Investment research firm TSCS reports that 60 to 65% of the highest-quality acreage in the Permian Basin, the most productive US shale basin, has already been drilled. The firm also estimates that only 3 to 4 years of Tier 1 premium inventory remains at the current drilling rate. This is driving industry-wide strategy shifts as companies move to lower tier and speculative acreage to maintain production.
Although these reserves are accessible, they pose challenges, including lower rock quality, higher temperatures, increased associated gas, and greater water production per barrel, all of which substantially increase production costs.
Hydraulic fracturing in the Permian requires approximately 15 to 20 million gal of water per well. With the region experiencing severe drought conditions and aquifer levels at historic lows, operators face mounting water costs that do not appear in headline production figures.
Some operators report water costs exceeding $5/bbl, a 300% increase from 2019 levels. Recycling infrastructure cannot keep pace with demand, and freshwater sourcing faces increasing regulatory scrutiny.
Despite these challenges, environmental efforts are focused on reducing flaring and the rate of water injection into saltwater disposal wells. While these are reasonable and important environmental goals that should be viewed positively, they add complexity to the already emerging challenges of secondary acreage.
In this context, Merichem Technologies developed a new technology, Ecotreat, and chemistries for gas desulfurization, using produced water as a solvent for gas conditioning. The solvent-based technology involves a modular treatment process that uses a proprietary catalyst designed to safely and sustainably remove hydrogen sulfide (H₂S) from sour gas streams using either produced water or an alkaline water as the treating media.
The solvent-based technology underwent a successful month-long field trial in the Permian to demonstrate whether it could achieve sustained removal of H2S without producing solid waste.
The Technological Solution
The solvent-based technology covered in this case study employs a proprietary water-soluble catalyst that forms covalent bonds with H2S, resulting in an irreversible reaction unless further chemicals are added.
Changes in pH or temperature do not release H2S. Each catalyst molecule can react with H2S multiple times, achieving similar efficiency to existing liquid scavengers. The reaction continues until the catalyst is fully spent. Unlike triazine (i.e., a scavenger chemical) derivatives, full consumption of the catalyst does not harm the product or produce amorphous dithiazine. The catalyst bond remains stable under low-grade heat and pH changes.
The catalyst can be regenerated in air under ambient conditions. When exposed to oxygen, it rapidly oxidizes H2S to thiosulfate anions and releases the catalyst from the bond. Thiosulfate anions are highly soluble in water and acidic, so the solution must contain sufficient cations; carbonate salts are particularly effective.
Produced water, such as that from the Permian, where it is generated at multiple times the rate of oil, is a brine rich in salts which contain sodium, calcium, and potassium. Its high salinity, typically above 3.5%, provides strong buffering capacity due to sufficient alkalinity present in the water, making it suitable for this reaction. The cationic strength effectively buffers the thiosulfate ions formed. Small volumes of water can absorb at least 5% of their weight in sulfur and can then be diluted into the main produced water stream, resulting in a minimal increase, often less than 1%, in total sulfur-oxoanion content.
This chemistry can be implemented in a variety of ways, but the simplest is a pair of vessels: an absorber and an oxidizer. Additional equipment, such as a condensate knock-out pot or flash tank, may also be required.
The field installation included two columns for testing: a packed bed column and a bubble column, also called a liquid full absorber (LFA).
A skid-mounted test system was equipped with process control and a compressor to provide utilities. Due to the small size of the tubing and relatively low flows, the unit was insulated and traced to prevent temperature fluctuations from affecting data collection accuracy. The columns included an oxidizer, a flash drum, a bubble column, an inlet knock-out, and a packed column.
The skid was transported to the site horizontally, set up in a field near Jal, New Mexico, and powered by a diesel generator. Gas from the separator was collected and returned to the sales gas line prior to custody transfer, but free of H2S.
Experimental planning included more than 30 days of testing and was broken down into three primary modes. The treatment solution was evaluated for pure potassium carbonate versus produced water, and the absorber design was evaluated for either packed-bed or bubble-column operation.
The Field Trial Process
Trials began with a prolonged start-up period due to low available sales gas pressure.
The technology developer’s staff worked with the wellhead pumper staff to improve available pressure from an initial supply of less than 10 psig (i.e., gauge pressure). This was insufficient to supply the skid, causing some of the data to be discontinuous.
Once the operation was smoothed out, several test runs were made. One of the runs clearly demonstrates more than 99% removal of H2S throughout the run. In this test, the unit was fed more than 14,000 ppm H2S, whereas it was designed to receive only a maximum of 10,000 ppm in the feed. In this condition, the unit exceeded its nameplate capacity of 2 lb/D of H2S.
For several more days, the operation was changed to utilize the LFA system. As in the packed bed, the solution was continuously circulated in a loop from the LFA to the oxidizer and back to the absorber. In this condition, a similar supply gas was used, but the overall concentration was much steadier over this period. Once again, sustained removal of more than 99% H2S was achieved. This trial showed a smooth operation.
The final test was conducted utilizing produced water. During this run, 16 gal of produced water was charged into the system each day and allowed to flow to completion during operation. In each day’s run, about 0.5 lbs of sulfur was removed. This created a ratio of about 30 gal of produced water per pound of sulfur removed. The alkalinity of the fresh produced water was very low. The produced water contained very small amounts of carbonate and mostly high levels of chloride.
This made the produced water used at this site one of the most challenging samples for the solvent-based technology process, yet the H2S concentration, gas ratio, and water ratio were sufficient to treat all the sales gas with produced water from the same wells.
Conclusion
Using the solvent-based technology, produced water offered an excellent, low-cost treatment opportunity at this well site, effectively treating the entirety of gas production with water from the associated wells. Even the use of pure potassium carbonate would have been a new and exciting opportunity to improve treatment options. The majority of components required to perform treating are already available at the wellhead, with only the catalyst and electricity needed to remove H2S in an environmentally advantageous way.
The solvent-based technology in this case study removes any H2S dissolved in the produced water, reducing downstream water handling hazards. With a reduced need to ship and maintain chemical inventories, this alternative proprietary solvent-based catalyst is environmentally friendly and offers substantial cost savings. There are a variety of advantages to this technology over existing applications, which has now been demonstrated in a field application.
As Tier 1 drilling locations become depleted and operators move to less productive areas, shale can continue to deliver, especially with innovative solutions to impurity treatment using readily available produced water in an environmentally favorable way.
Jeffrey Gomach is the senior vice president of Merichem Technologies and responsible for projects, engineering, and research of Merichem's sulfur treatment and fiber film reactor technology portfolio. He has worked at Merichem for 14 years and has patents in mercaptan, carbonyl sulfide, and H2S removal techniques. He’s previously worked for Topsoe and the US Air Force Research Laboratory. He holds an MS degree in chemical engineering from the University of Dayton.
