Hello and a very warm welcome to another Wood webinar where we discuss solutions to design, build and advance the world. My name is Adam Yun and I'm your host. I'd like to thank you for joining us. Today. We're going to talk about carbon capture and storage solutions and specifically looking at addressing implementation risks and how to manage them. Before we start, just a few reminders. If you have any questions or comments, please type them into the question box below the slide. We'll try to answer them as they come through. If you'd like a copy of this presentation after the event, please drop us a message below. And to receive a certification of attendance, please make sure you complete all three criteria that you can see the bottom left of your screen. You'll need to attend about 15 minutes of this webinar, participating in the polls, answering the questions, and this is scheduled for approximately 60 minutes, leaving some time for questions and answers at the end. So for today's agenda, we'll start with a brief introduction and safety moment before getting into the core of our presentation. During the presentation, we'll have a few polls to provide an opportunity for you guys to engage. We've got a few videos to show you, and then we'll wrap up with a summary of our discussions towards the end. We'll have some time for questions. Now before I begin, I just want to give you a little bit of background on wood. For those that don't know wood, we're a global leader in consulting and engineering across energy and materials, helping our clients design, build and advance the world. We're passionate about digital consulting and have a deep understanding and experience in designing, operating and supporting customer facilities. Our work is driven by our values, which are care, courage and commitment. These represent our focus on safety, our commitment to deliver and our courage to push the boundaries and innovate. Now let me introduce today's speakers and SM ES. I'm your host and facilitator for today. I'm an experienced business development professional working in the energy sector for over 20 years. I was originally based in Aberdeen, focused on the UK and Norwegian oil and gas markets before I relocated to Perth, WA in 2008 to focus on wood specialist engineering and consulting services in Asia Pacific. My remake extends to security new business across the life cycle of conventional and new energy projects and I'm passionate about working in collaboration across the industry as we strive for a lower carbon future. Next, we have our subsurface manager, Heather Coleman, who leads Woods team of subsurface specialists in developing fully integrated solutions for carbon storage. She brings over 16 years of experience working characterization and modeling of subsurface facilities for oil and gas and carbon storage. Her extensive experience includes onshore and offshore projects in places such as Brazil, Kazakhstan, Qatar, West Africa, continental US and Eastern Canada. Heather has been a key contributor on numerous EPA Class 6 permits, a lead technical contributor and over 35 CCS projects, and a co-author of several specification and guideline document. Heather has a bachelor's degree in Geology from Hope College and a Master's in geology from Western Michigan University. Finally, we have Stephen Stokes, who is the Global Head of CO2 Transport and Storage for Wood, providing technical leadership and experience for CCS developments worldwide. He brings 22 years of experience in oil and gas industry, covering all project stages from front end, detailed design, commissioning, operations, and decommissioning. He's a strong technical specialism in system engineering and floor shootings for hydrocarbon and CCS projects and brings a comprehensive understanding of CO2 transport and storage challenges from this from supply to the injection point. OK, Now before we begin, I'm just going to share a brief safety moment. I've entitled the safety moment important of ICE. ICE stands for In case of Emergency. Like you, I've always had my emergency contact name and details in my phone. But as phones have become increasingly more secure, our contacts and emergency details are becoming increasingly challenging to access. But did you know there's functionality on your phone that can help? First responders and emergency services should need them. Both Android and iPhones have this feature. It will let you add a list of emergency contacts to your phone. You can also add medical information, such as allergies or current medications. This information can be accessed by emergency services if you're unable to tell them about your medical history. It's also possible to use the Emergency SOS feature to send your location to your emergency contacts and alert emergency services. It can also be triggered by holding down certain buttons for the period of time. We've put the links to set up ICE on your Android or Apple device on the right hand side of of the console here, so please access them should you choose to do so. OK, so we're going to kick off this session with the first of our polls to get us thinking about CCS project development. And just a reminder to our audience participation participants that you need to get involved in these polls should you wish to receive a certificate for this webinar. OK, So the first question to get us thinking, what is the most critical component of CO2 injection development? And I'll just flash up the potential answers. So we've got number A, sequestration, the injection and storage, BCO 2, transport the pipeline, CCO 2 capture the process or D, it's critical. It's an integrated CCS value chain. So I'll get you guys just put in your responses for a moment and then we'll show the answer. OK. I'm just seeing, seeing that come through a bit of a spread of response. OK, So the answer is D it's all critical. It's an integrated CCS value chain now. I think that's a great way to start and segue into our session today. So I'm going to move forward and hand over to Stephen Stokes to give us an overview of today's session. Stephen, over to you. Thank you very much, Aaron. And yes, it's good to see those poll answers come through because it speaks to our theme today, which is the criticality of the full value chain. So to, to set the scene a little bit for our webinar today in, in most CCS developments, we're going to see two individual projects progressing in parallel. We'll have the CO2 disposal project and then we'll also have the CO2 surface facilities project. Now we've got very technical people in each of those teams, subject matter experts, and we're very much aware of each other that these domains of CO2 storage and CO2 interaction, they do tend to work quite separately and also at a different pace. So each is very technical but very siloed and they have a very siloed, blinkered view of the project and this segregation of the surface and the subsurface workflows that can lead to discrepancies in the CCS value chain. And then these discrepancies themselves can have a couple of effects. 11 could be under design. And so that means the project is going to carry forward quite a high technical risk. Alternatively, it could be over design and the project is carrying more CapEx than IT than it really needs to. And so with any project, not just CCSI, guess a design has multiple stakeholders with different issues and challenges that if the surface and the subsurface engineers assess these challenges in isolation with their own tools and their own basis of design, then we're going to see design gaps emerging. We're going to have operability risks and most importantly, we're going to have missed opportunities for improved overall project outcomes. Now a common cause of project delay or recycle is the poor common understanding of CO2 risks across the poor space. So a miscommunication between subsurface and surface. And today that's what we're going to focus on really it's to discuss some of these risks. And the best way to start doing that is to understand the storage challenges a bit better. And so with that, I will hand over to Heather. All right, thank you, Steve. So for the next few slides, I'm going to be speaking on carbon storage and how doing the right work can lead to minimizing risk while maximizing reward in the value chain of CCS where carbon is captured, transported and stored. The Subsurface group focuses on the storage aspect and as the name indicates, basically just anything below the ground. So in essence, we aim to address some of the upfront considerations by addressing CO2 storage projects through three main categories. The first category would be selection. Here, the Subsurface team evaluates all of the available data to select the most suitable site for injection. They'll be looking to make sure that the area is that is selected satisfies your geological criteria. Then it meets overall project volume and cost requirements and that it optimizes transportation distances and land utilization. The second category is going to be engagement. A key aspect of project success is going to be communicating technical aspects of the selected site to your key stakeholders, land owners and regulatory agencies. And lastly, we're aiming to work with projects to plan ahead, meaning we're trying to minimize the risk of future complications by thinking through all of those risks now. And to do this, we we work to assist projects with thinking about project design, using an end to end approach and considering how all of the different steps can impact one another. We're simulating and evaluating all of the potential scenarios to minimize unexpected issues. And then we're also developing a plan to mitigate any potential complications. So in its most basic form, simply subsurface. A subsurface study is going to be looking for three things #1 number one is a seal or an impermeable layer that overlies a reservoir and can keep injected CO2 sequestered in the storage formation #2 is to make sure that there's actually a reservoir that assesses that possesses the correct porosity and permeability in order to make this storage and injection work. And then #3 would be looking for any potential leak points where we're trying to make sure that there's no way that we can tell that the CO2, once it's injected, could potentially leak out. So figuring out those things basically sets up the basics for a successful CO2 storage project. But even under the best of circumstances, there are a number of situations in which surprises can occur due to some kind of an unknown. And that can happen in situations where you have maybe poor data coverage in the area that you're looking, or maybe you have data, but the data that's available is low quality. That could be due to the vintage of the data or local conditions that sort of mess up the data at the time that you're collecting it. And then you could also have known heterogeneities in the subsurface. And even further, you could have unknown heterogeneities in the subsurface. So for example, I was once working a project for a subsurface reservoir that was essentially characterized as a pile of sand. We had a lot of data that we were confident in and we were looking at two zones within this pile of sands. We determined that both of the zones were good quality because sand on sand, but one was a little bit better quality than the other and we thought that it was going to be the upper zone that was better quality than the lower. Again, we had a lot of data here and we were pretty confident in our in our characterization when we drilled the ball and acquired data. We were thrilled to discover that, yeah, our prediction in terms of the total thickness of the package and the total average of the properties throughout the package was right. But that donation that we were pretty sure of actually ended up coming in reverse. So when we thought the upper upper part was going to be the better package, it was actually the lower unit. And So what that did was it sort of triggered a revision in our perk strategy and we ended up having to rework the volume and the simulated plume. So what this example demonstrated to me was that even with high confidence, high quality data, good data coverage over your area, you can still get surprises in the subsurface. So it's important to think about the potential surprises that you can run, run up on as you're working through the details because one set, one surprise can really have a knock on effect to a lot of the other aspects of your project. So as we're talking about risks to storage, some of you might be wondering what those risks could be. So as a heads up, just want to let you know this is an animated slide. So you'll see text come up on the left, but you can also watch the animations on the right. As we're going through each of these risks in no particular order. I'm going to go through the risks now. The first is going to be geomechanical seal failure, and this is where your ceiling unit may end up not being able to withstand the changes in formation pressure that are caused by your injection. And what this ends up doing is you could have certain failures in that ceiling unit through geomechanical mechanisms that can cause things like fractures or other deformation that allows brine or CO2 to somehow escape. Next, you could have unanticipated plume migration or extension outside your area of review. If your plume ends up finding high permeability pathways or if the formation dynamics have permeability anisotropies which end up elongating the plume in an unanticipated direction, you risk that the plume could extend outside of what you're expecting the area of the plume to be. CO2 or brine leakage into underground sources of drinking water is a big risk because some something like this could obviously affect a potential drinking water source. So this could happen if the seal failure that we discussed previously occurs, or you could even find that the sealing unit qualities may change away from your injection sites or your data points. And so in that case, CO2 or brine could find a way to stay through either stratigraphic or even at sometimes structural pathways induced seismicity. If the CO2 injection creates conditions that cause micro tremors, then these events can happen. And these events are actually going to be monitored by and required to be reported by your regulatory agencies. Unanticipated pressure changes, which this is really kind of pointing to a change in pressure than that can occur if there's an interruption somewhere in your pipeline literally. And then lastly, if lastly, we have long term containment issues. So when you're sequestering CO2 underground, the intention and plan is for it to stay there permanently. One key focus of finding the ideal storage site is ensuring that the CO2 will in fact stay there for the duration. So the main impacts to subsurface risk kind of fall into two buckets. The first bucket is economic, the cost of that risk to the projects and the company at large. And the risks in the economic bucket could be things like distance from the emission source to the injection site, how far do you have to send the CO2 to be stored? You'll have to consider your transportation mechanisms like pipeline and that associated cost, which isn't cheap. The total injectable volume based on quantified storage space. Are you able to store all of the emissions volume you need over the planned duration of the project? Or do the volumes that you're able to store, or are the volumes that you're able to store are going to make sense for the amount of money that will be spent setting up the storage project in the first place? The number of wells that are required obviously will impacts the economics as well. If you determine that you're able to store the specified volume, but the project required requires multiple wells to make it work and wells aren't cheap, does that project still make sense financially? Total land impact is another risk to your economics because economically speaking you'll need to think about things like potential multi wells scenarios, how far well when you have those, how far away when you have those multiple well scenarios, do you have to place the wells? That's going to have an impact on your total land impact because you'll be requiring access to all of those injection sites. But in addition, with those multiple wells and whatever spacing you require, you're going to have to expand the area that you need to be monitoring as well. So it's kind of A2 fold thing. So given these land considerations, you know, projects really have to think about how many land owners they're going to need to partner with or is the project planning to purchase the land outright to use within the project? What do you material, what do mineral and poor space rights look like in the project region? There's just a lot of things to think about that can have a financial impact. And then lastly, the loss of revenue through potential fines and reputation damage. Certain risks can obviously carry associated fines if specific conditions are breached. So those risks are ones that would be monitored with the crucial conditions reported to your regulatory agencies. But further and potentially more impactful is the possibility that if things go wrong, a company could suffer reputation damage. So we're still sort of at the forefront of this commercial scale injection and really this infancy I would say is still kind of in its infancy. So if people, if projects aren't done properly, there is a potential that if something goes wrong, it's not not only going to cause issues for that responsible company, but it could really impact the industry as a whole. And that's why it's so important to make sure that you're doing the due diligence upfront to get the right work done by the right parties and mitigate, mitigate these risks. Now for the second bucket, this one has more to do with your environmental impacts. So a main focus of these projects is obviously, as I said, to protect those underground sources of drinking water or your underground fresh, fresh water, if you will, aquifers. This is why proving up the seal and ensuring the absence of leak points is an incredibly important part of the project's storage evaluation because it gives an indication for how well contained the injected CO2 will be. Next, the project's overall footprint. Like we previously discussed about the use of multiple wells and its impact on finances, there's an environmental burden there too, with regards to setting up shop, if you will, all of the wells, all of the monitoring stations, the pipeline, and then the extent of the plume itself. This all goes hand in hand with how much of A footprint the project will have as a whole. And lastly, the maximization to decarbonization. The overall objective of all of these projects is obviously to maximize how much CO2 we can take and keep out of the atmosphere and CCS provides the permanent solution for storing it underground. So in subsurface, our main objectives are twofold. It's working with projects to minimize risk to economic impact while maximizing the project's overall benefit to the environment. In terms of when to assess for risk, there are steps you can take throughout the project to determine and minimize those risks. This can be done during your initial site selection phase by ensuring that the storage site and reservoir are geologically stable and clear of any prohibited or inadvisable geographic locations and pre-existing features. Also, while evaluating the confining unit, you can determine by gathering and evaluating all the available data if the local and lateral presence of the geologic interval interval that you're looking at is adequate with in terms of its confining properties, then assessing your injection interval. This is the stage where the injection interval is assessed in a way such in such a way to assure that the formation is of the right quality to withstand the intended injection rates without exceeding your fracture thresholds and also to hold the planned volume of CO2. When you're doing your monitoring design. This is going to be the stuff where the plan is developed that ensures continuous detection of what those major projects risks could be in terms of your storage. So you're looking for CO2 risks, groundwater quality, the pressure front, the plume grows, and seismic activity projects, though, on top of assessing risk at all of those stages, should really have an actual risk assessment state stage. And this is where you'll look at all of the potential hazards in the project, review them, and then come up with any kind of mitigation plans to address what those risks could be. Then lastly, engagement is actually a really key step as well. This is where you really need to stay ahead of any potential misinformation by educating citizens and familiarizing reviewers of critical aspects of the project. Misinformation may not always be a project killer, but it can certainly present unnecessary problems for the for the project. So education and public engagement are really critical parts of the project. This is where you will want to reach out to your key stakeholders, local and regional public figures and citizens and regulatory agencies. So something as Steve noted that we've noticed in the space is that often subsurface studies are conducted in a silo. They're just really worked independent of other factors. And what this does for the project is, yes, it provides a basis for your economic analysis and it delivers results that will satisfy requirements for injection wall permits. But subsurface studies, when they're conducted alone, they kind of tends to utilize some broad assumptions like continuous injection of pure CO2, for example. And this leads to a base case which really actually ends up representing the best case when factors outside of subsurface are not considered. As much as I love subsurface, in reality it's really just the tip of the iceberg and there's a lot more to consider beyond subsurface when de risking the project as a whole. So by breaking out of the silo and thinking about how the subsurface connects to the greater capture and and transport system, you can start to address risks that can happen at the storage level as a result of things that are happening upstream, if you will, of the wildhead. Like potential influx of impurities getting into the system, which can impact your phase behaviors or hydrate formation in the transport pipes that can impact pressure within the system as a whole and lead to potential shutdowns. When you take these things into account, you'll be able to do a better job of optimizing on your well designed guidance because you're taking into consideration both your surface and your subsurface constraints. You can also do a better job of approximating injectivity over time to come up with high side and low side scenario based estimates when the scenarios can incorporate factors outside of just subsurface formation permutations. And so ultimately all of this in consideration will lead to greater certainty in your projects planning. And now I'm going to hand it back to. Thank you, Heather. Yeah, thanks Heather. We're just going to take a pause for our second poll of the session, but I just want to say thanks Heather. That was a a fantastic first section session section to the session. They're touching on subsurface, the risks, the impacts and start to touch on mitigations and really trying to break out at that that silo. So before we get into the second part of our session, we're just going to take another poll. OK, So I'm just going to flash up the question. So what is the critical success factor for integrated CCS system design? OK, So the answers are A a single integrated say surfaces subsurface model, B. An an understanding impurities and impacts. C an awareness of interdisciplined decision on wider implement implications, D collaboration, communication across the poor space. OK. So I'll just give you guys a brief second to answer. OK. So I think the answer is there is no wrong answer. It's a trick question. They're all critical success for CCS develops. OK, we're going to go into the next part of our session, which is across the poor space. I'm going to hand over to Steven Stokes to take us through this. Steven, over to you. Thanks, Aaron. Thank you and thanks everyone for doing the poll question. Sorry for the trick question, but obviously a key theme today is, is collaboration between surface of surface between the work I do and the work Heather does. For example. We just want to dig into this a bit more from a, an overall project CCS value chain perspective. And look, one key message I want to get across on this slide and to set the scene for the following slides is that the CO2 that's being injected, even in five years from now, that's going to come from very different sources than the CO2 that's injected today. The world, the world's changing CCS is growing in momentum. And importantly, we're seeing diversification in the industries that supply CO2 to CCS projects. So the graph on the screen is IEA data and we can see IN2023CO2 from natural gas processing is dominant counted for about 65% of the 50 million tonnes per annum has been captured. If we compare that to the 20-30 forecast from the same data set, there's two things that you can notice. First is obviously a nine fold increase in the CO2 quantity has been captured going from 50 to 440 million tonnes per annum. Importantly, the natural gas processing supply to that capture is actually now it's gone from 65% today to less than 20% in 20-30. In fact, power, heat, ammonia and hydrogen sources are expected to be dominant in 20-30. So why is this and what does it mean? So in a nutshell, the widespread adoption globally of economy wide decarbonization targets for 2050, that's stimulating diversification of CO2 capture applications towards sectors that are key to reaching net zero. So this includes the hard to bait industries, power sector and production of low emission hydrogen and ammonia. We are also seeing policy incentive changes, what we refer to as a carrot in the stick. So we're seeing government pledges and rising carbon prices and that especially for the hard to abate sector, it's started to make sequestration rather than a tax, the mission to the atmosphere more attractive now to cater for this diversification in CO2 supply. We're seeing the emergence of shared infrastructure within CCS hubs. So the clear advantage here is for a, for a remote or a small emitter is cost spread and economies of scale. So the overall conclusion that we're trying to set the scene with here is that deploying CCS to meet the carbonization goals, it hinges on timely rollout of CO2 management infrastructure, which is going to be able to manage a diversified source of CO2. This diversification of CO2 supply has serious implications when we're designing the CO2 value chain, which I'll dig into a bit now in this slide. So yes, so the last slide, we're setting the scene in the, it's sort of industry growth in CCS and the shift towards different emitters. And we're seeing emergence of hubs that service multiple industries. And the challenge here is that every industry will have a different composition of CO2. And to, to explain this, it's best to use the analogy of garbage collection. So everybody that's listening here, we have to put out our garbage either in the morning or in the evening. And every week we'll have a different mix of garbage in our garbage bins and our neighbors won't have the same garbage mix as we've got. And then the next week when we put our bins out again, the composition of that garbage will be different. That's very similar to the CO2. Not only is the different emitters that are going into a shared pipeline have a different composition, but daily, weekly, that composition fluctuates as well. We're going to get a great wide range of impurities and contaminants in the CO2 and this purity or impurity of the CO2 has a significant impact on the fluid behavior which we try and represent on a phase envelope. Very simple here on the bottom right, if you can see the red line that that actually is a phase envelope which represents a very pure CO2 stream, 99.7 mole percent. So that's something like we'd get from a liquefaction process where most of the light ends are have higher boiling points and are removed. In that process we have a very pure CO2, but the black line that's more representative of maybe a 96 more percent CO2 fluid. We've got 4% of impurities in there and that's because we've invited in multiple emitters from different industries with potentially pre combustion, post combustion, even oxy combustion capture and this widening of the phase envelopes very important, the overall value chain. So to dig into this a little bit, I'll explain. I think I've been clear. I'm, I'm, I'm a surface person. I, I, I focus on the surface engineering and specifically I managed CO2 transport systems. So the collection distribution, injection of CO2 and what keeps me up at night is flow assurance, fluid composition and asset integrity. And this introduction that I explained of a wide range of impurities that really matters because that fluid property and the behavior changes. Now we can classify impurities in two different ways. I call them minor. These are measured in the mole percent concentration. So we're talking about non condensables like nitrogen, hydrogen, methane. These components act to widen the phase envelope by increasing the fluid bubble point that is increases the pressure at which the CO2 transitions between liquid and gas. This is really important because high levels of purity mean that we need to guarantee potentially higher pressure operation to ensure dense phase and that phase is a very effective state for the CO2 to be in for transport. But if we need high pressure operation, we might need larger diameter pipe, may need higher design pressure pipe and ultimately we might need higher strength pipe. And this all that equals CapEx. There's also trace impurities in the in the CO2 and this is measured more at the PPM level that includes water, but also glycols, amines, potentially Knox and socks. These tiny quantities can do a couple of things. 11, They can shift the dew point line and that means we see liquid phase at higher operating temperatures and we don't want liquid phase in, in the CO2 system properties such as knocks and socks and combination with other impurities, we can get increased risk of acidic formation, not just carbonic acid, but nitric acid, sulfuric acid, and we can see acidic cooling and ultimately corrosion in the system. So that is what we're trying to manage from a transport perspective. But as I said, it's a full value chain, includes the injection and the impacts are not just limited to the surface. So the change in fluid has a system wide ramifications. So a good understanding of that fluid composition and behaviors also required subsurface to ensure efficient containment. So impurities can act to reduce storage efficiency. They can affect the CO2 viscosity and hence the movement, freedom of movement of CO2 in poor space. We can also have reactions and microbial activity that cause poor plugging. And that's not to mention that what Heather has already covered in terms of risks associated with water and hydrate information, potentially reducing injectivity. So there's a key thing that goes on in CCS value chain projects called the fluid specification. And it's really important for CCS value chain to set a fluid specification that is tolerance limits on the impurities in the CO2 fluid and tight limits. However, when when we say you can only have a certain amount of an impurity that has implications for the upstream emitters. You may be imposing by putting a very tight limit on a component. You may be imposing pretreatment steps at the emitter plant and they essentially we're shifting CapEx from the transport and injection system, we're shifting that back to the emitter to ensure the integrity of the assets. So it's a complicated process. Setting a fluid specification for a multi user CCS hub is something that needs to be looked at early and will get relatively complicated. So we're working hard with that is we're working very hard not only on the project where we do, but also in collaboration and joint industry projects to help understand fluid specification. Specifically, Wood are leading a joint industry partnership to have a set of industry guidelines for setting the CO2 specification for CCUS chains. This is quite an extensive bit of work which is almost ready to be shared with with wider industry and this will cover the full CCS chain all the way from capture ultimately through to geological storage. Be comprehensive. It's good to promote cost optimization, conditioning and purification and deliver enhanced safety, environmental, technical and operational performance metrics. So this JP is collaborating as you can see on the screen with a wide range of research, industry and operators to get that holistic understanding of the impact of impurities across the tool chain. So you're going to stay with me for a little bit. I'm going to now talk about that design gap that we touched on at the start. So the design gaps that might emerge between the surface and the subsurface and the challenges and missed opportunities. And we'll do that through three case studies from our global work. So case one and you'll, you'll forgive us for anonymizing these case studies, but case one is an offshore 200 kilometre pipeline, multiple subsidy wells. Now the original intent of this one was to inject CO2 only from shipped import of CO2 And now that is that liquefied CO2 I was talking about very pure 99.7% for example purity CO2 and the client was wanting 5 million tons per annum ultimate injection. That's what they're selling to the market. We've, we've got a 5 million ton per annum system, but the client also wanted to understand not only from import terminal perspective, but also can we open this hub up to local emitters from different types of industry. And it's do that they would have to reduce the specification of the CO2 to allow for 4% of impurities rather than a very pure CO2 with a 96 percent CO2 fluid due to the system. And there's some key considerations in doing this. Now again, from my surface perspective, not too bothered by this from a frictional pressure loss, that composition doesn't make a huge amount of difference in the pipeline. The important thing to look at here is the CO2 properties, especially the density. If we look at 4% of impurities, we're actually getting 50 kilograms from the cubes lower density. That means we've got less static head in the wells that increases are flowing wellhead pressure and hence reduces the well capacity. So in actual fact, we're seeing a reduction in overall system capacity of around about 10% because of 3.8 more percent impurity. And This is why we stress the engagement here is key across the reservoir and the surface. A design gap gap is going to emerge. If if I'm busy, a wave busy in the substance in this surface workflow looking at 96% fluid, the subsurface models and workflow is still considering pure CO2, then obviously there is going to be a gap that emerges there in a fundamental misalignment on things like tubing head pressure and ultimate field capacity. So we do need to ensure that alignment there and to ensure that and what the client wanted was to still ensure capacity to the market of 5 million tonnes per annum. And if we shift from a pure CO2 fluid to 96% fluid, in this case, the project would actually need to invest significant CapEx. So we'd either need an additional well to secure that injection capacity. Potentially we need a larger damage pipeline or a higher pipeline design pressure. So that small amount of impurities could have significant repercussions. Looking at Case 2, this is an interesting 1:00. We, we come across this actually surprisingly often. And, and this is where we have, again, it's an offshore storage in, in this case it's 100 kilometers from shore and we want dense phase assurance in the pipeline. In fact, the client was asking for dense phase assurance not only in the pipeline but in the wells as well. They want to dense phase fluid all the way to the bottom hole. But in this case it's quite interesting because we have a very heavily depleted pressure, pressure reservoir. So in actual fact we've only got 150 PSI, 10 bar remaining in the reservoir. In this situation concurrent create quite counter intuitive requirements. So we've got dense phase request. We want this dense phase system, but we've got A10 bar reservoir and managing that again requires that integration across the disciplines. So there's two key issues in this case study. The first one's injectivity. So typically we want high injectivity from a capacity perspective. If you want to get as much capacity from the well as possible, you want minimal pressure drop for the highest rate of CO2. But in this case, if we have minimal pressure drop across our formation, then we're only going to have slightly above 10 bar in the bottom hole. So therefore we'll have gaseous CO2, not density CO2. So that undermines our objective. So we end up having an I end up going to Heather with a very interesting conversation. I need to say actually, can you target lower injectivity? So again, quite counterintuitive actually I'm looking for higher pressure drop across the formation to give me something closer to 80 bar at the bottom hole to get dense phase assurance. Secondly, if we do get that, so if if Heather and her team can find 80 low injectivity and pressure drop across the formation, then we've got 70 bar pressure drop across that formation. So now we've got CO2 expanding from 80 bar to 10 bar in the reservoir. CO2 has very high Jill Thompson coefficient. So we'll get a lot of expansion cooling because of that. And that means we'll get very low temperatures in the near wellbore and there'll be water in the near wellbore. So we'll get hydrate formation and those hydrates can cause basically blockage of the pores and reduced injectivity. There's all sorts of mitigations that go on in a case study like this, including heating if you have a topsides facility, but essentially it can get very, very difficult and very, very costly. In this case study, the best strategy forward was actually to take a step back and have an initial period of gaseous CO2 injection. So have a number of years of gaseous CO2 injection until the reservoir had sufficient pressure above 10 bar, you know 30-40 bar that we could manage the the complications with dense phase injection and then we could have dense phase operation. And then finally case three, I'll just touch on something and then hand to Heather for this one. But again, from a surface perspective, we're very focused on dehydration. We want minimal H2O in our system. We don't want carbonic acid forming. And so we tend to get more and more and more aggressive water specifications down to very low PPM levels. And the risk is if we do that in isolation, we might be missing a trick. And I'll I'll hand to Heather to to finish that trick. Yeah. So when you're doing this, when you're doing all this dehydration, there can be some impacts in the subsurface which can include things like inducing salt precipitation, clogging fluid pathways and then sort of just resulting in an overall reduced injectivity. So an example of where this was seen is the Slackner CCS project, which experienced early injectivity problems. And the issue was resolved with the injection of MAG or monoethylene glycol, which is used to address the hydrates. And the near wallboard damage effect was determined to be due to salt drop out, which was attributed to the dehydration of the CO2. Now it's probably a combination of the dehydration and the the actual other factors within the reservoir like salinity. But this what this really points to. It's it's a case that really demonstrates how the integrated nature of those two things, the surface and the sub surface is vital and considering them together is really important in order to assure the project's success. All right, so now back to Erin for another poll. Great, Heather. Thank you, Steve. And Heather, that was another great session there for for the second part of the webinar. And you know, thanks again for for showing those case studies, those 33 very insightful case studies that you guys just walked through. OK, before we get into the last part of the webinar today, we're just going to break for the third pole or move this along. And question is what will be the dominant source of captured and injected seal to 10 years from now? So where are we headed? OK, answers. A natural grass gas processing B direct air capture C power Gen. D ammonia, hydrogen or E other. So I'll just give you guys a moment to put down your answer. See the spread coming through. OK, All right, let's move on. So the answer is, well, the answer is actually C&D, but in fairness and another bit of a trick question, they will, they will, you know, C&D will dominate, but they'll all, they'll all play a factor. OK, now we're just going to move on to the last part of the session and I'll hand back over to Heather to talk about closing the gap. Heather, over to you. Awesome. Thank you. So now I'm going to wrap this up with the hope that you all understand why closing the gap is such an important part of CCS and that risk mitigation should be looked at as a as a shared problem. So when we break down the boundaries between our silos, we're really able to have a greater insight into the overall system behavior and it also helps us to de risk better the overall projects. This is of course true for any project, but it is never truer than for CCS. When planning and working CCS projects, you want to make sure that you consider working the problem from end to end, like we've been talking about. So here at Wood, we have this unique fortune of housing all of this domain knowledge from capture through transport and storage within our organization. So our integrated CCS teams work together to ensure that we develop comprehensive plans for successful outcomes on the projects that we're working as a part of. Our integrated approach would also works with digital integrated solutions. So currently we have developed a workflow to close the gap between surface and subsurface parameters, connecting the surface geologic and dynamic models with the pipeline and the well bore models. And that's what's shown here with this diagram. Additionally, Wood has been evaluating commercially available software products for integrated surface and subsurface evaluation. So current offerings out there in the market would include a pairing of CMG with LED a flow and then also SL, BS Patrol, Intersect and Olga connection, which actually goes live next year as a fully and automatically integrated offering. We also have a proprietary software solution for integrated system monitoring called Virtuoso and that provides real time data for leak detection, volume verification and subsurface modeling, helping to ensure effortless monitoring and reporting of the key project risks. So I'd like to conclude by reviewing a few of the money benefits of de risking projects by utilizing this full chain thinking. First, taking an integrated approach will eliminate the utilization of broad assumptions that can occur when we work in silos. If projects take a more integrated approach to modeling, then they'll be able to really address sensitivities through the workflow, such as evaluating how changes in fluid composition can impact the entire system and being able to evaluate how impurities in the system can create a bottleneck to the full chain CCS capacity and then have an impact on your operatability. Lastly, when taking an integrated approach, project decisions will be based on the full picture. So in anticipation of all the project risks at all points of the project and that ultimately leads to fully successful outcomes for the project. So that's it for today. I'll hand it back to Erin. Yeah, great, Heather. Gotcha. Thank you very much. So that sort of wraps up the the core of the the session today, but we've definitely left some time for some questions. So, so keep them coming in. I've got a few that's been posted as as we're going throughout the session. So we'll probably just jump in into those. Just want to select a few here. So thanks for all those that have sent in. So first question, I can see here that I'm going to put out there. So can a model be built without a? Well Heather, can I hand that to you? Yes. So assuming this means without, well, data at the site, the answer is yes. A model can be built using what we call analog data or data from geologically similar sites that had that actually have data and a general understanding of the application of that data for your specific project area. But when you do something like this where you're using the analogs, you're taking a big assumption that that the site that you're looking at is going to be very, very, very similar to where you're taking the data from. So in a situation like this, in order to de risk, you really need to make sure that you're getting that on site data through a stratigraphic test well. Great. Thank you. Heather, I suspect the second one might be with you and it's very topical. How can you prove that the CO2 will stay in place? Yeah, that's a great question. I think that's a question that's on a lot of people's minds for a lot of different projects. There are a specific number of items that you're going to look for when you're proving up your storage container, and that includes having a really good understanding of that ceiling unit. So you really need to make sure that as you're doing your characterization in the 1st place, you're looking for specific qualities in that unit thickness, the permeability in the porosity, or at least very much the permeability has to be low. And then, you know, looking for any kind of structural features that could prove to be, you know, leak points. But in in doing that and sort of proving up that it within a large area around your injection site, you're pretty confident that you know, the seal is there and there aren't any other features that could cause leak points. Then that's how you're really proving up that the CO2 should be staying in place for the duration. Great. Thanks, Heather. I'm going to go to the next one. Steve, I noted in the presentation, somebody's asked here, you mentioned the JIP on CO2 specification. When will that be made available and will it be public domain or limited to the JIP partners? Yeah. OK. That's, that's a great question. So yeah, yeah, we're excited about the JIP. It's really comprehensive work. I think it covers around about 13 different work packages across all system components and it's going to provide the industry the great resource. I need to check that. My best information right now is that it is imminent. Hopefully we're talking about September that this will be made available. And again, forgive me if I'm wrong, but I believe it will be put in the public domain through an online portal. So I think the whole idea is collaboration here. It's not to contain information, it's to share information. And like I say, we're quite excited about that. But if you have a specific question, please reach out and I can Fact Check myself and we can provide you with some some more information there no problem at all. Brilliant. Thanks. Thanks, Steve. Probably got time for just two, two more questions. Let me just see down here what is the biggest uplift you see in dunes simulations with the surface considerations included. Steve or header when you want to grab that one. Yeah, sure. So we've been doing those with my, with my subsurface team. We've been doing those together with the flow assurance team and the collaborative nature of doing those simulations has provided quite an uplift in terms of the thinking from you know more of an end to end perspective. Also what we're able to do is get a better understanding of the flow behavior under various conditions and the injection into the reservoir and some. So we're actually, we've been evaluating things like obviously the rates and the pressures also things like near wild war effects JT cooling and and salting out. And so being able to do that in consideration from like the, the pipeline all the way down into the reservoir has been very cool. To be honest. You're you're just seeing a lot more and you're getting a better form informed answer at the end of the day. Thanks, Heather. OK, probably got time for one last question again, this one just jumps out. It's pretty, pretty topical right now. cross-border CO2. So yeah, cross-border CO2 shipment was mentioned on one of the earlier slides. Is there any specific considerations for surface subsurface integration good to? See someone, someone that's paying attention to the early slide. Yeah, so we did. We did talk about liquid CO2 cross-border shipment and yeah, it's, it's really an emerging area of the industry. It's actually apart from CCS hubs. It's one of the themes that we're seeing in the industry right now is countries with potentially high emission profiles, but poor access to geological storage, looking at exporting CO2 to jurisdictions that have good geological storage. So we are supporting projects in the North Sea for continental Europe over to Norwegian North Sea, for example, and also here in APAC, a lot of their SE and East Asia transportation to Malaysia, Indonesia, Australia projects being looked at in consideration. And there's two types of theme around the projects. One is you ship it over to a terminal which has some storage and then there's a pipeline that takes you to potentially offshore to your geological storage. The other kind of project we're looking at is where you try and minimize that interface and cost and go direct to the well site offshore. And so you're essentially bringing a ship alongside the wells. And the key surface subsurface integration aspect there is whether you can achieve continuous injection or batch injection. So I think, I think most people on the audience here will understand the hydrocarbon comes up from the ground and it's quite warm. So these wells are operating potentially, you know, 100° C And when you then go and look at using these wells for CO2, you're putting in a relatively cold fluid. And and that's even truer with liquid CO2 Liquid CO2 shipped potentially at low pressure conditions, potentially at -40 or 45° C, you still have to heat that to get in the well, but you don't want to spend too much money heating it. So you could just be injecting it sort of 0° C, 5° C, that sort of thing. So you're giving that well a real shock and thermally. And then if you have a batch injection, you're not just doing that once you're you're sailing away, you're letting the well warm up again to the geothermal gradient and then you're going to shock it again with the with the CO2. So from a well designed perspective at geothermal and potentially geochemical consideration pieces, a huge amount of work needed to be done to understand if the if the wells can tolerate that and if the formation indeed can can tolerate that. So it's, yeah, it's a really good question and is an emerging understanding of how some of these projects are going to operate. And some of the solutions could involve CapEx, additional heating, OpEx, additional heating when when you're offloading. So, yeah, great, great question. And whoever asked that, feel free again to reach out and find out more. Perfect. Great. No, thank you very much, Steve. Great answer a lot, a lot to that. So we're just coming up against time now guys. We'll we'll probably draw it to a close. Now. Apologies if we didn't get to your question, but please contest it. Contact us directly and certainly be happy to discuss in in more detail. Also, if you'd like to share this with your colleagues, the webinar will be available on demand from from our website. So I encourage you to to go to that and and please share that. So remains to say just on behalf of myself, my colleagues, Heather and Steve, thank you very, very much for joining us today. Hopefully you find out a really useful and insightful session. One last thing, there's a short survey on your screen now and after the webinar. And we'd really appreciate if you take a few seconds just to let us know how we did give us some feedback. That would be much appreciated. And that's it really. That concludes today's session and just want to say thanks again for joining and have a great day. _1743736767156