What's new in production

“Achieving a high perforation cluster efficiency (PCE) in shale laterals has been a challenge for the industry for many years. Early, PLT-based results suggested that perforation cluster efficiency in horizontal shale wells was as low as 40%. More recently, fiber optics-based analysis suggests that current cluster efficiency is between 50% and 70%, depending on completion design and pumping conditions.”

So say Samuel French and his co-authors in a recent paper that describes what they term an “innovative fracturing treatment design.” It was created “…to optimize perforation cluster efficiency, lateral placement and production results…” in the NEBU 602-1H, a Mancos shale gas appraisal well.

Immediately following “oil” and “gas,” the next two most often used words in this business surely must be “optimization” and “efficiency.” Their profligate use has no doubt helped to establish eyeball-casting skepticism as the default reaction upon hearing them. But, in this case, French, et al., may be on to something.

Overcoming extreme stress shadowing effects. Maximizing gas production from this New Mexico appraisal well required a fracture design that would maximize perforation cluster efficiency, and a lateral placement strategy that would maximize gas recovery. A key challenge was to design a fracture treatment that would overcome the extreme stress shadowing effects. As the authors point out, the core data indicated that the Mancos was a very hard, stiff rock with a horizontal Young’s Modulus of approximately 5 x 106 psi. The Mancos also had a large horizontal stress anisotropy. The stress shadowing effects while fracturing such a stiff rock would be large, and it would be a challenge to achieve a high perforation cluster efficiency.

Fracture treatment simulations were completed for various designs. Fracture simulations indicated cluster efficiency could be improved by optimizing the way [the pad is pumped]. A step-up technique for increasing pumping rates during the pad stage helped to initiate more fractures. Intra-stage diversion was [used]. Fracture simulations were performed to optimize lateral placement. This required balancing multiple factors to access the highest gas-in-place interval yet facilitate more fracture initiations per stage.

Step-up pumping rate technique. As noted in the paper, previous authors have documented the use of a “step-up” pumping rate technique to create more fractures and increase fracture complexity during the pad. Bartko et al. (2017) used control pressure pumping (CPP), in conjunction with a near-wellbore diverter to ensure the maximum number of clusters break down. King et al. (2017) refer to stepping up the rate gradually as being preferred.

Frac model cases were run with the Mancos model and indicated a positive benefit could be expected for using the step-up technique. This method was incorporated on most stages of the NEBU 602-1H. The pumping rate was stepped up in increments of 10 to 15 BPM, then held constant for 90 sec to 2 min. Fracture initiations are indicated by the rapid decrease in surface treating pressure at a constant rate.

Fracturing fluid optimization focused on meeting fluid viscosity requirements defined by the frac modeling results, reducing conductivity damage due to unbroken polymer retention in the proppant pack, and minimizing the proppant embedment that occurs with exposure of the Mancos shale to water-based fluids. Higher polymer concentrations, with optimized oxidative breaker, were the key to meeting the viscosity requirements and minimizing conductivity damage. Clay stabilizer optimization, using Mancos core, was important in minimizing proppant embedment.

Effective intra-stage diversion. Intra-stage diversion was used on as many stages as possible, to increase the probability of improved cluster efficiency. Granular biodegradable polylactide acid (PLA) resin diverter was used. The authors uncharitably characterize diverters in general as “…usually commodity chemicals applied with a minimum amount of engineering consideration.” Diverter placement typically involves pumping slickwater as a carrier fluid at a low rate (30 bpm), with a large amount of diverter mass (200-350 lb). Poor diverter placement can lead to low cluster efficiency, directly affecting gas productivity.

Improvements to the diverter pumping design were made to achieve a higher effective diversion. Results indicate that the new placement design had a higher, more consistent pressure response.

Choke management. A choke management strategy is necessary in shale gas wells to avoid damaging productivity and expected ultimate recovery. One of several concepts warns that increasing the rate and pressure drawdown too soon, before fractures have “clamped down” on proppant, risks moving proppant out of the fractures and into the wellbore, due to increased velocity in the fracture.

This appraisal well was the most productive Mancos gas well ever delivered in the San Juan basin. The 9,546-ft lateral produced at a choke-constrained plateau rate of about 13 MMscfd for seven months and produced over 6 Bcf during the first 20 months. A radioactive tracer log indicated an overall perforation cluster efficiency of 83%, a significant achievement.

The fracturing fluid design, diverter design and pumping techniques can be applied in many other shales as a low-cost way to increase perforation cluster efficiency, which will, in turn, result in higher production rates and higher cumulative recovery. Building on the success observed in the Mancos wells, BP and BPX Energy have subsequently utilized these techniques in other shale plays with success.

There’s more to the story, but the authors say the concepts and workflow used to decide the optimal lateral placement is a well-defined approach that can be applied to other unconventional wells.