well to well and, more importantly, why those variations occur. Any interpretation products you generate will then be built upon a solid foundation of geological understanding. You will also have confidence in knowing that what you generate matches the geology and those who view your work will gain confidence in your abilities as well.

Finally, a practical suggestion. Avoid looking at your cell phone during meetings. I know a few companies where this is formal policy. Likewise, when working in your office, consider keeping your phone out of reach. Doing so can improve concentration, reduce distractions, and help you remain focused on the task at hand.