Part 1: Putting the Potential Impending Texas Oilfield Water Injection “Crackdown” Into Perspective

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**Please note that the opinions expressed in this piece are the author’s only and do not reflect any official positions of Rice University or the Baker Institute for Public Policy.**

The Texas Railroad Commission said on 5 December 2018 that it is considering new restrictions on what volumes and pressures it would permit oilfield water injection disposal wells to operate at.  RRC Chief of Staff Jared Craighead noted that the Commission is bringing a special focus upon the Permian Basin—especially Reeves County, the most heavily-drilled county in the Basin at present with 84 rigs operating as of 30 November 2018, according to Baker Hughes.

Placing hard constraints on injection disposal of produced water would potentially have dramatic operational and financial impacts, a number of which the second piece in this two-part series will explore in detail.  But some preliminary perspective must come first.

To start, is there sufficient risk to people and property to justify regulations that could adversely impact a key regional and national economic and energy security engine?  TexNet earthquake data beginning in January 2018 (provided by the University of Texas) show the preponderance of the stronger quakes (Magnitude 2.5 or higher) occurring 10 miles or more from regional population centers such as Pecos and Fort Stockton. For reference, if I’ve done my math right, an M2.5 quake releases about 692 MJ of radiated energy—equivalent to 5.65 gallons of gasoline. In contrast, the most powerful quake in Oklahoma since 2009 registered M5.8—unleashing a burst of energy equal to that contained in approximately 339 thousand gallons of gasoline.

And then there is the reality that Texas is not Oklahoma. This is not a “Hook’ em Horns vs. Boomer Sooner” distinction. Rather, it centers upon the fact that to date, Oklahoma has been America’s exclusive test lab for how regulators respond to large-scale seismic activity that correlates with rising volumes of oilfield produced water pumped down disposal wells. And because Oklahoma possesses practical (and recent) experience in responding to the seismicity issue, it likely offers an analogue that regulators in Texas will potentially draw heavily upon. In response, let us consider three critical differences:

  • The first core difference is that North-Central Oklahoma—the epicenter of the state’s recent quake swarms—is much more heavily populated than the Delaware Basin and Reeves County. As such, the propensity for a quake in the zone between the Oklahoma City suburbs and Kansas stateline to interfere with human wellbeing and damage property is much higher than it would be in the western Permian Basin, which has some of the lowest population densities in the Southwest.
  • Second, many feared that quakes could potentially damage critical oil storage and transport infrastructure in and around Cushing—one of the world’s largest oil storage hubs and a prominent, globally-relevant crude oil price formation point. There haven’t been catastrophic failures to date—indeed, data from past earthquakes outside of Oklahoma suggest that to one-off seismic events, even very large ones, pipelines and tanks are fairly robust. Scholars are now examining the potential cumulative impacts that persistent low-level seismicity can have on energy and other critical infrastructure.
  • Third, and perhaps most importantly, many of the parties who could potentially be damaged by quakes in Reeves County have vastly different financial incentives than most of those living near the Oklahoma quakes. While at least one lawsuit in Oklahoma arose from a quake-related personal injury (a woman injured when pieces of her stone fireplace fell on her legs during a tremor), the bulk of cases center on property damage. This is where the Delaware Basin is likely to be different—unlike an Oklahoman who suffers damage in periodic seismic activity, but collects no royalties or other financial benefits, a West Texas rancher with a constellation of saltwater disposal wells injecting 500 thousand barrels per month at a royalty of $0.15/bbl would receive a check for $75,000 PER MONTH.

It is neither crass nor unreasonable to think that a party so situated would be willing to tolerate a high degree of seismic activity in exchange for such economic renumeration. It is also reasonable to think that among the community of Delaware Basin landowners reaping the benefits of “frac ranching”—of whom there are several, if not tens in Reeves County alone—there are likely to be many that take serious umbrage at regulatory action from Austin that imperils their cashflow. The current boom in all of its dimensions—mineral royalties, surface damages, water sales, and disposal royalties—represents a once in five generations monetization opportunity for landowners who only a decade ago were generally living from drought to drought in one of Texas’s harshest ranch climate zones.

The desire to monetize today and fill the coffers for future generations is even more pronounced among landowners who do not own mineral rights, but by dint of their surface ownership, control the injection disposal rights.  For these individuals and their families, injection disposal royalties may be their core—and perhaps only—large-scale monetization option. My analysis may turn out to be completely wrong, but based on the realities described above, injection disposal restrictions could very well stimulate opposition from unexpected quarters. It will be interesting to see how the new rules are structured and how various constituencies—especially landowners who may not be party to the current discussions between the RRC and stakeholders—react to them.

In the next day or so, I’ll publish a follow-on piece examining potential impacts injection restrictions could have on operators and water midstream firms active in the Delaware Basin.

Please cite as:

Gabriel Collins, “Putting the Potential Impending Texas Oilfield Water Injection “Crackdown” Into Perspective,” Texas Water Intelligence™, Water Note #8, 6 December 2018


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