Maximizing Production with Hydraulic Fracturing is about Surgical Placement

by Charles Hager - Subsurface Alliance Senior Associate Consultant

Not all fracture stimulations are created equal.? While it is not difficult to increase production by pumping just about anything, it is very hard to not see some type of increase; however, it’s a true challenge to optimize production.? So often, operators will try to increase production by hitting it with a “bigger hammer”.? Greater pump rate, higher viscosity, more fluids or more proppants are often the tools to coax out more production.? I recently heard from an operator planning to increase their slickwater frac from 90bpm to 130bpm to fix the under-performing asset.? I could only shudder as it will not change a failed stimulation into a huge win.

?So often, I have found that to increase production, one needs to look at a surgical placement of their proppant, instead of using a “bigger hammer”.? We only have a limited number of things to consider when changing our stimulation design.? Fluid viscosity and volume, proppant size, concentration and tonnage, perforating strategy, pump rates, and chemistry for timing of the fluid properties.? It will be shown that more is not always better, rather getting your proppant where it is needed creates success.?

Below is an example of a South Texas area.? Perforations were placed from 5,945’ – 5,975’ over the best 30’ of pay zone.? The yellow intervals are the layers with the highest permeability, as seen on the right track.? Additionally, as seen on the left track, there was only about 250psi of stress contrast to keep the fracture “in zone”.? This is not a lot of stress difference to work with.??

Below is the history match of an original stimulation design that an operator was using.? The entire treatment was a crosslink gelled guar fracturing fluid pumped at 25 bpm to place 150,000 lbs of 20/40 mesh sand.? As a result of pumping a high viscosity fluid system, a “Penny Frac” was generated, a term for a fracture that has around the same fracture height, and length from tip-to-tip.? The following figure shows the excessive height growth associated with pumping too much viscosity at too high of a rate.

As a result of this uncontrolled height growth, a propped fracture half-length of around 320’ was achieved.? This certainly stimulated the well and made a gas producer of around 1.5 mmscfd.? Was it better than no stimulation?? Absolutely!? Was it the best that could be achieved?? No at all. ?The following figure shows that within 10 hours after shut-in, proppant had fallen to the bottom of the crack created.

To achieve an increase in production, we had to focus on getting more fracture half-length generated in the most permeable zone located from 5,945’ – 5,975’ deep.? To improve this surgical placement, the viscosity was significantly decreased from a crosslinked fluid to a linear gel for over 70% of the pumped volume.? Additionally, the average pump rate was reduced from 25 bpm to 15 bpm.? This represented over a 95% reduction in viscosity and a 40% reduction in pump rate.? As a result, the redesign cut the overall fracture height from 700’ to 350’, while the propped fracture half-length increased from 320’ to over 900’.?

A more focused stimulation from lower viscosity and lower pump rate resulted in doubling the production.? This redesign stimulation generated a 3 mmcfd well with a 30% drawdown, up from 1.4 mmcfd in the offset well.?

To conclude, this common example is a case where less will get you more.? The same proppant volume can lead to at least doubling of a well’s productivity by focusing on getting proppant where it is needed most.? Consider this when investigating how to improve stimulation effectiveness.? Building a detailed history match and using a calibrated model for surgical placement is the best way to engineer success.? Hitting your well with a “bigger hammer” is not necessarily the right answer.