When a fracturing treatment is going almost entirely into one dominant set of perforations and starving the rest, engineers need a way to plug the greedy path and push the fluid elsewhere - without pulling any equipment out of the well. A frac diverter does exactly that. This guide explains what diversion is, the difference between ball sealers and degradable particulate diverters, and why a step-up in treating pressure is the primary real-time sign that a diverter has landed and is working.
Frac Diverter in one line: A frac diverter is a material pumped into a well to temporarily plug the dominant perforations or fractures that are taking most of the treatment, forcing the fluid to redistribute into under-stimulated clusters. Diverters include ball sealers that seat on perforations and degradable particulate that bridges and plugs, and both are designed to hold pressure temporarily and then be removed or degrade so they do not restrict later flow. Diversion improves how evenly a stage or well is stimulated.
Fracturing treatments do not distribute themselves evenly. Within a stage, fluid preferentially enters the clusters and perforations in the weakest or lowest-stress rock, so a few dominant paths can take the bulk of the treatment while other clusters are starved and barely stimulated. Those starved clusters represent perforated reservoir that was paid for but never contributes, which is a direct loss of the completion's potential. Diversion is the technique for correcting this during the job - it temporarily blocks the dominant paths so the pumping pressure rises enough to break down and treat the neglected clusters.
The same problem appears at a larger scale in refracturing, where an older well is stimulated again. In a refrac, some existing perforations and fractures are far more open than others, and without diversion a refrac treatment would simply reopen the paths that were already producing and ignore the depleted or bypassed rock the operator is trying to reach. Diverters let a refrac plug the easy paths and force the new treatment into the under-stimulated intervals, which is much of the reason diversion is central to modern refrac designs.
In both cases the goal of diversion is the same: to redistribute the treatment toward the parts of the wellbore that are not getting their share. A successful diversion improves cluster efficiency and the uniformity of stimulation along the treated interval, which is why engineers reach for diverters when they suspect fluid is being lost to a few dominant paths. The value of a diverter is measured by whether it actually shifts the treatment - and that is something the crew tries to confirm in real time as the job runs.
Diverters come in a few forms. Ball sealers are small balls pumped into the flow that are carried to the perforations and seat on the ones taking the most fluid, plugging them so the fluid must go elsewhere. Because the balls seek the most active perforations - those with the highest flow - they naturally plug the dominant entry points first. Modern ball sealers are often made to degrade or be otherwise removable so they do not permanently block the perforations they seated on, allowing full flow once the treatment and any waiting period are over.
Particulate diverters work differently, bridging and plugging within perforations or fractures rather than seating as discrete balls on perforation holes. A slug of sized particulate is pumped so that the particles bridge in the dominant flow paths and build a low-permeability plug that diverts the fluid. The great advantage of degradable particulate is that it is engineered to break down over time - through hydrolysis or reaction with produced fluids at reservoir temperature - so the plug it forms is temporary and disappears before the well is put on production, leaving nothing behind to restrict flow.
The degradability is what makes both classes of diverter usable, because the whole point is a temporary plug. A diverter must hold long enough to raise the pressure and redirect the treatment during the job, then get out of the way so it does not become a permanent flow restriction. This is why degradable materials and removable ball sealers dominate near-wellbore diversion: they provide the temporary blockage needed to redistribute fluid without leaving a lasting obstacle. The choice among diverter types depends on the well, the temperature, the size of the paths to be plugged, and how the diverter must clean up afterward.
The clearest real-time sign that a diverter is working is a step-up in treating pressure. When a diverter lands and plugs the dominant flow paths, those easy exits close off, so at the same pump rate the fluid now has to enter through more restricted or higher-stress paths - and the pressure required to keep pumping rises. That characteristic increase in treating pressure shortly after a diverter is placed is the primary evidence that the diversion took hold. A crew pumping a diverter watches the pressure specifically to see this step-up appear.
The magnitude and timing of the step-up carry information about how well the diversion worked. A clear, sustained pressure rise indicates the diverter effectively plugged the dominant paths and is forcing fluid into new clusters, while little or no pressure change suggests the diverter did not seat or bridge as intended and the treatment is still going into the same dominant paths. Because this judgment is made from the treating-pressure curve as the job runs, high-quality, continuous pressure data is essential - the diversion decision and its confirmation both live in that curve.
This is where continuous monitoring is directly useful. A cloud SCADA platform such as Merobix can ingest the treating pressure and pump rate from the fracturing equipment and present them live in a browser, so an engineer can watch for the step-up when a diverter is pumped and judge in the moment whether the diversion succeeded or whether another diverter drop is warranted. Keeping the pressure and rate record afterward lets engineers review how each diverter stage responded, correlate the pressure step-ups with the outcome of the treatment, and refine the diverter type, size, and timing on future jobs - turning the real-time pressure evidence into a lasting input for design.
A frac diverter temporarily plugs the dominant perforations or fractures that are taking most of a treatment, forcing the fluid to redistribute into under-stimulated clusters. This improves how evenly a stage or well is stimulated by rescuing clusters that were being starved. Diverters are designed to hold pressure temporarily and then be removed or degrade so they do not restrict later production.
Ball sealers are small balls that are carried to the perforations and seat on the ones taking the most fluid, plugging those specific holes, and they naturally target the most active perforations. Particulate diverters use sized particles that bridge and plug within the dominant flow paths rather than seating as discrete balls. Both are commonly made degradable so the plug they form is temporary and clears before the well is produced.
The main real-time evidence is a step-up in treating pressure. When the diverter plugs the dominant flow paths, fluid must enter through more restricted paths at the same rate, so the pressure required to keep pumping rises. A clear, sustained pressure increase after the diverter is placed indicates the diversion took hold, while little pressure change suggests it did not seat or bridge as intended.
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