More oil resources are deposited in the Rocky Mountain region of Colorado, Utah, and Wyoming than the entire world’s proven oil reserves combined. And nowhere are oil-water nexus issues more complex than in the Rockies. Many different types of oil are abundant in these states, including unconventional oils that require complicated, energy-intensive processes to produce. Additionally, unconventional oil production is more water intensive and involves more potential sources of contamination compared to conventional oil production.

Deborah Gordon Gordon was director of Carnegie’s Energy and Climate Program, where her research focuses on oil and climate change issues in North America and globally. More >

The tensions between water and oil resource challenges and opportunities are considerable in the Rockies. And the management of this oil-water interaction is particularly important because energy and water demands are intensifying as the region’s population grows rapidly. While the development of unconventional oil resources in this area is anticipated for economic and geopolitical reasons, problems could arise due to the region’s persistent water concerns and fragmented governance.

America’s Plentiful, Diverse Oil Region

Unlike other global geographies, the three heterogeneous varieties of unconventional oils—tight shale oil, oil sands, and oil shale—are all found in the Rockies (see figure 1). Overall oil production in the region is on the upswing due to shale oil production, as new technologies like horizontal drilling, directional drilling, and hydraulic fracturing have been developed to extract the oil trapped in these rock formations.

Massive Tight Shale Oil Reserves

Tight shale oils are a light crude oil by chemical composition, but unlike conventional oils, they are trapped in low-permeability shale formations. Therefore, getting the oil out of those formations takes more energy and water than in the case of conventional crude oils.

The region has several geologic shale formations that contain vast amounts of tight oil, such as the Niobrara and Mowry shales.1 Production in the Denver-Julesburg (DJ) basin, the current tight oil production hub of the region, nearly quadrupled to 235,000 barrels a day between January 2012 and August 2014, and is projected to double again by the end of 2019. (Note that this projection was made when oil prices were high. The growth of unconventional resource extraction depends on economics, and the impact low oil prices will have on the development of the industry is still uncertain.)

The DJ basin is underlain by the Niobrara Formation, the most prolific shale-oil-containing layer in the region that spans the DJ basin (in both Wyoming and Colorado), the Powder River basin (in Wyoming), and other areas. The Niobrara shale may have the potential to release 6.5 billion barrels of technically recoverable tight oil resources, more than North Dakota’s prolific Bakken shale. Compared to other tight oil resources, geologic faults and interspersed marlstone and shale layers are more common in the Niobrara, making the formation more energy intensive and expensive to drill relative to other shales.

Beyond the DJ basin, as of late 2014, Utah’s Uinta basin (the Green River shale) and Wyoming’s Powder River basin (the Niobrara and Mowry shales) are home to the region’s other horizontally drilled, tight oil wells. Huge amounts of continuous tight oil remain relatively untapped in the Paradox, Greater Green River (which includes the Washakie and Sand Wash basins), Bighorn, Wind River, and Hanna basins, adding up to more tight oil than is in the Powder River and DJ basins combined.

This oil is accessed by hydraulic fracturing (fracking), which involves pumping large quantities of fluid containing water, sand, and other solvents into the shale to create fractures that increase the rock’s permeability so oil can flow out of the rock. The process requires significant amounts of freshwater—about 2.8 million gallons per horizontal well is needed in Colorado. Given the Rockies’ massive tight oil volumes, full production will require vast quantities of water. The amount of water used in fracking in Colorado is expected to double to 6 billion gallons a year by 2015.

Although hydraulic fracturing currently only makes up about one-tenth of 1 percent of total water demand in Colorado and so does not have a significant impact statewide, it can create local water tensions. As of 2014, over 80 percent of the oil development is in Weld County, in the northeastern portion of Colorado—an area that is struggling with water scarcity. Water used annually for new oil and gas development is equal to between one- and two-thirds of total public and domestic water used in Weld.

More than three in every four Colorado residents live along the Front Range, on the east side of the Rockies, but only about 20 percent of the state’s precipitation falls there. In the future, more than half of municipal and industrial water demand in the east is expected to be provided for by water transfers involving pumping and transporting water from the Western Slope. Any sharp increase in water demand in northeastern Colorado has the potential to outpace the region’s infrastructure capacity, pitting industry against municipal and agricultural needs. This, among other reasons, prompted Governor John Hickenlooper of Colorado to direct his state’s Water Conservation Board to work on a Colorado water plan, which was released in December 2014.

Colorado’s scarcity problems are illustrative of problems elsewhere in this water-scarce region, but other states have been less proactive in addressing their water issues. Utah and Wyoming currently have a lower share of hydraulically fractured wells than Colorado, but as the second and fifth driest states in the United States respectively, they have more severe water shortage problems.

Experimenting With Oil Sands

Oil sands are a type of sandstone containing a hydrocarbon called bitumen that is bound up in a sand and water mixture. Utah is home to the United States’ largest and richest oil sands deposits, with resource estimates ranging from 12 to 29 billion barrels of oil in place. The majority of these deposits is in the Uinta basin, and a minority is in the Paradox basin. Uinta basin oil sands are not as high in carbon and sulfur (that is, heavy and sour) as Canada’s Athabasca resources in Alberta, but those in the Paradox basin are comparable to Athabasca’s.

The depths of oil sands resources vary, and that affects their production and water requirements. Oil sands sitting on or close to the surface are normally mined, mixed with hot water, and shaken vigorously to separate the relatively light bitumen from the heavier sand. This technique is water intensive, using between 3 and 12 barrels of water to produce 1 barrel of bitumen. When oil sands are deeper than about 200 feet underground, steam must instead be injected to liquefy the hardened bitumen, which is then pumped to the surface, a process that takes between 0.5 and 3 barrels of water for each barrel of bitumen produced.

Oil sands production is expected to start in the Uinta basin in late 2015. The company involved (and its competitors) employs an extractive process near the surface that uses solvents to decrease the amount of water required; the company claims the process consumes 1.5 barrels of water per barrel of bitumen produced. The solvents, such as d-limonene, aim to dissolve the bitumen and separate it once it has been dissolved. The company claims to recycle 95 percent of the water used, completely separate the bitumen from the sand, return sand to the mining site in an environmentally safe manner, and eliminate wastewater (tailings) ponds.

Whether solvent-based oil sands technologies save more water than they contaminate is unclear. Ultimately, however, innovations that use less water overall are being sought to replace water-intensive techniques. Well-designed regulations should encourage such innovation but also monitor water risks in the extraction of oil sands in the Rockies.

Oil Shale: The Next Oil Frontier

Oil shale contains large amounts of organic matter called kerogen. Kerogen is an oil precursor—the organic matter has not been heated or pressurized sufficiently to form oil. Applying heat and pressure through a process known as retorting can speed up thermal decomposition that would take natural forces millions of years, producing feedstock that can yield similar petroleum products as conventional crude (such as diesel fuel).

The Rocky Mountains contain an estimated 4.3 trillion barrels of oil from oil shale in the Uinta, Piceance, and Greater Green River basins. These form the largest known oil shale deposits in the world; they also contain more oil than the rest of the world’s total proven reserves, giving the United States economic and geostrategic incentives to ultimately develop them.

Oil shale is not currently being produced in the United States, given its much higher cost than conventional crude and shale oil. There is also significant uncertainty about the viability of current technologies to retort kerogen into oil products. Retorting oil shale requires significant energy inputs, so the energy returned on energy invested can be quite low. This also means that the overall water impact of oil shale production can be even higher when the water needed to produce the source fuel used to generate significant amounts of heat and pressure is taken into account.

Retorting uses one of two methods—ex situ (near the surface) or in situ (deeper underground); only the former has been demonstrated on a commercial scale. There are multiple research test sites on U.S. Bureau of Land Management leases where both types of extraction and processing techniques have been tested (Chevron and Shell had test sites, but they are not currently operational).

Ex situ oil shale is either surface- or pit-mined, then retorted at a separate processing site; this requires an estimated 1.8–4.0 barrels of water per barrel of oil. However, this technique can only be applied to the limited quantity of shallow resources, while the most geologically prospective resources are buried under more than 1,000 feet of rock.

As such, the future of the oil shale industry in the Rockies depends on the development of safe and cost-effective in situ processes. This is likely to involve drilling several wells into the oil shale, first to apply heat to the rock and then to collect the oil and associated gas (in a 2:1 ratio). The shale would be heated slowly to 650–700 degrees Fahrenheit over the span of two to three years.

With an average estimate of 4.8 barrels of water necessary to produce 1 barrel of oil through in situ oil shale processes, the future development of oil shale may eventually be limited by water availability. On any scale, however, the industry’s success depends on sustainable water use throughout the oil shale value chain.

An Unforgiving Water Situation

Although the central Rocky Mountain states receive very little precipitation each year, they nevertheless have some of the fastest growing populations in the United States, which strains water resources. Extracting unconventional oils may compound water issues by taking up scarce resources or contaminating existing ones. Each oil resource found in the Rocky Mountains has its own production techniques, and every technique has a different and complicated relationship with water.

Water Stress—Where Demand Exceeds Supply

Colorado, Utah, and Wyoming (along with New Mexico, which is not examined in this article) constitute the upper Colorado River basin, where water is perpetually stressed. Regional water demand is expected to hugely increase and outstrip supply due to a projected 45 percent increase in population from 2010 to 2040. Concurrently, water supply has been decreasing. Recent and extensive drought conditions make balancing the yearly water budget difficult—the years from 2000 to 2013 were among the driest 2 percent of any period of similar length on record.

Climate change will also exacerbate the situation. Although the magnitude of the effects from climate change is difficult to determine, an increase in snow evaporation rates, a decrease in the proportion of precipitation that falls as snow as compared to rain, and an earlier-than-usual melting of snowpack are all expected. That is problematic because the majority of these three states’ precipitation and the Colorado River’s flow comes from snowmelt, and decreased snowmelt results in reduced aquifer recharge rates and water availability. Indeed, significant reductions of river flow are projected. Large-scale climate effects are likely to complicate the distribution of water among the upper and lower basin states (Arizona, California, and Nevada).

An important question is how oil companies looking to acquire available water rights within the existing framework will affect other users. The doctrine of prior appropriation governs all of Colorado’s, Utah’s, and Wyoming’s water withdrawals from both surface waters and tributary aquifers. This means that oil companies can appropriate a water right by applying water from a source that is not overallocated directly to a so-called beneficial use, such as drilling.

To acquire water rights from sources that are already overappropriated, oil companies must either buy a right with a designated use for well completions or purchase an irrigation water right and then change its designated use. The price of water rights, however, is extremely volatile. Oil companies and other large entities have an advantage over farmers and smaller firms because more transactions provide better information—which means they can more easily determine who holds the most senior water rights (which are given to those who appropriated the water first—first in time, first in right) and obtain them at better prices. A tenet of prior appropriation may give oil companies another advantage over other users. Seniority takes precedence, so in times of scarcity, junior rights holders bear the full brunt of shortages, and oil companies have successfully purchased senior water rights. Creating a marketplace to facilitate the exchange of rights and provide information would protect small water rights holders by allowing them to access information about the competitive value of their rights.

Beyond prior appropriation doctrine, there are only a few other ways that oil producers can gain access to water. They can claim excess water during heavy-flow years or they may obtain a well permit for groundwater from nontributary aquifers, which is common for wells in the Denver-Julesburg basin that sit atop the nontributary Denver basin aquifer. Both produced water, which is naturally occurring water that has been brought to the surface along with oil, and flowback, which is fracking fluid that has returned to the surface, can also be recycled and used. But these methods cannot provide all of the water consumed because they can be unpredictable and sporadic, geographically uncertain, or limited to specific purposes.

Protecting Water From Contamination

Scarcity is not the only water-related problem in the Rockies—contamination is also a concern. Because the techniques used to produce oil in the region are so varied, the sources of contamination are also varied, but they can be broken down into several categories.

First, drilling, underground mining, or in situ heating can permanently impact aquifers and groundwater flow. Poor well integrity caused by improper cementing and casing during drilling is one of the most common causes of groundwater contamination. Underground mining of oil sands or oil shale can create large tunnels that are later filled with waste rock that has a higher porosity and permeability than the original rock, which may change the direction and pattern of groundwater flows. Such underground flows can lead to comingling of cleaner waters and contaminated sources. In situ extraction of oil shale is also likely to change the porosity and permeability of rock when formations are heated and pressurized to release liquid hydrocarbons and gas.

Second, leftover waste can contaminate nearby surface and groundwater. New technologies that process oil sands with solvents may introduce chemicals that taint water that is located near the oil. D-limonene, for instance, is a minor irritant that is considered benign, but it can increase the water solubility of polycyclic aromatic hydrocarbons (PAHs), such as benzo(a)pyrene—a known carcinogen—which is also an impurity in bituminous sands. How oil sands companies dispose of their waste in Utah will be of critical importance for protecting water quality and human health.

Oil shale production processes are reported to leave behind 1.2–1.5 tons of highly saline spent oil shale leachate per barrel of oil. If water dissolves the salt, it can drain into the Colorado River or groundwater. Salinity management is especially important in the Colorado River basin because agriculture predominates water consumption in both the upper and lower basin states.

Disposing of wastewater, including produced water from hydraulic fracturing, in lined or unlined evaporation pits can also cause contamination. If the pits leak, exceed capacity, or flood, wastewater that contains high levels of contaminants can flow into sources of freshwater. Evaporation pits for produced water are more commonly reported in Colorado, Utah, and Wyoming than anywhere else in the United States. And the quantity of water produced alongside tight shale oil varies greatly from basin to basin as does its quality—Colorado averages 2.5 barrels of water for 1 barrel of oil from fracking; in Utah the measure reaches 3 barrels of water.2

Third, the disposal of wastewater into surface water is generally well regulated through the Clean Water Act, though permits can be given to point sources through the National Pollutant Discharge Elimination System as authorized by the Clean Water Act. While the overarching goal is to prevent dangerous levels of pollutants from being released into surface waters, this wastewater disposal method can increase water flows in streams or rivers that in turn can increase downstream erosion, decrease sediment deposition, or decrease water quality by reducing oxygen concentrations or increasing temperatures. These outcomes can negatively affect aquatic life, property, and general well-being. Finally, accidental spills at the wellhead, at the extraction site, or during product transportation can lead to significant contamination—more safeguards can always be put into place to prevent these events.

To protect people, agriculture, wildlife, and natural environments, steps should be taken to reduce the amount of water consumed in unconventional oil extraction and to prevent contamination. The industry standard is to inject water into underground wells, and it has been largely successful at preventing contamination thus far. A similar method for disposing of wastewater from oil sands or oil shale extraction is also likely to be used. In 2011, Colorado disposed of about 60 percent of its produced water in such wells. Underground injection wells aim to trap produced water underground permanently, removing it from the hydraulic cycle and preventing contamination. However, the process does not always work perfectly: sometimes, the produced water can migrate and join aquifer or surface waters. Injected water can make geologic faults slip, inducing seismicity and increasing tremors.

With effective regulation, contamination is largely preventable. But governance in the Rockies is a complicated matter.

Who Is Responsible for the Rockies’ Oils?

A myriad of actors have a stake in these issues—industry, federal authorities, three states, Indian reservations, local governments, and around 9 million residents and growing. And each of these stakeholders subscribes to different rules and outlooks regarding the oil-water nexus. This makes establishing a comprehensive regulatory scheme extremely difficult.

But the combination of the harsh realities of water stress in the region and the superabundance of oil resources may create sufficient incentives to enact effective regulations. Preventing water contamination, reducing water use, and spurring innovations—such as solvents for bituminous sands, recycling of produced water, and waterless fracking—will be key steps.

Innovations are welcome. Yet reporting, monitoring, and regulating will be needed to assure the reduction of contamination and to manage overall water stress. There is a needle to thread between, on the one hand, establishing strict rules that ensure healthy water resources but erect barriers to unwanted development and, on the other, facilitating the development of the oil industry that provides jobs and wealth but does make mistakes that contaminate water resources.

Industry, state, federal, and Indian governments balance these needs differently, so regulation and other governmental oversight depend largely on the ownership of the land, water, and mineral rights. The federal government is in a unique position to control the development of the oil shale industry in particular because the U.S. Bureau of Land Management administers over 70 percent of geologically prospective oil shales, some of which can yield over 50 gallons of oil per ton of rock.

For other oil resources like shale oil and oil sands, especially those in Wyoming and Utah, land ownership is a checkerboard of federal, Indian, and state-owned land (see figure 2). State and Indian governments, especially the Uintah and Ouray Reservation in the Uinta basin, tend to be more supportive of oil development for several reasons, not least because they hope to obtain increased revenue from royalty payments. Federal regulations—particularly of water-related issues—are relatively precautionary, so the majority of oil development has taken place where the federal government has the least oversight: on state, Indian leases, or through the transfer of ownership of privately owned land.

State governments generally have their own regulatory schemes that tend to react to rapid development, and they put laws in place once threats become apparent. Occasionally this works—Wyoming and Colorado have some of the toughest laws in the nation governing well completions, and all three upper basin states require the disclosure of the chemicals in fracking fluid.

However, there are certain issues that state governments generally struggle to oversee effectively. The rate of development is often out of their control, as witnessed in the Williston basin’s oil boom in the Northern Great Plains. The Rocky Mountain states are not prepared for major development of the plethora of regional oil resources. Moreover, state governments are not able to effectively safeguard against interstate water issues, especially regarding the allocation of water in the Colorado River, which are expected to play out over the longer term should global warming decrease supply in the Colorado River basin to less than 13.5 million acre-feet.

There is also a trend toward increasingly fragmented governance in the Rockies, which means that already complicated issues are made even more complex. State sovereignty movements, for example, pose a threat to federal oversight. Governor Gary Herbert of Utah signed a law demanding that the federal government transfer more than 20 million acres of land to the state, including some of the most oil-rich regions. This is likely to result in a lengthy legal battle. Wyoming, meanwhile, has created a task force to investigate the possibility of pursuing similar action. If public lands are transferred, states are especially likely to increase the number of leases for oil development because they will need to raise revenue to cover the high costs of effectively maintaining public lands.

Additionally, some local governments are trying to go above and beyond regulation required by the state. Home-rule municipalities in Colorado—Boulder, Broomfield, Lafayette, Longmont (all within 20 miles of each other), as well as Fort Collins—have passed fracking bans within the Denver-Julesburg basin. Many of these bans have been overturned or are likely to be overturned on the basis that the Colorado Oil and Gas Conservation Act authorizes oil and gas drilling and thus hydraulic fracturing as a practice, and because county regulations are required to yield to the state interest.

Home-rule municipalities in Colorado may not be able to ban fracking entirely because of the state constitution. However, analysis suggests that they may be able to regulate fracking-related issues by requiring proposed wells to demonstrate that they have an adequate supply of water and by imposing impact fees to prevent and clean up water pollution. Such enhanced local oversight of water may result in “go” and “no-go” areas, with different entities battling for oversight.

Ground Zero for Future Oil-Water Challenges

Colorado, Utah, and Wyoming are stocked with about every type of unconventional oil known today. The region is also one of the most water-stressed places in the world. And the Rockies are ground zero for new concerns related to the evolving oil-water nexus as its different oils become available at different times—shale oil production is exploding now, oil sands are pending development, and oil shale may be further into the future.

The safety and livelihoods of residents in this growing region depend on carefully balancing resource protection and development. Striking this balance, however, will present challenges.

Different oils have very different water needs and impacts. The interdependency between states, localities, reservations, private interests, and those living downstream make the region’s water resources highly contested. The number of different governing bodies and diverse stakeholders fragments oversight, which only makes matters more confusing.

There are expected to be many lessons learned from experiences in the Rockies about safeguarding resources in the face of broad unconventional oil development. The Rocky Mountain region has historically been a leading laboratory for innovations on oil-water technologies. With resource development, however, comes responsibility. Effective oversight, transparency, and regulation will be critical to managing the oil-water nexus, especially in these states.

It is key that each governing body does its part. Monitoring groundwater and ensuring the safe disposal of wastewater, solids, and chemicals are especially important. Water crises have always been a theme in the story of the West, but the oil industry does not need to become the cause of one.

Eugene Tan is a junior fellow and Katherine Garner is a former junior fellow in Carnegie’s Energy and Climate Program.

Notes

1 Each of the shale oil basins is from a different total petroleum system. The Niobrara shale contributes to the continuous (tight shale oil) resources of the Powder River basin, Hanna basin, Denver basin, and southwestern Wyoming’s Washakie and Sand Wash basins. The Mowry shale contributes to the Powder River basin and the Bighorn basin; the Bighorn also has continuous oil from the Phosphoria total petroleum system. The Paradox basin is named after its own continuous oil total petroleum system. The Green River shale contributes to the Uinta basin.

2 These numbers were calculated based on the produced water ratios from active, currently producing, horizontally or directionally drilled oil wells. A gas-to-oil ratio of 15,000 cubic feet of gas to 1 barrel of oil produced was used to differentiate gas and oil wells. ArcGIS software may be needed to access this data.