What’s the Difference Between Tier 1 and Tier 2? Not much

Abstract

Financial reports have long lumped shale acreage like cuts of meat, with tier 1 for the best reservoir rock, and tiers 2 and 3 ranked as lower quality. Tier 1 is rated superior to the lower tiers based on a handful of geological measures related to the oil in the ground and the ability to stimulate flow with fracturing. Production tells another story. A recent study by the energy advisory arm of Deloitte of 35,000 wells in the Permian Basin and Eagle Ford found that production in regions outside tier 1 in those basins are not that different. “We are starting to challenge that general notion that just investing in established tier 1 acreage drilling a longer lateral, pumping more proppant,” ensures wells that are both productive and profitable, said Tom Bonny, a managing director for Deloitte. In the Eagle Ford shale, the breakdown in wells based on early production showed little difference between the tiers. Tier 1 wells had a slight edge in wells producing more than 1,500 BOE/D, but was also a bit higher in the percentage of wells at 500 BOE/D or less. In the Midland Basin, the pie chart for tier acreage showed tier 1 outperformed lower tiers at both the high and low end. The differences at the high end were relatively small. In the lowest quartile, the percentage of tier 1 wells was significantly lower but 42% of the tier 1 wells were in the bottom quartile, pointing to another problem highlighted by the datA&Mdash;many shale wells are not that productive. In this story, production is based on a 180-day measure that is adjusted as if it were from a 10,000-ft lateral, unless otherwise noted. The message in the study is that reservoir rock quality matters, but even in what passes for good quality shale rock, getting oil out depends on where the well was located and how it was drilled, fractured, and produced. “Rock is important, but a good rock without a good design is of less use,” said Anshu Mittal, an associate vice president for Deloitte. An average of the splits in the Deloitte pie charts are roughly in line with a rule of thumb offered years ago by George King, now a principal with GEK engineering, who said that for every 10 shale wells, there a couple of bad ones, a handful of marginally profitable performers, and a few strong wells that justify the effort. What was once a wry observation back when oil prices were $100/bbl now sheds light on a pressing problem after the 2014 price crash forced companies to focus on increasing well productivity. Operators reacted to that by driving down costs—often by reducing fees for services—and paying more to drill longer laterals and pump more sand. During those years, the growing use of data allowed those inside the business, and outside, to critically consider the methods used to produce more oil and gas, and whether a well that produced more was worth what was spent to deliver it.