It’s been an exciting and productive few years for Permian producers, but it’s also been a period fraught with challenges. Dealing with a mid-decade crash in crude oil prices. Struggling to improve yields from the Wolfcamp, Bone Spring and other hydrocarbon-rich formations to lower breakeven costs. Coping with major pipeline takeaway constraints — for crude and natural gas — and the resulting price discounts. Now, the challenge of produced water has come to the fore. Horizontal wells in some parts of the Permian generate six, eight, even 10 barrels of produced water per barrel of crude, and all of it needs to be either disposed of or treated. The volumes are enormous, the permitting and logistics mind-boggling, and the costs — well, you can imagine. Today, we consider the Permian’s produced-water conundrum as crude and gas production volumes ramp up. Warning!: Today’s blog is a blatant advertorial for new reports by B3 Insight on Permian produced water.
Crude oil production in the Permian now averages more than 4 MMb/d, and natural gas output tops 10 Bcf/d — extraordinary numbers. Over the next few months, new pipeline capacity (most of it from West Texas to the Gulf Coast) will reduce and then eliminate takeaway constraints that have plagued Permian producers for a year or two now, and enable production growth to accelerate. The catch is that, as production of crude (and associated gas) speeds up, so will the volumes of produced water generated.
As we said in our Drill Down report on Permian produced water last year, several million barrels a day of super-salty water emerges from wells in the play, and all that water needs to be gathered and safely disposed of. The task affects both legacy conventional (vertical) wells and newer unconventional (horizontal) wells. Because “water cuts” (the ratio of produced water to crude) increase over time, the large number of older vertical wells generate significant volumes of produced water — but most of that produced water can be re-injected into nearby pressure-depleted, conventional oil reservoirs for enhanced oil recovery (EOR). The re-injected water boosts pressure within the reservoirs and stimulates the production of still more crude. The thornier problem for Permian producers comes from all those new horizontal wells producing water and needing infrastructure capable of handling it to be developed. Large numbers of these wells are being drilled and completed, and in some areas — especially parts of the Permian’s Delaware Basin, but in the Midland Basin too — the water cuts can be quite high: as much as 10:1 (or even higher in a few cases), and the disposal of those water volumes is much more problematic.
The produced water needs to be transported — sometimes long distances — from the lease to saltwater disposal wells, or SWDs. (Figure 1 shows the distribution of these wells across the Permian, and their capacities by sub-region.) SWDs are drilled specifically to receive large volumes of produced water and inject them into non-oil-producing geologic layers so that they do not foul the oil-producing layers or layers that produce potable water. Most Permian SWDs send produced water into one of two shallow layers: the Delaware Mount Group in the Delaware Basin and the San Andres formation in the Midland Basin.
Until the past couple of years, there was very little pipeline infrastructure in place to help transport these large volumes of produced water to SWDs; instead, the common practice had been to rely heavily on trucks to do the hauling. That can be very costly, though, because of the number of trucks required and the long distances they often must travel. More recently, as a number of large Permian producers have been implementing long-term plans for the systematic, assembly-line development of their vast holdings, they (or the midstream companies working with them) have been building out pipeline systems to gather produced water and transport it to networks of SWDs. The ongoing transition from hauling produced water by truck to piping it is driven by two things: efficiency and cost. As well-site logistics become more complex — multi-well pads, longer laterals, more frac sand per linear foot of lateral, etc. — the ability to replace long queues of produced-water trucks with a pipeline is a logistical godsend. The shift from trucks to pipes reduces produced-water transportation costs by at least half, and often by far more.
According to our friends and water data experts at B3 Insight, the cost of transporting and disposing of produced water in the Permian can total anywhere from $0.50 to $4/bbl. That’s a wide range, and it’s particularly important if you’re a producer in the Permian’s Delaware Basin — where the water cuts are typically higher — that you be on the low end of it. Consider this: for each barrel of crude you produce, you might generate a half-dozen barrels of produced water. If you’ve got to spend $2/bbl to transport and dispose of that produced water, that’s $12 in costs ($2 times 6) for every barrel of oil — enough to significantly alter a well’s economics. Given that the gathering and disposal of produced water are must-do functions, and that the cost per well can vary so widely (depending on, among other things, the well’s water cut and the efficiency of the gathering/disposal operation), a number of producers have been working to (1) better understand their future needs, (2) develop strategies for ensuring they will have sufficient gathering and disposal capacity in place as their drilling-and-completion plans play out, and (3) minimize the produced-water-related costs they incur.
To do all this well, it helps to know things like what the water cuts are in super-specific parts of the Delaware and Midland, what produced-water pipelines and SWDs are in place and what’s being planned, and what those assets’ capacities and utilization rates are. It’s also important to understand the permitting process for developing new disposal capacity — such as how long it now takes to secure SWD permits in some parts of the Permian — and to be aware of state regulators’ concern about underground disposal causing seismic activity.
That brings us back to the folks at B3 Insight, who have spent the past few years wrapping their heads around “all things produced water” in the Permian and digging through (and digitizing) boxes full of regulatory filings such as the Railroad Commission (RRC) of Texas’s Form P-18 (in which Permian producers report how much crude they skim from produced water before it is injected into SWDs). All that work has now resulted in a multi-volume report, Permian Water Management: A Viable Emerging Market or a Tragedy of the Commons in the Making?, that discusses, among other things, current and projected produced-water generation by sub-region; remaining produced-water injection capacity (again by sub-region); the producers, midstream companies and others involved in produced-water management in the Permian; and how the region’s management of produced water is likely to evolve into the 2020s.
Also, B3 Insight is publishing a bi-weekly report — The UIC Permit Application Monitor — to provide updates on the number, location and status of underground injection control (UIC) permit applications to the RRC for new or expanded SWDs in the Permian. In addition, the report tracks the time it takes for permits to be approved and the conditions under which permits are approved — important considerations as operators assess how quickly new disposal capacity is likely to become available. (Figure 2 shows how long it has been taking to secure UIC permits in the Delaware Basin and where regulators have indicated they are most concerned about the potential impact of shallow-well disposal of produced water.)
According to B3 Insight, more than 400 permit applications for underground injection wells were submitted to the RRC in 2018, about three-quarters of them for new wells. (A few of the applications involved new wells for EOR, but most were SWDs.) As of July 15, there have already been 343 UIC permit applications in 2019 (300 for new wells) — a 167% increase from the same period last year. Most of the submitted permit applications were for wells in Reeves County, TX (a focus of drilling-and-completion activity in the heart of the Delaware Basin), with approximately 160 new well applications in all of 2018 and approximately 140 as of July 15 alone. It now takes an average of about 160 days for the RRC to review and approve a UIC permit, and the process has been taking longer and longer — some of the permits approved so far in 2019 took nearly two years to get their OK. Permit approvals in Reeves County can take the longest of all (in part due to specific concerns about potential seismic effects), and UIC permit approvals in Loving County (just northeast of Reeves) can take many months as well. This and other information about permitting for SWDs is becoming increasingly important as production of crude oil and associated gas in the Permian increases.
Our understanding is that by the late 2020s, the Permian may be generating more than 30 MMb/d of produced water — enough to fill an Olympic-size swimming pool every 45 seconds. The bottom line is this: the produced-water issue has come to the fore in the Permian, and having a full, deep understanding of things like hyper-local water cuts, SWD capacity and utilization, the timing of capacity additions, et al., is critically important for Permian producers, midstreamers and others. Why? Because their success in dealing with produced water will directly determine how much Permian crude and gas production can grow.
“Down in the Flood” was written by Bob Dylan and was originally recorded by Bob Dylan and The Band in Woodstock, NY, in 1967. The Band, formerly known as The Hawks, had been Dylan's backup band for his 1965-66 tours. Dylan's motorcycle accident (in July 1966) kept him out of the limelight for a while. During that period, The Band and Dylan recorded over 100 songs while they were all living in Woodstock. The song, also known as "Crash on the Levee (Down in the Flood)," was first released on Dylan's 1975 album, The Basement Tapes. It also appears on The Bootleg Series Volume II: The Basement Tapes Complete, which was released in 2014. In 1971, Dylan recorded a different acoustic version with folk singer Happy Traum that appears on Bob Dylan's Greatest Hits Volume II. The Derek Trucks Band, Sandy Denny, Flatt & Scruggs, and Blood, Sweat & Tears have all covered the tune. A live version with Dylan on vocals and guitar appears as a bonus track on the 2000 reissue of The Band's Rock of Ages live album, recorded in 1971.
Personnel on the original recording were: Bob Dylan (vocals, acoustic guitar), Rick Danko (bass, backing vocals), Levon Helm (drums, mandolin, bass, backing vocals), Garth Hudson (Hammond organ, clavinet, accordion, piano, tenor sax), Richard Manuel (piano, harmonica, backing vocals), and Robbie Robertson (electric and acoustic guitar, backing vocals). Bob Dylan continues to record and tour to this day; so do surviving members of The Band.