Completion Science, LLC®
Completion Science, LLC®
Completion Science, LLC®


 As the term is used in the oilfield,  diverting generally means that a material is pumped to seal off a section of the wellbore and redirect a subsequent fluid stage to a different section. 

The diverter stage is typically a particulate slurry, but may also be a gelled fluid. The physical form that the diverter is in will depend on what the situation is downhole. The diverter may be fine particles if the rock face is a high permeability sandstone or it may be a gelled fluid if the formation is a low permeability formation. Somewhat larger particles will be used if the near wellbore is packed with gravel or proppant, and the goal is to seal on this pack. Even larger particles, still, will be used if the diverter needs to work on fractures or slots. Large particles would also be needed if they are to bridge on the entrance to perforation tunnels. 

At some point, perhaps around 25 to 50 mD permeability, a gelled fluid begins to lose effectiveness in preventing or slowing fluids from flowing into the rock face. At this permeability range, a diverting stage design will begin to incorporate particulates to help seal. A rough rule of thumb is that the particle size needed (measured in microns) to seal on the formation pore throats is equal to the square root of the formation permeability (measured in mD). So, a 400 mD rock would require a particle slurry with some of the particles as big as 20 microns. This rule of thumb works well in natural rock.

 When the medium that is to be sealed is a fairly uniform particle bed, such as gravel or proppant, then sizing the diverting particle is gained simply by dividing the average poppant size by 6 and using that as the larger particles in a diverter stage. In addition, smaller particles will likely be needed to be included as well and this discussion is handled in the FAQ “How to size for bridging on Slots?” 

At this point, it is a good idea and pause to discuss a topic called “fluid loss.” If we wanted to test our diverting particle slurry in the lab and the particle slurry was just water and particles, we would probably be disappointed in the lab results (although the same slurry may perform well in the field, more on this later). Even a pack of very small particles still has significant permeability and given how small a lab test cell volume may be, it may only take a matter of seconds for all the fluid to be ejected from the cell, leaving a wet particle pack behind. If your goal was to size particles that would bridge on the “medium” used, then the test was at least a partial success. The disappointment came when the liquid didn’t stop also. To get a particle pack to be effective in stopping liquid would require having some of the particles in the pack down to perhaps the sub-micron range. This is expensive and could be a health hazard given how easy it would be getting these particles airborne. 

Another approach is to add something other than “rigid” particles. That is, to incorporate a “fluid loss” agent. This is generally a polymer such as guar or starch. With this in the mix, a more effective liquid barrier is formed with the particle pack. The polymer will form a final seal on the pack by being filtered out of solution by the particles. The component that gets filtered out and forms a filtercake on the particles is referred to as “fluid loss” control or may sometimes be referred to as the process of “filtration.” In shale fracturing applications, gaining fluid loss may not be a conscious, additional step. The presents of a friction reducer may be all that is needed, but in many cases, the function is provided by all the organic matter that comes from the water source used to make up the fracturing fluid. Any inspection of a real-life water source will make it evident that there is a significant amount of “fluid loss” agent being used. This should make it clear as to why a lab test with tap water may fail, when a real test in a diverter treatment produces a good pressure response.

Recall above that a low permeability formation can filter out polymer, and particles are not needed in a diverter stage. In this case, the formation is the fine “particle pack” and the polymer is the fluid loss additive. When the formation pores are larger enough to allow “whole” polymer to pass, then addition of “bridging” particles must be included.

It is not always necessary to include a “fluid loss” additive to get sufficient pressure build up. A good example is when a perforation tunnel gets filled with fine diverting particles. The “linear Darcy” flow in the particle pack offers enough resistance to injection rates to gain the needed pressure response. The same may also be said about a particle pack that may fill a near wellbore fracture such as those in shale formations.

If you chose to perform you own lab testing, be warned that it will have to be accompanied by some engineering calculations to scale up to field applications.

To design a diverter treatment:

1. Know what type of pressure differential is needed to get the needed fluid redirection.
2. Design the system for the downhole situation (rock face sealing, perforation bridging, slot bridging etc).
3. Work out the volume of fluid needing redirected and the amount of diverter material needed.
4. Decide if the diverter is going to be a separate stage or included in the treatment volume (sometime called “continuous” diverting).