Guest Speaker, LaFollette said that the U.S. reservoirs with the highest mobility, where oil and gas came up out of the ground without fracturing, were mostly depleted by the end of World War II, producing about 7 billion barrels of oil. The industry moved on to lower permeability reservoirs that needed some stimulation to produce oil. Today, LaFollette said, we are dealing mostly with the lowest mobility reservoirs, which are rock formations that have been under high pressure (0.7–0.9 psi per foot below the surface) for geologic time. Those formations are the most abundant by volume, and are actually the source rocks for the higher mobility wells.
National Academies of Sciences, Engineering, and Medicine. 2015. Chemistry and Engineering of Shale Gas and Tight Oil Resource Development: Workshop in Brief. Washington, DC: The National Academies Press. https://doi.org/10.17226/21882.
Treatment depends on the properties of the reservoir rock, more specifically the rock permeability and brittleness.
Javad Paktinat of the Anadarko Petroleum Corporation discussed his ongoing work to improve hydraulic fracturing production, while reducing cost and environmental impacts. He presented these advances in the context of emerging challenges, including recent restrictions on the use of fresh water, growing environmental concerns of reusing flowback and produced water, and lower prices for natural gas.
Paktinat said the elements that engineers can alter to optimize hydraulic fracturing are: (1) the water source (freshwater, flowback or produced water, or reclaimed or waste waters); (2) the fracturing fluid system (guar gel system, cross-linked gel system, or slickwater, see Box 1); and (3) the major fracturing fluid chemicals for friction reduction, bacteria control, clay stabilizer, and scale inhibitors. He illustrated in several areas how experimentation and case studies have provided new ways to achieve multiple goals.
Paktinat said that the source water is a major factor driving the choice of hydraulic fracturing fluid. Increased use of high salinity waters, such as those found in produced water, can adversely impact fracturing fluid performance. Thus designing systems and disposal systems that work well with high salinity waters is a priority, Paktinat noted, because using such waters can both conserves fresh water and help eliminate trucking traffic needed to bring in fresh water and dispose of produced waters.
Characteristics of Fracturing Fluid Systems
Guar gel system
Made from guar bean
Advantage of being a cross-linked fluid to better carry sand into the well
Resistant to high total dissolved salt (TDS) brines
Cross-linked (CMC) gel system
Made from cellulosic material
More sensitive to high TDS brines
A polymer required to achieve same viscosity as guar
Slickwater (SW), one type of friction reducer)
Polyacrylamide
Most common fluid used
High molecular weight, low cost
Paktinat said that bacteria control is the second most important element that engineers and formulators must consider when designing the fluids.
Bacteria produce hydrogen sulfide, which can sour a well very quickly.
Bacteria control must be compatible with the fracturing fluid, quickly kill bacteria and
Fundamental Rate Relationship for Hydraulically-fractured Wells
The production rate (q) of a hydraulically-fractured well is dependent on its mobility (k/µ) as determined by the “fundamental rate relationship” where k is the permeability of the rock, h is the thickness of the producing layer, Pres is the reservoir static pressure and Pwf is the wellbore flowing pressure, µ is the viscosity of the reservoir fluid in situ (the lower the µm, the greater the ease at which hydrocarbons can flow in that pore system), re is the drainage radius of the well, rw is the well radius, and S is the skin factor for the well.
LaFollette described several challenges his company and others in industry are examining and trying to solve, including:
Uncertainty in “height growth” barriers of the fracture, which can affect how far apart fractures can be placed and must account for vertical stress in the rock, subseismic defects, and other factors. LaFollette said that a big part of this issue is that the current computational models do not take into account the full 3D physics of the reservoir and 3D seismic data is limited. For example, subseismic defects (natural fractures) are mostly unknown.
Fracture propagation is not 100% efficient—there is “leakoff.” That is, some of the injected fluid moves into the pore system in the rock formation adjacent to the fracture walls, including open natural fractures. The extra fluid gets sucked in and stays put, LaFollette said.
Some fracturing proppants (sand or other material to keep the wells open) are not stable in harsh environments. Long-term immersion in high salinity brine and shale at high temperature results in strength loss and also scaling.
Keep it down, meet environmental standards, and be cost-effective. There are standard approaches to controlling these bacteria, but other approaches, chemical and physical are also being investigated.
Regarding fracturing fluid systems, Paktinat discussed innovations and modifications being used in an endeavor to increase return and to tailor systems to specific wells. For example, he highlighted the use of hybrid systems composed of two or three fracturing fluids, to maximize their distinct advantages. Typically, a fracture is opened with slickwater, which is a low friction system, and then cross-linked gels are used toward the end of each stage to better carry sand and proppants into the fracture.
With increased economic pressures in recent years, Paktinat said, all of the standard practices are being fundamentally re-examined. For example, he was involved with an experiment to determine the value of using clay stabilizer. The results showed that in that in one case there was no adverse effect when it was removed, the formulation was modified accordingly. Similarly, with regard to scaling of the well due to salts and minerals, Paktinat said the industry is now carrying out rigorous water monitoring to learn more about what is driving scaling and how best to treat it with available methods. Industry is also running predictive models to calculate the optimal amount of scaling inhibitor so as to eliminate most of the scaling without wasting the inhibitor, which is costly.
Paktinat also spoke of advances made by using polyacrylamide friction reducers—both cationic and anionic—which can be optimized depending on the water used. Notably, cationic friction reducers perform well in higher salinity produced waters, permit the use of a wider range of biocides, and exhibit some clay stabilizing properties. Anionic friction reducers perform well in fresh and mid salinity waters, and allow the use of a wide range of scale inhibitors. Increasing the understanding of the role and chemistry behind each of the elements of the fracturing fluids may result in additional tools operators can use to reduce water and material usage at the wells.
Bruce McKay, a chemical engineer at Schlumberger, discussed the engineering objectives that drive industry decisions in the design and development of fracturing fluids. The ideal goal of the oil and gas industry, said McKay, to provide society with access to energy sources and with feedstocks for the petrochemical industry as efficiently and responsibly as possible. This requires that a number of operators must first decide where to drill by evaluating the rock formations and determining the size and mobility of the reservoirs.
The next step, which is McKay’s job, is to design an efficient and economical completion system—defined as “the establishment of the intimate contact between the well as it is drilled, cased, and cemented—and the reservoir, as a living, breathing, producing thing through which hydrocarbons can be accessed.” McKay said his most important message is that, although every rational decision should be connected to a piece of information, engineers almost never have access to all the information that they would like to have.
Hydraulic fracturing engineering jobs are as complicated as the space shuttle, McKay said, because the shale formations really do not want to give up their oil and gas. Industry is always on the lookout for new methods. “Operators all want to be the second to try a new method of stimulating a well,” he quipped. “They have no tolerance for operational or safety risks, they all want to minimize costs and, if the last two are satisfied, they might be able to improve production.”
McKay said there are three roles for the hydraulic fracturing fluid: (1) propagate a fracture; (2) transport proppant; and (3) degrade or otherwise not interfere with recovery pathways. McKay works on permeability—the ease of fluid flow through a given rock system. To keep the fluid flowing, you have to add proppant to “prop up” the fracture to keep the fluid flowing through it, or the permeability may decline, said McKay, as a result of the residue from active drilling.
He talked about advances in hydraulic fluids being used to enhance production. The industry today is widely using a gel called borate cross-linked guar, McKay said. Guar is a biopolymer grown from beans. The guar gel has a viscosity comparable to olive oil, except it is much better at suspending proppant. The magic, McKay said, is in creating a cross-link by “stapling the polymer together” with borate. It displays a property known as shear recovery, making it possible to pump a thick gooey gel at 50 barrels per minute and pass it through holes about “the size of a pinky” and then through newly exposed fractured rock. The fluid is not degraded by all those high shear events and maintains its viscosity. It works well at temperatures below 300 degrees Fahrenheit, which is representative of the temperatures in many wells, but at higher temperatures other strategies arerequired, such as some of those described by Javad Paktinat.
McKay described another new development, slickwater gels, which are used primarily for gas and dry gas production. Slickwaters overcome friction because they contain a synthetic polymer that “flexes” as it meets eddy currents and dissipates energy before the rock walls can push back with friction. Slickwater moves through a pipeline at high velocity so that turbulent flow moves sand grains, turn corners, and even props open natural fractures. New research is focused on using a hybrid of slickwater and guar gel.
There are other areas ripe for future research because it is very difficult to replicate real-world conditions in the lab, McKay said. Developing the ability to test under real world conditions of pressure and temperature simultaneously may be a fruitful avenue. McKay also noted that improving the conductivity of proppants, controlling emulsions of oil and water, and controlling bacteria, biofilms, and scaling from carbonate and sulfate minerals—which some say create challenges for about 30% of hydraulic fracturing activities on a global scale—would support more efficiency.
ALTERNATIVE WATER SOURCES FOR HYDRAULIC FRACTURING
Key points made by presenters Danny Reible and Radisav Vidic:
Waste water handling and storage methods around the country vary widely.
Water availability for hydraulic fracturing may pose a challenge in certain locales. Shipping fresh water to sites where it is not locally available is costly, and reducing the reliance on fresh water is a goal for the industry.
Water sources used and being considered for use in hydraulic fracturing in the future include wastewater, brackish groundwater, and recycled produced water.
Efforts are underway to identify ways to use less desirable water sources, such as contaminated water from historic mining operations, for hydraulic fracturing operations.
There are many options being considered for use of produced water from hydraulic fracturing, but the risks of using these waters for different applications have not yet been fully assessed.
Danny Reible of Texas Tech University explained the challenges and opportunities of using alternative water sources for hydraulic fracturing. Reible began his talk by describing how issues of water availability tend to be local. Nationally there is water enough for hydraulic fracturing, but water scarcity is a local and regional concern, and addressing water usage must take that into account.
Total water use for hydraulic fracturing in the United States was expected to peak at 120,000 acre-feet per year, which is not a high number when compared to other water uses, such as agriculture. Nonetheless, both in the U.S. and abroad, Reible said, many shale plays are located in areas that are water stressed, sometime exceeding sustainable rates of water withdrawal (see Figure 4)2. “To the extent possible,” Reible said, “we need to minimize the “good water” we pump down the hole.”
He said that most of the technical issues could be overcome, but that most of the challenges lie in issues that are economic, regulatory, historic, and logistic. From an economic perspective, Reible said, we do not value water equally across all uses (e.g., agriculture, municipal, hydraulic fracturing) and water costs/value is a fraction of that of oil.
This affects the drivers for creating an infrastructure, such as pipelines, for water distribution to where it is needed. A second challenge in Texas is that disposal of produced water is much cheaper than treating or recycling it. It is the opposite in the Marcellus Shale (e.g. PA and WV) where the high cost of disposal has driven a lot of recycling. Alternative water use
Figure 4. Several shale plays are located in areas that are moderately to extremely water stress, making it important to assess alternative water sources for hydraulic fracturing.2
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2 Reprinted with permission from Avner Vengosh, Robert B. Jackson, Nathaniel Warner, Thomas H. Darrah, and Andrew Kondash Environmental Science & Technology 2014 48 (15), 8334–8348DOI: 10.1021/es405118y Copyright 2014 American Chemical Society.
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Suggested Citation:”Chemistry and Engineering of Shale Gas and Tight Oil Resource Development A Workshop for the Chemical Sciences Roundtable.” National Academies of Sciences, Engineering, and Medicine. 2015. Chemistry and Engineering of Shale Gas and Tight Oil Resource Development: Workshop in Brief. Washington, DC: The National Academies Press. doi: 10.17226/21882. ×
in Texas has been driven by the cost of access to water and also the negative perception of growth of hydraulic fracturing during a period of severe drought, Reible said.
Reible examined three types of water that could be used for fracking to address water availability: (1) municipal and other wastewaters; (2) brackish groundwater; and (3) recycled produced water. As always, Reible said, the old real estate adage applies: the extent to which each option can be applied is all about “location, location, location.” For each option, availability of the water near the point of use is critical. Regulatory factors can be a problem, for example some places require the return of wastewaters to the environment after use to maintain environmental flows, said Reible For example, the municipal wastewaters cannot be used unless they can be returned to the same watershed, something that is not feasible for flowback or produced water from a hydraulic fracturing process due to contamination and salinity.
Reible explained that many shale reserves are co-located with brackish ground waters that provide a possible alternative water source. The location of those waters is known, because industry needs to avoid them when they drill to get oil and gas, and the chemical characteristics of these waters can vary widely from site to site. One problem in their use in hydraulic fracturing, Reible said, is that an understanding of the chemistry of concentrated brine solutions and reactions that can occur within them is currently lacking. Though there is some understanding of the fundamental chemistry, thermodynamic models and an understanding of the conditions under which they could increase scaling, for example, would be beneficial.
Reible said that he thinks there is a lot of potential for reusing produced water to offset fresh water needs for hydraulic fracturing, but that conditions have to be right. The biggest requirement is a good match of the volume of produced water and the volume of water needed for fracturing, he said. Reible talked about one operator in Texas with the right conditions: they collect produced water from their 165 wells that produce about 30,000 barrels of oil per day and use it toward their ongoing requirement for 30,000–60,000 barrels of water for hydraulic fracturing; they own the water and mineral rights on the land; and they have developed a
Use of Abandoned Mine Drainage as a Water Source for Hydraulic Fracturing
Radisav Vidic of the University of Pittsburgh talked about some of the challenges of reusing produced water in the Marcellus Shale and some potential solutions he is exploring. The desire to reuse water is high in Pennsylvania for two reasons, Vidic said. The first is that water disposal is very expensive, because the produced water has to be trucked to Ohio or West Virginia. Second, truck traffic is the biggest complaint industry gets from members of the community. Shifting from trucking water into an area to pumping it could significantly reduce traffic and, potentially, costs. However, water reuse in the Marcellus Shale is complicated by the fact that the produced water is high in total dissolved solids (TDS) such as Ba2+, Sr2+ and Ca2+, which can cause scaling underground, and also very high in naturally occurring radioactive materials (NORM).
Vidic and his team had the idea of using Abandoned Mine Drainage (AMD) as a water source. In Pennsylvania, the Marcellus Shale is just under the state’s coal reserve. AMD water, which is full of sulfates, affects 4,000 miles of streams and associated groundwater. The idea was to mix the produced water rich in Ba2+, Sr2+ and Ca2+ with sulfate-rich AMD water in order to precipitate out solids such as, barite, celestite and gypsum, respectively, and help clear the water. “If you take the AMD from the environment,” said Vidic, “the industry is a savior because it’s helping to solve legacy environmental problems.”
Vidic and his team tested the idea in the lab. They found that barite precipitates out and leaves clear water with very low turbidity (<1 ntu). However, in real world conditions, they found radium was coming out of the water in equal parts with barium, resulting in a radioactive solid. Pennsylvania has allowed industry to dispose of radioactive solids in landfills under what is known as the Allowed Source Term Loading guidelines, but has recently made the guidelines more stringent. Vidic said that his calculations show that, with these new rules, such disposal will be violating the allowable limits by the 2030s.
Vidic has been exploring a new alternative for managing solid radioactive waste by putting it back in the ground as proppant. The only problem, Vidic said, is that the proppant particles were a too small to meet American Petroleum Industry guidelines. Thus, Vidic’s team has been working on a method to grow the particle size and is getting good results.
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Suggested Citation:”Chemistry and Engineering of Shale Gas and Tight Oil Resource Development A Workshop for the Chemical Sciences Roundtable.” National Academies of Sciences, Engineering, and Medicine. 2015. Chemistry and Engineering of Shale Gas and Tight Oil Resource Development: Workshop in Brief. Washington, DC: The National Academies Press. doi: 10.17226/21882. ×
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relatively easy treatment method to remove the iron and oil from the produced water and also control the bacteria in it. There are few environmental impacts of the recycling, Reible said, and the operator was proud that they eliminated 80,000 local truck trips to carry water. Barriers for reusing produced water are not as much technical as logistical and regulatory, said Reible. He noted that depending on local restrictions, it may not be allowable to recycle or reuse the water at a nearby site or to transport it to a different location. Some areas are modifying these restrictions to allow for increased movement of water between sites and operators.
ECOLOGICAL AND ENVIRONMENTAL CONSIDERATIONS
Key points made by presenters Briana Mordick, Avner Vengosh, Denis Tuck, and Will Stringfellow:
Public concern about hydraulic fracturing and its processes has grown along with the expansion of the practice. These concerns relate to water sourcing contamination from waste water and drilling operations, injection of chemicals into the ground, and risks from spills.
Transparency among companies, governments, and the public regarding chemicals used during the hydraulic fracturing process has increased, but there is room for additional work in this area.
The number of chemicals and complexity of the mixtures in which they are used, combined with the extreme and variable conditions under which they are handled, is a challenge for understanding their fate and transport as well as toxicity or environmental concerns posed by their use.
Additional research may help identify appropriate methods for monitoring of wells to identify sources of contamination.
As the utilization of hydraulic fracturing grows, so too does the level of public concern over the practice’s impacts on the environment. Concerns include the high consumption of water resources, the generation of large volumes of wastewater, the irreversible injection of chemicals deep underground, and the potential impact on drinking water and surface water resources via potential migration of contaminants from well pads or accidental and operational spills.
Briana Mordick of the Natural Resources Defense Council said that the majority of states that have significant oil and gas production all have some sort of law requiring disclosure of the chemicals used in hydraulic fracturing, but that there are several issues with the quality of what is being disclosed. One issue, she said, is that it can be hard to determine the specific chemicals being used and in what amounts. A recent EPA study found that, on average, disclosure reports had five chemicals that were reported as “confidential business information” (CBI), Mordick said. Disclosures include the total volume of water used and the ingredients are noted as a percent mass of the total fluid. As neither the total volume of fluid used nor the total mass of the fluid used are reported, Mordick noted that this introduces “a bit of opacity” in understanding the total quantity of a given chemical used, though it can be approximated by assuming the majority of the fluid is water. She added that chemicals are often reported by their trade name and by their purpose, which is sometimes straightforward (e.g., corrosion inhibitor) but can be vague (e.g., “additive”).
Another issue, Mordick said, is that there is no disclosure of chemicals that form as hydraulic fracturing fluids interact with the rock formation. This is an issue that is very important for an occupational health researcher, because the person who is most likely to be exposed is the person who is dealing with the produced water from the service company.
It is also important to realize that hydraulic fracturing fluids are only part of the universe of chemicals used in the oil and gas production process, but they are currently the only fluids for which the chemical components are disclosed, Mordick said. Other fluids, such as drilling fluids, enhanced oil recovery fluids, and produced water do not have to be disclosed. The task is made all the more difficult, she said, because produced water has a very wide range of compositions.
Mordick pointed out that while public interest over fracking is driving public policy, it is not necessarily where the greatest environmental or health risk lies. In California, the vast majority of oil and gas production is still conventional, which she said has been mismanaged for decades—more than 2500 wells were permitted to inject wastewater into federally-protected drinking water aquifers. It is extremely important, she said, to get the scientific information to those who are setting policy and make sure that policy focuses on the “right risks” with regard to hydraulic fracturing.
Avner Vengosh of Duke University said the motivation for research his team has conducted is that
the U.S. Energy Information Administration (EIA) has shown that, in spite of the price drop, natural gas will be in demand for the foreseeable future (see Figure 5). Thus, understanding the environmental impact, especially on water, is important.
Vengosh and his research team have reviewed the scientific literature and collected samples from several states in an effort to understand the different processes that occur both upstream and downstream from shale gas development.
Specifically the team is looking for evidence of:
stray gas contamination of shallow aquifers;
contamination of surface water and shallow groundwater from spills, leaks, and disposal of wastewater and hydraulic fracturing fluids;
accumulation of toxic and radioactive residues in soil or stream sediments;
formation of carcinogenic disinfection byproducts in downstream drinking water utilities from disposal or spill oil and gas wastewater; and
over-extraction of water resources that could induce water shortages.
Vengosh said that the naturally occurring chemicals in the brines contained in the produced waters should be added to the list of chemicals that are managed. He referred to a 2009 report by Hayes3 showing that 25–45% of the total injected water is returned, which means that a lot of injected water is staying underground and that the water coming back is mostly brine that was entrapped within the shale formation. Vengosh also pointed out that the high concentrations of bromide and iodide present produced water, even if diluted as part of disposal procedures, has the potential to result in the creation of unexpected byproducts during drinking water disinfection procedures. He noted that these byproducts should also be monitored.
The need to monitor the dose level of NORM, which were a known concern for hydraulic fracturing back in 1950s, is very important, Vengosh said. The Marcellus Shale formation contains a high concentration of radioactive nuclides compared to other formations in the United States, and some of these nuclides are present in produced water from the wells at concentrations far exceeding those allowable under the federal drinking water standard. The rapid intensification in oil and gas production is increasing the risk of leaks or incorrect disposal that could lead to ground and surface water contamination, and this may affect the ability of downstream water treatment facilities to maintain acceptable levels of radiation in drinking water, he said.
Figure 5. EIA projections of energy consumption by fuel show that natural will be in demand for the foreseeable future. SOURCE: EIA 2015
To help determine if contamination in a sample is coming from hydraulic fracturing fluids or if it is coming from other sources of contamination such as acid mine drainage, Vengosh said his team developed a systematic method of looking at chemical isotopes in a sample. Using multiple geochemical and isotopic tracers (carbon isotopes in hydrocarbons, noble gas, strontium, boron, and radium isotopes), they developed an isotopic fingerprint
Sampling by Duke University Research Team
800+ shallow private wells in PA, NY, WV, AK, NC, TX;
About 100 produced/flowback waters samples from conventional and unconventional wells in PA, NY, AK, CA;
200+ surface waters in PA, CO, WV and river sediments downstream from waste waters disposal sites.
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3 Hayes (2009), Sampling and Analysis of Water Streams Associated with the Development of Marcellus Shale Gas
to distinguish between naturally occurring dissolved gas and salts in water and contamination directly induced from shale gas drilling and hydraulic fracturing operations.
With their method, Vengosh’s team was able to help show in a 2013 paper4 that in Pennsylvania, wastewater being moved to brine treatment facilities was not adequately treated to remove all the inorganic contaminants, some of which were ending up in streams and rivers.
Vengosh said other potential pathways into the environment include spills and accidental releases, spraying of salts from operations onto roads for deicing and dust suppression, and leaking from ponds and storage reservoirs.
University of the Pacific and Berkeley National Laboratory, explained the work he has been doing over the past two years to better understand hazards and risks posed by tight oil production in California. He said the studies were prompted by the Bureau of Land Management in response to a public concern and related lawsuits about hydraulic fracturing on federal lands, and also by a group of new laws in California requiring various scientific studies.
Stringfellow emphasized the fact that the studies are very California-specific and so would not necessarily apply to other geologies and places where natural gas production is the focus, rather than oil production as it is in California.
Stringfellow said his team has developed inventories of chemicals used, which are heavily reliant on voluntary reports from industry, such as those provided thorough FracFocus, an online registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission that encourages voluntary reporting by industry of the chemicals they are using.
Stringfellow’s team identified more than 300 chemicals or chemical mixtures that have been reported as being used in California for hydraulic fracturing. “The problem in trying to respond to public concerns is how to evaluate so many chemicals, because you have to go through the whole list,” Stringfellow said.
Produced water used for irrigation in the Cawelo water district in California. SOURCE: Lauren Summer/KQED Public Media for Northern California.
To get a handle on this problem, Stringfellow’s group is developing an environmental profile for each chemical, which is a necessary first step for evaluating the hazards and risks associated with a chemical and for conducting analysis such as how the chemical is transported in groundwater. As the list of chemicals to be profiled is long, chemicals that are used most often and work in the largest quantities and concentrations are being given priority. The profile assigns a level of toxicity (aquatic and mammalian) as well as other hazards, such as flammability and corrosiveness, on the basis of the Globally Harmonized System for the Classification And Labeling of Chemicals (GHS)—a worldwide system now adopted in the United States. Added complications arise, he said, because industrial chemicals often are not pure compounds; they may be mixtures, blends, and include such things as solvents and surfactants.
Some companies have developed similar scoring systems for internal use. For example, Denise Tuck of Halliburton describes her company as having a system that takes into account environmental concerns such as bioaccumulation, biodegradation, ozone depletors, volatile organic compounds, hazardous air pollutants, priority water pollutants, and environmental
Data Sources for Chemical Inventories in California
Voluntary industry reports
FracFocus (Versions 1 & 2)
Department of Oil Gas & Geothermal regulation (DOGGR)
Central Valley Regional Water Quality Control Board (CVRWQCB)
South Coast Air Quality Management District (SCAQMD)
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The studies are just beginning to look at releases of chemicals into the environment, Stringfellow said. A big issue, he continued, is communicating to the public that chemical inventories do not become an environmental hazard until there is a release into the air, water, or soil. His team is looking at the known ways chemicals are released into the environment, including re-injection of produced water for enhanced oil production and use of produced water in dust control and irrigation, a process that is unique to California. According to Stringfellow, some produced water is going into unlined disposal pits in the California Central Valley.
