Working file March 2023 Journal

THE VIEW FROM GÖKHAN: CO2 COULD BE MORE IMPORTANT THAN YOU THINK An Interview with Gökhan Coskuner, Sr. Technical Advisor, Strathcona Resources Ltd.

CHOA JOURNAL - FEBRUARY 2023 I 10

Gökhan Coskuner has over 30 years of oil and gas industry experience and currently works as Sr. Technical Advisor at Strathcona Resources Ltd., specializing in Carbon Capture Utilization and Sequestration (CCUS), in all aspects from capture technologies to ensuring safe disposal of CO2 . He worked previously for Husky Oil as Manager of EOR and New Technology in the Heavy Oil and Gas Department, Asset Manager and Reservoir Engineering and Development Lead in Oil Sands, Team Leader involved in the development and optimization of deep basin tight gas fields, and as Reservoir Engineering Specialist in projects ranging from gas storage to offshore field delineation and development.

Prior to joining Husky Oil, he worked for Agip (Eni) as a reservoir engineering advisor, Scientific Software Intercomp as a senior consulting associate and at Imperial Oil, Shell Canada and the Petroleum Recovery Institute in various research capacities. He holds a B.Sc. degree from the Middle East Technical University in Turkey, and M.Sc. and Ph.D. degrees from the University of Alberta, all in petroleum engineering. He is the past Chairman of the SPE Canada Regional Awards Committee, the past Chairman of the Board of Directors of SPE Canada and the past Executive Editor of the Journal of Canadian Petroleum Technology. He has been a member of the Journal of Canadian Petroleum Technology Editorial Review Board since 1990, was a director of the Petroleum Society and the general chairman for the 2004 Canadian International Petroleum Conference. He was the recipient of the Petroleum Society’s Outstanding Service Award in 2009 and the Society of Petroleum Engineer's Distinguished Member award in 2013, Outstanding Service Award, A Peer Apart Award in 2014 and SPE Calgary Section's Outstanding Service Award in 2019. He has 37 publications and holds 3 patents.

Can you talk about your time at Husky?

I spent 20 years at Husky, and I loved it there. It was a great career for me. I started offshore, went to the deep basin, then thermal oil sands, and then finally to heavy oil. I had great fun. Husky allowed me to learn a lot and experiment with quite a few new technologies. Over my 20 years there my budget probably added up to a billion dollars, some of which was spent on new technologies like CO2 capture and EOR. Management was onside and supportive if you could justify what you wanted to do.

CO2, among many other technologies, was one of the ways Husky looked at increasing recovery in the Lloydminster heavy oil block. With the primary production method of Cold Heavy Oil Production with Sand (CHOPS) in Lloydminster, average oil recovery is 8%. That means 92% of the oil is left behind. This is billions of barrels of oil still in the ground and you have to do something with that.

Husky started its life in Lloydminster in the 1940s and it was still a key component of Husky’s production. We tried many, many new technologies such as cyclic injection of various chemicals, electrical shock treatments, microbial EOR, cyclic injection of solvent, of gas and of water vapour, hot water circulation, etc. CO2 injection was another new technology we piloted. CO2 is kind of interesting. In principle, if you look at screening criteria for heavy oil EOR, CO2 will not fit. Immiscible gas injection should not increase recovery.

CO2 is a magic gas, really. It was amazing. When we utilized the wormholes that are created during CHOPS to deliver CO2 to the reservoir and pressure it up, we proved that you could make money as a post CHOPS EOR technique. It was done in a cyclic manner, or huff and puff, where you inject CO2 to pressurize the reservoir and dissolve it in the oil and then produce back CO2 and heavy oil from the same well or group of wells in communication. Produced CO2 is separated and reinjected back into the reservoir with make up CO2 to repeat the huff and puff process. When I left Husky in 2018, we had 5 expanded pilots, we were capturing and trucking our own CO2 and were producing 2500 barrels a day of oil with CO2 EOR. Most importantly we were commercially making money.

At Husky, what helped commercialization was that we built our own CO2 capture plant. Once we figured out that CO2 would work, the next question was where the CO2 would come from. The most logical answer was our own thermal operations in the vicinity. We built three CO2 capture pilots at our Lashburn SAGD facility to test different technologies and a 220 tonne/day commercial CO2 capture plant at the Lloydminster Ethanol Plant to support our EOR operations. It was a multi-pronged approach of EOR and CO2 capture.

My experience at Husky directly translates to what I do today, which is studying the capture of CO2 from SAGD plants for sequestration in a deep saline aquifer.

My reservoir engineering background and experience helps with CO2 sequestration aspects and my experience in piloting and building CO2 capture facilities helps with the selection and implementation of capture technologies.

The engineering knowledge that you need to use for EOR and sequestration is similar. EOR adds complications of producing and optimizing oil production, while in sequestration you are just concerned with safely injecting the CO2 into the reservoir/aquifer. CO2 used for sequestration is in dense phase liquid or supercritical phase and is still immiscible with the brine in the saline aquifer.

At Husky, when we ran our economic models, we never counted on the CO2 credits, but if you think about it, there should be some CO2 credits because every injection-production cycle, you leave behind and store 30% of the injected CO2 in the reservoir. There should be CO2 tax credits for this amount. CO2 EOR carbon sequestration tax credits as well Investment Tax Credits should be implemented. Governments at the Federal and Provincial level need to develop those to help the industry implement CCUS on a wider scale. It’s a match made in heaven. We have the CO2 sources in the area, thermal plants and other point sources we can capture. And why not use it for CO2 EOR while storing it in the reservoir. There are tens of thousands of wells at the end of their lives. We can use the existing infrastructure and minimize our carbon footprint.

Can you talk more about how you were able to convince management to invest in new technology?

New technologies require an understanding that you are going to fail a lot of the time, and if you never fail, you aren’t doing the right level of innovation projects. Every once in a while, one or two of the projects will succeed and make up for all the others that fail. The value of failure should be pre-accepted for any kind of innovation. Failure should be welcomed and is an opportunity to learn and not a reason to give up. With that in mind, as an innovator you need an internal champion: somebody to shelter you, to open the path for you.

The senior vice president of the heavy oil group at Husky was Ed Connolly and he was my internal champion. Every time I took a new idea to Ed, he would first say no because he needed me to do more work on it. But if I eventually convinced him of an idea, he would support me and allowed me to follow up the idea to the pilot stage, and with post-CHOPS CO2 EOR, eventually to the level of commercialization. In addition, we were presenting our new technology projects to the COO of Husky at the time, Rob Peabody, every 6 months. He was interested and supportive for the same reason that Husky had a huge potential in Lloydminster if we could squeeze out a few more percentage points of recovery from our huge in situ resource. Obviously, they both trusted our group to be able to come up with at least one successful technology that would unlock Lloyd’s potential.

What are the uses for CO2 in SAGD operations? Does it make more sense economically to capture and sequester the CO2, or to utilize it to increase production?

Anytime you can use CO2 to increase production, it’s a more economically attractive solution. In SAGD, the one alternative to sequestration is that you can use the CO2 you capture as a non-condensable gas (NCG) co-injection with steam. We use methane for that purpose these days, but why not replace it with CO2. It has added benefits of increased solubility and swelling, because it dissolves more in the oil than methane. CO2 is 4 times more soluble in heavy oil than methane, thus, you get more benefits. There have been some field pilots of CO2 injection as NCG with steam. The results have been positive. The problem has been the CO2 supply. You need a significant amount of new investment for that. For CO2, we need to capture flue gas from the steam generators and remove the CO2, which makes up a small percentage of that flue gas. Methane injection is basically fuel gas used for steam, diverted to the reservoir. It’s already there. There are lower economic and technical barriers to inject methane. However, if all the CO2 from the generation of steam is captured, we calculated that only about 5% of it can be used for NCG injection because the amounts captured are so large compared to what is needed for NCG injection.

Therefore, vast majority of what is captured needs to be sequestered.

You've worked on a lot of carbon capture technology development. What are your lessons learned along the way, and what is your philosophy today?

My philosophy differs based on whether we are talking about technology that is commercially available today, or technology for the future. If we want to do it today, the only technology mature enough is the modified amine. That’s what is available at the commercial scale. There are lots of other technologies: enzyme, molten carbonate fuel cells (MCFC), cold membrane, solid adsorbents just to name a couple. These are promising technologies being developed today and some of them are probably better than amines. But they are at a lower technology readiness level (TRL) than amines.

You can’t take one today and start building a capture plant. If that’s what you want to do, you go with a modified amine solvent. Take the MCFC: they have many power generation facilities as commercially operating technology, but nowhere is it being used to capture CO2. It’s a higher TRL but I think it’s still not commercially ready. The capture efficiency and energy consumption is not there. It can be overcome. It’s just not there yet. The attractive feature is that there is a revenue stream in form of produced power.

What new technologies do you foresee making a difference to Alberta oil production in the next few years?

I think CO2, because of the environmental implications as well, is one of the forerunners for heavy oil EOR technologies. The other technology that we tried very successfully is hot water circulation. It is not quite injecting steam, but injecting hot water, that is, injection of mild heat compared to SAGD. It’s a thermal process using horizontal wells. It is a very promising technology. In the oil sands there is a big push for incorporating solvents, with or without steam. I see that as being a promising future as well, mostly because of the GHG concerns. Solvents have been tried in heavy oil. I mentioned this in a pair of papers that I wrote. The biggest problem with injecting solvents to recover heavy oil is the solvent loss, especially as post-CHOPS EOR. Technically it’s a great technology and works very well. Economically it’s a big challenge. With oil sands, if you can form a solvent chamber similar to a steam chamber (i.e.

VAPEX and its derivatives) it may work. Solvent loss is still a challenge to overcome, but it’s less of a challenge than a wormholed and low-pressure heavy oil reservoir at the end of its CHOPS life.

What are the most urgent and important things that need to happen for the long-term success of the oil sands and heavy oil industry?

One of the things I see as a problem in Canada with CO2 technology, in particular CO2 EOR, is that it is excluded from a lot of financial incentives, for instance, Investment Tax Credits. If the government is going to incentivize capture and storage of CO2, EOR has to be a component in there. In fact, EOR is a good candidate because the government probably has to contribute less to such a project compared to sequestration. From a policy perspective, we have to make the case and convince the government to make incentives available for CO2 EOR. In the US, regardless of how you store the CO2, you get some credit, whether that is through EOR or pure sequestration.

Do you have any advice for people early in their careers?

In the petroleum industry, I see two paths. The first path is that the world is going to need oil, long into the future. The oil industry is good to be in. Learn as much as you can about the standard problems we have to tackle, like optimizing production and reduction of cost.

The other path is we are seeing CCS is becoming a big focus with Pathways and all of the other potential sequestration hubs in Alberta. Anyone coming from our industry is ideally suited for these projects. Phase behaviour, drilling wells, optimizing production/injection, etc. Our standard day-to-day problems are directly transferable to the subsurface aspects of the CO2 sequestration.

Same is true, for the CO2 capture side, of our experience in constructing oil field facilities and pipelines. Alex Pourbaix said this, and I see the same thing: if we are going to invest billions and billions in these projects, we are going to have a shortage of experienced personnel to make these projects happen.

What are recommendable books, podcasts, websites for CHOA's audience of nearly 15,000 professionals?

SPE has a special program (GAIA Sustainability Program) and Sustainable Development Technical Section (SDTS) specifically focused on CCS. That probably is a good source to keep in touch with the discussions going on today.