Water

Production growth in the Permian Basin continues to have profound effects on the crude oil, natural gas and NGL markets. It also has helped to spur the rapid development of what is, in effect, another midstream sector: one that focuses on the delivery of large volumes of water for hydraulic fracturing and — just as important, and even more challenging — the gathering and transportation of vast and increasing amounts of “produced water” that emerge from Permian wells with crude and associated gas. Until now, most Permian produced water has come from legacy conventional wells, but last year, the water volumes from unconventional, tight-oil wells caught up and their share will only rise from here on out. That’s a problem for producers — and a big one — because they can’t just re-inject the water back into the producing formation like they can with conventional wells. Today, we discuss highlights from RBN’s new Drill Down Report on water-related issues and infrastructure in the U.S.’s hottest shale play.

Exploration and production companies (E&Ps) in shale basins have a water problem — in fact, they have three water problems. Two are upfront well-completion costs: sourcing water for the frac job and disposal of the flowback water from the frac job.  These are nontrivial issues, but they pale in comparison to a much bigger problem – produced water – the water that always comes along with the oil and natural gas out of a well. It is a lot of water; on average in the U.S., somewhere around five to six barrels of water are produced for every barrel of oil that comes out of the ground, more from some basins than others. The Permian, for example, produces six to eight barrels of water per barrel of crude. That’s over 1,000 Olympic-size swimming pools full of water out of the Permian alone each day. And because this water is chock-full of minerals, petroleum residue and especially salt (which makes it brine), producers must dispose of the water in a safe, environmentally responsible manner. They are doing that today. But what happens if Permian production doubles — a distinct possibility. Today we continue our surfing-themed series on the effect of sand and water costs on producer economics with a focus on produced water in the U.S.’s hottest shale play.

It is certainly no secret that hydraulic fracturing, the process used to crack shale to yield natural gas and oil, is highly controversial.  Numerous reports, claims, protests, etc. have asserted that hydraulic fracturing poses a danger to drinking water, which has led to a storm of argument and opposition in many areas of the country.  Anyone wondering how oil and gas markets will work in the future must have in the back of their mind the possibility that opposition could lead to rules that would stifle supply development.  So many were anxiously awaiting an Environmental Protection Agency (EPA) study of hydraulic fracturing and drinking water that had been going on for five years.  The draft of that study was released in June.  What does it do, and what does it mean for oil and gas future development?  Today, we explore some of the findings of the draft report and focus on its implications for the natural gas industry.

RBN blog pages are replete with discussions of the Shale–Rail revolution.  We’ve shown how rail has become a formidable competitor to pipeline transportation.  Twice as much crude oil moves by rail out of the Bakken versus pipe.  Almost 100 new rail terminals will be built during 2012-13.  But that’s not the only impact that shale is having.  Most of the vast quantities of materials that support shale drilling arrive by rail.  Among these are proppants (sand, ceramics), pipe, lubricating chemicals, and water.  Today we examine the other end of the shale-rail revolution – the inbound material supply chain.