Sealed Wellbores and the Unlikely “Breakthrough” Behind Cheap, Accurate Fracture Diagnostics

Abstract

A little over 2 years ago, amid the flat farmlands of central Oklahoma, Devon Energy sent a suite of measurement technologies downhole to study how hydraulic fractures move between wells during the stimulation treatment. The operation in the STACK tight-oil play was what the industry calls a “science project.” Once the field work was done, and as engineers got to work on the data, they expected to uncover some new learnings. What they did not expect was to find themselves on course to invent a new way to measure the size of fractures, the speed of their growth, and the energy that it took to form them. Knowing these parameters invites the use of the scientific method to control fracture growth for optimal productivity. The goal of the monitoring project was to marry up data from permanent fiber-optic cables with data acquired by down-hole pressure gauges from two wells on the same development unit. Each of the monitor wells was equipped with fiber that ran the length of the lateral. At different points, pressure gauges were ported to the outside of the casing along with gauges that were ported to the inside. All were wired up to the surface. Engineers at the Oklahoma City-based shale producer had been looking forward to the project because it was one of the first times they would be using fiber optics to measure cross-well strain. A newly established diagnostic in its own right, cross-well strain data have become popular among operators that can afford it because it delivers clear visuals of hydraulic fractures as they come into contact with offset wellbores. The engineering team wanted to know if the data from the externally-ported gauges, which were touching the rock in order to “feel” pressure buildups, could be tied to the fiber data. Meanwhile, the internal gauges were there to detect any production interference between wells after the completion. What redefined the project was that the operator—acting on the advice of its fiber-optic vendor—did not perforate the two monitor wells. This was done to prevent reservoir and stimulation fluids from flowing into the casing which might have altered the temperature of the fiber, and subsequently, the quality of the precious strain data. This recommendation was the difference maker. It effectively turned thousands of feet of steel pipe into a low-cost proxy to high-dollar microseismic surveys and fiber-optic installations. Devon is calling the discovery a “breakthrough” for subsurface engineering. The person to see the first clues of this was Wolfgang Deeg, who at the time was a completions advisor with Devon and is now an independent consultant. Deeg’s role in the project was to analyze the fiber data, but he also decided to take a look at the data collected from those internal pressure gauges. He was puzzled. Within the data set were small, but clearly identifiable pressure changes. “The first thing I asked myself was, ‘Does that even make sense?,’” recalled Deeg. “I ended up calculating what the required increases in pressure had to be on the outside of the casing, and they were consistent with the numbers we were seeing. That was encouraging.” However, the mystery was not yet solved. For others on the team, the unforeseen pressure data remained “more of an interesting discussion than it was meaningful—we didn’t know what it meant,” said Kyle Haustveit, a senior completions engineer at Devon.