[Editor's note: This story originally appeared in the March 2020 edition of E&P. Subscribe to the magazine here.]
IHS Markit estimates the U.S. oilfield water management market to be valued at approximately $40 billion in 2020, representing a 5% year-on-year market growth above 2019. This is mainly driven by the water disposal and water logistics segments as produced water volumes continue to increase. In fact, produced water is expected to grow at a 1.7% CAGR through 2024 for the U.S. market.
The Permian Basin continues to produce and demand the largest volume of oilfield water among all U.S. onshore regions, with water spending in the region estimated at $13.3 billion in 2019 and produced water volumes of about 6.5 Bbbl. Permian Basin water disposal volumes contribute to more than 30% of the total disposed volumes for the onshore U.S. market. Volumes increased more than 40% between 2010 and 2019, and disposal volumes in West Texas reached a five-year high in 2019.
To further put the water market in perspective, a typical well in some of the most productive basins could have an initial 2:1 water oil ratio (WOR). By about year four, the amount of produced water could double to 4:1 per well; and this ratio could be as high as 10:1 for legacy wells. In the December 2019 WaterIQ report published by IHS Markit, it was estimated that in 2020 wells in the U.S. would produce 20 Bbbl of water—up almost 5% from 2019 volumes alone. IHS Markit projects that produced water will increase to 22 Bbbl by year-end 2024, a nearly 9% increase, under the “base case” assumptions.
Now that there is a considerable and established legacy production, operators fully realize the extent to which produced water is not only a sizable issue but also an ongoing and perpetually growing challenge.
Recently, IHS Markit conducted an annual proppant market survey to capture the leading-edge view of industry stakeholders. Participants were asked, among many questions, which technologies, techniques or improvements they foresee operators using, adopting and/or re-implementing within the next six months. Out of the 11 technologies, the second highest resulting rank in expectation of adoption/utilization was “improved chemical and fluid designs.”
Reducing formation water with advanced chemistry
To assist with the produced/formation water challenges in the onshore U.S. oilfield industry, Hexion’s AquaBond formation water reduction technology can be implemented as part of an operator’s water management strategy. The AquaBond technology is a proppant coating that alters the relative permeability of the proppant pack to flow hydrocarbons over water preferentially. This product has the ability to reduce WORs. This can lead to increased revenue from improved oil and gas production and reduced costs associated with treating, transporting and disposing of nuisance formation water.
Other commercially available relative permeability modifiers may wash off and lose effectiveness over time. As the well matures and the volume of produced water increases, the benefit of running these chemicals is lost. The AquaBond technology is a chemistry that is part of the resin coating, so it will remain in place on the proppant for the life of the well.
The resin coating has a secondary benefit of controlling proppant flowback by forming a consolidated proppant pack at temperatures as low as 120 F. It is important to note that consolidation is not necessary to achieve the water reduction characteristics.
The AquaBond technology proppant pack acts as a semipermeable membrane that admits hydrocarbons and limits the admission of water (Figure 1). The contact angle and surface energy of the coating have been altered so the proppant has this characteristic. Details on how the concept was proven and tested are outlined in the SPE-191394-MS paper. Additionally, numerous laboratory tests have been conducted to ensure the technology is effective with various crude oil and formation water samples. The salinity of the formation water does not appear to have any effect on the water reduction characteristics.
Only standard hydraulic fracturing equipment is needed to use AquaBond technology. Because it is already on the proppant, it is pumped downhole using the same method as traditional proppants. In most cases, only a tail-in percentage of the total proppant is needed to achieve desired results (increasing the tail-in should result in improved water reduction/production enhancement). If proppant flowback control is a concern, care must be taken to ensure the technology is placed near the wellbore. Fracturing water should return to the surface per typical flowback procedure. Once hydrocarbon and formation water contacts the chemically altered proppant pack, the AquaBond technology will preferentially flow hydrocarbons over water. The result will be more oil and gas and less water produced to the surface.
Recently, Hexion launched its mobile resincoating plant in the Permian Basin. The Voyager resin-coating service is currently located in Kermit, Texas. This unit can be deployed anywhere in the world and coat AquaBond technology on local sand. By using in-basin sand and the resin-coating system, operators can utilize AquaBond technology for reduced logistics cost.
Operators have utilized this product in multiple basins. In the Permian Basin, a comparison was made between two AquaBond technology wells and 11 traditional resin-coated proppant wells in the San Andres Formation. All 13 wells had identical completion details: true vertical depth of 5,280 ft, lateral length of 5,300 ft and 3 MMlb of total proppant per well, with a 16.5% tail-in of either 20/40 traditional resin-coated sand or 20/40 AquaBond technology. All wells in the dataset were from the same operator and service company.
After seven months, the AquaBond technology wells had a 15% decrease in water cut and a 17% increase in oil production (Figure 2). Water disposal costs for this operator were $1.25/bbl. The reduction in water production saved more than $150,000 per well. If the 11 offset wells had utilized the AquaBond technology, total savings would have been more than $1.7 million. The 17% increase in oil production yielded an average additional revenue of more than $500,000 per well.
Formation water continues to be a concern for operators, with volumes expected to increase through 2024. The Permian Basin is a major contributor, generating 34% of the water produced in the U.S. The AquaBond technology is bonded to proppant, so the modified surface chemistry remains in place and effective even as the well matures.
Texas American Resources Co. retained PetroDivest Advisors to market for sale its oil and gas leasehold and mineral interests in Burleson and Washington counties, Texas.
XTO Energy selected EnergyNet as the exclusive adviser to market a Permian Basin operated opportunity located in Loving and Winkler counties, Texas, through a sealed-bid process closing Sept. 15.
Wagner Oil retained TenOaks Energy Advisors for the sale of four packages comprising South Texas, South Louisiana, Permian Basin and Delaware Basin royalty interests.