Why Produced Water Is Becoming the Permian’s Most Important Planning Variable
Oil production numbers used to be the main signal operators and investors watched in the Permian, but that appears to be changing. B3 Insight CEO Kelly Bennett and Campbell Gough of B3’s Product Management team have highlighted why produced water volumes, disposal capacity, and formation pressure are now driving decisions that used to be made almost entirely around drilling schedules and commodity prices.
Water Is Growing Faster Than Oil
B3’s forecast projects produced water volumes across the Permian’s Midland and Delaware basins reaching approximately 29 million barrels per day by 2036. That growth is structural: as the basin matures, the ratio of water to oil keeps climbing, so volumes will keep rising even if drilling slows. Water is no longer a byproduct of the drilling schedule. It has a trajectory of its own.
Reuse Has a Ceiling
Reuse already supplies approximately 67 percent of the water used in completions and B3 projects that share reaching 95 percent by 2036.. But reuse is bounded by how much water completions actually need and available infrastructure to ensure it is available on time and in the right place. Even at 95 percent of completions needs, reuse cannot absorb everything the basin produces, and the volume left for disposal keeps growing. Reuse growth and disposal needs getting larger are not contradictory. They happen at the same time.
Disposal Capacity Peaked in 2024
B3’s InjectIQ platform models formation pressure and volumetric capacity well by well, applying physics-based decline modeling to every operating saltwater disposal (SWD) well in the basin. What it measures is operational capacity, meaning what a well can actually accept within the bounds of its permit, By that measure, capacity across the existing Permian SWD base peaked in 2024, and new wells coming online are largely replacing capacity lost to pressure buildup rather than adding to it. Pore space can’t be built, only used, which means the next round of investment has to go toward finding, permitting, and developing usable reservoir.
InjectIQ gives operators and midstream providers a clear view of where capacity is eroding and where new investment creates the most value as they seek to maximize the volumes they can manage. Learn more at b3insight.com/injectiq.
The Permian Sub-Basins Are Constrained Differently
While the Permian Basin is often treated as one water market, the difference between the Delaware and Midland sub-basins illustrate different capital needs. The Delaware’s constraint is geologic: water production is projected at approximately 20 million BPD by 2036 into reservoirs that have absorbed decades of concentrated injection, and InjectIQ modeling shows approximately 7.9 million BPD of unmet disposal demand there by 2036. The Midland’s constraint is logistical. It holds surplus operational capacity in aggregate, but injection is heavily concentrated, with 63 percent of basin disposal sitting in just three counties, meaning localized tightening in areas like Dawson, Martin, and Midland County is already visible even as basin-wide capacity remains sufficient. One basin needs long-haul takeaway and the other needs interconnection.
What it Takes to Add Capacity
Adding capacity has gotten harder for the same reason capacity is eroding: pressure. The RRC’s revised permitting guidelines, effective June 1, 2025, require applicants to identify and evaluate every wellbore penetrating a proposed disposal interval inside a significantly expanded area of review. Pre-permitting costs can now reach six figures before a new SWD is drilled, and approved SWD permits are down 85 percent year over year. New Mexico’s permitting is tighter still with incredibly slow growth in capacity, resulting in approximately 3.1 million BPD of New Mexico’s produced water crossing the border into Texas for disposal.
B3’s InjectIQ modeled what happens if every currently approved permit across the Delaware Basin and Central Basin Platform comes online as quickly as possible: roughly 438 new disposal wells at approximately $5.5 million each, representing around $2.9 billion in well capital alone, with total system capital of the order of $5 to $6 billion once export infrastructure is included. Capacity added through 2031 primarily offsets pressure-driven declines in existing wells before it begins adding meaningful net new headroom.
That is why more than $750 million in long-haul water pipeline projects were announced in the past year, routing water from pressure-affected Delaware areas toward zones with greater long-term headroom, particularly the Central Basin Platform. Pressure Is Now an Asset-Level Economic Driver
Pressure has become a constraint on the disposal well’s entire useful life. As formation pressure rises, new wells drilled into already-pressured intervals start with lower initial capacity and decline faster, meaning the economics of each new well get harder to justify even as the need for disposal grows. It also erodes acreage. B3’s analysis of Delaware footprints larger than 50,000 acres found annual reservoir availability losses of 2 to 5 percent from offset disposal pressure development, with some assets losing 10 to 28 percent cumulatively over six years. That is why large, contiguous surface positions now carry strategic value: they let a disposal operator direct injection within its own acreage to maximize the amount of usable reservoir while insulating new wells from the impacts of offset injection. Permitting alone does not provide that control, which is why several companies have pursued land acquisitions as a key part of their disposal strategy.
Where the Displaced Water Goes
Water that local disposal cannot absorb has five places to go: distant disposal within the basin, out-of-basin distant disposal to Central Basin Platform, deep disposal, evaporation and desalination, and treatment for beneficial reuse, including surface discharge, irrigation, industrial use, and cooling for data centers and power generation. Each should be judged on scalability and time-readiness of technology and cost: how long until it can absorb meaningful volumes and what it costs per barrel versus conventional disposal. At present, disposal, including with long-haul pipeline development, presents the most scalable, cost competitive option, but treatment projects are under development. The next year will provide critical information about permitting and unit economics for treatment facilities; with a clear regulatory path and operational insights from large pilots, expect more project announcements. Data center and power generation projects under consideration in West Texas provide exciting potential water users and sources of both heat and power for treatment.
The Bottom Line
Water is now a first-order factor driving capital allocation like drilling decisions and asset acquisition rather than a cost managed after the fact.
The complication is timing. Without a meaningful revenue stream from treated water sales, B3 estimates gathering and disposal costs would need to rise 75 to 100 percent before the largest treatment infrastructure projects become competitive. Operators partnering with midstream platforms that operate distant disposal options may be accepting slightly higher prices today but will enjoy greater surety of water takeaway and thus oil production. Understanding how pressure-related disposal dynamics will evolve over the next decade is critical to success.
“The trade-off is clear: paying a premium today for guaranteed capacity tomorrow may buy cost advantage on a large portion of production costs tomorrow.” Kelly Bennett, CEO, B3 Insight
Read the full summary: 6 Forces Shaping Permian Water Management through 2035