The Permian Basin has long been considered the place to be for many operators. The Permian has produced about 30 billion barrels of oil and, according to Woods Mackenzie, about 2-3 times that amount is still in the ground.
The Permian has accounted for two-thirds of the increase in U.S. oil output and a quarter of the increase in global production. The beauty of the Permian is that it is a stacked play with multiple pay zones to drill into. As time goes on, operators get better and better at drilling into these multiple pay zones. From zipper wells to “triple zippers” to multi-well pads, operators continue to drive down cost and increase oil production.
What does this have to do with water? The Permian is also a prolific producer of water. After the Mississippi Lime, the Permian has one of the highest water-to-oil ratios, with the average about 4.5-5:1. The Midland Basin is about 2:1 and the Delaware Basin can reach 5-7:1 for older wells. This leaves a significant volume of produced water to manage. Estimates are as high as 500 MM bbl/month, with total fracing demand around 200 MM bbl/month. For the water management industry, Plan A has always been injection wells, either saltwater disposal wells or waterfloods for enhanced oil recovery.
Sidetracked by Seismicity
In Oklahoma, Plan A was sidetracked when induced seismicity, also known as earthquakes, reared its ugly head. Since 2008, earthquakes measuring magnitude 3.0 or greater increased from two to nearly 900 quakes a few
years later. We learned it was Oklahoma’s unique geology that was triggered by water injection and not the idea of water injection that was at fault.
We won’t see that scale of seismic activity in the Permian, at least not to that extreme. There have been magnitude 2.5 quakes in the Permian; as many 60 in one year. However, the difference between a magnitude 2.5 and
3.0 quake on the Richter Scale is significant. A magnitude 3.0 earthquake is three times more powerful than a 2.5.
As someone born and raised in California, I have slept sleep thru magnitude 2.5 quakes and would probably sleep through a 3.0.
Regardless of our personal thoughts, regulators are paying attention. New Mexico has already made permitting of SWDs more difficult and the Texas Railroad Commission (RRC) may be moving in the same direction. On Dec. 5, the RRC announced it is considering new restrictions on SWDs and new rules could be approved by the end of the year.
For water managers, that brings us to Plan B. For many operators, Plan B is a produced water recycling program.
In the past, some operators hesitated to reuse produced water as a completion fluid. Over the years however, data supported produced water reuse and as a result, more operators have pursued a program.
Eventually, water treatment goals were refined. At first, the goal was to remove salts and dissolved solids. Later, many discovered that wasn’t necessary and water treatment goals became simplified.
For well completions, there are similarities when we look at how proppant quality requirements have evolved. A few years ago, proppant quality was the primary concern and operators brought in sand from Wisconsin.
Currently, proppant quality concerns are not more important than available quantities and logistics. Many operators mine sand in their own backyard, as we see in Monahans, Texas.
Produced water treatment is not so different. Today, quality is less important, and quantity is more important. Of course, treatment quality standards are as important as ever. Our experience shows standards have been narrowed to bacteria, iron and sulfides.
Entrained oil and solids are primarily managed thru existing infrastructure, such as tank batteries and gun barrel systems. This simple treatment scheme has made produced water recycling less expensive than even disposal. Compared to the treatment trains of the past, produced water treatment has been narrowed to a couple simple steps. As a result, produced water recycling costs have been reduced significantly.
From here, Plan B seems like a good one: recycle produced water at a lower cost than SWD disposal. Great news.
Unfortunately, Plan B is a Band-Aid and it is too small.
When we look at the numbers again, there are 500 MM bbl/month of produced water generated and only 200 MM bbl/month needed for well completions. Even with an aggressive recycling approach, the industry could reach 150 MM bbl/month recycled, but logistics makes this difficult.
Takeaway capacity has caused completion activity to slow down. Oil company spending in the fourth quarter has reduced completion activity largely due to a 20 percent slide oil prices since October. As a result, demand from well completions simply cannot be considered a reliable outlet in the long term. Even with a completions uptake of 30 percent of all produced water generated, that would leave 70 percent, or 350 MM bbl/month, undisposed.
Back to Plan A?
The tried-and-true Plan A, salt water disposal, will always be the backbone of produced water management. Today, the question is: will it always be there? Look in the Midland Basin at the San Andres Play for example. This pressured up disposal zone is causing more than just a disposal problem. Just drilling through it is a challenge. Then you have hydrogen sulfide issues complicating matters even more. The pressuring up of the San Andres is not just an SWD issue.
What about waterfloods. There are operators using this EOR method to improve production from existing fields and they do manage a significant volume of produced water this way. If waterfloods aren’t in your plans, then maybe they should be. Of course, EOR is limited to those operators who have fields with enough older wells for this to make sense.
New SWD Concerns
So where does this leave us with salt water disposal? With its Dec. 5 announcement, the RRC seems truly concerned. But a tripling in the number of magnitude 2.5 quakes is not anywhere close to what happened in Oklahoma. There, they had more than 900 events of magnitude 3.0 or more. In comparison, Texas had 60 events of magnitude 2.5, three times less powerful.
Does this seem like a possible overreaction? Whether you agree with RRC’s action or not, we have already seen New Mexico pull back its support of for SWDs. The RRC seems to be moving in that direction.
Plan A may come at a price. For midstream operators, this may mean using their network to move produced water to areas where SWDs are less restrictive or pressured up.
Induced seismicity may not be the only issue affecting underground injection. Look at the San Andres, for example. The issue in the San Andres it is not induced seismicity but a pressured-up formation that is losing capacity for more water and the ability to drill through it.
As a result, earthquakes aren’t the only threat to SWDs; capacity is also a concern. I’m not a geologist, but I have been told that using surface pressure measurements to regulate reservoir pressure does not tell the whole story.
The experts say when you take surface pressure and translate it intoreservoir pressure, capacity is being lost. I won’t render an opinion here, but it is clear the regulators are paying attention. What I do know is the oilfield is resilient and always finds a way. Even so, a Plan C is needed.
The question is, what does Plan C look like? There is talk of a pipeline to the Gulf of Mexico, but that does not seem realistic. It will have to be something different.
Of the options, the simplest is improved evaporation processes. Another option is discharge quality water or finding an agricultural use like cotton that is salt tolerant and doesn’t need discharge quality.
As an industry, we need to develop a Plan C. Putting our head in the sand, or in the proppant, and hoping that Plan A never goes away is not the answer. Underground injection will likely never go away but it may be restricted in some places. Plan B is limited by inconsistent well completion schedules driven by volatile oil prices. The answer is a safety net; a Plan C.
Treatment system options range from floating surface-spray evaporators all the way to crystallizers, basically low tech to high tech. Many of these newer systems are designed to produce a clean distilled water, which increases the cost. Straight evaporation will likely be the more cost-effective choice. Hydrozonix has developed an evaporator driven by field-gas, but there are a variety of options available. The trick will be developing an evaporation system that works in high TDS without fouling.
The next challenge is what to do with all that salt. We’re talking mountains of salt. Some salt will be used for heavy drilling brines and kill fluids, but there will be mountains of salt, mostly low-grade stuff that would require further processing. Established industries that consume salt would not place much value on this low-grade byproduct, so the most likely option would be industrial disposal cells similar to fly ash and other industrial residuals.
Discharge quality or ag reuse will require some level of treatment. Options include membrane filtration ranging from forward osmosis to reverse osmosis and membrane distillation. Other options include vapor recompression and crystallization.
These additional steps usually require a treatment train with multiple stages. Of the Plan C options, these are likely the most expensive. Although costly, they may also be the most reliable in terms of consistent quality.
A few years ago, this these technologies were in the range of $4-$6 bbl. Today, some claim the cost needs to be closer to $1 bbl For Plan C to be realistic. And disposal of salt or brine is still and issue.
Plan C will come with challenges, but none than can’t be overcome. Many believe that producing a discharge quality water is workable with SWDs used to dispose the brine. Maybe that is the path forward.
A produced water Plan C needs further evaluation but over the next two years, I believe it will come into focus. Having a fallback option is too important when it seems Plans A and B might not work out.
Authored by Mark Patton
Mark Patton is president of Hydrozonix. He has more than 25 years’ experience in the development, design, implementation and operation of treatment technologies. Mr. Patton’s oil and gas background includes treatment systems for waters, wastewaters, drilling muds, tank bottoms and process residuals. He holds one produced-water patent with two additional patents pending.
Mr. Patton earned his B.S. in chemical engineering from the University of Southern California in 1985.