Oil and Water. Conventional wisdom says they don’t mix.
While that may be true in cuisine, the natural world is a series of interactions between dynamic, complex systems. Oil and water may not mix but, when it comes to energy, the two are deeply intertwined.
The modern hydrocarbon renaissance in tight formation oil and gas development is a direct result of the connection between oil and water. In the drilling process, water, mixed with muds, provides the lubricant to bore safely into the earth and carry cuttings back to the earth’s surface. In the well completion process, hydraulic fracturing is only possible through the application of large volumes of water, which serves as both a hammer to crack brittle rock deep underground, and as the medium to transport proppant to keep those fractures open. Such fractures allow unconventional, or tight formation oil and gas to move into the well bore, and to the surface, where hydrocarbons create wealth and opportunity and serve as the oxygen that fuels the greater economy.
Without water, horizontal drilling for oil and gas is difficult, hydraulic fracturing is not possible, and modern oil and gas production is vastly curtailed.
Water Water Everywhere?
Water use in oil and gas well completions increased dramatically after 2002 with the move to tight formation oil and gas development. Growth in water consumption stems from an increase in the number of horizontal wells drilled annually coupled with substantial growth in the volume of water used per well in unconventional horizontal drilling.
Beginning in 2002, and led by horizontal shale drilling, median water use for tight formation gas wells increased more than 50-fold on a per well basis from 94,000 gallons to 5.1 million gallons at the end of 2014. Similarly, median water use per well for horizontal tight formation oil grew by a factor of five after 2009 to 4.1 million gallons. American Geophysical Union Hydraulic Fracturing Water Use
Horizontal Wells Per Year
Concurrently, the number of horizontal wells rose tenfold for natural gas after 2002, and nine-fold for oil after 2009. Those numbers illustrate the sudden and meaningful increase in water use for well completions in unconventional plays.
The trend in water intensification was compounded further by the move after 2014 to high density completions with longer laterals, more frack stages and closer stage spacing, coupled with higher proppant loading. In a majority of cases, high density completions involve a return to slickwater fracks, which use greater volumes of water in the hydraulic fracturing process.
While the median water use per well in all horizontal drilling is north of 4.2 million gallons on average, individual operators employing high density completions can use up to 14 million gallons per well in plays like the Eagle Ford Shale. On a four well pad, a program that size amounts to potential consumption of 56 million gallons, or enough water to supply the annual use for 200 suburban homes. 42-366-34—008 FracFocus
Water Use Per Well
While the example is at the high end of industry usage versus median values, it is illustrative of the potential upper limits of water consumption in unconventional oil and gas extraction as more operators turn to high density completions. For rule-of-thumb perspective, consider two analogies. At peak rig count in 2014, the oil and gas industry, was using about the same volume of water for drilling and completing tight formation oil and gas wells as consumed annually in a city the size of San Antonio, Texas with 1.4 million people.
The horizontal drilling and completion process also generates flowback water (water used in well stimulation that returns to the surface within a few of weeks following the frack), and produced water as a byproduct of oil and gas extraction.
As in all things oil and gas, current trends are changing when it comes to water volume, partly due to evolution in water management practices in unconventional oil and gas extraction, but more so from the decline in oil and gas activity associated with falling commodity prices. Total domestic horizontal well count of 12,200 in 2015 is projected to finish with 5,600 fewer horizontal wells than in calendar year 2014. That drop in horizontal oil and gas activity implies water consumption in tight formation oil and gas extraction will fall to 157,000 acre feet at year end, down 32% from a 2014 peak in excess of 230,000 acre feet.
Two other factors addressing the decline in aggregate produced water volumes include shut ins for stripper wells in conventional oil and gas due to low commodity prices and the increased use of best practices such as water recycling in unconventional oil and gas.
For produced water, trends are unfolding at a slower rate. However, produced water volumes destined for disposal via injection wells are declining because of the commodity price-induced decline in well completions. Produced water is formation water, separate from flowback water that is part of the well stimulation process. A majority of produced water volumes originate in conventional production. For unconventional oil and gas, produced water volumes vary by horizontal play from negligible to factors such as 18 to 1 in plays like Oklahoma’s Mississippi Lime. The Ground Water Protection Council established ratios of 9.7 barrels of produced water for each barrel of oil, and 97 barrels of produced water per million feet of natural gas production nationally. Ground Water Protection Council: U.S. Produced Water Volumes
Produced water volumes decline over time as a well matures.
As in all things water-related, data regarding the volume of produced water are inconsistent. Tracking is done at the state level, which creates wide variability in data quality. For example, a few states break produced water out by commodity while others don’t, while few states break out produced water from conventional wells versus unconventional wells.
Total Water Use by Commodity
Water usage occurs in volumes that boggle the mind. For illustration purposes, think of an acre foot of water as enough H20 to cover an area the size of a football field (without the end zones) one foot deep. Metrics vary regionally, but one acre foot of water would serve the needs of two suburban households for one year. The industry uses roughly 13 acre feet of water to drill and complete a single horizontal tight formation well.
Similarly produced water from conventional oil and gas production is often recycled in enhanced oil recovery (EOR) programs. This remains the single largest source—and disposition—of produced water. The Ground Water Protection Council estimates oil and gas activities, including offshore, generate 21.2 billion barrels of produced water annually, or roughly 2.7 million acre feet. That equates to annual water consumption for 4% of U.S. households, or approximately 5.4 million dwellings.
Whether occurring in conventional or unconventional applications, 45.1% of produced water was injected as part of enhanced oil recovery programs. Additionally, 38.9% was injected for disposal with 6.7% dispatched to offsite commercial disposal. The rest was managed via evaporation or surface discharge. In other words, 93% of produced water is injected underground in onshore drilling markets, including EOR programs and disposal wells.
Points of Friction
On the one hand, water use in unconventional energy extraction is modest when compared to national water consumption. Water in oil and gas extraction represents less than one percent (.87%) of domestic industrial consumption while the volume of water used for unconventional oil and gas extraction is less on a per unit energy basis than the volumes of water consumed in other energy extractive industries such as coal or uranium mining.
On the other hand, usage looms large when viewed from the fact that a majority of water use in tight formation oil and gas production occurs primarily in 50 counties nationwide. Here, the local impacts are intense, frequent, and visible daily to the surrounding community. Drilling and well completion can employ 2,000 truck loads over a six to nine months for transporting water in for drilling and later hauled out as flowback from hydraulic fracturing, plus produced water associated with oil and gas production. In unconventional oil and gas, volumes for produced water can be triple volumes used in drilling and well completion.
A four well pad, which is common in tight formation oil plays, can entail up to 8,000 truck loads for water transportation alone. As a general rule of thumb, picture water handling theoretically as 1,000 truck loads per month, or an 18-wheeler rolling by every hour every day for every well. At peak completion count in 2014, the Eagle Ford Shale play averaged a truckload of water every six minutes across the South Texas play, according to this formula, although intensity varies by county and is generally concentrated in a handful of core counties, as is the case in most unconventional plays.
Because of mitigating factors water use in energy production are illustrative rather than definitive. There is no overarching repository of data that collects and publishes statistics on all aspects of water consumption in oil and gas although several studies, referenced in the supporting documents section of this web report, address the gamut of water volumes in energy extraction over varying time frames and in different locales.
While water usage in unconventional oil and gas is minimal on a national level, it is highly visible at the local level where the intersection of oil and water has led to points of friction between the industry and the community at large. Those frictions originate from several issues. The first is the perceived competition between industry and non-industry for scarce fresh water sources. A large number of the 50 counties that account for the most intensive unconventional development are located in semi-arid locales, many of which have experienced drought conditions over the last half-decade. Here, the oil and gas industry is often viewed as a competitor for freshwater resources with pre-existing municipal, industrial, and agricultural users.
Keep on Trucking?
A second point of friction involves localized intensity of water use in unconventional oil and gas extraction. As noted previously, multiple well sites, primarily in rural areas, experience high truck traffic volume. Rural roads are often designed for low freight vehicular traffic. Consequently, the increase in heavy freight hauling in concert with oil and gas development is an economic and public safety concern to local, county and state governments who maintain roadways, and to local residents because of noise, dust and other irritants that accompany heavy truck traffic in rural areas. Nothing engenders troublesome optics like the image of a school bus bouncing down a deteriorating rural road in concert with industrial level trucking.
A third point of friction involves the reality that water used for oil and gas extraction essentially is consumed rather than returned to the water cycle. Water may be considered “fresh” when injected downhole for hydraulic fracturing but flowback and produced water can be highly saline, laced with chemicals, some of which are naturally occurring downhole, and destined for wastewater injection where water essentially is removed permanently from the water cycle.
Ohio has done a great job of monitoring some of our disposal wells and regulating them.
A fourth point of friction is also highly visible from a headline standpoint. This is the issue of induced seismicity from injecting produced water as waste into underground disposal wells. Large volumes of wastewater pumped into underground disposal formations can generate low level earthquakes if injection wells are located near or along buried faults.
Not all low level earthquakes are induced from oil and gas extraction, but links between wastewater injection and and an increase in low level seismicity have been established scientifically in Oklahoma, Arkansas, Ohio, Colorado and Canada. There is evidence to support the connection in Texas, although the state, industry, and third party interests are still developing baseline data.
You Say ‘Toe-MAH-Toe’
As a result, the first decade of tight formation energy development created multiple tensions as the rapidity and intensity of oil and gas development spread across rural areas. The speed of development often outpaced the ability of state level regulatory agencies to monitor a dynamic situation, especially in regions that were experiencing high density energy development for the first time.
I really believe our job as water recyclers is to make things easier.
These tensions were compounded by the evolution of divergent views between the industry and the community when it came to the concept of “fracking.” For the general public, “fracking” was not about a mechanical process confined to a single underground lateral. Rather, the term “fracking” encompasses all activities surrounding oil and gas development both underground and at the surface.
In contrast, the oil and gas industry narrowly defines “fracking” as a discrete mechanical process of pumping water and proppant at pressure into a horizontal lateral a mile or more beneath the surface. This process, in the industry’s view, could not contaminate water supplies that were thousands of feet up hole and hindered by gravity from moving upwards, and further protected by impermeable geological barriers.
For the community at large, the initial issue focused on whether hydraulic fracturing could contaminate fresh water supplies. The industry responded by noting there were virtually zero instances where the fracking process contaminated groundwater, which is true in the narrow construct inherent in the industry’s definition of fracking. But there are instances where shoddy practices in well bore integrity or surface operations resulted in localized contamination. In the public’s mind, those instances were caused by fracking using the broader unofficial designation in which the term “fracking” encompasses all well site practices.
Divergent perspectives create a situation in which the industry and the community at large have been unable to communicate effectively since both sides view a common term differently and use that term to refer to different things. The breakdown in communication unfortunately furthers suspicion and mistrust between parties.
The level of dialogue between industry and the community at large was further muddied as those members of the affected community opposed to oil and gas development were successful in framing a negative perception surrounding water use in energy development. Video presentations, such as the movie Gasland, created an iconic image of water exiting a faucet that is subsequently lit on fire. This image of faucet water on fire has become universal and is the main thing viewers around the world associate with the term “fracking,” whether they reside in Poland, the United Kingdom, Colorado, California, or Pennsylvania.
I think we understand groundwater in northeastern Pennsylvania today probably better than groundwater is understood any other place in the world.
Perception is everything when it comes to polarizing issues. In fact, there was a methane charge to the groundwater in that iconic image from Gasland. Visually, the image told a truth. However, the methane contamination in northeastern Pennsylvania groundwater pre-dated the advent of Marcellus Shale development. Had the industry sampled groundwater chemistry and established a baseline before drilling began, the power of that globally recognized image would have been moot.
They Feel the Earth Move Under Their Feet
The difficulty in dialogue extends to the topic of induced seismicity. The general public assumes that earthquakes in oil and gas producing regions are a byproduct of fracking. The confusion is compounded because the industry uses tools such as micro-seismic to monitor the creation of fracture events—essentially localized earthquakes—underground.
However, the size of those well stimulation fractures remain modest and highly localized to within a few hundred feet of the wellbore. Less well understood among the public is the fact that induced seismicity is associated with wastewater injection of produced water into disposal wells, a process that occurs independently from the well stimulation effort.
The ties between low level earthquake swarms and Class II wastewater wells has only been established recently. A major impediment to clarity on the subject involves the lack of baseline data. For example, there were 7,725 active injection wells in Texas as of mid-2014 but only 16 seismograph stations in continuous operation in the state, many of which were not located near oil and gas operations. In response to growing complaints among citizens in the Barnett Shale region, the state of Texas is increasing seismic monitoring before taking further administrative or legislative steps to address disposal wells or permitting for injection wells. StatesFirst: Potential Unjection-induced Seismicity
Class II injection wells have been shut down or reduced in volume in Ohio, Arkansas and Oklahoma where the connection between low level induced seismicity and wastewater injection is evident. However, the issue of induced seismicity is early in its resolution phase. For example, news about the connection in Oklahoma was first released publicly in April 2015, though the state seismologist presented findings about the connection to the oil and gas industry at Hart Energy’s DUG Midcontinent Conference in February 2015.
Finding A Path Forward
Despite the rapidity at which points of friction increased between the industry and the community at large, efforts are underway to alleviate areas of concern. Leading edge water management practices in oil and gas extraction are evolving out of two core regions in Appalachia and the state of Texas. The first region is the center for an extensive world class natural gas extraction effort in the Marcellus and Utica shales, which will unfold over several decades. The second is a focal point of tight formation oil development in the Permian Basin and the Eagle Ford Shale.
Best practices in water management in oil and gas extraction are evolving through regulatory fiat and a combination of improved technology and beneficial economics as operators seek ways to lower the per barrel cost of energy extraction.
In the Northeast, new regulatory initiatives were developed quickly to cope with rapid development of the Marcellus Shale after 2008. In Pennsylvania, regulatory standards address a checklist of best practices. These include groundwater sampling before drilling commences and the use of enclosed transportable self-contained trailers for storage of flowback water in lieu of lined, open pits.
Other best practices include the use of FracFocus.org as a repository of information on the types of materials pumped into wells, and their volumes. With FracFocus, it is possible for a citizen to look up individual wells on or near their property and obtain a list of what has been pumped underground.
FracFocus now contains data on about 80% of horizontal wells drilled in the United States and several states, such as Texas, require all operators to report what is pumped underground during well stimulation to the FracFocus database. 42-366-34008 FracFocus
Also in Pennsylvania, regulatory attention was directed towards ways to ensure wellbore integrity to prevent contamination of groundwater as materials passed from the producing formation up through the well bore. The impetus for industry to adopt best practices follows the state setting a zone of presumed guilt up to one-mile in diameter with the wellbore in the center. The establishment of a zone of responsibility creates accountability in the event of groundwater contamination or surface spill.
In general, the number of energy industry violations cited by the Pennsylvania Department of Environmental Protection (PADEP), have been on a five-year declining curve. Citations aggregate a range of incidents that also include water management and cover the spectrum from the trivial (filing issues) to the profound (chemical spills, well control, fatalities). In 2014, the PADEP issued about one third the level of citations versus 2010. However, the state also levied a record $8.9 million fine for a violation involving a publicly held independent that dated from events in 2011.
In 2014, violations cited by the agency involve E&P companies of all sizes, whether international oil companies, publicly held independents, or privately held firms, though there were fewer citations among public independents in unconventional oil and gas development in 2014 and an uptick in citations involving conventional oil and gas operations among smaller players. Shale gas citations fell 28% year over year during the first six months of 2015 to 205, while the number of conventional oil and gas citations rose 25% to 1,552. Meanwhile the total number of wells drilled during the first six months of 2015 fell 42% to 720, according to the PADEP.
Discussion of water management issues in oil and gas extraction is challenging in part because Pennsylvania, Colorado, and West Virginia are the only states that provide easy access to enforcement actions in regards to energy extraction. It is difficult to ascertain whether incident trend lines for serious issues are expanding or contracting.
In Pennsylvania, the lower citation number came despite an increase in the number of inspections as the PADEP added inspectors to its enforcement program. Additionally, many citations stem from incidents that originated from rapid activity expansion in 2010-2011 and may not reflect current realities.
At the end of the day, it all comes down to cost.
In Texas, one example of regulatory evolution occurred when the Texas Railroad Commission in 2013 altered existing rules addressing liability associated with the handling of produced water to allow for the transfer of liability to third party water recyclers who could subsequently commingle water, extending the ability to participate in water recycling programs, which work at scale economics, to smaller operators who otherwise lacked the financial means to participate. TexasWhitePaper: Sustainable Water Management
We talk about it in terms of license to operate and as an industry we all earn that license each and every day.
Beyond the regulatory level, the industry is simultaneously and independently developing its own set of best practices. This process is still in infancy although a major thrust among a handful of forward thinking E&P firms centers on centralized water management for multiple well sites in large-scale extraction programs.
Centralized water management in large-scale development programs began with Range Resources Corp. in Pennsylvania in 2009. Eventually five oil and gas operators and representatives of various community at large associations founded the Center for Sustainable Shale Development which, in turn, developed a set of best practices in oil and gas extraction that extend to water management. The CSSD consortium monitors the operations of participating E&P companies and provides certification when member companies maintain practices that meet CSSD standards. Those standards exceed the minimum level set by state regulatory agencies.
The four remaining oil and gas companies in the consortium appear to exhibit lower levels of regulatory citations versus oil and gas peers, according to PADEP data.
The recycle system allows us to recycle 100% of our produced water. That's massive.
In Texas, centralized water management, including water recycling, is underway in both the Permian Basin and the Eagle Ford Shale. In 2014, Fort Worth, Texas-based Approach Resources Corp. debuted a pilot centralized water management and recycling facility in its Pangea development in West Texas. The system, which is capable of processing 330,000 barrels of water, makes the company self sufficient in water usage from sourcing brackish groundwater for supply through recycling produced water for use in drilling and completing new wells. The Approach centralized water management system is scalable for larger, well-financed publicly held companies but also provides competitive economics for small and mid cap E&Ps. Approach Resources 2015
Other examples of creative water use include Pioneer Natural Resources, Inc., which is working with the cities of Midland and Odessa in the Permian Basin to obtain municipal effluent and condition it for use in oil and gas extraction.
Meanwhile interest in developing best practices is now extending beyond water management to address well site emissions, such as gas flaring and volatile organic compounds, which is the next point of friction on the horizon between the industry and the community at large.
Industry adaption is occurring despite the fact that the capital markets provide little reward to oil and gas operators who employ best practices versus those who don’t. However, those operators employing best practices are realizing economic advantage in terms of cost reduction and, as Approach Resources has discovered, in higher production volumes as well.
It's really our intent to maximize reuse of all of our fluids. It's the right thing from a sourcing standpoint. It's also the right thing from a cost standpoint.
Points of friction are responsible for the perception gap between industry and the community at large. Shorter term, perception about the industry in the community at large is seldom tied to best practices among the best operators. Rather, instances originating from shoddy practice among poorly performing companies still colors the image of the greater industry as a whole.
Consequently, the industry’s immediate goals in water management should exceed the lowest possible bar of barely meeting a state regulatory checklist. The industry is better served when pushing efforts beyond minimum requirements as part of a broader philosophical approach to establishing a social license, or license to operate, with the community at large.
The social license concept refers to a local community’s acceptance of a company’s presence. It is gradually becoming a prerequisite for conducting business that impacts a range of direct and indirect constituencies ranging from shareholders to community residents. The concept originated internationally in mining operations and has become an operating principal for oil and gas development in Australia and Canada. The concept is slowly establishing a beachhead in the U.S. energy sector.
The concept ultimately consists of a series of intangibles in a complex interplay between a community and industry. It exists outside of the regulatory process and refers to industry efforts to build trust with the community at large through establishing effective communication before a project begins, recurring timely dialogue with community stakeholders as the project evolves, and conducting operations in an ethical and responsible manner.
In the end, both the industry and the community at large are better served operating on a level that attracts support of industry from within the community at large. The industry can establish credibility as a good corporate citizen, providing local jobs, leadership and other intangible benefits to the community at large. Alleviating points of friction between the industry and the community at large is an important strategy in building trust between parties.
Follow the Leaders
The narrative of Oil and Water reflects a recurring theme in U.S. history. The nation developed as citizens moved into a new frontier that presented challenges to established practices, which is best illustrated when agriculturally oriented emigrants moved from the East, where rainfall was adequate, to the West where rainfall was intermittent and sparse. Those emigrants adapted over time through alterations on multiple levels. Adaptations included the development of state and federal policy to address the challenges of the new frontier on the one hand, and encouraged either development of new technologies or adaptation of existing technologies in the new, drier environment.
In modern times, oil and gas extraction echoes this historic analog as the industry conducts a three dimensional journey through the earth’s crust. This new underground frontier encourages adaptation on multiple levels. In Oil and Water, the more prosaic adaptations include efforts to source water from deeper zones that do not compete directly with municipal, residential, agricultural or industrial uses. These sources often incorporate non-potable brackish water found at levels that are outside the economic reach of competing users, reducing the stress around a point of friction involving direct competition for freshwater between industry and the community at large.
We're already working with service companies and service providers to find an economic way to recover and reutilize the water we use in our operations today.
Industry is also developing technologies, or expanding the scale of long-standing technologies, to treat oilfield produced water to remove solids and brine, and return freshwater as a byproduct in a self-contained system that recycles water for oil and gas extraction. These systems can be employed by individual oil and gas companies to support large-scale unconventional oil and gas extraction programs in arid regions, often spanning hundreds of thousands of acres, or accessed through third party entities that enable less well capitalized oil and gas companies with smaller acreage holdings to participate via purchase of discrete specialized services.
We know that if you have a permeable barrier between an injection well and the basement, you are much less likely to trigger seismicity.
Wastewater injection into disposal wells can also be done in an environmentally sound manner even in heavily faulted regions. However, wastewater injection does not solve the greater issue of one-time consumptive water use versus the greater water cycle, in which water passes through multiple uses. While best practices will alleviate the source of friction that stems from induced seismicity, longer term policy goals involve an array of solutions to water management and can incorporate water recycling.
The critical thing is the water handling. Water is important, very precious.
The reduction in volume of “new” water consumed in oil and gas extraction and the evolution of industry self-sufficiency in water use effectively creates its own version of the water cycle. As in other applications, attempts to solve one challenge in water management inevitably provides unexpected solutions for other challenges. Water recycling may not be an industry silver bullet, but for those companies pursuing the option, a real world benefit includes lower operating cost and may include production enhancement.
For those in the crosshairs of the intersection between oil and water—and the industry and the community at large—change seems to occur at glacial pace. In the broader context of time, change is evolving at a remarkable rate and will accelerate as the oil and gas community adapts to follow the best practices of industry’s innovation leaders.
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