[Editor's note: This story originally appeared in the March 2020 edition of E&P. Subscribe to the magazine here.] 

The beauty of water is that it takes the shape of its container. The beauty of the container is the near-infinite variations in shape it can take to accommodate that water. Things get ugly when there are not enough containers to get that water from one point to another. This is where water midstream teams attempt to bring balance to the demands of many.

Over the last two years, more than 30 water transfer projects have been identified in the Permian Basin alone, according to Bluefield Research. Water transfer projects have popped up across many of the U.S. shale basins as water is a key operational component.

According to Bluefield’s report, “Midstream Water Management: U.S. Hydraulic Fracturing Strategies, Solutions & Outlook,” water management for the hydraulic fracturing sector has maintained a steady clip since 2017. Spend on water supply, transport, treatment, storage and disposal has increased 12% per year from $11.74 billion to a projected $15.49 billion by the close of 2019. From 2019 through 2028, Bluefield forecasts water management spend for hydraulic fracturing to average $17 billion per year.

It is a value chain that has rapidly grown in the last five years. E&P recently sat down with several thought leaders to discuss the continued growth and the growing pains facing the water midstream sector in the year ahead:

  • Matthias Bloennigen, director of upstream consulting, and Evan Tikka, senior consultant, at Wood Mackenzie;
  • Rob Bruant, director of products at B3 Insights;
  • Laura Capper, president and CEO of EnergyMakers Advisory Group; and
  • Andy Adams, director of water management and infrastructure for Select Energy Services.

E&P: What are your thoughts on the growth of the water midstream sector in 2019?

Rob Bruant
Rob Bruant

Bruant: We saw the true emergence of a water midstream market. It existed in a much more nascent state, but really in 2019, there was considerable growth in the sector. There was a large influx of private-equity capital to support the growth of the water midstream market, at a time when private-equity funds were not necessarily being made available to more traditional E&P entities. 

Associated with that is the increasing focus on reuse and potentially recycling water for beneficial reuse outside of the oil and gas industry. More and more companies are touting their environmental sustainability and operations that are supported by reusing produced water. It seems to be gaining momentum at the same time when there is a lot of emphasis and considerable research on some other opportunities to use this water outside of the oil field.

Evan Tikka
Evan Tikka

Tikka: We see 2019 as a year of scale and year of trust. Over the last 12 months, we’ve seen E&Ps and water midstream companies continue to plow capital into building out and scaling up their water infrastructure—more SWD [saltwater disposal] wells, more gathering systems, more pipelines and larger-scale recycling systems. It’s been a step change, in our opinion. 

From an E&P perspective, it’s been a year of a trust as we’ve started to see some of the larger U.S. independent and supermajors’ views change on the types of contracts and types of relationships that they’re willing to enter into with the water midstream players, characterized by longer-term acreage dedications and some larger divestments.

Look at what WaterBridge has done in the southern Delaware Basin. They’ve acquired close to 10 different systems, and all of those have resulted in a 10-plus-year acreage dedication. And we’ve also started to see some longer-term acreage dedication in the State Line area with some of the large E&Ps walking into these long-term acreage dedications that go through the 2020s and the 2030s.

Bloennigen: The water industry has attracted a diverse set of investors, ranging from infrastructure and private-equity firms to large foreign conglomerates, on the hunt for midstream-like growth opportunities. There is no shortage of dry powder on the sidelines; however, investors in the water midstream sector are entering with caution in mind. We’ve helped organizations execute thorough due diligence processes to ensure they are entering at a reasonable price and risking the opportunities appropriately. 

E&P: Will we continue to see more E&P companies selling their water infrastructure assets to water midstream companies?

Matthias Bloennigen
Matthias Bloennigen

Bloennigen: The short answer is yes. We believe the trend of E&Ps divesting water infrastructure is going to continue, with the exception of water recycling assets. In a world where E&Ps are capital constrained, water assets are offering operators some of the same benefi ts that midstream infrastructure offered in years past ... an opportunity to raise capital by divesting assets at attractive EBITDA multiples. We believe that E&Ps will continue to be less willing to let go of water recycling facilities as they provide operators control of water quality during fracking.

We are advising our clients to diligently research the assets being spun off from operators as we’ve heard multiple times from E&Ps that they’re more likely to sell their less strategic and underutilized water infrastructure assets. With the risks come opportunities for third-party water midstream companies that are able to integrate infrastructure and increase utilization by tying in additional third-party customers.

Bruant: All E&P companies are facing scrutiny with regard to their balance sheets and their cashflow. And one way that the companies can augment cash availability is to reduce capital spending or to make divestitures. [For] companies that may have had dedicated teams and infrastructure associated with water management, I would expect to see continued selling off of some of those assets to water midstream operators.

There is greater confidence among oil and gas producers that these water midstream companies can actually accommodate the produced water that is being generated. There is a greater appetite to shed some of those assets and provide them to midstream entities and then basically have their water management needs be met on a contractual basis versus reliance on inside expertise or dedicated assets within the company.

E&P: Cost is a key driver in water management. Are water costs increasing or decreasing?

Andy Adams
Andy Adams

Adams: The costs to provide a specific service or solution—largely labor, chemicals and capital equipment—are relatively fl at. But the solutions we are providing continue to evolve. This allows for efficiencies and the ability to reduce or avoid certain costs. As our customers continue to take cost out, many are relaxing water KPIs [key performance indicators], which enable us to reduce the type or amount of treatment. It also can result in less capital equipment as we continually refine processes to drive down cost. One example of this is if we recycle and treat water in a manner that maintains a certain ORP [oxidation reduction potential] level, then our customers can potentially decrease or alter their disinfection chemistry (for example, biocide versus oxidizer). Lastly, technology is contributing to
new efficiencies in water management. The automation solutions we have implemented at Select Energy create a safer and more efficient system that also allows us to avoid certain expenses.

Laura Capper
Laura Capper

Capper: Cost is absolutely a key driver to overall oil and gas profitability. The larger players are going to see their costs decrease over time. Relative to that, the smaller players that don’t have the infrastructure and the economies of scale are going to essentially be paying more on a per-barrel basis to manage their water. And that’s where I do see a divide. If you have enough volume and enough resources, then you can put together more effective water management programs. But if you’re a small independent operator, it is much more challenging, and your costs relative to the larger operators I think are going to go up over time, not down.

The pipeline companies know they have to have a reasonable value proposition—in most cases coupling transport together with the disposal. And so they may be charging a bit of a premium on the disposal side, but there are cost savings by routing it via pipeline versus trucking. So overall you should pay less in the bigger picture. We’re going to see more economies of scale as time goes along. But the question of water balance remains. Are we really going to be able to dispose of all the water that we don’t need for oil and gas operations? And what’s that capacity going to look like? How far away is that disposal capacity?

E&P: What are some of the challenges that water teams are facing in the year ahead?

Bruant: Things will continue to be challenging on the regulatory front. For example, New Mexico has been quite strict with regard to water disposal into shallow formations, and issuing new permits for that activity has kind of gone to almost zero. So operators in New Mexico are facing greater costs to dispose of the water into deeper formations. There is going to be a continued net movement of water from New Mexico to Texas, where the regulations are getting stricter but not nearly as strict. Permits are more easily obtained in Texas than they are in New Mexico, so we see a pretty significant flux of water moving from New Mexico into Texas disposal facilities that are permitted for shallow disposal intervals.

In Texas the Railroad Commission is definitely paying attention to permits that are submitted in the areas of increased seismicity or areas where there are known faults to exist. And those permits that are identified as being close to areas of possible seismicity are again facing later scrutiny or going through a longer review process, and operators see additional requests for data to substantiate the injection borings that they have prescribed on their permits. We’ve seen in numerous cases significant reductions made to the injection rates.

Capper: In most of our models, we show that there is going to be more produced water generated than can be disposed of in the local operating area. And even if we recycle it a really good clip, there’s still more produced water than we can get rid of into disposal wells on a local, cost-effective basis.

That’s just a reality in the Permian now, and no place is this more evident than in New Mexico where clearly the disposal well capacity is not keeping up with the amount of produced water. And so that water has to be dealt with some other way. It’s either going to be piped by a midstream provider probably into Texas to more receptive disposal wells, which is going on as we speak. Or it’s going to have to be dealt with locally, and we need to find new uses for that water. If the oil and gas industry can’t use all of its own produced water, can we give it to agriculture? Can we give it to farming or some other industrial use that keeps it in the hydrocyle? 

There are a lot of folks starting to look at beneficial reuse. Challenges include kind of an unknown regulatory landscape, how that’s going to unfold and the pace that it’s going to unfold. My personal belief is that we need to start looking more critically with a longer window into the future at things like our selection of biocides for use in frac fluids. What’s the residual of those biocides? Are we going to be 100% comfortable discharging water that was treated with certain biocides or giving that water to a farmer to water crops that may be consumed?

I believe there’s going to be a lot of ongoing learning into what the regulatory framework should look like for beneficial reuse. Technical, environmental, costs and regulatory research on these beneficial reuse issues is in fact a key charter in 2020 for the state of New Mexico, where we and other volunteers are working with a team of exceptionally qualified government, private and industry stakeholders who are collaborating to solve these challenges under the New Mexico Produced Water Research Consortium. Given long timelines for regulatory changes, I would say there is urgency in thinking about those issues sooner rather than later, and folks are rapidly coming on board and supporting these initiatives. But there is so much more work to be done.

Adams: The greatest issue I see is the logistical challenges of managing and sharing water. Everybody wants to share the water; everybody wants to reuse produced water. But the most difficult aspect of this is actually managing the logistics of delivering the water safely and on time. The challenge with utilizing produced water is that there is never enough in the right place at the right time. Your refresh rate isn’t enough to meet frac demand or compensate for what is in storage, so brackish water is often needed as a supplement. Providing a turnkey solution that doesn’t interfere with the operation of the frac is a challenge. That’s something I believe we do well at Select because we provide each of those services to customers every day. Managing and understanding all the drilling and completions schedules, water KPIs, supplies and more in a format where you can make it work financially and logistically is really difficult. We’ve invested millions of dollars into technology, specifically in developing a water dashboard to track and manage water from source to disposal and every step in between.

Bloennigen: Reliability of handling ever-larger volumes of water is one of the primary challenges being fought by water teams as any mishaps could be very costly and lead to production disruptions. This all goes back to our theme of scale and trust.

On the technology front, we are keeping a close eye on enhanced evaporation as we believe that it could become a game changer one day. As of today, it is not close to being cost-effective. If someone could actually make it a lot cheaper, say into the range of 50 to 60 cents per barrel of produced water, it would be a game changer.

Tikka: One of the things that the industry probably doesn’t think about enough is that unlike hydrocarbon production, E&Ps aren’t incentivized to maximize their water production. It is ultimately a liability and a cost. One of the areas we’ve been helping E&Ps with is identifying ways to limit the amount of water production that’s coming out of the wellhead, or to put it another way, maximizing the amount of water that stays in the reservoir. Some of the conversations we’ve had are focused on artificial lift selection, the chemical program and more. These are areas that are still out on the fringe of conversations but are still being discussed.

Bloennigen: Avoiding water production in the first place. That is a new technology front that needs to be explored.

Read E&P magazine's March 2020 "Water Management Techbook" articles:

Bringing Balance to Water Demands   (story above)

Meeting Water Management Demands  

Innovations in Water Management Technology  

The Rise of Water in the Midstream