Texas has been betting big on oil since 1901, when its first well erupted at Spindletop, and over the past century, production has boomed. But new oil extraction techniques required to ensure continued production consume and threaten to degrade the state’s precious water resources.
With a history of repeated water shortages, Texas’s projected increase in water usage for oil production is expected to create problems as the state’s population grows, aquifers deplete, land subsides, and the state struggles to meet future water demands. Oil production can also contaminate water, which is a major concern given Texas’s insufficient groundwater supply. And the practice of disposing of water used during oil production by injecting it underground may induce seismicity in a state that is not prepared to deal with elevated earthquake activity.Despite these ongoing challenges, Texas will likely never stop drilling for oil. As oil companies develop cutting-edge techniques to gain access to Texas’s oil bounty, the state will need to work as hard to protect its water resources and mitigate the damages associated with oil extraction processes. Real trailblazing in oil and water management is needed.
Oil pervades Texas. The resources are spread far and wide into nearly every corner of the state. Compared to other U.S. states, Texas has the most abundant oil reserves and produces the most oil (see map).
The supply of conventional oil—that is, crude that flows relatively easily from wells drilled into the ground—is dwindling, and companies have invested billions of dollars in tapping oil supplies that consist of light, tight oil bound up primarily in shale rock. Five major shale basins in Texas contain oil and fan out well beyond the state, including over a dozen individual hydrocarbon plays—oil, condensates, wet gas, and dry gas—typically stacked atop one another. Of the 254 counties in Texas, 218 include shale resources with trapped oil, encompassing approximately 75 percent of the state.
And Texas isn’t expected to lose its lead, according to the Energy Information Administration. There were 33 new Texan oil fields discovered in 2011, more than double the number of fields discovered in North Dakota, another state with plentiful oil resources, during the same period.
Meanwhile, the state has been plagued by recurring droughts. The legendary dustbowl of the 1930s, for example, was followed by a six-year drought in the 1950s. From 2010 to 2013, Texas experienced its second-worst drought on record in terms of both intensity and longevity. Years of little or no rainfall will be felt long after a dry spell passes, especially in the most arid region in west Texas.
Oil production in the Midland and Delaware Basins—subdivisions of the Permian Basin in west Texas—has been drawing down groundwater supplies due to the lack of rainfall. In Texas, more than 99 percent of the rural population’s drinking water comes from groundwater, and 80 percent of groundwater used goes to agriculture (predominantly irrigation), making clean groundwater a top priority. Without enough rainfall to replenish the aquifers from which oil companies pump, water supplies continually decrease until disaster strikes, as it has in the town of Barnhart, Texas, which ran out of water.
Part of the problem is that oil production in Texas is a very water-intensive enterprise. Current extraction methods—secondary recovery and some enhanced oil recovery techniques—use freshwater to displace oil or to produce steam in order to decrease oil’s viscosity and prompt it to flow more easily toward the surface (though some companies are shifting to carbon dioxide instead of steam). And as companies seek to extract more light, tight oil, the stress on Texas’s limited water resources will only increase.
Hydraulic fracturing, known as fracking, is currently used to produce oil from tight shale rock formations buried between 5,000 feet (shallow) and 15,000 feet (deep) below the earth’s surface throughout several basins in Texas, including the Permian, Western Gulf, Bend Arch–Fort Worth, Anadarko, and Texas-Louisiana-Mississippi Salt (or TX-LA-MS Salt, also referred to as the Cotton Valley Group). The method used today is called slickwater fracking. The technique dates back to 1997 and involves adding a cocktail of chemicals to a huge volume of water. This mixture is used to crack and prop open shale, allowing tight oil to flow.
Fracking is a highly water-intensive process that uses mostly freshwater. Between 1 and 5 million gallons of freshwater are typically consumed in a hydraulically fracked well within the first few days. Such water-use practices pose challenges to the long-term viability of hydraulic fracturing in water-starved Texas.
Texas’s oil resources are particularly problematic in terms of water usage because of their geology. Many shale basins contain conventional oils, ultra-light oils (condensates), wet gas with condensates, and/or dry gas that are arrayed side by side or stacked on top of one another (see map above). The Permian Basin’s blended plays, in which six plays are stacked imperfectly at varying depths, stand out as a prime example of this phenomenon. In plays that are stacked vertically, operators can produce at many depths and in multiple formations along one well bore. Producing stacked plays increases the amount of water consumed per well, thereby intensifying the stress on the water supply in a given production location.
Statewide, total mining—including hydraulic fracturing—accounts for less than 1 percent of water consumption, but locally, water use can be far greater. For example, La Salle County, home to the Eagle Ford shale play, is projected to allocate 40 percent of its water almost exclusively for fracking by 2020. In parts of the Permian Basin, the share of water consumption allocated for fracking has reached double digits, and drilling continues to intensify.
The freshwater used in fracking, secondary recovery, and enhanced oil recovery is almost always permanently consumed, which means it is essentially removed from the hydrologic cycle. The goal is to prevent contamination by ensuring that this water is never returned to any source. That is because produced water contains fracturing fluids, salts, hydrocarbons, and naturally occurring radioactive materials from within wells. The concentration of constituents and the volume of produced water differ dramatically depending on the type and location of the petroleum product, making the handling of this water difficult.
Produced water requires extensive treatment or underground disposal. Treatment generally involves separating produced water into clean water and highly concentrated wastewater or solid wastes, while disposal intends to isolate the wastewater in underground formations. Operators in Texas use both techniques, but the sheer volume of water makes it difficult to ensure that all produced water is safely handled. Texas generated a massive 44 percent of the total amount of produced water in the United States in 2010. Over a well’s lifetime, an average of ten barrels of water is produced for each one barrel of oil, with some wells producing up to 50 barrels of water for each barrel of oil.
The higher the concentration of hazardous materials in the produced water, the more damage that could be wrought by spills and leaks into groundwater supplies. Contamination from fracturing fluid, produced water, or concentrated waste products of fracking could render large volumes of groundwater unfit for human use. This threat of contamination raises the oil-water stakes, especially in a water-starved state that cannot afford to render its limited resources unusable in the future.
Underground disposal of produced water has been linked to earthquakes in Texas and elsewhere (see map above). Earthquakes can be triggered when water is injected into a closed system, increasing pore pressure, lubricating the faults, and allowing slippage along the fault.
While induced seismic activity does not always result in serious damage, there is a worry that more subsurface injection of wastewater from increased fracking could lead to a higher number of larger and more damaging earthquakes. Residents and local officials have voiced their concern over recent earthquake swarms near Fort Worth, where up until 2007 no earthquakes had been recorded.
Beyond seismicity caused by injecting water underground, according to the U.S. Geological Survey, pumping out large volumes of oil and groundwater have also been known to contribute to land subsidence. When large amounts of underground resources—groundwater, oil, gas, and other minerals—are withdrawn from an aquifer, the earthen layers in the aquifer compact and settle. Over time, as more water is removed from the area, the ground subsides further and creates a depression. Once water has been removed from the sediment, it cannot be replaced.
Subsidence also activates seismic faults. Earthquakes occur when the hydrologic support of the overlying rock and soil is removed and is caused to settle down.
Land subsidence also increases the potential for flooding, causes elevation changes, damages infrastructure, and compromises well integrity. The greater Houston area, possibly more than any other metropolitan area in the United States, has been adversely affected by land subsidence.
The Railroad Commission of Texas (RRC) is responsible for regulating all waste associated with oil. And since 1982, the RRC has regulated the 50,000 currently permitted Class II underground injection and disposal wells in Texas. As of April 2013, an estimated 7,500 disposal wells could be found in Texas.
At a minimum, Texas includes in the 50,000-well total those injection wells that use produced water to enhance oil recovery. It is unclear whether this count encompasses wells used for the injection of a range of additional products (water, steam, carbon dioxide, and other agents) that the U.S. Environmental Protection Agency includes in its definition of enhanced oil recovery. Hydrocarbon storage wells, another form of Class II well, are not included in this count.
Disposal wells—often referred to as saltwater disposal wells, SWD wells, in Texas—are used to inject wastewater from oil and gas operations into isolated formations for permanent disposal. (Although it uses a similar process, hydraulic fracturing is not included in the category of Class II injection wells because it has been exempted from the Underground Injection Control Program under the Safe Drinking Water Act.)
Currently, the regulations covering hydraulic fracturing and Class II wells have gaps that are exploitable and hazardous for Texas’s water security. Injection and disposal wells are designed to protect groundwater. The Texas Administrative Code regulating the disposal of oil and gas waste only ensures the protection of freshwater, defined as 1,000 mg/L total dissolved solids (TDS) or less. Current regulations stipulate that saltwater disposal wells must be geologically isolated from “usable-quality” groundwater (defined as 3,000 mg/L TDS or less and saltwater that is suitable for desalination). The sources of potential drinking water (10,000 mg/L TDS or less) that remain underground are not adequately protected.
Moreover, Texas offers exemptions that allow wastewater disposal in a freshwater aquifer if that aquifer is not being used as a source of drinking water and will not serve as a source of drinking water in the future. As of 2012, the U.S. Environmental Protection Agency had approved more than 50 such exemptions in Texas.
Prospective well owners must identify all wells that penetrate the injection zone—the rock formation in which they intend to insert their injection well—in the public record that are within a one-quarter-mile radius of their proposed site, known as the area of review, and must plug those that are open. Without proper plugging, it is possible that injection into one well could build up pressure, forcing fluid out of nearby unplugged wells. Given Texas’s oil-producing history, there are many abandoned wells that are not within the state database, so operators do not know if they are injecting into a formation with an open conduit to the surface. Problems with unplugged wells are documented, but they are difficult to address.
Wells must also be pressure tested to check for leaks monthly, with reports sent to the RRC. If wastewater is being injected at a constant rate but pressure in the well drops that indicates the wastewater is no longer only being injected into one isolated and approved formation but is instead leaking out into other formations somewhere along the wellbore. Even at this monitoring frequency, however, leaks could cause irreversible damage before being detected. In 2005, for example, a leak from a disposal well into the Pecos River Cenozoic Alluvium Aquifer was identified. By the time the leak was stopped, 6.2 billion gallons of wastewater had contaminated the aquifer. The company responsible went bankrupt.
Moreover, the regulatory structure is lacking when it comes to seismicity and subsidence. The RRC has repeatedly denied a connection between wastewater injection and induced seismic events. The RRC recently stated that its jurisdiction over these wells only extends to water pollution prevention, not seismic activity regulation. Texas has found itself both vulnerable and in need of action. Moreover, the RRC, with its powers to permit oil and gas extraction, has no regulatory oversight on land subsidence caused by underground mining of petroleum and water resources.
Texas’s distinctive groundwater laws are somewhat problematic as well in that they permit extreme overuse of groundwater with few provisions to limit withdrawals. In what is known as the rule of capture, Texas law stipulates that landowners own the groundwater below their property. Landowners can withdraw however much water they choose provided that they do not willfully waste groundwater, they do not have malicious intent, they do not contaminate others’ wells through their own withdrawal, they do not drill diagonally under another’s property, and the withdrawals do not cause land subsidence. In practice, however, these limited exceptions have hardly restricted landowners. This absolute ownership of the water below one’s land allows landowners to sell groundwater to whomever they choose, including to oil companies drilling in the area.
In order to prevent water supply shortages and environmental damages caused by the withdrawal of groundwater, the Texas legislature has created 99 groundwater conservation districts that overlay major aquifers and manage 89 percent of Texas’s groundwater. These districts are legislatively authorized to modify the rule of capture by requiring permits for certain wells, instituting well-spacing regulations, and limiting water withdrawals.
The powers of these districts to regulate the oil industry, however, are limited. The Texas Water Code (Sec. 36.117) exempts from district permitting processes water wells that are used “to supply water for a rig that is actively engaged in drilling or exploration operations for an oil or gas well permitted by the Railroad Commission of Texas.” This includes any drilling or exploration operations in the 295,000 oil and gas wells that the RRC currently oversees.
Those wells used for hydraulic fracturing may or may not be fully regulated under the code. State rules, written before fracking came to be widely used, are ambiguous on whether or not these exemptions apply to hydraulic fracturing, and this regulatory vagueness has opened the door to contradictory claims. Wintergarden Groundwater Conservation District (located within the Eagle Ford shale), for example, holds the traditional view that hydraulic fracturing is a drilling or exploration technique and is exempt from districts’ permitting processes. But the Evergreen Groundwater Conservation District (also located within the Eagle Ford shale) views fracking as a production technique and regulates water withdrawals accordingly. This discrepancy in code implementation from county to county results in a wide disparity in water protection within and between oil basins where fracking occurs.
This disparity can have significant implications. Insufficiently protecting groundwater risks serious public health hazards and economic damage.
The importance of oil to Texas, economically and culturally, underscores the need for innovation to find and maintain a delicate balance in the state’s oil-water interactions. The question is whether the far-reaching oil-water risks will propel policymakers from and companies operating in Texas to become bellwethers, advancing new water management techniques just as they have done for fracking technology.
Many oil companies have begun to look for solutions to the problem of decreasing water supplies. With areas running out of freshwater, some companies have turned to brackish water, or water that contains 1,000 to 10,000 mg/L TDS and therefore has too many contaminants to be acceptable as drinking water in Texas. Companies that augment their fracking fluid water supply with brackish water are reducing dependence on and consumption of freshwater in some of Texas’s driest regions. Some are looking to end their dependence on freshwater altogether and begin fracking with 100 percent brackish water.
Despite the growing popularity of brackish water, however, there are geologic and economic limitations that could prevent its use for hydraulic fracturing throughout Texas. Brackish water is not available everywhere and, in some locations, is found at much greater depths than freshwater. This increases the cost of extraction. Moreover, brackish water can cause scaling, a buildup of sediment along wellbores, that can damage the wells. And since brackish water must be treated to remove unwanted chemicals that may impede the drilling process and the chemical signature of every brackish groundwater source is different, oil companies have to modify the treatment process for each new source.
The use of brackish water as an alternative to freshwater in the fracking process may prove to be a helpful transitional step, but it is not likely to be an effective long-term solution. Texas has to plan for an even drier future—one in which residents are left without freshwater resources. The supply of brackish water is also limited, and as groundwater decreases, the public will increasingly turn to brackish supplies for their everyday needs. Texans could come to depend on desalinated brackish water as their main potable supply. Accordingly, it will not be enough for oil companies to switch to brackish water; they will also need to significantly reduce their use of water overall.
In order to address both environmental concerns and increasing costs, some companies are developing methods to recycle and reuse their produced water as reconstituted fracturing fluid or for enhanced oil recovery in another well. Depending on where they are drilling, companies find that it can be cheaper to clean or reuse produced water than to dispose of it. The Apache Corporation, for example, currently claims to conduct “freshwater-less” operations with a combination of brackish water and produced water that has been reused instead of disposed. In 2011, the Anadarko Basin used more recycled water (20 percent) than other basins, which fracked with less than 5 percent recycled or reused water.
Recycling may reduce underground disposal and freshwater demand, but some recycling processes separate produced water into usable water and highly concentrated, contaminated wastewater and/or waste products. This wastewater must be trucked and disposed of in Class II disposal wells that are isolated from groundwater while waste products may be shipped to a landfill. If at any point throughout this process wastewater is spilled or if waste products leach into groundwater—either through operator error or a failure of the well—serious damage could result.
The state government has established incentives to encourage recycling produced water. In 1992, the voluntary Waste Minimization Program was established to guide well operators in cost-effective waste reduction, expand options for recycling produced water, and develop waste-minimization plans. The government also provides an exemption from sales, excise, and use taxes for equipment used to process, reuse, or recycle wastewater from hydraulically fractured wells. In March 2013, the RRC eliminated the need for permits if well operators are recycling produced water on their own land or transferring the water to another operator’s land to be recycled, streamlining the process and removing regulatory hurdles.
But the government still needs to take steps to make the process of recycling produced water safer. Texas policymakers need to remain abreast of the technological advances in produced water recycling and reuse to ensure that the environment and public safety are both protected while continuing to encourage responsible water use within the oil industry.
Texas has been a pioneer in oil exploration and production for over a century. Today, the sheer quantity of oil produced and major water concerns in Texas compel the state government to implement more robust standards for oil and water management. Advances in this area could spur significant transformations in the way the industry operates in the state and across the world.
Companies in Texas have made strides in the recycling and reuse of produced water. The state government has also succeeded in increasing transparency, requiring industry to disclose fluid additives and the amount of water used in fracking. Recent rule amendments require the RRC to monitor wells and guard against geologic conditions that could compromise wells’ integrity.
Yet, despite this progress, the state needs to continue strengthening regulations in light of Texas’s dwindling groundwater resources. More precise accounting for freshwater that is usable for human consumption, brackish groundwater, and recycled produced water is required. Collecting these data could inform recycling rates and brackish water withdrawals, and it could clarify the effect that fracking has on fresh groundwater quantities.
Disclosure of the quantity and quality of water produced from each well should also be required. Currently, Texas tracks the amount of water injected into disposal wells or for enhanced oil recovery. While this can be used to estimate produced water quantities, a direct measurement would be more accurate. Disclosing what exactly is in this water would prove useful in tracking contamination, remediating spills and leaks, and determining recycling potential.
In addition, real-time monitoring of changes in both disposal and injection wells’ pressure would help identify leaks more expediently than the current practice of monthly pressure testing. Instead of regulating usable water quality at levels below 3,000 mg/L TDS, Texas should tighten groundwater protection laws to include federally defined underground sources of drinking water (those under 10,000 mg/L TDS). The ease with which aquifer exemptions are granted should be reconsidered. And the state must also clarify whether groundwater conservation districts have the right to regulate withdrawals of groundwater for hydraulic fracturing.
Protecting groundwater resources is at least as important as facilitating oil production. The state’s recurring droughts, low precipitation levels, limited aquifer recharge capacity, and booming population apply tremendous collective pressures on its water resources. Companies in the state are also increasingly using highly water-intensive techniques to produce oil. These tensions will only become more pronounced as oil production increases and aquifers continue to be depleted. As the top oil-producing state in the United States, Texas needs to lead the effort to protect groundwater.
It will take initiative, but Texas can make forward progress. Policymakers are walking an oil-water tightrope that requires balancing the needs of industry while protecting public health and safety.
The Carnegie Energy and Climate Program engages global experts working on issues relating to energy technology, environmental science, and political economy to develop practical solutions for policymakers around the world. The program aims to provide the leadership and the policy framework necessary to minimize the risks that stem from global climate change and competition for resources.
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