Research says fracking methods leave lots of stranded shale gas

HYDRAULIC FRACTURING:

Research says fracking methods leave lots of stranded shale gas

Nathanial Gronewold, E&E reporter

Published: Tuesday, October 1, 2013HOUSTON — Oil and gas companies might be missing out on big gains in natural gas well productivity through a flawed process of injecting fracking and well-stimulation material into the ground, if one company’s preliminary findings are correct.

Higgs-Palmer Technologies LLC, in developing new software for analyzing microseismic data during hydraulic fracturing, says it found a wide gap in the permeability of shale formations during the time between injecting the water and sand fracking mixture and the start of gas production — by a factor of nearly 1,000 in some instances.

That could mean drillers aren’t using enough proppant during the well completion process, and it could mean producers are leaving huge quantities of gas stranded underground.

Ian Palmer, a partner at Higgs-Palmer, said data suggest many fractured formations are more permeable during the treatment phase than after proppants are placed into formations and gas production starts. Proppants are materials such as crush-resistant sand, coated sand or synthetic granules used to hold open the cracks that hydraulic fracturing makes.

Greater permeability would allow more hydrocarbons to escape the rock and travel around the specially designed proppant and into the well bore.

Palmer outlined the findings at a gathering last week of the Research Partnership to Secure Energy for America, a nonprofit consortium of academic researchers and oil and gas companies. RPSEA helped fund the research.

“The injection permeabilities are [about] 1,000 times larger than the production permeabilities in the final SRVs [stimulated reservoir volumes], and so we have lost a lot of the permeability that was created during injection,” the company reports in the latest fact sheet on the research project. “This information may be important for choosing proppant type, size, and concentration for optimal fracture treatments in tight shales.”

The data it outlines indicate that more than 90 percent of a well’s potential stimulated reservoir volumes could be lost by not sufficiently propping open fractures created during injection.

Palmer’s firm is developing a “domain analysis” well diagnostic tool aimed at getting more quantitative data from the monitoring of microseismic events that occur during a well stimulation, namely hydraulic fracturing and proppant injection. One main objective is to develop a tool the industry can use to see how the permeability of fractures changes during and after well stimulation.

“The overall deliverable is a user-friendly software tool, which can be used by operators to fully characterize flow properties of stimulation domains, and provide guidance to improve well stimulations,” researchers write in an abstract outlining the R&D project. The effort was given a budget of about $824,000.

The software Palmer’s company is developing, now about 85 percent finished according to the most recent update on the project, was tested on wells owned by Southwestern Energy Co., the company says.

Once it’s completed, the hope is that the software will provide better data on changes in reservoir permeability and give a well operator better guidance on how to improve well completions. The software’s developers believe enough microseismic data on U.S. shale gas plays already exist to allow the industry to immediately improve the performance of new wells.

Shale gas wells experience steep decline rates. Enhancing the permeability and porosity of formations during a fracturing job could extend the life of a well.

Speaking at the conference, Palmer said the findings suggest shale gas companies are not using enough specialized proppant at the early stage in fracturing to inject into the smallest fractures and keep them open before the natural rock pressure closes them tight.

Palmer said one way companies may be able to maximize the reservoir permeabilities they induce in fractured wells is by using more smaller, lightweight proppant and less of the larger-grade proppants. Proppants with a smaller diameter are injected into fractures first, and pumping these into a formation at greater volumes for a longer time could help work them into the tiniest veins of fractures that he believes the industry can reach into.

Aside from Southwestern Energy, other partners assisting with Higgs-Palmer Technologies’ research include PCM Technology and Aetman Engineering.

 

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