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FRACTURE TIP EXTENSION - WHY SHALE DFITS PRODUCE UNUSUAL RESULTS

Diagnostic Fracture Injection Tests (DFIT) are a great way to gain some insight into how a formation will perform during a frac treatment. A DFIT will yield some crucial frac parameters, including formation breakdown pressure, treatment pressure, true reservoir pressure and fracture closure pressure. Typically DFITs are performed prior to a frac treatment in a new area and they are one of the few forms of well testing that are applicable to shale reservoirs.

The general concept of a DFIT is pretty simple: a small amount of fluid is pumped into the reservoir, just enough to breakdown the formation and propagate a small fracture. Then the pumps are shut down and and the well is shut in. The bottomhole pressure is then monitored to determine when the fractures have closed, using G-function plots.

As with most types of well testing, DFIT theory and procedures were developed at a time when all of the commercial reservoirs were conventional. This means that a lot of the assumptions that this theory was built on do not necessarily apply to unconventional reservoirs, such as shales. This results in some very unusual plots when analyzing a shale DFIT. One of the primary phenomena that causes these unusual plots is known as “fracture tip extension”.

Traditional DFIT theory makes several assumptions about fracture closure and leak-off. Two of the critical assumptions are:

1.       Fluid within the fracture leaks off slowly into the matrix

2.       The fracture closes uniformly and all fracture walls come to rest as the same time

These two assumptions are reasonable in conventional reservoirs where the matrix is permeable and the fracture geometry is simple. However, when we look at shale reservoirs it is easy to see how these assumptions may not apply.

First, shale reservoirs have an extremely low permeability, often on the order of micro or nano-darcies. Therefore, fluid cannot leak off into the matrix in any reasonable amount of time. This means that as the fracture closes, the fluid is leaking off somewhere else, most likely into the natural fractures.

Secondly, because most commercial shale reservoirs have a natural fracture system, the fracture geometry is much more complex. Often, the artificial fracture connects into a network of natural fractures. The creates a scenario in which you have a network of primary and secondary fractures. The primary fracture will always be oriented perpendicular to the minimum in-situ stress, however the natural fractures will likely be oriented in a different direction and at least some portion of the maximum in-situ stress will be pushing against these secondary fractures. This creates a scenario in which the secondary fractures will have a higher closure pressure than the primary fracture. As you can see, the second assumption that fractures close uniformly, does not apply.

So how does this relate to fracture tip extension?

When a DFIT is performed on a conventional reservoir, the fracture closure is identified by a “hump” in the G-function derivative plot. This hump will form a straight line as the fracture is closing and this straight line is used to identify the moment of fracture closure. In shale reservoirs, however, we often see two humps in the G-function plots, which likely represents both the secondary and primary facture closures. Furthermore, it is often the case that a clear straight line is never formed. So what causes this phenomenon?

Let’s go back to our assumption that fluid within the fracture leaks off into the matrix. We established that this assumption is not valid for extremely low-perm reservoirs such as shale. However, the fluid must leak off somewhere. We should expect the secondary fractures to close first due to their orientation against the maximum in-situ stress. As these fractures close, the fluid within the fracture is pushed out (like a sponge being squeezed) and at least some of that fluid probably flows back into the primary fracture. The rest of the fluid is pushed deeper into the natural fractures where the frac propagation did not reach. If this is the case, then that means that even after shut-in, the primary fracture continues to see fluid flow into it.

Now let’s consider the primary fracture. The matrix is extremely tight, such that it cannot accept any fluid from the fracture (at least not over the short period of time that we are talking about). So, as fluid is forced into this fracture with no way to leak off, it only has one place to go, which is to extend the fracture. Thus we have fracture tip extension.

Think about what this means. Traditional DFIT theory assumes that as soon as the well is shut in and fluid stops being pumped, that the fractures immediately stop propagating and begin to close. However, what we often see in shale reservoirs is that the primary fracture continues to grow even after shut-in.

This explains why we tend to see very unusual G-function plots in shale reservoirs. Understanding what causes these unusual plots helps us provide a more accurate and meaningful analysis. Fracture tip extension can play a significant role in a DFIT and it is important to consider this when analyzing a DFIT.

Do you need help with your next DFIT? Click here to contact FyreRok so we can begin helping you find the answers you are looking for.

If you want to learn more about fracture tip extension, there are some really great SPE papers in which this phenomenon is discussed. Here are some that I would recommend:

1.       “Holistic Fracture Diagnostics” – Barree, Barree, Craig (SPE-107877)

2.       “The Fracture-Compliance Method for Picking Closure Pressure from Diagnostic Fracture Injection Test” – McClure, Jung, Cramer, Sharma

3.       “DFIT Analysis and Simulations in Shale Formations: A Utica Case Study” – Hildebrand, Liang (SPE-196149-MS)

4.       “DFIT Analysis in Low Leakoff Formations: A Duvernay Case Study” – Zenganeh, MacKay, Clarkson, Jones (SPE-189826-MS)

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