Estimating the Water Used in Unconventional Oil and Gas Development

The U.S. Geological Survey's Water Availability and Use Science Program aims to give a more accurate picture of the country's water: how much is available for beneficial uses, of what quality, and how that has changed since the 1950s, to improve forecasts of water for the economy, energy and the environment. Within it, the National Water Census supports studies of water availability at regional and national scales.

This fact sheet sets out one such study: how much water it takes to produce and sustain unconventional oil and gas (UOG) over its whole life cycle, from extraction, production, refining and delivery to disposal of waste. Its data and models are meant to be applied to similar oil and gas plays across the country, and to sharpen the USGS's five-yearly national water-use estimates in categories such as mining, domestic self-supply, public supply and wastewater.

Conventional and unconventional

Fossil fuels are the country's main energy sources. In 2014 crude oil, used mostly for transport, supplied 35.4 percent of U.S. energy consumption; natural gas and coal, used mostly for electricity, supplied 27.9 and 18.3 percent.

• Conventional oil and gas sit in discrete deposits with well-defined contacts between hydrocarbons and the water they float on, generally high permeability, clear seals and traps, and relatively high recovery. Easy to extract, they have historically been the cheapest to develop, with vertical wells.
• Unconventional, or continuous, oil and gas are spread throughout a formation rather than in discrete pockets, and often need special drilling and recovery methods.

Figure 1. Water use and energy development where conventional and unconventional oil and gas are produced in the Williston Basin. Modified from Caldwell and others (2015) and Seth Haines, USGS. USGS.

From the 2000s, new technology, dwindling access to conventional deposits and rising prices drove development of unconventional resources. Horizontal wells expose far more of a thin reservoir than vertical ones. After drilling, fluid (usually water with additives) and a proppant (solid grains such as silica sand or man-made ceramics) are pumped in at high pressure to open cracks that release oil and gas from tight, low-permeability formations, usually shale: hydraulic fracturing, or fracking. Hundreds of thousands of wells across the country are now fractured every year.

The water it takes

Where unconventional oil and gas are developed, water supply and shrinking aquifer storage matter. Initial fracturing of a well in tight shale takes about 2 million gallons for an oil well and 4.1 million gallons for a gas well. More goes to re-fracturing and maintaining boreholes; to indirect uses such as crew camps and keeping dust down on roads; and to ancillary uses such as supporting industries, businesses and recreation. None of this additional use has been measured at a regional scale.

The plan

The study has three phases:

1. Phase I: measure water use for unconventional oil and gas at a pilot site, build an estimation model, and work out its uncertainty.
2. Phase II: test the model in similar plays around the country.
3. Phase III: finalise the model and prepare for a national assessment.

Choosing the pilot site

The USGS Energy Resources Program assesses undiscovered oil and gas in priority provinces. Its last complete national assessment, in 1995, used plays as its basic unit; since 2000 it has been reassessing the priority basins instead. The 32 basins being reassessed hold about 97 percent of the country's discovered and undiscovered oil and gas. The U.S. Energy Information Administration has mapped the shale plays in the lower 48 states.

Figure 2. Current (April 2015) and prospective shale plays in the lower 48 states. U.S. Energy Information Administration.

Of the 32 basins, 14 were reassessed for unconventional oil. The total mean undiscovered, technically recoverable oil was about 13 billion barrels, and most of it, 56 percent or about 7.4 billion barrels, lies in the Williston Basin.

Figure 3. Mean continuous, technically recoverable oil resources in the United States; mean total 13 billion barrels. USGS.

The Williston Basin was chosen as the Phase I pilot. Since 2005 production has soared from the Bakken and Three Forks Formations of North Dakota and Montana. Water use there was fairly stable from year to year before 2005, so any substantial change since can be put down to oil and gas development. Oil prices move production too: the 2015 fall in prices slowed new development, giving a chance to see water use through both the rise and the decline, and to apply the lessons to other plays. Those include the Barnett Shale (Fort Worth Basin, Texas), the Eagle Ford (Gulf Coast Basin, Texas), the Haynesville-Bossier Shale (Louisiana and Texas), the Fayetteville Shale (Arkoma Basin, Arkansas) and the Marcellus and Utica Shales (Appalachian Basin, Pennsylvania). Phase II will favour plays with the most recent and robust development.

The Williston Basin

The basin covers more than 100,000 square miles of western North Dakota, northwestern South Dakota, eastern Montana, and Saskatchewan and Manitoba in Canada. Oil and gas were found there in the 1920s and 1930s, but North Dakota's first producing well was drilled only in 1951. Vertical wells paid in several plays but not in the Bakken; only when horizontal drilling, fracking and other technology became widely available in the late 1990s did its low-permeability rock become worth developing. North Dakota's oil output rose from about 35–40 million barrels a year in 2005 to more than 1 million barrels a day in 2014, and in 2013 the USGS estimated 7.4 billion barrels of technically recoverable oil in the U.S. part of the Bakken and Three Forks Formations.

Figure 4. The Williston Basin Province, the Bakken total petroleum system and the Three Forks assessment units within the United States. USGS.

More than 10,000 unconventional wells were producing from the Bakken and Three Forks Formations in North Dakota in 2015. Photograph by Joanna Thamke, USGS.

• Fracking: almost 20,000 acre-feet of surface and groundwater went to hydraulic fracturing in North Dakota in 2013, 5 percent of the state's consumptive water use.
• Maintenance: the Bakken and Three Forks formation water is so salty that keeping a well going over its 30–40-year life can take more than three times as much water again, 6.6 million gallons or more.
• Wastewater from drilling, fracturing and production can be injected into underground disposal wells (the main practice in most of the country), treated and discharged to surface water, or recycled for future fracturing.

Temporary crew camps, like this one near Medora, North Dakota, are one of many indirect uses of water that grow with oil and gas development. Photograph by Joanna Thamke, USGS.

Development is expected to keep growing, with more wells and more workers, and local, State, Tribal and Federal stakeholders are asking where the water will come from, whether there is enough, and what it means for people downstream and for the environment. The study's objectives come straight from those questions.

Water depots, like this one near Watford, North Dakota, fill trucks with groundwater and surface water for oil and gas development. Photograph by Joanna Thamke, USGS.

Phase I

Phase I, begun in 2016, will measure water use tied to unconventional oil and gas in the Williston Basin from 2005 to 2015, develop estimation methods for a digital model, and quantify their uncertainty.

• Data: water use, sources (surface or groundwater), reuse and disposal for direct processes (fracturing, borehole maintenance), indirect ones (crew camps, well pad upkeep, road dust control) and ancillary ones (supporting industries, businesses, recreation). Available data will be gathered and ranked, gaps identified and a plan made to fill them; results will be published as reports and data releases. The water-use characteristics of selected shale plays in the 14 basins reassessed for unconventional oil will be compared at the same time.
• Model: methods to estimate the whole life cycle, water sources, use, consumption and disposal, will feed a digital model, with techniques to measure its uncertainty, including where data are missing. The methods, and the model's test results in the Williston Basin, will be published before it is applied to other plays in Phases II and III.

Sources

• Janet M. Carter, Kathleen M. Macek-Rowland, Joanna N. Thamke and Gregory C. Delzer, Estimating National Water Use Associated with Unconventional Oil and Gas Development, USGS Fact Sheet 2016–3032, May 2016. https://doi.org/10.3133/fs20163032
• The figures and photographs are taken from the fact sheet's PDF.