Where Will All the Water Go?
As operators in the Permian and elsewhere across the United States and around the world announce capex cuts of 50 percent or more, drilling rigs are stacking up like dry bones in the valley. A two-thirds (so far) reduction in drilling means a similar cut in frac’ing.
Saltwater disposal wells (SWDs) and their attached pipelines in the Permian were already strained due to record production increases since 2010. Now it seems the reduction in drilling and completions could, at least in the near term, push SWD capacity over the edge, say some water midstream experts. This could indeed be a near-term issue only, as commodity prices descend into negative territory, forcing producers to shut in more and more wells.
Everyone wants the oil from a well but what they actually get is anywhere from 4-10 times as much water as oil, depending on the basin and the age of the well (water cuts tend to increase as a well’s oil production decline curve plays out). Except for what’s recycled for fracturing, the rest of the water is currently unusable for anything other than disposal. Efforts are being made to reduce the cost of treating water for other uses, including agriculture and even municipal input, and some feel those alternatives may be the solution someday, possibly sooner than later.
Joshua Adler, founding CEO at oilfield water data analytics company Sourcewater, says about 12 percent of produced water is recycled for use in fracturing. That number is up from about two percent being recycled as recently as four years ago. Now much of that 12 percent is headed instad for SWDs, which could strain the wells and the system. Everyone polled in this story feels that some combination of sub-$20 oil prices and costs or restraints on produced water could cause a significant number of wells to be shut in.
Shutting in wells, of course, would reduce the flow of produced water much faster than would be seen in natural decline curves, which could alleviate the problem after a few months. Samuel Oliver, Chief Commercial Officer for water midstream investor BlackBuck Resources, said he knows of one company that has already shut in almost 100 wells due mainly to water disposal issues.
Even with oil prices at two-decade lows, Oliver said producers who are hedged at $55-$60 per barrel can continue to produce profitably, as long as there is storage capacity somewhere, an issue that is of growing importance as demand has dropped by as much as 35 million barrels per day.
Continued production of oil means continued production of water, but “treating of water will drop to near zero,” he said. “There may not be enough disposal capacity, in the short term. There is a decline, so eventually, if you never drill again,” water production for some producers could drop below flow rates they’ve contracted for with water midstream companies. He doesn’t expect this to be an issue for several months.
Producers who have water midstream takeaway contracts that allow leeway for switching to more disposal than recycling will be okay. But if excess disposal requirements drive producers to the spot market, they may pay a premium, Oliver believes. “If [oil] prices materially improve for the short term, it will drive commercial [disposal] rates up,” he said. “Any disposal company, if they have spot market capacity, can handle your fluid, but the price now goes up.”
In Addition to Pipelines and Wells, Concerns about Formation Capacity
Source Rock Midstream President Ben Samuels also sees a congested SWD market in the short term. “I have had a number of conversations about this exact issue, and there are competing theses that there are going to be certain disposal zones that are going to start to fill up within weeks from now,” Samuels said. He cited the San Andreas formation in northeastern Martin County and across into Borden County, which has absorbed copious amounts of produced water over the years, but is now reaching saturation.
There are two options when that happens, both of which would seem to be cost-prohibitive at sub-$20 per barrel oil. “You either have to drill potentially down to the Ellenberger,” for which drilling costs would be three to four times that of a traditional disposal ($8-10 million versus $2.5-3 million for a traditional well).
“Is that the answer, or is it, now I have to truck produced water to somewhere else?” Even before this downturn, Samuels was seeing pipeline congestion issues due to record oil production in the Basin. “I think it’s going to become a major issue. I think going to see a lot of above-ground storage in ASTs (above-ground storage tanks) or things of that nature.”
In the near term Samuels agrees with Oliver’s concerns about shut-ins. “I think there’s going to be a number of operators that will have literally no choice other than to shut in only because they cannot move their products—whether that be the crude they’re producing or the water. If you have nowhere to take it, you have no other options.”
Creativity is the Key to the Future
Hard times often lead to innovation and Samuels sees evaporation as an idea whose time may have come. “Some groups are talking about cleaning the salt water in a series of Weirs and then evaporating it into the air.”
He continued, “There are a number of technologies that could take hold if they’re given the opportunity. If some of those technologies end up being viable and scalable, those things could completely change the industry for years to come.”
There Are Two Sides to This Coin
Sitting on top of a massive database of water resources covering fresh water, disposal, pipelines, and more, Sourcewater’s Adler fills in some gaps—and sees things a bit differently.
Disposal capacity is not the only issue—disposal costs themselves, said Adler, can be at or near the top of production expenditures. “In 2018, in the Permian Basin, on average, about $5.11 was spent on the transporting and disposing of water, for every one barrel of oil produced. And in the Delaware Basin it was more like $9.44 per barrel of crude produced.”
At $19-20 per barrel pricing, Adler said “A lot of wells are going to get shut in, especially the ones for which water disposal costs are almost half that amount.
But while he noted that drilling and fracturing are down by two thirds, he is not concerned about that creating a backwash of SWD inflow. “Logically, it’s kind of a wash.” While fracturing uses a certain amount of produced water, Adler notes that the drilling slowdown will also slash the amount of flowback from fracs.
“So, yes, if frac’ing stops, then there’s no recycling, so any water coming out of the ground has to go to disposal. But you’ve also, within a few months, cut off the flowback component.”
So, “Recycling would basically go away, but the amount of water going SWDs shouldn’t change very much,” because of the associated dropoff in flowback water.
In the longer term, it is true that the ratio of water to oil goes up, but there is a decline curve in the volumes of water produced, similar to the decline curve in oil, Adler noted. This would give SWD operators a more steady flow of water as opposed to spikes that happen in areas with sudden inflows from frac flowback.
Shut-ins and bankruptcies are “where things go haywire” in predicting SWD input, he said. In structuring contracts with producers, SWD operators would make a baseline assumption that all wells in a field will continue to produce, and would use standard decline curves to set prices and inflow minimums. “That water pays the bills and the upside is the flowback from the fracs, and the growth in production that comes from new wells over time.”
The expected variable would center on a possible dropoff in fracs as the price drops—but with shut ins and bankruptcies even the baseline assumptions are made invalid.
Water midstream entrepreneur Matt Giblet believes this shutting in of wells will quickly alleviate any uptick in disposals based on reduced recycling—which could lead to challenges for SWDs and pricing help for remaining producers. Enough shut-ins could bankrupt SWDs as well, and would certainly lead to per-barrel price reductions, he believes.
“The ones [SWDs] that don’t go out of business are the ones that are going to play ball. I don’t think you’re going to see rates where they’re at right now because, if you own a saltwater disposal well, especially if you’ve been around a while, you’re going to cut way back on your pricing. I would run it at cost-plus-10 percent as long as I could.
For a short-term uptick Giblet agrees that evaporation as preferable to shutting wells in.
Since April 20, when prices dropped below zero, shut-ins are rapidly gaining momentum, so any waterflood overflow may indeed be short-lived—at least until Covid-19 restrictions are lifted and the world begins to burn off the storage backlog of crude and refined products.
In the last five-plus years, water has become a major subset of the oil and gas industry. Water midstreams have arisen, many of which handle all aspects including fresh, produced, recycling, and disposal. Now they, like every other oil and gas sector, are facing decisions that likely will change their operations forever. Some changes will be for the good and possibly should have been made sooner. On others the jury may still be out, pending the rebound from Covid-19 shutdowns.