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To “Right Size” Fractures, Producers Adopt Robust Monitoring and Custom Completions

Source: Getty Images.

As the shale sector looks for ways to improve well results, momentum is building to take a much closer look at how and where hydraulic fractures are created while pressure pumping fluids into tight, complex reservoirs.

The effort is being driven by unresolved questions over optimal well spacing and fracturing techniques. They are two closely related issues that dovetail into sector-wide production shortfalls associated to frac hits, a common well-to-well effect that experts in the technical community have recently named fracture-driven interactions.

One of the biggest challenges in overcoming these issues is to learn how to control the size of hydraulic fractures (the general emphasis is on reducing their lateral and vertical extensions) with a far finer degree of accuracy and finesse than is realistic today. There is an expanding array of diagnostic studies and new technologies working to this end. Several of the latest examples were highlighted at the recent Unconventional Resources Technology Conference (URTeC) in Denver.

Operators both large and small used the conference as an opportunity to express support for the broader use of tools considered to be classic components of petroleum and reservoir engineering: wellhead and bottomhole pressure gauges. These two technological cousins are nothing new to the oil field, but have only recently become viewed as essential among those seeking affordable answers about how their fractures behave during the treatment.

“The industry badly needs a low-cost, stage-by-stage method that we can use for assessing the reservoir quality, the completion design, and fracture complexities,” said Michael Sullivan, a reservoir diagnostics advisor with Chevron, during a technical session at URTeC. “Unfortunately, the high-cost and operational complexity is a barrier to most other stage-level assessments. What we need is something we can afford to do.”

Sullivan was presenting a paper (URTeC 970) that describes how Chevron’s Canadian asset team in the Duvernay Shale recently began using “free” wellhead pressure data to estimate each fracturing stage’s performance. His hope is that others follow the workflows as Chevron looks at more than half-a-dozen ways to use the data (including perforation cluster efficiency analysis and frac hit identification) to refine its completions approach.

Sullivan highlighted that the new learnings are thanks to pressure gauges it uses per standard procedure, meaning they are on wellheads whether the data is analyzed or not. To drive down costs further, Sullivan advised other operators to buy their own gauges vs. renting them from service companies. “What I’ve been emphasizing around our company is that this is a measurement we can afford to make—so let’s make sure we’re getting the most out of it,” he added.

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To “Right Size” Fractures, Producers Adopt Robust Monitoring and Custom Completions

Trent Jacobs, JPT Digital Editor

01 September 2019

Volume: 71 | Issue: 9

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