An interview with Jason Schweigert

INTERVIEW COORDINATED BY SATINDER CHOPRA

‘Do good work, work hard, be reliable, and build a reputation as ……’

An executive geophysicist with more than two decades of experience, Jason Schweigert has led the design and modeling of complex seismic acquisition programs around the world. As President of BJV Design Inc., he provides strategic leadership, oversees operations, and manages client relationships for a specialized geophysical consultancy. He is widely recognized for technical expertise in 2D, 3D, 4D, VSP, and microseismic survey design, having contributed to more than 5,500 seismic programs across a wide range of operating environments. Clients value him as a trusted advisor on advanced acquisition methodologies that enhance data quality, operational efficiency, and return on investment.

He has also served the Canadian Society of Exploration Geophysicists as Director of Communications (2013–2014) and as Chair of the Digital Media Committee (2015–2021).

He graciously accepted our request for an interview, and selected excerpts are presented below.

Jason, could you begin by telling us about your educational background and professional journey to date?

I graduated from the University of Calgary in 1999 with a B.Sc. in geophysics. After working as a consulting geophysicist at Petro Canada and Canadian Hunter, I began my career in 2000 as an acquisition geophysicist with Veritas DGC’s 3D field design group. In 2005, Veritas DGC’s seismic survey design department was divested and became part of BJV, and I became a partner. In 2006, I became President and Chief Executive Officer of BJV. I completed an M.Sc. in geophysics at the University of Calgary in 2009 while continuing to work full-time at BJV.

You began your career with Veritas in Calgary in 2000 and joined BJV just two years later, where you have remained ever since. What motivated that transition, and how did it shape your career path?

My move from Veritas to BJV came out of a business change at Veritas. When I started my career with Veritas in Calgary in 2000, John Voskuyl was effectively my boss, even though he was not a Veritas employee. At that time, John had been consulting to Veritas and providing survey design services through BJV since 1987. So, although I was employed by Veritas, I was able to work closely with John and learn survey design from one of the recognized experts in the field at that time.

In 2002, Veritas made a business decision to reduce overhead. At that time, survey design was provided free to Veritas clients acquiring surveys through Veritas DGC Land, so our group was viewed as an overhead cost. As part of that change, I moved directly from Veritas to BJV. We continued doing much of the same work, but under a different model where the work was paid for on a project basis rather than carried as overhead.

Over time, I realized I genuinely loved survey design, both the technical work itself and the chance to work with a wide range of clients and great people across the industry. When John retired in 2006 and the opportunity came for Kari and me to purchase BJV, we took it.

For readers who may not be familiar with BJV Design Inc., could you describe the company’s focus on seismic survey design, the services you provide to the local market, and the areas in Alberta and British Columbia where you have conducted seismic acquisition?

BJV Design Inc. is a geophysical consulting company focused on seismic survey design and modeling, and that specialized expertise has been at the core of our work for decades. Our work includes helping clients define seismic survey design parameters for their seismic program. Important parameters include source line interval, receiver line interval, source interval, receiver interval (SLI/RLI, SI/RI), far offset requirements, parameter optimization, and source and receiver types to meet the technical and business objectives of the survey.

Our seismic modeling services include surface exclusion modeling, 3D illumination studies, 4D seismic response modeling, synthetic seismic modeling, compressive sensing modeling, and seismic feasibility studies. We also develop custom training courses.

Although many of our projects are in Western Canada, BJV has long supported clients well beyond our local market. We continue to work across Canada, the United States, and international markets. Over the decades, we have contributed to more than 5,800 seismic surveys spanning a wide range of geological settings and acquisition environments.

You mentioned that BJV has contributed to more than 5,800 seismic programs across diverse operational environments. What differentiates your company from competitors, and what do clients find particularly appealing about working with BJV?

One thing that differentiates BJV is the depth of experience we bring to seismic survey design and modeling. Since 1987, we have worked on more than 5,800 projects worldwide across 2D, 3D, 4D, and VSP surveys.

Our main focus is helping clients determine the acquisition parameters and survey geometry required to meet their technical and business objectives. That includes parameters such as SLI/RLI, SI/RI, source arrays, receiver arrays, source type, and overall survey outline, along with the analysis required to define those properly.

Beyond survey design itself, BJV provides services such as illumination studies, synthetic and finite-difference modeling, feasibility studies, surface exclusion modeling, 4D response modeling, custom training courses, as well as Vibroseis test program design, script generation, survey QC, and real-time surface exclusion modeling during active field operations.

What has differentiated BJV over the years is not only the technical expertise, but also the way we work with clients. We place a lot of importance on understanding their objectives, being responsive, and delivering practical solutions that are aligned with what they are actually trying to achieve. That client first approach has been foundational to BJV for a long time, and over time it has helped us build strong long-term relationships with clients. It has also meant less back and forth, resulting in less rework. Our clients know we understand what they are looking for and can deliver what they need when they need it.

High-density seismic surveys have been widely discussed in recent years. What advantages do they offer your clients, and how do the costs compare with conventional survey designs?

High-density seismic can offer real advantages when our clients’ objectives justify it. At BJV, we usually see that value when the objective goes beyond a stratigraphic or structural image. Better wavefield sampling can improve imaging, enhance small fault detectability, strengthen near-offset coverage, and support more demanding analysis such as AVO, inversion, thinner target resolution, and rock property characterization. That said, the goal is not simply to make a survey high density. We are always limited by the frequency content the earth gives back to us, so there is a point where added trace density goes beyond what is useful. A technically rigorous survey design is needed up front to determine the acquisition parameters required to meet the client’s economic objective, rather than assuming a denser survey will automatically deliver proportionally better data. We must always consider the law of diminishing returns. From a cost standpoint, high-density surveys typically have a lower cost per trace than conventional surveys, but the total survey cost is usually higher, so the economics must be justified. In the right application, though, that added cost can create significant economic value by enabling inversion and improved rock property characterization that may not be achievable with a more conventional survey. For me, it comes back to creating a fit-for-purpose design that optimizes the survey around the objectives.

From your perspective, what defines the current state of the art in seismic survey design? In particular, could you elaborate on your role in developing the Theseus 24D strategy for optimizing seismic monitoring and verification?

From BJV’s perspective, the current state of the art in seismic survey design is the ability to integrate modern acquisition technology with advanced imaging and inversion requirements in a way that is properly matched to the subsurface objective. That includes single-sensor nodal systems on land, ocean-bottom nodes offshore, and source types such as vibroseis, dynamite, and other emerging methods. Those acquisition choices now play a major role in how a survey is designed, especially when the objective is to support depth imaging, FWI, AVO, inversion, and time-lapse monitoring.

What defines state of the art is not a single survey style, but how effectively current technology, wavefield sampling, illumination, statistical diversity, and repeatability are combined into a practical design that supports the geological and business objective. From our perspective, it still comes back to a strong survey design up front. The technology continues to evolve, but its value depends on how well it is applied to the problem being solved.

That thinking is very much reflected in BJV’s role in the Theseus 24D strategy. Our contribution was to help Lee Hunt and his team from Carbon Alpha take the Theseus concept and turn it into a practical seismic monitoring strategy from an acquisition perspective. BJV provided survey design and modeling expertise to evaluate how the concept could be implemented in a technically sound and cost-effective way.

In simple terms, we helped move the idea from concept toward application by applying our survey design and modeling expertise to the acquisition side of the problem. That included providing input on the geometry, baseline survey design, and acquisition considerations needed to make the strategy practical for long-term monitoring. For me, that is what state-of-the-art survey design really looks like today: not just better technology, but the ability to apply it in a practical way that meets the monitoring objective and the economics of the project.

Some companies are promoting affordable ultra-high-density seismic surveys for CCUS applications. How do you assess the value these surveys provide to oil and gas operators?

To answer that honestly, I am not sure the terms “affordable” and “ultra-high-density” always go together in the way they are sometimes presented. That said, I do understand why some companies are using that language. Modern nodal systems can be deployed very efficiently at high channel counts, and high-productivity vibroseis methods can drive production rates up significantly. That can lower the cost per trace quite a bit, which is one of the reasons ultra-high-density surveys are viewed as more affordable today than they would have been in the past. But even with those efficiencies, the overall program can still be very expensive.

In terms of value to oil and gas operators, I think it is often easier to justify than in CCUS, simply because the economic upside can be higher. If the added sampling and resolution improve imaging, inversion, rock property characterization, or drilling confidence enough to reduce risk and support a better economic decision, then the value can be significant.

That said, I would still assess it through the same lens in both oil and gas and CCUS: geology, objectives, and economics. In both cases, the seismic program has to reduce subsurface uncertainty in a way that supports an economic decision. The difference is that the business case can look very different. In many CCUS projects, it can be difficult to justify seismic in general, never mind ultra-high-density seismic. In traditional oil and gas, there is often more upside potential, which in some cases makes it easier to justify a higher-cost, higher-density program.

The value is not really defined by whether the project is oil and gas or CCUS. It is defined by whether the additional sampling and resolution create enough economic value for that specific project to justify the cost. Ultra-high-density seismic can be the right answer, but only when the technical benefit is large enough to materially improve the business decision.

You previously published an article in the RECORDER titled ‘What Is the value of a VSP and why should it be modeled?’ What key message were you aiming to convey through that piece?

The core message of that article was that a VSP can provide significant technical value, but if you do not model it first, it is very easy to spend too much money on a program that is not properly optimized for the objective.

A VSP can deliver very high-resolution data around the wellbore and answer important questions that surface seismic may not resolve as well on its own, whether that involves imaging, multiples, AVO behaviour, or anisotropy. It is also an acquisition method where costs can escalate quickly because of downhole tool moves, repeated source effort, and field logistics.

That is why I believe the modeling must come first. It helps define what the VSP can realistically illuminate, what source geometry is actually needed, and what receiver depth range is required to meet the objective. Once that is understood, you are in a much better position to optimize the geometry, control costs, and avoid spending money on acquisition effort that does not add value.

The bottom line: define the technical and economic objective first, model the VSP to determine the acquisition geometry required, and then price and execute the program. That is how you maximize the technical value of the VSP while keeping the program as cost-effective as possible.

Although VSPs are recognized as valuable tools for enhancing project economics, how much VSP acquisition activity is currently taking place among oil and gas companies in Canada? In your view, what are the primary reasons behind the limited adoption of VSPs in seismic interpretation workflows?

I am probably not the best person to comment on the overall level of VSP acquisition activity in Canada, because BJV has been more involved on the modeling side than on acquisition itself. What I can comment on is that over the last three to four years there has been a growing interest in VSP related work. In our experience, though, most of that recent activity has been tied more to CCS than to conventional oil and gas. VSP adoption in Canadian oil and gas has been fairly limited compared with some international markets. A major reason is likely basin maturity. In the Western Canadian Sedimentary Basin, companies often already have a large amount of well control and surface seismic. In that context, the incremental value of a VSP is not always enough to justify the added cost. In many Canadian oil and gas settings, VSPs have been viewed as useful, but not essential. CCS is different, because the value can be tied more directly to monitoring plume growth over time in a cost-effective way.

You also specialize in microseismic survey design. Since microseismic monitoring was introduced around the turn of the century, how has it evolved, and what level of value does it deliver to operators today?

BJV does offer microseismic and induced seismicity survey design services, but it is not an area where we have been highly active in recent years. Because of that, I do not think I would be the best person to comment in detail on how the field has evolved overall or to give a strong view on the value it delivers to operators today.

One significant innovation in microseismic monitoring has been the use of distributed acoustic sensing (DAS). Could you explain how this technology works and what advantages it offers?

Distributed acoustic sensing, or DAS, uses fiber-optic cable as a continuous sensing system to record acoustic energy along the length of the cable. It is an interesting tool and can offer real advantages in some applications. One of the biggest advantages is the very fine spatial sampling, often around 1 m, which is much denser than a conventional VSP. In some cases, it can also be attractive because the fiber is already installed in the well, which can make VSP-style acquisition easier.

That said, DAS also brings processing challenges, and the data is not always easy to work with when compared with conventional geophone-based VSPs.

Seismic methods are increasingly applied beyond conventional oil and gas, including geothermal, hydrogen storage, wind farm planning, gas storage, CCUS, and mineral exploration. Could you comment on the scope and effectiveness of seismic applications in these emerging areas, particularly hydrogen and mineral resources?

Seismic is a valuable tool for any application that requires an understanding of the earth’s subsurface. Therefore, it is not surprising that industries requiring a detailed understanding of the subsurface are using seismic more frequently. In recent years, we have seen a significant increase in the number of seismic surveys being applied beyond the scope of conventional oil and gas.

Whether a company requires a subsurface hazard assessment to better understand structural geology, faults, and fractures, or to optimize drilling locations related to structural traps, mineralization, or other subsurface features, seismic surveys are providing economic value across many industries.

It is encouraging to see the seismic method, which has been used in the oil and gas industry for decades, being deployed more frequently in emerging industries such as hydrogen, mineral exploration, geothermal, gas storage, and CCUS.

In the end, it really does not matter what industry we are talking about. If the changes in the subsurface geology that are important to a particular industry can be detected by the seismic method, and if it is economically viable, seismic can be a very effective tool.

Multicomponent seismic data has been available for more than three decades, yet its adoption has progressed slowly. Why do you think the industry has been hesitant to fully embrace it?

Multicomponent seismic has been around for a long time. I remember back in my Veritas days when VectorSeis 3C sensors were being introduced, and we were looking at different 3D geometries to try to improve the acquisition of multicomponent data. In some cases, clients acquired modified slants based on BJV’s recommendations instead of acquiring traditional orthogonal designs to improve the quality of the 3C data. I also remember that in the early days of multicomponent acquisition, many companies acquired the data but never fully used it. They continued using the P-wave data, but the economic value of the converted-wave component data was rarely realized, and that likely reduced the incentive to keep acquiring it.

As for why adoption has been slow, it comes down mainly to economics, workflow complexity, and turnaround time. There is certainly literature showing cases where multicomponent data can add real economic value, but it has not been universally demonstrated in a way that made the added effort easy to justify for most projects.

The acquisition cost itself is not necessarily the main issue, because in many cases it is only incrementally higher than conventional seismic. The bigger challenge is after acquisition. Multicomponent data generally takes longer to process, longer to interpret, and requires more specialized expertise throughout the workflow. In a lot of companies, especially where exploration and development decisions move quickly, that added time and effort can become a real barrier.

Could you share some of the most challenging and technically interesting projects you have worked on, and how you addressed those challenges?

One of the most interesting projects I have ever been involved with was the seismic work done for The Curse of Oak Island TV show in Nova Scotia. Eagle Canada acquired multiple seismic programs over a couple of seasons for the show, and from my perspective it was interesting on every level: technically, economically, and from an entertainment standpoint.

From the technical side, it was one of the shallowest projects BJV had worked on, with the deepest target at only about 50 m, and the goal was to image as close to surface as possible. The geology also made it challenging. Around that depth, the target was anhydrite(with voids likely related to karst features), and above it was mostly glacial till. From the client’s perspective, the real question was whether some of those voids could be man-made tunnels related to the long-standing treasure hunting story on Oak Island.

Another major challenge was the lack of data. There was no existing seismic in the area, no velocity logs, and very little subsurface information to help constrain the design. In that kind of situation, you must rely much more heavily on academic work, first principles thinking, and experience-based assumptions to build the best design you can.

What also made the project very unusual was the economic driver. In most seismic projects, regardless of industry, the economics are tied to defining something in the subsurface that can be produced, developed, or used for storage. In this case, the economics were different. The value of the seismic program was tied much more directly to how much airtime it could generate for the show. That is not something you see in normal seismic survey design, and it made the whole project unique.

Over a couple of years, five 3D surveys and one 2D survey were acquired over a significant part of the east side of Oak Island. In one of the 3D surveys, a swamp was drained just so the seismic survey could be shot. The final 3D on the project was also what I like to call the perfect 3D, where the line spacings and station spacings were all equal at 2 m. In that case, SLI = 2 m, RLI = 2 m, SI = 2 m, and RI = 2 m. All in all, it was a very unusual project, but also one of the most technically interesting and memorable ones I have been part of in my career.

Artificial intelligence and machine learning are frequently discussed in geophysics today. What is your perspective on their application in seismic data acquisition?

AI and machine learning are useful in seismic acquisition and survey design, but mainly as support tools that help geophysical experts, field crews, operational teams, and technical teams work more efficiently. Their real value is in improving productivity, helping teams make faster decisions, improving safety, and making acquisition workflows more efficient overall. I do not see AI as replacing geophysical expertise or field operations expertise, but rather as support for the experts that make seismic a reality from the initial survey design to final delivery to the processor.

Looking ahead, where do you see seismic data acquisition heading, and what developments can we expect in the near future?

Looking ahead, I think seismic data acquisition will continue moving in two directions at the same time. One is toward reduced environmental impact through continued improvements in sources, receivers, field efficiency, and miniaturization. The other is toward higher-density acquisition to improve data quality and support more advanced imaging and inversion objectives.

Those two directions are somewhat contradictory, which is why balancing them will continue to be a major challenge. To improve data quality, we often need higher-density surveys but unfortunately the environmental footprint is increased with higher-density surveys. That is where ongoing improvements in source technology, receiver technology, and miniaturization become very important, because they help reduce environmental impact while still supporting the data quality the objective requires.

In Canada specifically, one of the big changes has been the move to next-generation all-in-one nodes, which have largely replaced the earlier first-generation nodes. We are also seeing more nodes with 5 Hz geophones, whereas 10 Hz geophones were more typical in the past. That will be helpful moving forward, especially for work such as FWI where lower-frequency data is important for building the low-frequency model.

Overall, I think the near future will be about continuing to balance reducing environmental impact and cost with the need to acquire data that can support more demanding imaging, inversion, and interpretation objectives.

From seaside moments to alpine adventures in the Rocky Mountains, Jason enjoys every opportunity to be with his family

Considering the breadth of your work, do you feel you have adequately documented and shared your contributions through presentations and publications for the benefit of the broader community?

To be honest, this question made me stop and think, because I do not think there is a simple yes or no answer without putting it into the broader context of my life.

When my wife and I got married, we decided early on that family would come first. When our daughters came along, they became the top priority. After that came our business and supporting our family, and then everything else after that. That decision shapes how I spend my time to this day.

For example, when my daughters were in elementary school, I made a point of never missing a field trip. With three daughters, at times that meant a lot of days out of the office, and working in the evening to make up for it! Those were special years, with so many memories that I would not trade for anything, but it also meant there was very little time left for things like ‘broader industry presentations and publications.

In that sense, I probably have not documented and shared as much of my work as I could have over the course of my career, but I am very comfortable with why that was the case.

Now that my daughters are older, things have started to shift. Over the last three or four years, we have had opportunities to develop and deliver custom courses on seismic survey design, and I have really enjoyed doing that. It has been rewarding to share some of that experience more directly with industry, and I look forward to doing more of it. On the publication and presentation side, we were recently involved in Theseus 24D (as previously discussed), which led to multiple publications, as well as presenting at the 2024 CSEG Symposium. I also look forward to presenting a seismic acquisition talk at the upcoming 2026 GIFT.

Beyond your professional work, what other interests or pursuits are important to you?

My family is my number one priority. My wife and I have been married for 26 years, and together we’ve raised three incredible daughters, now 16, 20, and 22. Our home is always full, not just with family, but with 3 cats and 2 dogs as well.

I began coaching junior high girls’ basketball when our oldest daughter entered Grade 7, and I had the privilege of coaching all three of our daughters throughout their junior high years. Each of them continued to play in high school, which has been a lot of fun. The funny thing is that I was never really into basketball until my girls started playing. When my oldest daughter was in Grade 7, I was asked to help coach her team for one game because their regular coach could not make it. Since I was going to be there anyway, I decided to help as best I could. Even though I was not very familiar with the rules at the time, I learned the game on the fly and quickly came to love it. Coaching basketball became a real passion for me because it was so rewarding to watch the girls grow and develop, and being part of that, even in a small way, was very special.

My two oldest daughters are now attending university and no longer playing competitive basketball, and I continue to cheer on our youngest while she plays high school and club basketball. I’m proud to say I have been there for every game and tournament along the way.

Finally, what advice would you offer to young professionals entering the geoscience and energy industry today?

I think the biggest piece of advice I would give to young professionals entering geoscience and the energy industry is to focus on networking and relationships first. This is still a relatively small and connected industry, and people genuinely do want to help each other. Getting out, meeting people, and building real connections matters.

The key is to do that in a genuine way. Build relationships because you actually want to know people and be part of the industry, not because you immediately want something from them. I think that is where some people go wrong. They meet someone and right away ask for a job or a favour before any real relationship has been built.

Beyond that, the next thing is simple: do good work. work hard, be reliable, and build a reputation as someone who delivers quality work and gets things done properly. If you make a mistake, own it and fix it quickly. In the long run, that is how you build trust, and trust is what really builds your reputation in industry.