Wipe Out! - Investing in Pipes, Treatment and Injection Wells to Trim Produced-Water Costs

The largest single expense associated with operating wells in a number of U.S. shale plays — including the Permian — is the cost of dealing with the large volume of produced water that emerges from wells along with crude oil, natural gas and NGLs. In many cases, produced-water disposal costs account for more than half of total well-operating costs, and every dime or dollar per barrel that an exploration and production company (E&P) needs to spend on produced water increases its break-even cost and saps its bottom line. To rein in trucking and other produced water-related expenses, more E&Ps and midstream companies are (1) developing produced-water treatment plants that allow the water to be reused in hydraulic fracturing and (2) building centralized systems that efficiently transport untreated produced water from multiple wells to treatment plants or to regional disposal wells. Today we continue our surfing-themed series on the effect of sand and water costs on producer economics with a look at how the old ways of dealing with produced water are being replaced by the new.

Before we delve into today’s blog, our Houston-based RBN team and all of our folks throughout the country again wish to express our heartfelt condolences for the victims of Hurricane Harvey and its aftermath.

Faced with lower-for-longer hydrocarbon prices, E&Ps have been working hard to reduce their operating costs and improve the productivity of their wells. This has been an all-out effort — it’s had to be. With crude oil and natural gas prices falling below $30/bbl and $2/MMBtu, respectively, a year-and-a-half ago and struggling to stay near $50/bbl and $3/MMBtu today, E&Ps have had no choice but to become leaner and (most of all) smarter if they want to survive and even thrive in an era with oil and gas prices much lower than they were three years go.

NEW Backstage Pass Drill Down Report

With a Permian Well, They Cried More, More, More Part 3 – Permian NGLs: Plants and Pipelines

Permian NGL production is on a tear, doubling over the past four years to 800 Mb/d, with the possibility of almost doubling again by 2022.  With that much supply growth, pipeline takeaway capacity is an obvious concern. But this is the Permian, where big-league NGL volumes are nothing new. A lot of legacy infrastructure has been in place for decades, and a couple of new pipeline projects came on line just last year. So there appears to be ample takeaway capacity to serve the region. But appearances can be deceiving.    Not all of the pipeline capacity exiting the Permian can be used by Permian producers, and there are a number of factors – such as the looming end of Permian ethane rejection – that will accelerate the need for more capacity sooner rather than later.   Fortunately for Permian NGL producers, several pipeline expansion projects are in the works.   But exactly how many pipelines, and how soon they will be needed remain open questions.  This Drill Down report addresses these questions and many others. 

Click Here for More Information on Part 3 of our Permian Drill Down Report Series

Among the more significant trends during this particularly cost-conscious period has been what you might call the supersizing and assembly-lining of oil and gas production. As we said in Back in the Saddle Again, producers have been piecing together ever-larger leaseholds in the parts of key shale plays they have determined to be the most promising; drilling multiple wells from the same pad; drilling much longer laterals (made possible by large, contiguous leaseholds); and increasing production by ramping up how much frac sand they use per linear foot of horizontal well. While it may cost more to drill longer laterals and use more sand (and frac water), these steps and others (such as throttling, or “choking back”, initial production from wells to increase their long-term production) have enabled E&Ps to wring far more oil, gas and NGLs out of each well.

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