Water and Sand for Future Eagle Ford Oil and Gas Production, South Texas

The U.S. Geological Survey has assessed how much water and proppant would be needed — and how much formation water would be produced — if the undiscovered oil and gas in the Eagle Ford Group of south Texas, rocks of Cenomanian–Turonian age, were developed. The assessment is tied directly to the USGS's 2018 geology-based estimate of the Eagle Ford's undiscovered, technically recoverable continuous oil and gas.

Why water and sand

Oil and gas in continuous (unconventional) accumulations like the Eagle Ford can be produced only with hydraulic fracturing: large volumes of fluid, water carrying proppant — mainly sand — are pumped into the reservoir, and the proppant holds the new fractures open so oil and gas can flow. Water is also part of drilling mud, some of which is lost into the surrounding rock, and is needed to cement the well casing.

Production brings up wastewater too:

• flowback water — fracturing water that returns early in a well's life. It could not be assessed here for lack of data;
• formation water — water that exists with the oil and gas in the rock, produced throughout the well's life. This is what the assessment covers.

Figure 1. The four assessed units of the Eagle Ford Group in south Texas. Base map from the National Park Service.

How it was done

The method builds on the USGS approach to continuous petroleum resources: each well's estimated ultimate recovery, and the calculation of how many wells each assessment unit (AU) would need. To these it adds water per well for drilling and cement and for fracturing, the proppant-to-water ratio, and a long-term ratio of produced water to oil or gas, which stands for formation water. A Monte Carlo approach turns ranges of inputs into ranges of outputs.

The 2018 petroleum assessment defined seven continuous AUs in the Eagle Ford, part of the Jurassic–Cretaceous–Tertiary Composite Total Petroleum System. Three were left out of the water assessment, because so little drilling has happened there recently that no patterns in water and proppant use show in the sparse data. Inputs came from IHS Markit (2018) data and are given as ranges of possible means.

Inputs that reflect operators' technical choices were set the same for every AU, since similar fracturing technology is used throughout and the differences in the data follow operators, not geology. The long-term ratio of water to oil or gas, which reflects the geology, was set for each AU: a mean of 0.6 barrels of water per barrel of oil in the Eagle Ford Marl oil AU and 0.21 in the Submarine Plateau–Karnes Trough oil AU, and 1.05 gallons per thousand cubic feet of gas in both gas AUs.

A data gap. Texas does not require monthly well-by-well reporting of produced water, as some states do. The assessment used production-test data instead, usually reported every six months — far sparser than in places such as the Williston Basin — which is why flowback could not be assessed.

Results

Outputs are distributions; the table gives each one's mean, in millions of gallons of water or thousands of tons of proppant.

In short, developing the whole undiscovered resource would need on average about 15.8 billion gallons of water for drilling and cement, 671.8 billion gallons for fracturing and 420 million tons of proppant, and would bring up about 177 billion gallons of formation water. How fast, and how completely, the resource would ever be developed is unknown.

Per unit of oil or gas

The undiscovered resources behind these figures, from the 2018 assessment, average 5,129 million barrels of oil in the Eagle Ford Marl oil AU, 182 million in the Submarine Plateau–Karnes Trough oil AU, and 8,100 and 35,304 billion cubic feet of gas in the two gas AUs. Like-for-like figures allow comparison with the USGS's water and proppant assessment of the Bakken and Three Forks formations in the Williston Basin.

Putting it in context

Recent drilling (IHS Markit):

Hypothetical drilling rates, in any AU, using mean inputs:

Other water in each AU's area — produced water from all oil and gas wells (yearly mean, 2013–2017) and 2015 withdrawals and uses, in millions of gallons:

Sources

• Gianoutsos, N.J., Haines, S.S., Varela, B.A., Whidden, K.J., and others (the USGS Eagle Ford Water and Proppant Assessment Team), 2020 (version 1.1, March 2022), Assessment of water and proppant quantities associated with petroleum production from the Eagle Ford Group, Gulf Coast Province, Texas: U.S. Geological Survey Fact Sheet 2020–3037. https://pubs.usgs.gov/publication/fs20203037
• The tables and figure come from the fact sheet's PDF, which the web version lacks.
• Rewritten in hubnx's own words.