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Irene Arango - Understanding Expulsion Capacity and Organic Porosity in Unconventional Petroleum Systems

AAPG Distinguished Lecture Series, 2018-19 Season

AAPG Distinguished Lecture Series, 2018-19 Season


A Distinguished Lecture talk given by Irene Arango during 2018-19 AAPG DL Season. Click here for abstract.

Full Transcript

Hi, everybody. Thank you for being here. My name is Irene Arango. I am a geochemist. I work for Chevron Corporation. And I am very honored of being part of AAPG and the AAPG Foundation Distinguished Lectures Program. I'm going to tell you today about the expulsion capacity and organic porosity in unconventional petroleum systems. We will start by describing what are unconventional petroleum systems.

I will then get into a bit of detail about the concept of hydrocarbon expulsion and how that ties into unconventionals. We're going to discuss porosity in tight reservoirs, the connections between expulsion and porosity. And then we'll describe some of the issues that we run into as practitioners where we're trying to learn from the samples and draw into possible impact on the samples by our observation of them. And then we'll just wrap it up and I look forward to your questions at the end.

What is an unconventional petroleum system? By definition, it is a system characterized by the restricted flow rates, which can be then enlarged or enhanced via horizontal driving, hydraulic fracturing, and other means that technology has allowed to help us make flow rates that would be otherwise non-commercial, completely commercial. So this technology is what has facilitated this boom in unconventionals that we have been experienced for almost 20 years. If you think back at the beginning of this boom, Barnett shale, of course, was one of the bigger assets that there was in this space.

And Barnett shale is a shale reservoir, source reservoir, seal and trap, all contained within one organic-rich unit. In general, this type of unconventionals have very low permeability and porosity, often less than 5%. There was significant increase in unconventional gas production since the 2000s. The Barnett, as I mentioned, it's actually the one that started the boom and it became the largest daily gas producer in the US since 2001. And overall, the US unconventional gas production now exceeds conventional gas production.

So if you look at the plot on the right hand side, we're seeing historical unpredicted dry gas from shale gas plays and other sources in the US. This is a plot from the US Energy Information Administration from 2016. On the y-axis, you are seeing dry gas in trillion cubic feet. And on the x-axis, we're looking at the year. So you can see how, prior to 2010, other gases produced from conventional systems were the bulk of gas production in the US.

But shortly before 2010, we started seeing the significant shift where more and more gas was being produced from unconventionals. And the projections into 2040 are with unconventional dry shale gas being the bulk of the volume of gas produced in the US. But not only unconventionals were a boom in the gas space, but actually in the liquid space now they are critical. In 2016, the Eagle Ford reached peak production of 1.5 million barrels per day.

This is from having a production that was not even considered commercial before that. And we well know that there are other places, such as the Permian Basin, where now many companies are exploiting the resources for unconventionals as associated with the Wolfcamp and other units in that area very commercially and economically viable these days. In terms of unconventional systems, I did mention the typical Barnett-type unconventional play, which is a massive shale reservoir. Those are known as massive source reservoirs.

These are shale gas or shale oil plays, very fine grained, less than 62.5 micrometers in diameter in terms of the grains. And they are contained by themself. They are self-source. And the liquids in this type of plays will crack to gas and some of the gas will be stored in the sorbed state. So you have all these retention capacity that these types of plays have, that will enhance the volumes of hydrocarbons that you will eventually find in them. So if you think of the plot on the left side, you have this thick unit that is the source, that is the reservoir, and is self-contained.

You are trying to produce directly from it. You are producing from the source. And so richness is quite critical because the richness is what's going to define those volumes that you're going for. But also understanding how expulsion affects these type of units, because when you are dealing with a massive source reservoir, you are still going to be losing hydrocarbons to the carrier system, so expulsion is going to happen outside-- to the outside of the rock. But where within the rock would you find the largest accumulation of hydrocarbons?

We'll get into that when I discuss expulsion in more detail. There is another type of unconventional system which is a sandwich reservoir. The best example I can come up with, the Bakken shale. The Bakken Formation, is, if you want to describe it this way, a mini conventional system, because you have two source layers that are bound in a tight reservoir. It is unconventional because the reservoir is tight, so it requires enhancement. But it is conventional in the sense that you have traditional generation from the source, expulsion into the reservoir and we are producing from a clearly reservoir-type interval.

These tight reservoirs, bounded by source intervals, are like a sandwich. That's why we call them sandwich reservoirs with the ham in the middle. They have low permeability and the hydrocarbons are migrating into the reservoir and that's what you're going to target. But because of the nature of these systems, long distance migration is possible and has been shown, based on your chemical data that shows evidence of significant long distance migration in some places associated with the Bakken.

The third type of unconventional system is the interbedded source reservoir couplets. These are high frequency interlayerings of mudstones with coarser lithologies such as very fine sands. Great example of these in the Permian Basin, the wolfcamp formation. You have these, as you look at the plot on the left hand side, source layers interlayered with tight sands. What happens in this particular location is expulsion processes work in a different way. You have generation from the source, expulsion into the tight sands, and because they are so closely together, everything seems like one unit.

But actually, there are differences in the fabric between the layers. And you have a high expulsion efficiency because you have increased contact area between these layers. Because we have these differences in models in unconventional system, it's quite important to understand the process of expulsion from them. The way how we're going to produce from these systems is going to be different based on the type of expulsion system that they are managing.

In unconventional systems, we have seen that many times you have high production wells being tied to what they call secondary cracking. This is, you have kerogen, the kerogen-generated oil and gas, and then that is primary cracking. But that oil that was generated in that primary cracking process can be retained within the unit and then cracked to gas. That is secondary cracking. What we learned from places like the Barnett shale was that the volume of oil and gas accumulated in the reservoirs was heavily influenced by the extent of expulsion and facilitated in places where oil was retained and further cracked to gas.

So secondary cracking seemed to be quite important in that regard. So understanding the key controls that determine expulsion efficiency is going to be critical for what we want to assess. Expulsion in unconventional systems, it's important to understand how it proceeds because understanding the key controls that determine expulsion efficiency will help us determine the ultimate potential of unconventional plays. An example to the right is from the Barnett shale. What we learned from data collected from Barnett shale, was that there seemed to be higher quality wells, higher production from wells where the gas isotopically could be identified as gas that was generated from the cracking of oil.

As you know, when kerogen cracks, it can crack to oil and gas. Kerogen cracking to oil and gas is known as primary cracking. But when the products of that primary cracking further develop into other products, so oil is transformed to gas through thermal heating, that is called secondary cracking. What we can have traced in some cases is production being enhanced when you have oil retained within the rock that is further cracked to gas.

So in a case like Barnett, when you are dealing with a typical massive source reservoir, having that retention inside the rock will then ultimately reflect in the volumes of resource that we're going to recover when we're producing from it. So because of this, we need to understand what is the model of expulsion we should be looking at for a wide play of interest, and how signs of higher oil rotation might correlate with areas of higher product that we're going to be producing in the future.

So let's talk a little bit more about expulsion. Expulsion is the movement of hydrocarbons from the kerogen, through the source, into the ports and fractures of the carrier system. Oil expulsion, rather than gas expulsion, requires sufficient volumes of oil to saturate the porous spaces in the source rock. When you're dealing with gas expulsion, typically what you need is a pressure differential. You need to saturate the porous space, but you need to have enough pressure differential that you're going to facilitate diffusion.

The plot on the right shows the case of oil expulsion. When oil is generated, initially you have isolated droplets that are starting to form within the pores of the rock. As generation progresses, more and more of these oil droplets will be coming together. And ultimately, they will establish a continuous flow path that will facilitate the movement of the oil through the rock. Because if you know, rocks tend to have water in them, bound water. Bound pore water can disturb the flow of oil. But if you have a continuous network, it will allow the oil to flow, connecting those droplets together.

Because of this, there is also some connection which we'll discuss later, in terms of the amount of richness in the rock and how much you can expel or not find. So let's look at the process from generation to expulsion. When you are generating, you don't expel at the same time. Generation occurs, of course, initially and then slowly you are building up to the point of expulsion. How that happens? You initiate burial and compaction of the source. So you have sediments and organic matter deposited and they are being buried and they are being compacted. And a reduction happens naturally to the spaces between the grains.

As the sediments are being deposited farther down, and temperatures increase, kerogen maturation proceeds. So the organic matter that is now sediment organic matter, kerogen, it starts to be transformed. As generation progresses, you are going to be seeing changes in kerogen into oil and later to gas. Kerogen transformation to hydrocarbons results in a change in volume in the organics. As you go from-- if you look at the plot on the right, I was trying to show here how you originally have some spaces between the grains, including the organic matter.

But as kerogen maturation progresses, you start losing those spaces by both function of the normal pressure changes are basically compacting the rock, but also because kerogen is changing to oil and gas and those occupy more volume for the same amount of organic carbon. So you can end up increasing the original volume up to 25%. And this causes pressure against the weight of the rock. What that results in is a discontinuous pressure built up and opening and closing of microfractures as expulsion proceeds.

So if you can imagine, you're generating-- you start pressurizing against the weight of the rock. Then that pressure needs to go somewhere, so you micro-fracture, fluids move a little bit up, and then you again compact down. So it's not just going, but actually it's a process of expansion and contraction in a way. This release results in oil migration. Also, there might be micro pore networks that facilitate the movement of the oil through the rock fabric. So it's not just a function of fractures. But fractures, micro fractures, are quite important in the process of expulsion.

This is an example from the Tremembe formation in Brazil that shows that timing of generation and expulsion and how it is not equivalent but rather a 2-step process, or even a multi-step process like I was describing. You have that initial build up if you look at the plot on the left hand side. You have the amount of hydrocarbons by gram of rock. And on the x-axis, you have the pyrolysis temperature. And you can see that, initially when you're generating, you are impregnating the sediments with oil.

And at some point, you start expelling. And because you are expelling, you see a drop in the amount of hydrocarbons at that location because it has been moved out. And you can see on the right hand plot, the formation of those micro fractures, which may provide primary migration pathways. So what is expulsion efficiency? It is the mass of fluid expelled over the mass of fluid generated.

So if you generate a certain amount of hydrocarbons in your rock, and then those hydrocarbons are going to be moving out. But a portion of them will be retained within the rock so it's not a perfect system. Not everything goes out. When we were worried only about conventionals and you were modeling your system, a basic modelist would put something in the model saying, we have 15%, 20%, 50% expulsion. And that tells them how much out of a volume that is estimated to be generated by the rock actually made it to your conventional reservoir elsewhere.

In the world of unconventionals, it works similarly but backwards in many cases, in the sense that you are more concerned about what is retained. And so it becomes even more important to correctly estimate the volumes that were generated and that retention capacity of the rock because that allows you to estimate how much volume you think you can find in that rock that you are going to try to frack and get out of it.

What are the main controls on expulsion efficiency? Organic matter type, organic matter richness, the rock matrix, the contact area, and the source rock thickness. There are, for sure, other parameters, but those are the ones I'm going to be describing today. So let's first talk about the influence of organic matter on expulsion.

There's a couple of concepts here I'm going to try to describe. The first one, the higher the TOC, usually the higher expulsion efficiency for rocks that reach in the same kerogen type. So in this case, I'm comparing three rocks. They are all type two kerogens. But the difference between them is that one has a 1% TOC, another has 3% TOC, and another has 10% TOC. So you can see on the left hand plot how the amount of expelled oil versus temperature increases for the higher TOC level.

That is because if you think about it, the higher the TOC, the higher your chances of having a connected coordinate where it facilitates the movement of the oil out of the rock. So even if you are dealing with the same kerogen type and it's all oil-prone and we're all going to produce oil, you might see more movement out of the rock relatively speaking in terms of expulsion efficiency terms, in a higher TOC scenario. But also, the type of organic matter, matters. Because of course you're not going to get the same level expulsion out of a type three source rock versus a type one source rock.

So we have increasing expulsion efficiency in the plot on the right hand side increasing to the right, and transformation ratio going down. And we're comparing here two rocks, one that has high hydrogen index and one that has low hydrogen index. The high hydrogen index one would be akin to a type two source rock. And we know that most unconventionals that our commercial are rich in type two, oil from kerogen.

And what's going to happen is by having just about 20% of that kerogen transformed to oil, you are already starting to experience an incrementing expulsion efficiency, much more so than it happens with type three sources, which in general produce more-- they do produce some amount of oil and gas, of course, because they're gas prone, but they retain whatever oil they might generate within the rock on expulsion is mostly going to be of gas out type three sources.

But not everything is the organics. You also have to think about the rock matrix. The example on the left side shows expelled oil yield going up and temperature increasing towards the right. What you're seeing here is a very nice comparison between expulsion as measured from kerogen isolates versus directly from the shale. So this is work by Lewan et al. from 2014. And what they did is they took the clay and hardened shale, and they heated it up using hydropyrolysis. And they measured the amount of oil expelled.

Then they took a kerogen isolate and they did a similar heating and measured how much oil they could get out of it. What you see is very significant reduction in the amount of expelled hydrocarbons when you compare the whole rock versus the isolated kerogen. Expulsion is much more efficient if you don't have the rock matrix to deal with, which would be anticipated. In this example, the difference is about 88%. So why do I mention this? For a couple of reasons.

First one, to stress the fact that the rock matrix may defer and may cause changes between one type of facies and another, even within the same unit. And also I should say smectites and clays are quite important in this type of process. But also to stress the fact that when you are trying to establish expulsion efficiency, you need to check whether the values you are getting from laboratory experiments are related to kerogen isolates or to the entire rock because there will be a difference right there. And you might be looking at something more akin to primary migration rather than full blown expulsion, if you isolate the kerogen.

What other influences are there in terms of expulsion? The source rock contact area. This is something that is actually quite important to consider in the context of unconventionals. If you recall the slide I was showing at the beginning, we have different types of unconventional plays. In a massive source reservoir, you are going to have this thick source. And it's going to have much less contact between the shale and the outside carrier zones. So you have a lower contact area.

But if you think about Wolfcamp, one of those interlayered shale reservoir couplets, you will have a more higher scenario, where there is a lot more contact area between the source and the reservoir, which facilitates expulsion. That is the reason I mentioned that Wolfcamp doesn't have the highest TOC levels but it has a very nice expulsion efficiency, which might help balance that out. So what we're seeing here is expulsion efficiency being favored by the increased contact between the source and the carrier beds, exactly function of lithostratigraphy.

And you can see an increment as you have more of the layers in the expulsion efficiency. Thickness ties back to the example of the massive source stressor boards. You have low contact area and you have a lot of thickness of rock to go through before you get to the carrier zones. So expulsion efficiency is going to be favored by proximity to the carrier rock. And what you will see in this type of shale systems, is that as you approach the little boundaries, you're going to see an increase in expulsion, a decrease in retention.

So if you see that plot, the cartoon on the right hand side, what is showing is lower retention towards the edges of the source and higher rotation towards the center. This has been normalized to TOC to account for differences in regions. Capillary forces are going to favor that oil movement into the higher porosity interval. That's why we see this drainage from the edges. And if you are thinking about producing from a particular massive source reservoir, you might consider that, as you go into the source, you have higher chances of finding a larger resource accumulation.

Of course, there is going to be also other things to consider, such as the variability of the richness, which in the case of Marcellus results, with a high concentration of a produce in the lower Marcellus because it's so much more organic ratio. So we were talking about expulsion. And now I'm going to explain to you what is the connection between expulsion and porosity. If you think about it, when you are expelling hydrocarbons, some of the hydrocarbons that leave, would leave behind some space.

Some of the hydrocarbons that stays will have to be stored somewhere. So there is definitely a connection between the spaces in the rock, the non-solid portions of the rock that provide the space for hydrocarbon storage and those pores, that's the porosity. If you look at the plot on the left hand side, you can see very small to larger pores as you go from left to right. In the space of unconventionals, we are dealing with pore sizes that are usually below the 62.5 micrometer range. An oil droplet can have a diameter of about 500 nanometers.

When we deal with nano pores, we can talk about pores very, very small, significantly less than what you see the oil droplet size to be. And you can store gas in those nano pores. But there is certain limits to how much oil you can store in the very tiny pores that are usually hosted by organic matter, because of the size of the oil droplets. So producible oil in unconventional plays is usually associated with pores of more than 200 nanometers.

And an example is the Eagle Ford, where the pore size is usually more than 250 in terms what is involved with producible oil. You might have oil in smaller pores, but it's difficult to get it out because the pore throats are going to limit the flow out of them. So what are the types of pores that we deal with in tight reservoirs? There are different types of pores. We have interparticle pores, intraparticle pores, and organic matter pores.

Interparticle pores are pores between non-organic matter particles, controlled by compaction. The Pearsall shale, for example, is dominated by interparticle pores. There are other type of plays where you also will see a dominance of that pore type. There are intraparticle pores, which are pores within non-organic matter particles that are controlled by chemical diogenesis. A good example of a shale dominated by this is the Bossier shale.

But there is also a number of pores that are organic in nature. These are pores that are hosted by organic particle, such as kerogen, bitumen, and/or pyrobitumen. Pores in the organic matter are what we call organic pores, the Barnett shale, the Marcellus shale, the Duvernay all seem to have a predominance of organic matter pores. That said, different shales are dominated by different pore types. But the dominance of one pore type does not preclude presence of other types.

So we can have a mixed pore network and that happens in many cases. And in fact, through the history of one given unit, the relative importance of one pore type versus the other will vary. We have seen that organic porosity may account for up to 30% of the kerogen volume at high maturity levels. So again, depending on what you're prospecting for, understanding porosity and understanding organic porosity can be quite important to assess the resource that you're looking for.

Not only does porosity seem to increase or develop with higher maturity, but there are other components to that story. And because of that, understanding organic porosity has been something that practitioners have been trying to do for a number of years. And there is a very large range of references in the open literature that share insight into this. So I will try to give you a brief overview of what are those key things that affect organic porosity.

But before I do that, let's just describe clearly what I mean by kerogen, bitumen, and pyrobitumen. So kerogen is the insoluble organic matter that's preserved in sedimentary rocks. Kerogen is derived from the breakdown and diogenesis of plant and animal matter. It is capable, as we well know, of generating oil and gas. And it displays alignment with the mineral grains because it's in situ. So as the sediments are being accumulated, the kerogen organic matter is settling waste and transforming into kerogen as maturation progresses. And then oil and gas.

Kerogen macerals are what make kerogen. The macerals in kerogen-- think about them as the minerals that form a rock. So kerogen macerals have distinct morphological and structural features that are inherited from the original organic matter. For example, vitrinite, which is a very common type three kerogen, tends to contain pores in it that are inherited from the original plants that generated the vitrinite. And nanoporosity in the space of 2 nanometers or so is quite common in vitrinite particles and has been reported.

So that is an amount of organic porosity that is already there before maturation took place. The images that you're seeing here are a beautiful picture from the USGS that show different types of macerals and how their structures and their way how they are formed are different. You can see different distribution pores in the different types of macerals. Bitumen is the fraction of organic matter in sedimentary rock that is soluble in organic solvents. Now, this is a very chemical definition. This is how we geochemists define bitumen.

It is a mobilized product because once you generate it, it can move. It's not in situ. It's not like kerogen that was deposited with the rock. It formed after. And so as such, it's going to be filling the spaces in and around crystal overgrowth, within fossil voids. It can develop shrinkage cracks due to devolatilization, like in the plot on the right-hand side. That image is an SEL image that is showing bitumen accumulating. And you can see a shrinkage crack. It is happening as volatile material is being removed as the function of maturity. It has, bitumen, greater potential for interconnectivity than kerogen.

Why? Because as you generate oil, as I described before, those oil droplets would start connecting to each other. So if you think about an interconnected network of oil droplets through that is allowing that flow of hydrocarbons, then when you make that into solid bitumen and start forming pores in it, there is greater chance that there is connection between them that will facilitate flow of things through once they act as starter locations. It may be bitumen present as a liquid or as a solid.

That solid bitumen is the main form of bitumen at the peak of oil and gas generation. And what happens is that over time, as maturity continues to increase, solid bitumen becomes pyrobitumen, which is what remains of the thermal cracking of that oil or bitumen and is mostly insoluble. It has limited solubility in carbon disulfide. And it can be confused because of that, with kerogen, if you are analyzing it optically without considering the textural evidence in the sample.

So one of the ways to try to better assess whether you are dealing with kerogen or with all different forms of bitumen, is looking for evidences of flow and evidences of contacts between the grains that show that that was not something that was deposited with, but it actually had some movement in it. In the picture on the right hand side, we're looking at the Tuscaloosa formation and pyrobitumen is filling in spaces. And you can see the authigenic calcite lining those pores.

Now, once you have established that you're going to be looking at organic pores, one of the things that practitioners did was to try to establish the forms of organic pores because they might tell us something about the formation processes. So that morphology can be tied to formation processes, which in turn can help us understand what has affected the rock and have a better understanding of the system we're interested in.

The three main organic pore textures that have been identified are bubbly, fracture or cracked based pores, and spongy pores. The bubbly pores are common in the oil window. And as you can see on the left hand side of the slide, they form basically little bubbles in the organic matter. And those are formed by a solution of gas during thermal cracking. However, they could also be formed by possible artifacts of water droplets bound by capillary forces and surface tension.

Fracture or crack-based pores are linked to devolatilization of solid bitumen or fracturing associated with volume changes during generation. If you recall, I mentioned earlier in the talk how the process of oil expulsion can result in fracturing of the samples. If you think about that, as you devolatilize with higher maturity, as you move volumes of hydrocarbons out, then you're going to have some of that fracturing happening. And it can also affect the organics and result in fractures in the organics.

And the spongy pores are more common in condensate and gas window range maturities. And they are associated with gas generation and evacuation. If you'll look at the spongy material on the right hand side of the plot, you can see it looks indeed like a sponge. And if you can imagine, lots of little gas bubbles coming out of the organics at higher maturity will result in a texture like that. But you can not expect a sample or a particular unit to have only one type of pore, even at the same maturity level because there is lots of variability in the distribution of the pores within the rock that is linked to changes or heterogeneities in the structural fabric of the rock, in differential exposure to compaction.

There might be differences in nucleation sites that allowed the organics to form one way or the other. And the macerals, the macerals vary. So a view in a rock, you'll have more than one maceral type. And the development of pores will also be affected by the maceral in which the pores are being developed. So in this case, we're looking at two pictures from the Kimmeridge shale at the same maturity level, same sample even, and you can see some more spongy pores develop on the left side, and then on the right hand side you have maceral-- intramaceral variability with parts of the macerals showing this bubbly pore types and some showing very little, if any, porosity.

So what controls porosity and how does permeability come into play? Burial and sedimentation overburden can result in a reduction of initial porosity. As you can imagine, as you are compacting the rock, you're going to see a decrease in porosity. But what happens to pores in the organics and to nano pores particularly? Well, nano pores are very less influenced by compaction and overburden because how small they are. Kerogen particles might be compacted and be affected.

But at the same time, kerogen will have some porosity of its own originally before any maturation happened. So you might start with porosity that is going to be reduced in the kerogen with compaction, but depending on the size of the pores, it might or might not be as influential. The original kerogen would expect to have limited connectivity because they are more associated with the original texture of the organic matter and not with processes associated with oil generation.

So the organic porosity in the immature rocks is likely inherited from the original organic precursors. Now we will look at the plot on the right hand side. This is from Mastalerz et al in 2013. And in this plot, they were showing how the pore volume was increasing towards the right with maturity downwards. And you can see how, at the compaction level, they are showing a slight increment in the nanopore range. But in the two to 50 nanometer range, you were seeing a loss of some of that porosity with increasing compaction.

This is for an example in Devonian shales. As the maturity progresses, organic porosity will change. And what we have seen from this work I showed you on the right but also from multiple other publications, is that that change is non-monotonic. So some of the pores are being created but some are being destroyed through burial. So if we look at the primary cracking space, that's the moment when your kerogens start breaking down to oil, we see an increment in pores.

Because you are seeing that change of kerogen to oil and gas in some spaces are being created. The nanopores will seem to increase in the main oil window into the early gas window and then disappear at the dry gas window, to then reappear again at very high maturity levels. So it's a fluctuating process. There is higher potential for interconnected porosity when we get into that secondary organic matter space, because the bitumen may form continuous stringers, which facilitate formation of permeable flow paths.

So if you see the plot on the right, you can see those changes reported by those authors that more or less describe what I said, although there are other observations by other authors that might contradict these, which are showing generation of these pores and then start destroying them as the bitumen starts filling the pores that were created during that initial boost of generation. So you generate, then your products start plugging the pores that were created.

And at some point, as you start cracking those products, then you start creating continuous spaces for storage. As I was saying before, maturity is an important control on organic matter porosity. In fact, I will say it is one of the most well-documented aspects that influence organic porosity. However, there is other things that also influence it in addition to maturity, the type of organic matter, and the richness of the rock are also critical.

On the left hand side plot that you observe here, we are seeing how, as maturity is increasing from immature on the top towards more mature on the lower level plots, you can see that those droplets of oil are going to start getting connected-- well, above you really are dealing with kerogen. And then as generation starts, they are getting connected. And that is going to allow that interconnected network that I was talking about before. But if you look at the right hand side, you have low TOC.

So what you're going to have there is that even though maturity is progressing, you don't get that connection happening between the oil droplets. So once porosity is developed in the organics, you will have two things happening here with that low TOC. One is you will have less organics to have pores. But also, the connectivity between those pores will be much more limited because there is not that network established, not in the kerogen, not at the bitumen level, to facilitate the flow.

Specific maceral types are also going to be affecting these because some types of macerals are more conducive to organic porosity development during maturation. For example, the type one kerogen is going to be 40 times more prone than type three kerogen to develop organic pores. And some porosity will be inherited. So yes, you could have some porosity, let's say, on type three kerogen. But over the maturation space, you might see that to become much less relevant and much more so in type 1 and type 2 kerogen, so oil-prone sources.

At high maturity levels, the original organic matter type will lose its relevance, really, because most of the porosity will develop in association with the secondary cracking of hydrocarbons. So porosity migrated hydrocarbons is going to mimic that 3D distribution of the original pore network, providing greater connectivity. I would say that, as a whole, reports show that organic porosity will be maximizing high TOC rocks if they are oil prone and at high maturity levels. So you having a combo of that will increase your chances of having a robust organic pore network.

But it is not just the pores. As I said, the network matters. And this plot from Curtris et al., 2012, shows how for a small small cube-- this is actually a 5 micrometer side cube, you can see that you can have kerogen distributed through the rock. There will be certain pore network associated with that, but connected, not all of it. So it is not the same and that's why we are bringing back and forth this concept.

And there is-- and I said this before but let's stress it out a bit more-- a clear connection between expulsion efficiency and organic porosity. Expulsion efficiency could influence the evolution of pores in organic matter. Authors have reported how at maturity levels between 1.2 and 2.4, in low expulsion efficiency shales you will have a higher increment in organic porosity, mostly bitumen porosity, evolve through that maturity range. While the high expulsion efficiency shales will experience lower porosity development.

So if you think about it, all things the same, same kerogen type, same richness level, even, if you'd have a shale that is interlayered with lots of different intervals, versus one that is more that massive shale that is contained within the thicker unit, you might have higher organic porosity develop in that shale to have the lower expulsion efficiency because you're going to have more of that interconnected network and more of the bitumen to begin with to provide the spaces for those pores.

As you increase maturity to a very high range of 2.4 to 4.5, so well into the dry gas window, again, the low expulsion efficiency shales would experience a slowdown in organic porosity development. So you're seeing less pores being formed. But there's still pores being formed. And the organic porosity in a high expulsion efficiency system will decrease. You will actually start losing those pores. So it's not only all the parameters I described, but also how efficient is my system at expelling the hydrocarbons, will have also an impact on the pores that will be developed in the organics.

Now granted, some of this will also be the result of mechanical properties, rock fabric evolving, for instance, from flexible to brittle, and other things of the sort. So I'm not proposing that this is the only thing controlling organic porosity but these are some key parameters. So far, we discussed expulsion, porosity, things that affect them, why we care, how they interact to each other. And one of the things that we have to wonder is, how do we learn this?

So one of the things, of course, that we do as scientists is we take samples. We study them. That's how we're getting the data and those beautiful pictures that I showed before of different textures and organic pores and all that. So we do have to question whether the fact that we're observing the samples is somehow affecting them. And we did a little study that I'm going to share with you. I'll say, though, before I enter into this, that of course we know that taking samples from the ground by itself is changing the samples, you are going to depressurize them.

It's possible that some devolatilization will happen to bitumen as the samples are being taken of the ground. Fracturing might happen, micro fracturing might happen. So we do as best as we can to minimize the effect of our handling of the samples to hopefully get samples out as representative of the natural system as possible. One of the things we were doing internally was trying to put together a set of samples spanning a range of maturity.

So to do that, we have immature samples and we artificially mature them using hydropyrolysis over a range of maturity. And then we looked at the samples we'd run a series of age or chemical measurements, we run different studies. We'll look at them under the organic petrography microscope. We did SEM work and things to assess porosity. That was one of the aspects of that study. And from it we learned certain things.

So we knew from published studies, of course, the potential for artifact development when the samples are handled under the ion milling or SEM. But we also had people who are very accomplished at what they do trying to minimize that and handling the samples in the most efficient way. So we were a bit surprised by what we learned here. We were trying to get porosity evaluated on samples, and then tried to determine precisely what maceral those pores were happening on.

So we had two plugs here in this example, original-- in plug one, the original refers to the original sample as it was before any artificial maturation. It had a maturity of 0.45% vitrinite reflectance. And the second plug was actually matured to 1.53% vitrinite reflectance. So you see in the first line on the first plug, it has a distribution of macerals that shows the rock to be oil prone. It had no solid bitumen present and quite a bit of fluorescent amorphous organic matter.

And the second plug, it was already in the condensate to wet gas window. It had 15% of solid bitumen in it and it was no longer oil prone. When the samples were taken and prepared for observation, they were ion milled, and they looked under the SEM. The maturity of the second line in the plug one table there shows a maturity of 1.16% vitrinite reflectance. That is what the organic petrographer measured after the sample was looked under the SEM and brought back to the petrography lab.

The reason we did that is we were actually trying to map the macerals and observe the pores and then say on what macerals those pores were being developed. So we brought the sample back to the petrographer. She did an assessment of it. And it turned out that the maturity was much higher than what it was supposed to be. And also, we were puzzled by that 70% of solid bitumen present in the sample where we had no solid bitumen before. Significant change in the sample. It looked like a very different sample.

So we questioned, could that've been a mix up in the lab. Maybe we just sent the wrong sample back and forth. Stuff happens, right? But actually, after the sample was split and reprocessed by the organic petrographer, we came back to values that were very similar to those of the original sample. So really something happened at that surface that was ion milled and observed under the SEM. An argument is that you could be altering the vitrinite reflectance by the fact that you are super polishing a surface and that can result in some changes in that.

But that wouldn't explain the changes in the maceral distribution and the development of that solid bitumen layer. Of course, we do anticipate this is completely at the surface level but it's something that, if you are trying to learn porosity, based on your observations under the SEM, you have to be aware this could be happening and you could be looking at artifacts that are not representative of the natural system.

For the second plug, this was a plug at a higher maturity level. It had seen thermal maturity already. So it's less susceptible to be affected by heating during the polishing process or by the SEM beam. And you can see that because there were changes as well on the surface of that sample. And we in fact, reduced the gas proneness of the rock and increased the amount of solid bitumen, but to a lesser extent than what we observed in the less mature sample.

The bottom line here, though, is we observe changes. And the changes were at that surface. Because in the case of the second plug, for example, when we re-polished that surface and measure again, the properties went back to what they were originally, or very close to it. We are not alone in observing these. Sanei and Ardakani 2016 actually showed significant changes to organic matter texture and thermal maturity following ion milling. In fact, they suggest that the observed changes were the result of overheating of the sample surface during the milling. And they proposed that samples within the main to wet gas maturity windows, might suffer devolatilization of light organic components due to the induced thermal maturation.

So if you look at the plots, you can see how they had samples originally with the reflectance of 0.52% that went as high as 2% or so when using focused ion milling, or as high as 0.74% when using coarse beam ion milling. So depending on the type of ion milling you do, that also will change how much the samples are affected. There are ways to control these. You can keep the samples cooled using liquid nitrogen. There are other things that can be done.

But you should be aware that artifacts might happen and so you have to be very careful not to over-interpret the data that you are looking at. And of course when we're looking at nanoporosity or small pores, it's easy to think that changes could, in fact, occur during these observations because at that scale things can be very susceptible, especially if we are living in a world that is focusing now more and more on oil plays in unconventionals which are at the maturity where changes to temperature can impact more the organics than when you were working in place that were more in the gas space, where maturity had progressed enough and the samples were less susceptible to this type of effect.

So now that we get to this stage of the talk, I'm just going to summarize some of the key things that I've been talking about. And hopefully you will see the connection between the entire story that I've been telling you. Proper assessment of source potential in general does require-- and this is my disclaimer, not just looking at organic attributes. I know that very well. There is also many other aspects that need to be considered. But when you're looking at the sources, you have to really study the organics because that is ultimately what is going to generate those hydrocarbons that you are looking for.

In unconventional systems, we have different types of unconventionals which would have different expulsion and retention efficiencies which would require different development plans to get these things into production in an efficient way. So if we go from lower to higher expulsion efficiency, we have the massive source reservoirs-- think Barnett, Marcellus, Duvernay-- which have an overall efficiency that is dependent on thickness. And their generation potential is closely tied, of course, to TOC.

The sandish reservoirs-- here we're thinking something like the Bakken shale-- are capable of developing a supercharged system. Migration can happen. You can actually have focused migration in some cases. But it's considered unconventional because the reservoir properties, because they had such tight reservoirs where you're going to be producing from. And then you have the interbedded source reservoir couplets, such as the Wolfcamp, which maximize the charge per unit of TOC and results in a higher expulsion efficiency. You are losing those hydrocarbons from the rock at a much more efficient way from the source, and they are getting right there next to the source interval into the reservoir facies where we can produce them much more efficiently because we are looking at slightly better porosity conditions because you're looking at the tight sand rather than a shale for producing.

Expulsion efficiency might influence the evolution of porosity in organic matter. So it's actually a link between the two. Not only because as the hydrocarbons are leaving the rock, they're leaving the spaces behind, but because the hydrocarbons that stay in the rock are occupying the spaces. And also depending on the level of maturity, that influence will vary. Total shale porosity, as I have been describing, evolves in a non-linear manner. It is affected by maturity. It changes with depth.

But porosity can be destroyed and created through the maturity windows. Organic porosity may represent a substantial portion of the shale's total porosity. And it becomes particularly relevant when you are in a condensate to gas time frame because of the size of the particles that can be stored within those pores. The preservation of the organic pores is at least partially dependent upon the nature of the rock framework. So of course, we have to take this into consideration.

If you think, for instance, on the Kimmeridge shale, it has been well reported that it's more ductile and destruction can happen versus other plays where maybe you have more biogenic silica that helps preserve some of that structure. The impact of organic porosity in liquid plays may be limited. Why? Because of the size of the oil droplets versus the size of the organic pores.

And particularly because the pore throats may restrict the flow of liquid hydrocarbons. Thermal maturity, organic thickness, and kerogen composition are the most commonly cited influences behind organic porosity development during maturation, by far. If you look at a large range of papers and publications, you will notice these are the key drivers that everybody mentions. And they interact in a non-linear, non-monotonic fashion. So in some cases, in some plays, the importance of TOC is magnified because you can see quite striking differences in terms of porosity when you have a TOC within a certain range.

But maturity is definitely one of these aspects that clearly ties to the development and destruction of organic pores. Organic porosity in mature rocks is more likely inherited from the regional organic matter. Not all organic porosity is going to contribute equally to matrix permeability. The nature of the matrix porosity and the type of the organic matter are critical controls. And in all you do and all the observations you do, you have to remember that if you are learning these from samples and from observations, textural artifacts might be introduced during the sample acquisition, handling, or by simply looking at the samples.

And so in those cases, you have to be careful and you have to know how things were prepared and what are you looking at and what are the chances and acknowledge that as part of your workflow. I have some references here. And I would like to thank my co-author Barry Katz and Chevron Corporation for their permission to present this work. And again, AAPG for having me here today. And I am looking forward to your questions. Thank you.

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