Lesson Contents

01. Learning Objectives02. Flow Regimes in Unconventional Reservoirs03. How Does Exposed Surface Area Influence Production Rate04. How Does Exposed Surface Area Influence Production Rate05. Compartmentalization - Multi-stage Fracturing06. Multi-Stage Fractured Horizontal vs Vertical Fractured Well -- Observed Performance07. Multi-Stage Fractured Horizontal Observed Performance08. Simulated Reservoir Volume (SRV) Concept09. Illustration of SRV Concept Using Simulated Production10. Surface Area and SRV11. Surface Area and SRV (cont'd.)12. Impact of Increased Surface Area on Performance and Reserves13. Impact of Increased SRV on Performance and Reserves14. Concept of Production-Measured Permeability (Effective Permeability)15. Effective Permeability Around a Horizontal Well16. Effective Permeability Around a Horizontal Well (cont'd.)17. Effective Permeability Around a Horizontal Well (cont'd.)18. Effective Permeability Around a Hydraulic Fracture The learning objectives for this session are to talk about some of the fundamental production drivers in unconventionals. Namely surface area and stimulated reservoir volume (SRV). We're gonna start by reviewing the flow regimes that occur in conventional versus unconventionals. And then we're going to get into a discussion specifically about how surface area can compensate for low permeability. And it has to do this in unconventionals, that's the only way that these reservoirs can be economic. We're going to talk about how completion compartmentalization can efficiently allow us to create an enormous effective surface area in a horizontal well, something that simply can't be done in a vertical well. And so this is part of the reason why almost all wells that are drilled in shales and tight reservoir rocks now are multi-stage horizontal wells. We're going to explain the concept of the stimulated reservoir volume which is obviously a huge driver of well performance in unconventionals. And we're going to describe how surface area and SRV influence well performance and EUR. This is a critical component. Once we have a fundamental understanding of that, we'll be able to go forward and do some analysis which will be the next lesson. And then finally we're gonna talk about production measured or effective permeability as opposed to a permeability that you would measure in a laboratory. So there's some very clear differences between these two, and we want to talk about what those are.

So let's review the flow regimes first of all. As everybody should be fully aware now, when you're talking about conventional vertical wells even wells that are fractured, because usually the fractures will be small in comparison to the external reservoir boundaries, you're typically dealing with radial flow. So this is where we have a flow path that's convergent on the well, the transport medium is the pore space; the connected pore space. When we get into unconventionals we're almost always going to see linear flow. Not 100% of the time but it's going to be a dominant flow regime. We're going to see linear flow from the formation into the fracture. That transport medium is going to be the fractures, we get very little flow occurring in the matrix because we're talking about extremely tight rock, and there's a very high contrast between matrix and fracture connectivity. So we commonly call these dual porosity models but linear flow is going to be an overriding characteristic of these systems.

Okay what I'd like to do is a little bit of a thought experiment and we're going to show how exposed surface area can influence production rate. So on the left hand side we have our standard radial system, conventional system. And this equation here which you've seen before is the steady state inflow equation for a radial system. So this is the steady state production rate, stabilized production rate that we would expect given a pressure difference of average reservoir pressure down to flowing pressure and over here on the right hand side we have a linear flow system. So this could be thought of as a horizontal well or a vertical fracture or a multi-frac'd horizontal well. And the equation that describes the flow into that bounded linear system looks like this. And so what I would like to do in the thought experiment is to say, the radial system as a conventional reservoir is going to be 1 millidarcy (mD) of permeability and the linear system is going to be 1000 times lower than that. And we want to ensure that these things have the same flow rate. So what do we need to do in terms of extending the available surface area so that these two systems will be equivalent and have the same flow rate? And that's a good way of thinking about how in unconventionals we can design a well completion that will be economic. It will allow us to produce the same rate that an equivalent 1 mD rock in a conventional reservoir would allow us to produce.

So to equate these two things we're just looking at these two components of the equation for flow rate. And because the linear flow system is going to be a 1,000 times lower permeability we're going to have that 1,000 coming in there. And for a drainage area 160 acres, that's a quarter section, we're going to find out what that looks like for a radial system and what that looks like for a linear system. So for a radial system we have a radius of 1489 ft. And for a linear system we have a total square footage of 1.7 and change million square feet. So we're making equivalent drainage sizes in terms of the area. But of course the shape is going to be entirely different between these two. So the first thing that we've figured out by equating these two terms is that the ratio of X to Y, in other words the ratio of the length of the linear system to the width of the linear system is almost 84 times. So that's going to mean that our X distance is about 12,000 ft in our Y distance is about 144 ft.

So let's take a look at what that looks like as a linear system. If we were trying to design this as a single vertical fracture we would have a 12,000 ft half-length and so more than 24,000 ft in total distance of this fracture. That is highly impractical. Even if you could design something like that, it would be impractical to develop your field that way. And most experts would agree that you probably couldn't make an effective fracture/producing fracture that large or that long. So what we're gonna do is we're going to break that up into components and use a horizontal well that's less length and compartmentalize it. So create the same total fracture area using for example a 10,000 ft lateral with 18 fractures and xfs of 660 ft, that's one way to do it. There could be other solutions that could accomplish the same thing. This will give us the equivalent stabilized rate. So this explains in a nutshell how compartmentalization or multi-stage fracturing has allowed us to take somewhat of an impractical field development scenario and turn it into something that's much more practical and doable. And so this is why the industry has been successful in exploiting these resources is because we're creating these compartmentalized solutions.

Here's an example of real well performance and so what you're looking at here is a multi staged horizontal well versus a single vertical fractured well. And their behaviors, on the log log plot shown over here, couldn't be more different. So if we look at first of all the multi-stage horizontal well what we see is after about18
days we transition from linear flow; b = 2 into something that looks like boundary dominated flow very quickly. So that's our horizontal well. When we look at the vertical well with one single fracture, we have 200 months which is more than just about 17 years of production where we don't see any evidence of boundaries. So if you think about this in terms of efficiency, the horizontal well is draining its area much more efficiently than the vertical well is. You're getting those resources out a lot faster. So these are real examples of horizontal versus vertical wells. It just shows the value of compartmentalization and how it's able to accelerate that resource recovery and create production scenarios that are much more economic.

Here's another example to further illustrate this point. What you're looking at here are normalized rate responses on a log-log plot for 50 Eagleford gas condensate wells. And each one of these has about 2-3 years of production. And so the interesting thing to consider here is that these all start with a half slope so you show your early linear flow behavior and they all transition into something that's very close to boundary dominated flow; a slope of 1. It looks like boundary dominating flow, but the interesting thing about this is you might think that that boundary dominating flow would be the extents of the reservoir. In fact it is not, in almost all of these cases, it's an area or drainage volume that's significantly smaller than the available drainage volume due to well spacing. This is a very important observation because what it tells us is that we're not draining the inter well spacing in a lot of these wells. Especially in these 50 that we're looking at here. These drainage volumes are very small and so you're really only draining something that's potentially very close to that wellbore.

So we come up with this idea of the stimulated reservoir volume concept and that's largely come about as a result of observation in the field. There are many of many such examples of these wells that drain limited areas. So the stimulated reservoir volume refers to the hydrocarbon pore volume that is in immediate contact with the effective fractures. And that's typically going to be applicable to a shale oil or gas. A very tight rock, nanodarcy permeability type rock. It's a convenient concept for RTA because it simplifies the production analysis problem significantly. So this shows you some examples. This is what an SRV might look like in reality, the way we typically are going to model them is as a bounded linear flow system such as what you see on the right hand side. So here's an example using a simulation we can illustrate the concept of SRV very clearly using the simulation. We start with a nanodarcy rock such as a shale. This one happens to be 50 nD.

And what you're seeing here is the simulation of production response from two distinct reservoirs. One in which the completion exists in a semi-infinite or bounded reservoir but it's but it's much larger than that than the stimulated reservoir volume. And the other one where the reservoir boundaries coincide precisely with the stimulated reservoir volume. And what this teaches us is that looking at the timescale here, this is more than 5 years, they're almost identical. There's very little difference between the case where the completion exists in a larger reservoir and where it exists in a limited reservoir. So the contribution of oil and gas outside the immediate fractured region is negligible in many of these cases. And that's why the stimulated reservoir volume concept works.

We talked about stimulated reservoir volume. I want to tie together now surface area and stimulated reservoir volume. So what you're looking at here, you can consider this sort of a general rock volume that has some fractures in it. And the stimulated reservoir volume can be thought of as the bulk volume multiplied by the hydrocarbon filled porosity at standard conditions. The surface area would be the total connected fracture area within that SRV. Those in many cases can be completely independent parameters. If we're looking at just geology in general, you could have stimulated volume that has sparse fractures or he could have stimulated volume that's got much much more dense fractures, and the orientation of those fractures varies as well. So generally speaking there's no obvious relationship between the stimulated reservoir volume and the surface area.

However when we talk about a compartmentalized completion where we can control where we're placing the fractures, we can infer usually with pretty good reliability a relationship between the stimulated reservoir volume and the total connected surface area. So our assumption that we're going to have to make to do this to make this work is that the fractures are planar and parallel and they have uniform size and distribution. So we're talking about a, I sometimes call this a shoe box model, it's shaped like a box it has a length of L (horizontal well length) a height of H and then a stimulated reservoir width that's gonna be double the fracture half-length (xf). Because we're assuming that those fractures are penetrating perpendicularly from the horizontal well into the reservoir.

So what I what I'd like to show here is the impact of surface area on well performance and reserves. So what you're looking at here is a plot of production rate versus cumulative production. And we have the same reservoir rock, this is just simulated data, but we're gonna look at this for 12 stages, 24 stages, 48 stages and 96 stages. And if you're paying attention the stage count is doubling each time, but the stimulated reservoir volume is staying constant. So what we're showing here is what happens when you keep SRV constant but you increase your total connected surface area. In other words you're increasing your compartmentalization, you're increasing the amount of fracturing that's occurring within that stimulated reservoir volume. What happens is very clear when you look at it, your overall reserve value is not going to change appreciably. All of these rate versus cums are converging, and this is only a 5 year forecast, are converging at the same number at about 130,000 barrels. So the addition of more surface area on its own doesn't add reserves, all it does is it adds stabilized productivity. So it can increase your production rate but it doesn't really affect your reserve recovery.

If we look at this in a different way, and now what we want to do is keep the surface area the same but increase the SRV, the exact opposite thing happens. So in this case what we're doing to increase the SRV and keep the surface area the same is we're varying the size of each treatment. So we have very short fracs with 96 stages that has the same surface area as half the number of stages but double the frac length and so on and so on. So in this case what we see is the 12 stage scenario actually is going to have the best reserve recovery because it's got the largest SRV. So we've done the exact opposite here, we've preserved total surface area, but we've made the SRV double in size each time. Now that's one way to make SRV get larger. The other way to make SRV increase in size is of course to extend the horizontal well link that would be the other way to do this. So this is just one possible scenario. I could have the same treatment size and same number of stages but make the horizontal well longer, that same result would be expected under those conditions. So if you have the same number of stages the same treatment but extend your horizontal well length, what should happen is something very similar to this. So what do we see here. Well we see because the surface area is held constant, total production rate of all of these scenarios is identical at the beginning and the EURs of each case are going to change. So SRV is directly correlated with EUR but does not impact production rate unless the surface area is also increased. So if surface area and SRV are increased then you're going to have an impact on production rate and reserves and recovery. So the way these two components impact performance now is very clear.Nobakht M., Mattar L., Moghadam S. and Anderson D.M. 2010. Simplified Yet Rigorous Forecasting of Tight/Shale Gas Production in Linear Flow. SPE 133615 presented at the SPE Western Regional Meeting, Anaheim, California, 27-29 May.

What I want to do now is describe how we can relate surface area in a system to what we would call a production measured or effective permeability. This is a very useful parameter to use because a lot of times we don't know where all those fractures are. So here's an example where we have a connected fracture network. We might not know what that total surface area is. So what we're going to do is we're going to come up with an effective permeability. And to do that we define what's called a nominal area. And the nominal area is based on some known geometry of the system. For example the horizontal well length multiplied by h, that would be a nominal area. And the effective permeability is always going to be larger than the matrix permeability, assuming that your fracture system has somehow enhanced the productivity of the system. And it's always going to be less than the permeability fractures, so it's going to be somewhere in between. But it's a combination of fractures and matrix acting together. We can define the effective permeability using this relationship so the A√k comes out of the √t specialized analysis. If we normalize it with that nominal area, we can very quickly and easily calculate that effective permeability.

So let's do an example. An effective permeability around a horizontal well with known fractures. And we're gonna assume to make it easy that the fracture permeability is infinite. So if we have 12 fractures each 500 ft and half-length and a matrix permeability of 0.01 mD, and a 5,000 ft horizontal well length, we're gonna come up with an equivalent or an effective permeability. And we can do that using this definition that we looked at before. So as long as I know the number of stages, the fracture half-length and the matrix permeability I can come up with that effective permeability. In this case it's 0.0058 mD. That's roughly six times the matrix permeability.

So what we end up seeing here is when you have your surface area, and let's say you double your surface area, that results in a 2 to the power 2 increase in effective permeability. So because permeability always occurs under the square root sign, your linear increase in area results in a geometric increase in permeability based on that power sign there. So that's something to keep in mind. Area also impacts directly the production rate. A doubling in area will result in two times production rate. In this case I require four times the effective permeability to get that doubling in production rate. So the way permeability varies is different than the way surface area varies.

Here's the here's an example of an equivalent multi-frac system and effective permeability. So we have a multi-frac system with 12 fractures and we have a known matrix permeability here. We substitute in here the effective permeability that we calculated, and we have absolutely identical production flow rates. So effective permeability is a good functional model that allows us to create a model without having to make assumptions about how much surface area there is connected, we can use this effective permeability concept.

The other place where effective permeability becomes very useful is we can take that whole horizontal well and turn it on its side now. Instead of using as our nominal area the horizontal well length we're going to describe the region around each one of the fracture stages as an effective permeability. And that's something that we do very commonly in RTA of unconventionals. In fact we probably use this effective permeability even more so than the one describing it around a horizontal well. For the pure fact that we just simply do not know, when we're looking at this sort of geometry, we have no idea where these fractures are occurring. There's no way to measure there's no way to know how much surface area is being created proximal to the hydraulic fracturing when we're creating one of these stages. So the functional model is to basically represent that with an effective permeability. I mean do it exactly the same way, the only difference here is that the nominal area now is based on the area of that frac length not based on the nominal area of the entire horizontal well. And that's it.

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What is in here?

This lesson describes the influence of permeability and surface area in a fractured reservoir. Included are the concepts of compartmentalization, SRV and production-measured (effective) permeability. Also included are the impact of surface area and SRV on well performance and EUR.

Why should you care?

Permeability, surface area and SRV are key drivers of well performance. Understanding how each of these contributes to the production equation is critical to making good decisions around completion and field development optimization.