Testing Tiny Grains Seeking More Output
- Stephen Rassenfoss (JPT Emerging Technology Senior Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2017
- Document Type
- Journal Paper
- 28 - 34
- 2017. Copyright is held partially by SPE. Contact SPE for permission to use material from this document.
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The challenge of selling microproppant was obvious when the first question asked after a recent presentation was: “I thought 100 mesh [fine proppant] was dust. So what is microproppant?”
Rather than repeat the explanation in his talk, the speaker James Calvin, a technical sales advisor at Halliburton, responded, “It is even finer.”
The exchange drew a laugh from the audience at this year’s SPE Hydraulic Fracturing Technology Conference and Exhibition in January, which had heard him explain that proppant that is a fraction of the size of the smallest now used—about 300 mesh—may be able to significantly increase production by holding open fractures that cannot be reached by widely used grains of sand or ceramic.
The question suggests that it is still hard for experts in this field to conceive of how particles whose size is typically measured in microns could offer meaningful benefits. And even among those who see value, there are conflicting theories about what it does in the ground.
At this stage the only company reporting results is Halliburton, which pumps microproppant as part of its MicroScout service. “Field results for MicroScout have shown a positive uplift of production in most of the wells that we have field trialed,” said Philip Nguyen, the chief technical advisor for Halliburton’s production enhancement line. “To be frank, there are lots of unknowns with the application of microproppant as we are only beginning to scratch the surface of using this material in shales.”
That paper (SPE 184863) and others from Halliburton dating back to 2015 offer examples of wells with double-digit production gains when a relatively small volume of these particles are pumped early in each stage, and can reduce the treating pressure required while pumping a job.
“We have seen about a 15% uplift in production over 12-month time frame,” said Mark Parker, technology manager for the Mid-Continent area at Halliburton, which includes the South Central Oklahoma Oil Province (SCOOP) in Oklahoma, where it has been used on nearly 20 wells.
In the Permian Basin, gains have ranged from 15% to 30% where this has been pumped during the early part of each stage. “Theoretically, you are getting secondary fractures [propped] and getting added flow from reservoir to the well,” said Dean Prather, area technology manager for Halliburton’s production enhancement business line.
In a sense this is the logical next step. Over time operators have slowly embraced the idea that using higher percentages of 100-mesh sand to prop early in the job can open smaller fractures and reduce the required pressure needed to treat stages.Calvin described the production gain by saying: “We placed it in the secondary fracture network and it can go where 100 mesh cannot go. It can keep the secondary fracture network open through production and help minimize the production loss.”
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