Time to revisit re-fracks? July’s oil price drop is prompting operators to take a “wait and see” approach on new drilling in 2015. Consequently, new oil may very well come from old oil sources. Re-fracks, or reentering existing wells and re-stimulating the wellbore to harvest hydrocarbons left behind, represent one way to get there, as does winnowing down the backlog of 3,800 drilled but uncompleted wells.

Indeed, there has been a publicity flurry on re-fracks. In July 2015, oil services giant Halliburton and BlackRock Inc., a national investment funds manager, announced a $500 million capital commitment to move the re-frack effort forward. That pool of capital is enough to cover about 250 horizontal attempts.

Meanwhile several companies announced active 2015 re-fracturing programs during the first half of the year. Devon Energy Corp. pointed to a 150-vertical well re-frack underway in the Barnett Shale with plans to test 15 horizontal re-fracks. Comstock Resources Inc. planned to spend $23 million on 14 re-fracks in the Haynesville Shale, citing 40% to 70% internal rates of return at a natural gas price deck above $3/Mcf. Similarly, Exco Resources Inc. said it had identified 270 Haynesville Shale re-frack candidates and attempted six earlier in 2015. Chesapeake Energy Corp. was also on board.

In retrospect, renewed interest in re-fracks rose concurrently with the retrenchment in commodity prices. Well stimulation crews were in short supply during the high-demand scenario in 2014. When those fleets began stacking out in 2015, the largest oil service companies sought ways to keep employees on the job, reinvigorating the re-frack drumbeat.

There are currently three re-frack technologies, including chemical diversion, mechanical isolation, and coiled tubing. All three exhibit individual characteristics that make each a niche technology in specialized applications rather than a magic bullet for all applications.

Re-frack costs range from $1.8 million in the Bakken Shale to $2.8 million in the deeper Eagle Ford. In general, re-fracks increase both reserves and profit. Payout comes in 12 to 18 months, although a generally positive Bloomberg re-frack study in mid-2015 found more than 25% of attempts failed to add incremental net present value.

Identifying market size is challenging. Out of a universe of wells that expands at the rate of 3,000 or more monthly in boom times, recent horizontal re-fracks have been numbered at less than 1,000. In ideal circumstances, the re-frack market could grow to 11% of horizontal wells in 2020, according to an IHS study.

Re-fracks are easier said than done. They imply the original stimulation treatment was defective, either mechanically, or because the stimulation process missed the optimal zone, or failed to induce conductivity, or experienced proppant failure. Regardless of cause, re-fracks promise to reach new areas of the reservoir, improve estimated ultimate recoveries (EURs) in understimulated rock and, in some cases, exceed the original initial production (IP) of the original well.

The greatest predictor of economic success lies in screening existing well populations for suitable candidates. The best candidates will lie within the very best rock in core areas across the country. For example, the early scramble to capture acreage in the Marcellus Shale meant many wells were drilled to hold land by production and may not have been stimulated in an effective manner. Initially, stages were placed as far apart as 500 feet with laterals containing only five or six stages and low proppant loading—200 pounds per lateral foot versus 200,000 pounds or more currently.

In the Barnett Shale, the industry has a long history of reentering old vertical wells that were fracture-stimulated with crosslink gels and re-fracking the wells using slickwater. The Bakken Shale has exhibited multiple re-frack initiatives, but many wells were completed open hole, which increases technical challenges. Recent innovations in hydraulic and mechanical packers allow for better zonal isolation and expand the possibility for Bakken re-fracks. Several deep Eagle Ford wells have also been re-fracked. Often re-frack candidates display higher clay content and are overpressured. Tight oil formations that feature greater brittleness, such as the Wolfcamp Shale in the Midland Basin, are less likely candidates for re-frack, pending a technology breakthrough.

In general, dry gas plays with the oldest wells provides the greatest opportunity for re-fracks. However, the process of revisiting the re-frack process sometimes reveals it’s better if operators just drill an offset well in core acreage and apply modern enhanced completion techniques.