Simon O’Brien is a well-known and rare geophysicist, who joined Shell Canada in 1997 and is still going strong as the Quest Subsurface Manager, managing a multi-disciplinary team that is responsible for monitoring activities at the stellar Quest CCS (Carbon Capture and Storage) Project.
Beginning his career at Shell as a seismic processor, Simon quickly diversified into several other areas, including anisotropic depth migration, finding and evaluating AVO targets, seismic-based pre-drill lithology prediction for deep-water wells in Atlantic Canada, developing QI approaches for the Canadian Beaufort Sea, and managing the lithology prediction and Bayesian inversion-based evaluation of reservoir quality, for Foothills and offshore plays.
Over the last decade or so, Simon has delved into data processing and analysis for such applications as the first deployment of distributed acoustic sensing (DAS) technology in a well, using it to evaluate the potential for production flow monitoring and seismic acquisition; fracture detection using azimuthal data analysis, seismic attributes, microseismic, and borehole geophysics; and also navigated a major shift away from the traditional focus on Foothills plays to the more subtle structural and stratigraphic plays in unconventional gas.
Since 2015, Simon has led monitoring activities at the Quest CCS Project, ensuring the safe storage of more than one million tonnes of CO2 per year in a deep saline aquifer. Quest has been a success story which has shown that Alberta has world-class storage potential.
Simon is a Professional Geophysicist (P.Geoph.) registered with APEGA.
My request for an interview was sportingly accepted by Simon, and the following are excerpts therefrom.
Tell us about your educational background, work experience, and what you are engaged in these days.
I grew up in Newfoundland and always enjoyed scrambling around on rocks, so I started my university studies with an undergrad degree in Earth Sciences at Memorial. I also really liked programming, so geophysics was a good fit, and my honours work focused on hydrothermal heat flow modelling. I then went out to Vancouver to do my M.Sc. at UBC, interpreting crustal scale refraction data from the Yukon and Beaufort Sea. Finally, I returned to Memorial for a Ph.D., where I developed a multiple suppression technique for processing offshore seismic reflection data.
I joined Shell Canada in Calgary after finishing my Ph.D. and have been here for more than 24 years now. Early on, I had a pretty wide range of technical roles, including processing, depth imaging and quantitative interpretation of onshore and offshore data from across Canada, the US and around the world. After about 10 years, I started taking leadership roles for technical teams. It was a great opportunity to coach and mentor new geophysicists, to help steer our seismic strategy, and to have an impact on the development of new technologies. For the last six years, I have been the Subsurface Manager for the Quest CCS facility. I never thought I would work at a downstream asset, but it has been a great experience to be able to work on something as important as CCS.
In your B.Sc. (Hons.) Geophysics degree, you focused on the modeling of hydrothermal heat flow; then went on to do interpretation of seismic refraction data for your M.Sc.; and for your Ph.D. studied the suppression of water-bottom multiples in marine seismic data. How did you decide to work on these diverse geophysical problems?
There is a bit of a common theme of crustal geophysics through my degrees, but my choices were pretty random. The hydrothermal modelling project was an adaptation of some work I had done for Gary Quinlan, one of my professors at Memorial. I developed some code for heat flow modelling, to look at how lithospheric thinning would impact sedimentary basin development, and the inclusion of hydrothermal effects seemed like a cool idea. My M.Sc. thesis was really an attempt to make me more marketable to industry, so I thought pretty much anything to do with seismic would work. My supervisor, Bob Ellis, had some refraction data from the Yukon that looked interesting, but to be completely honest, UBC was mostly an excuse to go to Vancouver to bike and ski. It was great to learn from a whole new group of professors, and my understanding of northern geology and tectonics was really useful later, when I worked in the Beaufort at Shell. My Ph.D. started as an interpretation project with Jeremy Hall, looking at a variety of reflection data shot off the northeast coast of Newfoundland. However, the data quality was terrible, and the multiples were so impressive (in some shot gathers, we could still see multiples from the previous two shots!) that multiple suppression seemed like a much better problem to work on. At the time, we weren’t really set up to develop processing techniques at Memorial, so I ended up writing a lot of basic processing code. It was an amazing experience that had a huge impact on a lot of the work I did at Shell.
Apparently, your training/experience in the processing of seismic data helped you secure your first job at Shell Canada in 1997, and since then you have stayed put. What this suggests to me is that you found that craving for career fulfilment that any individual has. Your reaction please!
When I started with Shell, we had quite a large geophysics group, and were looking at data from all over Canada. There were many different problems to work on, and I always enjoyed finding creative solutions and better ways to get things done. Over time, we have been through quite a few changes at Shell, but each time, I have been lucky enough to find a role that has kept me interested.
Your first role at Shell Canada in processing and reservoir characterization seemed to focus on the East Coast of Canada and the Beaufort Sea. Tell us about the challenges you faced in both of these regions as you experimented with QI approaches for detecting potential AVO targets, assessing reservoir quality, and pre-drill lithology prediction.
My work in the Sable Basin was relatively early in the pre-stack interpretation days. The industry in Calgary hadn’t completely bought in yet, so the biggest challenge was in convincing our management and JV partners that what we were seeing in the AVO characterization was real and that we could trust the data. It was quite good 3D data, and the calibration to the wells was excellent. We were able to predict reservoir quality really well, and the gas pretty much glowed, so we had a number of successful wells. The deep-water wells were pure exploration wells, so they were more challenging. There were few drilled wells in the area, often separated from our prospects by faults or rises, that made it difficult to predict the age of potential reservoirs. We were pretty good at predicting lithology, but reservoir quality was a challenge, and we didn’t have a good hydrocarbon signature.
The Beaufort was very different. We had only old 2D data, and the quality was not great. Reservoir quality was generally good, and pretty much every well that had ever been drilled up there seemed to have gas. Unfortunately, only oil plays had any economic potential, so the gas was useless – it generally just made it harder to see the oil. I came up with a processing/AVO screening approach that was able to pick up the subtle oil signature, and it calibrated across numerous wells. We were able to identify several good prospects, but low oil prices at the time couldn’t justify drilling a well.
In the next phase of your career as a technical team lead, you performed data processing and analysis for the first deployment of DAS technology in a well, using it to evaluate the potential for production flow monitoring and seismic acquisition. Could you share your experiences in doing that?
A few Shell folks saw a presentation on a DAS pipeline security implementation and had the idea that maybe we could use fibre optics to monitor a well. They contracted the company to deploy a fibre in a well. During a fracturing job, the company thought they heard something (they were monitoring the DAS with headphones – common practice at the time) and wanted someone to analyze the data. The data was originally displayed as a waterfall display coloured by frequency because the security application relied on a frequency signature to determine what might be making noise. I was brought in to translate the data into something resembling seismic and to work with the contractor to help them understand what we were looking for (phase stability and more accurate timing, for example). I wrote some code to scan the data for possible events and found the noise that they heard – it was clearly a microseismic event very close to the well bore. I also wrote some code to use the data to assess which perforations were receiving the fracturing fluids - this also looked quite promising. Despite the poor quality of the data from the original lightbox, we were really excited by those early results, and the subsequent development work on DAS by many other folks has realized a lot of the potential we saw.
This was also the time that you shifted from the traditional focus on Foothills plays to the new, more subtle structural and stratigraphic plays in unconventional gas. Tell us where these efforts were focused, and how they panned out.
We had gotten pretty good at imaging complicated structures in the Foothills but had not put a lot of effort into doing ‘true amplitude’ processing. A lot of the things we wanted to do for unconventional plays required better amplitudes and more reliable offset and azimuthal datasets. This required a significant overhaul of our processing workflows, but the final product showed considerable improvement. We were able to see much more subtle stratigraphic features that proved to be important for some of the unconventional plays. The refraction data also showed promise in identifying shallow hazards, and the migrated data was generally much more suitable for pre-stack inversion. This allowed us to do some decent work on predicting reservoir properties, but, in the end, most of the unconventional plays turned out to be hydrocarbon factories, so I don’t think we had as much impact as I would have liked.
Over the last six years or so, you have been working as the Quest Subsurface Manager. Please elaborate on what this Quest CCS project is, and its importance to Alberta and Canada as a country.
Quest is a carbon capture and storage (CCS) facility that captures CO2 emissions from the hydrogen manufacturing units at the Scotford Upgrader in Fort Saskatchewan. We capture roughly a million tonnes of CO2 each year, equivalent to the emission of 250,000 cars, and inject it into the Basal Cambrian Sands at a depth of about 2000 m. Shell operates it on behalf of our JV partners: Canadian Natural Resources and Chevron Canada. We have been in operation for almost 6 years, and through July 2021, have injected almost 6.5 million tonnes of CO2.
Quest has been an amazing success story. The capture facility has been extremely reliable, and our operating costs are well below our original estimates. The reservoir quality and the overlying seals are excellent, and the wells have demonstrated that we have more than sufficient capacity to continue injecting CO2 for at least the 25-year projected life of the facility. Quest has shown that Alberta has world-class storage potential, and that it should be possible to do significantly more, at a very competitive cost.
Models of climate change mitigation by the IEA, among others, have consistently shown that CCS needs to be part of the solution if we are to have any chance of limiting the global temperature increase to 2° C. However, there aren’t very many commercial scale facilities like Quest currently in operation, so the learnings from operating Quest are really important. The funding agreement we have with the Provincial Government ensures learnings are shared broadly and can be used by everyone to help build the CCS industry, both here in Alberta and abroad.
As you ventured into this Shell Canada initiative (Quest), what were some of the challenges you faced, and the steps you took to overcome them?
It was a significant change for me. I went from a role where I was part of a broad community at Shell, all working on similar things, and understood most of the technical details of the problems we were trying to solve, to a new role where I knew almost no one, and where many of the technical details were outside my discipline. I had to rebuild my networks, establish new relationships with people across a completely different organization and get up to speed technically so that I could talk to my team about the things that they were dealing with. It was a huge learning curve and constant challenge, but also proved to be very rewarding. In general, my approach was to find the experts, both internal and external, listen to what they had to say, ask lots of questions, and challenge assumptions. Over time, this helped me get a good understanding of a very wide range of CCS topics, and to build a broad network of colleagues around the world, both in Shell and outside.
As CO2 is captured and stored in a subsurface formation, it is important to monitor the behaviour of the injected CO2 plume. How do you do this? By adopting time-lapse seismic, or anything else? Have the techniques been effective?
As with all monitoring, the first thing we ask is, why we are doing it in the first place? What risk are we addressing? For monitoring the CO2 plume, we really want to know whether it might go somewhere problematic (outside our lease space, for example) and whether the plume size and shape is consistent with our models, so that we know how well we are using our available storage space. We are fortunate with Quest that there really isn’t anywhere problematic that the plume can go – our storage complex has lots of space, there aren’t any legacy wells close by that we need to avoid, and the geologic seals are world class. So, really, it comes down to understanding the storage efficiency, and for that we have used time-lapse 2D VSPs. The imaging has been a bit challenging, since the injection zone is only 25 m thick and there are a number of coals and thick salts above the reservoir that produce a fair bit of multiple energy, however, we are now getting quite a good picture of the plume development.
How do you investigate the storage potential of a subsurface formation, as well as that of the confining rock, for CCS?
CCS reservoir evaluation is a lot like conventional hydrocarbon reservoir evaluation. You’re generally looking for similar things – reasonable thickness, good porosity and permeability, and understandable structure with relatively few potential baffles. One specification for CCS is that the reservoir be at sufficient depth to keep the CO2 in a dense phase. Reservoir modelling is used to provide a prediction of how much CO2 the reservoir can take within the constraints of the injection setup, and, as you’d expect, well calibration and testing is critically important. Identifying a reliable seal complex is also a lot like it is for conventional exploration, but for CCS in a saline reservoir, you don’t get the benefit of hydrocarbon indicators telling you that the seal has worked. One area that is completely different is that you don’t have to evaluate source rock potential – you just take what the capture facilities can generate (so proximity to capture is an economic advantage).
Given your insight into CCS as a viable means to achieve a significant reduction in carbon intensity for industrial facilities, how do you see the oil and gas industry changing over the next ten years or so?
Things have changed a lot in the last few years. Almost everyone in the industry now recognizes that significant action is required to deal with climate change, and that we have a lot less time than we thought. The challenge is that storing CO2 in the ground does not create a product you can sell, so it doesn’t fit the standard economic model that drives the oil and gas industry. However, countries are now putting CCS into their carbon reduction strategies, and financial mechanisms are being put in place to fund it. The oil and gas industry has the expertise and experience to ramp CCS up to a scale that could have a big impact. If you look at how the industry has changed in the last 10 years, it’s pretty clear that we can do it if the incentives are there. It would not surprise me to see many, if not most, large oil and gas companies using CCS to reduce their emissions in the next 10 years. Shell has recently stated that we will seek to have access to an additional 25 million tonnes per year of CCS capacity by 2035.
You have made many contributions, by way of implementation of the latest technologies and smart ideas for addressing challenging problems. If selected correctly, technologies can create competitive advantages for organizations, but the selection process can be challenging. Technology assessment done prior to its adoption can reduce the risk of ineffective investment. In this context, how have you been able to make sound decisions?
Good question. Early in the development phase, my work has usually been done without a lot of actual financial investment – I have often worked on things that have interested me in my spare time (just because I was curious), building simple models or prototypes, and if I was able to get someone else interested, we usually had a better chance of success. If we’d actually gotten to the point where investment was required, it was important to have review points, where we could bail out if it didn’t look like the idea was going to work. Recognizing that not every idea was going to work was hard, but it was the key to ensuring that we were working on the right stuff.
The term “Quest” has prompted me to ask you, on a philosophical note, many stalwarts in our industry have had a quest in pursuit of something extraordinary, or a quest for achieving excellence in whatever they do - have you had any such quest in your formative years?
Yikes. I think my quest has always just been to understand. Anything, everything – I am very curious, and I am never satisfied until I understand at a basic level why things work the way they do. Sorry, not very extraordinary.
The COVID pandemic that we have been experiencing for over a year now, has forced most of us to work remotely, conduct online meetings, etc. Some democratized voices that have been heard also say that the old normal (office-centric culture) was not all that great. How do you view it from the Shell perspective and your personal perspective, if the two are different? Do you think, in the interest of productivity, the old normal has given way to the new normal for work (going to the office a few times a month), and is that what we will see when the pandemic subsides?
Throughout the current pandemic, Shell has been very focused on keeping our people safe, and we have adapted our approach a number of times as we learned more, and in response to government measures. I have really appreciated the very thoughtful and scientific approach. We have been working virtually from the beginning, and there have been plenty of challenges, but we have been able to find ways to manage. There have even been a few benefits – collaboration with folks outside the team has often been easier, since everyone is much more willing to make accommodations for virtual ways of working, and the need to travel has been reduced significantly. I get to spend a lot more time with my family, and the 10 second commute is great! I think the new normal will be a lot more flexible than we have seen in the past, and it will be able to accommodate a wider range of individual circumstances, while still delivering the business.
Communication is key to success in the industrial workforce! Would you agree? If so, why is it that we seldom see presentations from Shell employees at conventions or workshops?
invitation carefully to ensure our participation aligns with our ambitions as an energy company, our desire to share knowledge with professionals in our field, and our commitment to regulators. I think we have been very active in the CCS community over the past few years, and there have been quite a few presentations from my team at numerous conferences and workshops.
Outside of the work that that you do for a living, what other interests do you have?
I enjoy just about anything that gets me moving – I run, rollerblade, bike, and kayak, and skate skiing is almost an obsession. I still like scrambling around on rocks, but I’m mostly just hiking now.
What would be your message for youngsters who have joined our industry recently?
It’s been a pretty tough few years for the industry, but there is still work to do. We’re going to need hydrocarbons for a while yet, and CCS will need geophysicists as it ramps up to meet our increasing carbon reduction ambitions. Keep challenging old assumptions and keep solving the interesting problems!
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