Fracing Horizontal Unconventional Wells

Let’s begin with a review. Fracturing in conventional wells is typically bi-wing with a preferred stress orientation perpendicular to the least principal stress. Because the reservoir has decent permeability, the fractures are typically contained and the local natural fracture network is barely engaged. Fracture half lengths are measured in hundreds of feet for the most part. The main fracture is typically wide with good proppant per square foot of area. The reservoir permeability to fracture permeability ratio is high but still less than one. The area of influence (AOI) of the fracture is measured in hundreds to potentially thousands of feet. When fracing a horizontal conventional well, the fractures can be spaced fairly far apart (say 500-1000’), and the reservoir is generally drained completely.

In unconventional wells, the permeability is just a fraction of what it is in conventional reservoirs leading to a massive change in how wells frac. Unconventional reservoirs typically have natural fractures on both the macro and micro scale. These fracture systems are generally engaged when a fracture treatment is placed on it. The fractures are generally smeared in an oval around the wellbore and engage with other fracs nearby. Microseismic and proppant tracer has confirmed this many times. Fracture half lengths are measured in tens of feet with 150’ being a good data point to shoot for. The reservoir permeability to fracture permeability ratio is very low. The AOI of the fracture is measured in inches to tens of feet. To drain the reservoir, many more frac jobs are needed with many being on the 150’ stage length side with 3 to 5 clusters per stage. Typical frac heights are 200 to 400’ exclusive of excellent frac barriers.   

There has also been much discussion on whether certain reservoirs have natural fractures (Haynesville comes to mind). Just because a core doesn’t see natural fractures doesn’t mean there aren’t any. The Haynesville exhibited a natural fracture signal (at 500’ stage length spacing) even though core suggested no natural fractures. This was mainly due to the lowering of frac pressure as the fracs proceeded from the toe to heel of the well. We can infer macro natural fractures in this case, and this was proven through microseismic and core later on.

We also see a signature akin to stress reorientation (see my Stress Reorientation article) as the fracs move from heel to toe. The azimuths of fracs change slightly as we move up the wellbore. This is not stress reorientation. Instead it is the phenomenon of imposed pressure redirecting the fracs. Pressure does not leak off in tight permeability networks like it does in more typical conventional reservoirs. The pressure can “pump itself up” and exceed the fracture pressure of the rock. All of this needs to be taken into account when fracing unconventional reservoir horizontal wells.

Next article will be a discussion of the infamous subject of proper spacing of wells.