A series of images that look like yellow lumps on a line are the first-ever images of the area around the wellbore where fractures have been propped open using specially coated proppant stimulated by electromagnetic (EM) energy. The images created by Carbo Ceramics could represent a milestone on the journey to find an answer to a critical question facing unconventional producers—how much rock is being stimulated and propped with grains of sand or ceramic for maximum production?
Four groups of researchers are seeking a direct way to visualize what is left behind after fracturing. Three of the projects involve getting images by using proppant specially treated to be visible when stimulated by EM energy.
Microseismic images currently used in the industry to show fracturing results are based on the popping sounds of rocks rubbing against each other, like fingers snapping, but not the quiet, productive work of opening fractures and pumping in proppant to ensure they stay open.
“Microseismic doesn’t really tell us where the proppant has gone. It shows where failure events are occurring,” said Mukul Sharma, a petroleum engineering professor at the University of Texas (UT) at Austin. He heads the Hydraulic Fracturing and Sand Control Joint Industry Project (UT Fracturing JIP) at UT, which is leading one of the projects mentioned earlier. “What matters is where the proppant is. In many rocks, the propped part of the fracture is the primary contributor to well productivity. That is the main advantage of electromagnetic (visualization) over microseismic.”
Imaging the area that has propped fractures is a starting point for multiple investigations into how to efficiently extract more than 10% of the oil in unconventional plays. It can define the length and height of propped fractures, offer more accurate measures of the productive rock for modeling, and tell engineers how to space wells to effectively stimulate the reservoir without hitting nearby wells.
A fourth project for visualizing fracturing is aimed at adding proppant location information to microseismic imaging by pumping in tiny sound emitters, which produce a distinct noise when the microdevices are lodged in a fracture.
Depressed oil and gas prices, which have made most unconventional development unprofitable, add pressure to find tools to understand why so many fractures are not productive. Bj?rn Paulsson, chief executive officer of Paulsson Inc., which is developing the in-well receivers, pointed out that “80% of production comes from 20% of fractures, wasting a vast majority of the fracturing cost.”
Electromagnetic Testing
The microseismic approach is aimed at creating a 3D array showing points where proppant is present, but it will be years before the partners on that project have built the equipment needed for its first test. EM-based methods are already being tried in the ground.
A technical paper by Palisch et al. (SPE 179161) presented at the 2016 SPE Hydraulic Fracturing Technology Conference was a first look at what is possible in a producing well. The imaging involved using 230,000 lb of proppant covered with an electrically conductive coating, which made it visible when stimulated by electromagnetic energy from the well casing in an 8,000-ft deep well.
Multiple new technologies were required for this method, including development of the conductive coating, a transmission method to send out a strong EM field using the steel casing, and new algorithms for processing.
In January, Carbo was still working though the large body of data gathered to reduce the noise in hopes of improving the image. After the injection of the 180,000 lb of white sand, 230,000 lb of treated ceramic proppant was injected through four perforations in the last stage fractured. One unknown is what the propped area would have looked like if all the proppant had been conductive.
The company has been refining its image-processing method to sharpen the resolution from 25-m grid blocks to a fraction of that measure. Over the next year, the largest maker of ceramic proppant will be doing more well tests. It is seeking to expand the number of stages covered, and to significantly reduce the cost and effort required for testing.
Those working on EM proppant imaging methods need to convince skeptical reservoir engineers that these images created using methods based on esoteric physics and mathematics represent reality in the ground.
A priority for the EM proppant imaging project put together by the Advanced Energy Consortium (AEC) is gathering physical evidence to see if its models provide “useful information of the extent and basic properties of fractures,” which can be relied on, said Douglas La Brecque, chief scientist for Multi-Phase Technologies. The company is providing the EM technology for the effort by the AEC, which is part of the Bureau of Economic Geology at UT. The project also involves other universities and institutions (SPE 179170).
While there is value in knowing the height and length of the propped fractures—frequently measures of fracture lengths are too high, leading to exaggerated production estimates—there is a limit to what operators will pay and how much time and effort they will commit to answering these questions.
The US Department of Energy summed those limits up in a statement of goals for its proppant imaging research when it said it is seeking a new method that “will have a very significant impact on fracture diagnostics, as it is cheap, repeatable, and fairly simple to run.”
At this early stage, the cost of EM proppant imaging is comparable to another widely used diagnostic test: collecting and analyzing core samples. Palisch said the next step is to reduce the cost so that it is comparable to microseismic, and reduce it from there.
“Ultimately, I would like the price of EM proppant detection to be like logging, which is low enough to be done on nearly every well, ” he said.
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