Why care about treatment fluid recovery?

The low recovery of treatment fluid has always been a mystery in hydraulic fracturing operations. There are two facets of slow recovery that are of financial and operational interest to the industry. These are the low percentage of injected fluid that is recovered after the treatment, and the long unloading times. The recovery factor in many treatments is often less than 50% even after several months of production. The percentage is much lower in horizontal wells, often in the range of 10% to 20%. The question is all of the injected fluid not recovered, and why is the fluid return so slow, especially in light of the computations that show fractures closing shortly after we stop injection?

One of the mechanisms offered for slow and incomplete fluid recovery has been fluid leak-off into the formation. Depending on formation permeability, porosity, fluid viscosity and fracturing pressure, some of the injected fluid leaks into the formation during the treatment. The general expectation is that this fluid is gradually displaced back into the fracture by the reservoir fluid. However, this displacement may not be complete. If the formation water saturation in the vicinity of the fracture is very low then some of the water may be permanently retained by the formation and reduce the relative permeability to oil and gas. The percentage of fracturing fluid that is lost as leak-off is a strong function of fracture surface area and formation permeability. It can range from a few percents up to over 50% of total injected volume. In ultra tight gas reservoirs it is expected to be less than 25% due to very low formation permeability.

Figure 1. Different fracturing modes.

The dominant factor for low fracturing fluid recovery is the mechanics of fracture propagation and the types of fracture created. Three different mechanisms can cause fracturing of a formation1. These are tensile, sliding shear, and twisting shear. In the tensile mode the hydraulic fracture is created by tensile forces that cause separation of the two faces of the fracture (Figure 1a). The tensile force is created by fluid pressure inside the fracture that induces tremendous tensile stresses at the fracture tip which cause separation of the two faces of the fracture. Tensile fractures are the easiest to propagate in rocks. They grow perpendicular to the least in-situ principal stress and require the least amount of pressure for their extension. Without a mechanism to keep them open (such as proppant) they also can close very easily and quickly when the fluid pressure drops below the least in-situ principal stress after pumping is stopped. This is the dominant type of fracture created in all industrial treatments. Almost all early fracturing theories assumed that this is the only type of fracture created. The expectation of complete or very high fluid recovery is based on this mode of fracturing.

In the sliding shear mode, the fracture is created by sliding along the fracture plane (Figure 1b). In this mode the two faces of the fracture slide relative to each other. In the twisting shear mode the fracture is created by rotation of its two faces with respect to each other in the same plane (Figure 1c). Sliding shear and twisting shear types of fractures are created by shear forces. Both types of shear fractures require a higher pressure for their extension compared to tensile fractures. Because of the friction along the fracture face, these types of fractures do not close easily and in fact often resist closure. An industrial hydraulic fracture often includes fractures that are created by combinations of these forces (Figures. 1d and 1e). Such fractures are often created in response to planes of weakness (such as natural fractures) in the formation. Their effect is to locally divert the fracture into a different path and cause branching. They will have narrower widths compared with adjacent tensile fractures and can block the movement of proppant and divert the slurry elsewhere inside the fracture. An industrial hydraulic fracture can therefore include a large component of tensile fracturing together with randomly distributed shear fractures along its main path. The extent of shear fracturing depends on formation heterogeneity, and the extent of natural fracturing in the formation.

Figure 2. Shear fracturing keeping tensile fractures open.

As stated earlier, shear fractures do not close easily. In addition, they can also block closure of attached tensile fractures, which usually have narrower widths because of their smaller extent, and the restricting effect of the attached shear fractures (Figure 2). Shear fractures can also cause trapping of the proppant and formation of proppant packs at their vicinity2 (Figure 3). These proppant packs also prevent closure of the nearby fracture.

A hydraulic fracture growing under above conditions is called “off-balance.” The common characteristics of off-balance fractures are:
• Fracture growing in a narrow band while maintaining a gross orientation perpendicular to the least in situ principal stress (Figure 4);
• Many small and narrow branches;
• Larger surface area compared to a single tensile fracture (higher leak-off);
• Random fracture extension along the tips of the fracture and not always at points farthest from the well bore/perforations; and
• Random proppant distribution inside the fracture, including many proppant packs formed by restrictions caused by very narrow shear fractures.

The hydraulic fracture thus created has many very narrow tensile and shear branches which can trap the fracturing fluid and isolate it from the rest of the fracture. When the width of the branch fracture is sufficiently narrow (which is true for most of them) the capillary forces inside the tensile or shear fracture can prevent flow of the fluid and even keep it permanently trapped in place. The volume of immobile trapped fluid will depend on the extent of shear fracturing. Another important parameter in these situations is the formation texture. For very fine grained formations (such as many shales) the tensile and shear fractures will have smooth surfaces. Under the right conditions the two faces of some shear fractures may make sufficient contact to prevent fluid movement, while they also keep the adjacent tensile fractures open.

Figure 3. Proppant packs keeping tensile fractures open.

Yet another mechanism for trapping of the fracturing fluid is the proppant pack itself. Since the hydraulic fracture is kept open by the packs, the reservoir fluid tends to flow around the packs, instead of through them. This leaves part of the fracturing fluid trapped and immobile inside the packs. The flow pattern inside the fracture is highly dispersed due to its off-balance growth, and coalesces when it gets near the well bore. This results in low fluid velocities in most of the fracture except the near wellbore region.

The fracturing fluid often has a higher density than either oil or gas. This causes the mobile water to gradually displace to the bottom of the fracture. In low productivity reservoirs the local flow velocity of the formation fluid inside the off-balance fracture is often not sufficient to lift the fracturing fluid, causing the formation oil or gas to bubble through the water and move to the well bore, leaving the water trapped at fracture bottom. In this situation the best chance for water recovery is at the beginning of production while reservoir fluid is flowing at higher rates. If the flow velocity at this stage is not sufficient to lift the water, it is not likely to lift it afterwards when rates are lower.

From the above discussion, the various mechanisms that can account for fracturing fluid retention and low frac fluid recovery include:
• Fluid leak-off into the fracture faces. In formations with low water saturation or low reservoir pressure some of this fluid stays permanently trapped in the formation.
• Narrow fracture branches where fluid is retained by capillary forces.
• Shear fracture faces that are too close to each other to allow fracture closure. They can also prevent fluid flow due to capillary forces.
• Fluid trapped inside proppant packs that is not displaced by reservoir fluid.
• Fluid moving to the bottom of the fracture by gravity forces and not lifted by reservoir fluid due to low and dispersed local production rates.

Figure 4. Off-balance fracture growth.

Fracturing fluid recovery in horizontal wells with multiple fractures.
The three important differences in horizontal well fracturing are:
• By design, these fractures are more off-balance;
• Around half of the fracture is below the wellbore level (well assumed to be in the middle of the fracture); and
• Much lower reservoir permeability and flow rate inside each individual fracture.

The higher level of off-balance growth allows more fluid retention in fracture branches. Around half of the fracture volume is below the wellbore level and thus fluid could be retained in place by gravity.

The lower flow rate inside each fracture and the dispersed nature of flow because of higher off-balance growth create an environment not conducive to lifting of the frac fluid by reservoir fluid flow.

The combined effect of these parameters explain the much lower rate of fracturing fluid recovery from horizontal wells.

Effect of fluid retention on well productivity
Effect of fluid retention inside the fracture on well productivity depends on its cause. Retention of leak-off fluid reduces well productivity by varying degrees depending on original water saturation in the formation. In very low permeability reservoirs this can be significant. Use of surfactants can reduce the negative impact. Surfactants will also help fluid recovery from very narrow branches, shear fractures or trapped fluid inside proppant packs. However, these do not have a major impact on well productivity.

The fraction of retained fracturing fluid is a good indicator of off-balance growth; the smaller the recovery, the larger the extent of off-balance growth. There is anecdotal evidence that suggests a connection between low fluid recoveries and better productivity. One possible explanation for this observation is presence of abundant self-propped fracture branches created by off-balance growth. These will have very high conductivity. However, this positive effect is offset by the much shorter lengths of off-balance fractures (compared to single tensile fracture). Very high fluid recoveries can indicate more complete fracture closure, which leaves less of the fracture open for production. Indeed, the off-balance growth of the fracture and formation of proppant packs keep the fracture open and with high conductivity.

References
1. 1. Daneshy, A. A., “Off-Balance Growth : A New Concept in Hydraulic Fracturing” JPT, April 2003, 78-85
2. Daneshy, A. A., “Proppant Distribution and Flowback in Off-Balance Hydraulic Fractures”, SPE Production & Facilities, Feb 2005, 41 – 47