5.1.1 Precautionary Principle

Certainly, caution should be taken on evaluating site‐specific risks and concerns. Adherents of the precautionary principle require that public policy should resist the introduction of a new product such as genetically modified organisms (GMO) or processes such as hydraulic fracturing whose ultimate impacts some say are disputed or unknown. In December 2014, Governor Andrew Cuomo of the State of New York, in a bold move to eliminate the potential negative (and positive) impacts of hydraulic fracturing, banned high‐volume fracturing for shale gas development. This political decision follows the precautionary principle and will affect the residents by shielding them from negative impacts of hydraulic fracturing such as potential environmental and health issues. The decision also limits job growth, royalty potential of land owners, and economic development. The potential impacts and risks of spills are described below.

5.4.1 Air Resources

Air resource impacts are directly related to air quality degradation; these impacts range from the introduction of equipment and vehicle exhaust of diesel fumes and particulate, to sulfur compounds such as hydrogen sulfide (H₂S), fugitive emissions from methane (CH₄) and other gases leaking from wells or pipelines, and volatile organic compounds (VOCs) spilled on the surface, which evaporate, to fine silica dust from the sand proppants. Air emissions are influenced by work practices, weather patterns, local topography, prevailing wind directions, and specific contaminant characteristics. Sophisticated air dispersion models can be used to predict air contaminants and the spatial patterns of air dispersion and deposition (TEEIC 2017).

Sites having air quality degradation issues may be located hundreds of miles away or more from the drill site. Dust and air pollution from vehicles and equipment from the borrow areas (off‐site sand and gravel pits) that produce the raw materials for the gravel pads, cements and concrete, and sand proppants may create local air quality issues. An example would be the proppant sands mined in Minnesota but shipped to Pennsylvania for Marcellus Shale gas production. Transportation sector exhausts from diesel trucks, ships, and trains can also impact areas from a regional to international scale. Greenhouse gases (GHG) from vehicle and equipment exhaust add to the growing atmospheric carbon buildup, as well as fugitive emissions of methane and light‐end hydrocarbons leaking from wells, valves, and pipelines. Combustion of the tight oil and shale gas also adds to global atmospheric carbon buildup.

5.4.2 Geological and Soil Resources

Geological and soil resources importantly include archeological and paleontological sites, drainage and erosion issues, landslides and earth movement, and soil contamination related to industrial activities. The area of influence related to geology and soil resources includes the well site and the borrow areas (off‐site sand and gravel pits). Even the fluid disposal sites, which can be hundreds of miles away or more, can be impacted by tight oil and shale gas exploration and production (E&P). Some fluid disposal sites in Oklahoma, for example, have been experiencing seismicity related to the waste injections from conventional and unconventional resource recovery (Ellsworth 2013).

5.4.3 Ecological Resources

Habitat destruction or fragmentation during construction of the well pad, access roads, and pipelines and unintended introduction of invasive species on boots and tires through air or water can damage ecological resources. Agricultural and grazing disruption can occur, and damage to native vegetation and wildlife populations are a concern near the well pad, pipelines, roadways and the built environment associated with the unconventional oil and gas extraction and production. Migratory species may be impacted. Barriers such as fences or walls can impede migration of certain species.

5.4.4 Land Use Resources and Socioeconomics

The category of land use resources includes a variety of impacts. Social issues such as environmental justice, health and safety for the community and workers, worker training, historic and cultural resource protection, and land use planning are difficult to address. Community concerns of rapid and uncontrolled change added to the social challenges of newly introduced or rapidly expanding industrial activities and an increased (or decreased in time of economic bust) workforce from outside the area create local friction. The nuisance factors such as noise, odor, light pollution, increased traffic, and degradation of visual aesthetics are annoying impacts that add up to reduce the quality of life, unless they are mitigated. The area of influence for this resource depends on the socioeconomic factors of the area, with urban areas having different issues than rural areas (TEEIC 2017). Land use resources and socioeconomics also include worker and community safety issues. The explosive nature of tight oil which is produced from the Bakken Formation has high volatility caused by a large proportion of dissolved light hydrocarbons methane, butane, and propane. Pipelines and railway cars engineered for safe conventional crude oil transport were not designed for the characteristics of highly volatile tight oil.

5.4.5 Water Resources

This category of resource includes both surface water and groundwater resources, and phases 3–6 of the exploration–production life cycle include handling large volumes of fluids. In the process of handling fluids, impacts can include the depletion of limited water supplies and the degradation of quality of water resources related to surface or subsurface contamination by specialized industrial chemicals used in drilling muds or makeup water for the hydraulic fracture stimulation process or natural fluids (crude oil, condensate, natural gas, or produced brines) associated with the oil and gas production. The areas of influence of impact to water resources include where water is withdrawn and extends to where the chemicals are spilled. Water contamination caused by accidental spills or leaks of industrial chemicals or produced fluids, improper wastewater storage and handling, mechanical failures, and inadequate worker health and safety training is predictable as well as avoidable. Water resources can be impacted in many possible pathways. Impacts to water resources can occur because of a release at the wellhead from spills of hydraulic fracturing fluid or additives (Figure 5.2), from pipeline or tanker car spills of Bakken crude oil, or from releases of fluids in the subsurface (Figure 5.3).

Water resource impacts can be large, although many other industries use significantly more water than the oil and gas industry uses for makeup water for hydraulic fracturing operations. Based on years of assessment (US EPA 2015) and evaluation of hydraulic fracturing for oil and gas and the impacts from the hydraulic fracturing water cycle on drinking water resources in the United States, US EPA (2016a, b) noted the following threats to water resources:

(1) Water withdrawals for hydraulic fracturing in times or areas of low water availability, particularly in areas with limited or declining groundwater resources; (2) Spills during the management of hydraulic fracturing fluids and chemicals or produced water that result in large volumes or high concentrations of chemicals reaching groundwater resources; (3) Injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, allowing gases or liquids to move to groundwater resources; (4) Injection of hydraulic fracturing fluids directly into groundwater resources; (5) Discharge of inadequately treated hydraulic fracturing wastewater to surface water resources; and (6) Disposal or storage of hydraulic fracturing wastewater in unlined pits, resulting in contamination of groundwater resources.

5.6.1 Impacts from Phase 1: Prospect Generation

Phase 1 includes collecting information from public records, university libraries, file research, and local interviews. Some of the work entails locating information about the subsurface conditions and geology. Although there may be a limited number of local field inspections, rock and fluid sample collection, interviews with owners, and other limited interactions, most of the geologic prospect generation processes will occur in the office. Therefore, impacts from Phase 1 prospect generation are limited to field work: geochemical sampling and geophysical surveys.

5.6.2 Impacts from Phase 2: Planning and Site Preparation

Phase 2 includes exploratory activities and consists of lease acquisition and documentation of background conditions and potential nearby concerns, such as residents, water supplies, etc. Damaged or abandoned legacy oil and gas wells can affect groundwater resources in an historic oil and gas production area. In addition, the condition of nearby active and abandoned water supply wells must be examined, and tested, if possible, as a way to verify predrilling water quality. The environmental regulations in the 1980s in the United States (and later in other countries) have minimized the potential of improperly abandoned oil and gas wells. Unfortunately, there are many improperly abandoned or lost oil and gas wells drilled prior to the enforcement of environmental regulations. Old water supply wells or abandoned water wells also are common in historic oil and gas production areas. Some of these historic wells were installed without proper well design and impermeable cement seals, or they currently contain damaged or corroded well casings. Historic oil, gas, and water wells can create unintended conduits for surface or subsurface contaminants to enter groundwater resources. Orphaned wells with no existing owner or operator are largely a legacy of the past, when site restoration was not commonly deemed necessary. Not all historic wells create water resource impacts. However, identifying and addressing historic oil, gas, and water wells as possible subsurface conduits prior to the start of unconventional oil and gas activities reduces the risk of future litigation. Sampling of historic and current water supply wells in the area for background geochemistry and water production can help in identifying water quality and quantity concerns prior to oil and gas production. Modern operators performing unconventional resource extraction in an area with historic oil and gas production should locate and document prior environmental damages before the field activities start in order to avoid litigation and environmental discussions about legacy and background conditions.

Only after the leases have been acquired, the environmental impacts have been identified and documented, should the drilling project and well be permitted, followed by site preparation. Limited exploratory drilling of a small‐diameter test borehole may be performed to identify specific basin ‘target zones’ during this phase of activity. If an exploratory well is drilled, direct impacts could include construction of a limited number of access roads, noise, air emissions and wastes produced by the drill rig, and possible spillage of fluids or sludges from lined reserve pits or tanks. Examples of possible indirect impacts of phase 2 activities include disrupting wildlife in breeding or calving season, sediment runoff from erosion, and dust generating from traveling on unpaved roads. Phase 2 also includes well pad and initial access road construction. Excavation and blasting at surface mines for construction materials such as sands and gravels are common. These construction materials may be imported from hundreds of miles away if local sources are not available. Finding adequate supplies of water and nearby gravel and sand and ruling out historic water, oil, gas, and disposal wells, utility conduits, trenches, and geologic faults near areas of industrial activity (drilling wells, laying pipelines, storing oil and gas) reduces potential subsurface impacts should a release of chemicals occur.

Specific Impacts/Activities

• Emissions – Clearing, grading, excavation, and blasting can create dust emissions. Vehicles and earth‐moving equipment generate exhaust emissions. Fugitive gas emissions can be generated by improperly stored fuels, gases, cleaners, degreasers, paints, and solvents.
• Surface Footprint – An individual well pad would occupy <5 acres; however, up to 40 acres per well could be disturbed depending upon the length of access roads, diameter and depth of pipelines, size of excavating equipment and size of equipment storage yards, the number of wells being drilled from each drilling pad, and other factors associated with the field. Horizontal well drilling techniques can minimize surface disturbance. For example, six to eight horizontal wells on a multi‐well drill pad can access the same shale gas reservoir volume as sixteen vertical wells (TEEIC 2017).
• Waste Generation – A potentially large quantity of solid waste derived from vegetation removal would include woody tree and plant debris and miscellaneous wastes associated with pad construction activities. Industrial wastes such as used lubricants and waste oil would also be produced from equipment. Human sanitary wastes are generated by the workers.
• Water – Water will be used for dust control and making cement and concrete features, including tank pads.
• Workforce and Time – About 6–10 workers, mostly equipment operators, could construct a well pad and access roads in about 1 month.
• Other Impacts – Increase in vehicular and pedestrian traffic at the drill site. If the drill site is isolated, construction and installation of work camps and dining facilities would occur.

5.6.3 Impacts from Phase 3: Drilling

During the drilling phase, the activities that may cause environmental impacts include the removal of vegetative cover, ground clearing, grading, drilling, vehicular and pedestrian traffic, and construction and installation of drilling facilities (and work camps, if the site is isolated). Examples of direct impacts include land disturbance, soil erosion, drilling noise, vehicle noise, air emissions, worker activity, drilling‐derived waste material disposal, fuel spills, timing and duration of drilling, and number of jobs created. Indirect impacts include sediment runoff, demand for services, creation of service jobs to serve increased population, and overuse of local infrastructure and emergency services such as roads, water and wastewater plants, schools, hospital, and fire and police services.

Specific Impacts/Activities

Emissions – Vehicles, pumps, and well drilling equipment generate exhaust emissions. Fugitive gas emissions can include natural gas that is mostly methane and other VOCs; polycyclic aromatic hydrocarbons (PAHs); benzene, toluene, ethylbenzene, and xylenes (BTEX); carbon dioxide (CO₂); carbon monoxide (CO); and hydrogen sulfide (H₂S). Improperly stored fuels can contribute to fugitive gas emissions. Monitoring fugitive gases is performed using multigas detection meters.

Hazardous Materials – By definition, hazardous materials are those substances considered to be toxic, corrosive, flammable, reactive, irritating, and strongly sensitizing. Numerous hazardous materials are used during the drilling and hydraulic fracture stimulation process that may pose a threat to human health of workers or the community or to the environment through unintended fugitive emissions or accidental releases of hazardous chemicals or wastes.

Surface Footprint – Depending upon the ongoing operations, the surface area needed during the production phase could be reduced from the acreage required for the drilling and development phase. After drilling has been completed, a well pad is often reduced in size to 1.5 acres or less. Portions of the area disturbed during construction and drilling that are not needed for ongoing production could be revegetated after drilling to reduce the overall footprint of the well pad.

Waste Generation – Industrial wastes from equipment includes machine and engine waste oils, lubricants, and engine coolants from a variety of on‐site maintenance of construction vehicles and equipment. Spent solvents, cleaning agents, paints, and other corrosion control coatings are used on equipment and applied to structures. Human sanitary wastes and small amounts of wastewaters are generated from cleaning and drill rig assembly operations. Other assorted wastes include dispersants, corrosion inhibitors, surfactants, flocculating agents, concrete, casing, and paraffins.

Water Requirements – Water is used for making concrete and in preparing water‐based drilling fluids. Water is also used as a low‐cost option for dust control. Potable water is needed on‐site for sanitary and cooking uses as well as for cleaning and drilling operations. An emergency water supply for fire suppression is required.

Workforce and Time – The activities for an individual well would require about a dozen workers and take about two weeks for a shallow well and up to six weeks for an especially deep horizontal well.

Utility Requirements – Electricity needed to power the drill rigs would probably be supplied by electric power generators that run on diesel fuel and produce air emissions. Some areas connecting to the existing electric grid for power will reduce noise and local air emissions.

Other Impacts – Continued vehicular and pedestrian traffic occurs at the drill site.

Potential impacts from the drilling and development of an oil or gas field affect much of the project area. Environmental impacts to soil and groundwater resources from the drilling of tight oil and shale gas wells are an important issue in many parts of the world. Oil field facilities, in addition to production wells, may include sumps for the storage of waste fluids (mostly water), injection wells for subsurface disposal of waste fluids, pumping facilities, storage tanks for recovered oil, and pipelines. Impacts while drilling include specific industrial accidents that can occur with great consequences.

5.6.4 Impacts from Produced Fluids and Gases at Oil and Gas Fields

Petroleum is a naturally occurring mixture that usually exists in gaseous phase (natural gas), or in a liquid form (crude oil), but can also exist as a solid (waxes and asphalt). Primarily composed of hydrocarbons, which are compounds that contain only hydrogen and carbon, petroleum varies widely in chemical complexity and molecular weight. Crude oil is unrefined oil or petroleum.

Petroleum can be any mixture of natural gas, condensate, and crude oil. The term petroleum is derived from the Latin derivative “petra” for rock and “oleum” for oil. A petrochemical is a chemical compound or element recovered from petroleum or natural gas or derived in whole or in part from petroleum or natural gas hydrocarbons and intended for chemical markets. Petrochemicals and hydrocarbons are simply compounds of hydrogen and carbon that can be distinguished from one another based on composition and structure.

Crude oil (commonly just called crude) is the initial oil extracted from the subsurface without any refinement into other liquid forms or products. It is a naturally occurring heterogeneous liquid consisting almost entirely of the elements hydrogen and carbon. The composition of crude oil can vary significantly based on its origin and age. Crude generally ranges from 83 to 87% carbon (by weight), 11 to 14% hydrogen with lesser amounts of sulfur (0.1–5.5%), nitrogen (0.05–0.08%), and oxygen (0.1–4%). Trace constituents comprise <1% in total volume and include phosphorous and heavy metals such as vanadium and nickel.

Crude oil is classified based on the relative content of three basic hydrocarbon structural types: paraffins, naphthenes, and aromatics. About 85% of all crude oil can be classified as either asphalt base, paraffin base, or mixed base. Levels of Sulfur, oxygen, and nitrogen contents are often relatively higher in paraffin base crude, which contains little to no asphaltic materials. Mixed base crude oil contains considerable amounts of both wax and asphalt. Chemically, crude oil is composed of methane (normal straight‐chain paraffins), isoparaffins (branched‐chain paraffins), cycloparaffins or naphthalenes (ring structures), aromatics (benzene ring structures), and asphaltics.

5.6.5 Impacts from Natural Gas

The most common hazardous compounds and constituents associated with oil and gas fields include methane gas. Natural gas is composed mostly of methane (CH₄); methane gas is a colorless, odorless, tasteless paraffin compound that is less dense than air and formed as the by‐product of organic decomposition. The gas composition of various US shale gas plays also shows methane at 97.3% as the major component (Table 5.6). Methane is also the main component of natural gas (70–94.7%) at various stages of production (Table 5.7).

The concern surrounding methane is its flammability and explosive potential, particularly in man‐made enclosed spaces such as poorly ventilated rooms, basements, conduits, etc. Since methane is lighter than air, it can migrate upward along natural or man‐made conduits (fractures in bedrock) or along oil wells that have not been abandoned properly. When it reaches a confined space, the methane can be explosive when its concentration in air is in the range of 5–15%.

Methane in an oil field environment is typically biogenic (bacterial) or petrogenic (thermogenic) in origin. Biogenic gas typically is the result of the decomposition of nonpetroleum organic deposits such as plants, landfill deposits, etc. Petrogenic gas typically is a by‐product of petroleum hydrocarbons. Background levels of methane are usually less than a few hundred parts per million (ppm). In situ values of 1 000–20 000 ppm are potentially hazardous, and >20 000 ppm are considered potentially dangerous. In 1985, an explosion and fire destroyed a department store and several adjacent structures overlying the abandoned Salt Lake Oil Field in the commercial Fairfax District of Los Angeles, California. More stringent regulations were subsequently developed to assess whether abandoned oil wells have been properly sealed and to require mitigative measures as necessary.

5.6.6 Impacts from Crude Oil

Crude oil or the common petroleum hydrocarbon products derived from the refining of crude oil can negatively impact drilling and production sites, as well as transportation corridors. Refined crude oil products include compounds in decreasing volatility and increasing boiling point: fuel gases, gasoline, diesel, lubricants, and asphalt (Table 5.8).

Crude oil and refined products can contain levels of naphthalene, benzene, ethylbenzene, toluene, total xylenes, and polyaromatic hydrocarbons (PAHs) that exceed acceptable regulatory levels. Although crude oil and some of the fuel‐related refined products like gasoline or diesel are not considered a RCRA waste, some states such as California consider some petroleum hydrocarbons a designated waste, should it exceed certain maximum contaminant levels for arsenic, chloride, chromium, lead, polychlorinated biphenyls (PCBs), or should it exceed the flash point. Thus, the disposal of crude oil or its byproducts off‐site is subject to regulation. Excavated soil containing crude oil or refined products should always be placed on bermed plastic sheeting (10 mil thick) and covered with plastic sheeting to prevent volatilization and migration with storm waters. Soil containing crude oil has been left in the subsurface during many redevelopment projects throughout Los Angeles and Orange Counties in southern California, typically at depths of 5–10 ft below final grade; however, their presence can have a significant financial impact on developers and lenders during oil field property redevelopment or transfers.

During rotary drilling for oil and gas wells, two types of wastes are generated: used drilling fluids (commonly called muds) and drill cuttings. Drilling muds are mixtures of water and other chemical additives used to lubricate the drill bit, remove cuttings from the well bore, and maintain the integrity of the hole until casing and production equipment is installed or during well abandonment or to prevent blowout. During drilling, different additives are mixed with water to yield the desired properties for the mud. The consistency (density, viscosity, weight, gel strength, filtration, and salinity) and mineral content of drilling muds vary to accommodate the nature of the strata, oil, gas pressure, and other oil and gas field characteristics. Drilling muds can occasionally be of environmental concern because of the potential presence of heavy metals, NORM, and other compounds that may exceed certain regulatory standards.

For tight oil and shale gas sites, surface spills from lined pits of drilling muds, hydraulic fracturing compounds, backflow fluids, or production fluids are the most likely source of leakage. Best management practices include keeping fluids in dozens of closed frac tanks (21 000 gal) that have secondary containment, and work to minimize surface spillage and impacts to shallow groundwater resources. Closed‐loop drilling systems are also effective to control fluids at the drill site.

A line pit or sump is typically excavated adjacent to the drill rig, which serves as a mixing area for the muds and as a settling pond. Since drill cuttings and muds may in some instances be considered a waste material, they must be handled in an appropriate manner. The waste muds and cuttings are disposed of by being injected into the subsurface, reused, or transported off‐site to a landfill or off‐site treatment facility. If the characteristics pass engineering structural and stability test, drill cuttings can be used as aggregate in the cold mix asphalt process (Testa 1997). Pits, lined or unlined, are less than optimal for containing liquids or other wastes.

Regardless of the type of drilling mud used, typical contaminants of interest that require periodic monitoring for significant changes are pH, electrical conductivity, sodium adsorption ratio (SAR), cation exchange capacity (CEC), exchangeable sodium percentage (ESP), and total metals. Other constituents of concern include oil and grease and total petroleum hydrocarbons. Drilling fluids usually have a pH that fall within the alkaline range (pH > 10). This high pH is a result from the addition of lye, soda ash, and other caustics, which allows for the dispersion of clay and increased effectiveness. Weathering and aging causes a decrease in the overall pH. Soil salinity is measured by determining the electrical conductivity. This is an important test for soils and waste because of the potential for high brine content that adversely affects plant growth and water quality. Soils exhibiting an electrical conductivity more than 8.0 mmhos cm⁻¹ usually require some manner of management or remediation. SARs are determined to assess potential damage associated with sodium salts from a waste material, which when used in conjunction with electrical conductivity can be ascertained. A SAR less than three can restrict such materials for land disposal. Acceptable metals loading in muds are evaluated by CEC. Measured in meq per 100 g, CEC values are required to estimate the ESP. Excess sodium typically results in a general lack of structural stability among soil particles and impeded water infiltration. Combined excess salinity and sodic conditions can limit remediation efforts (i.e. remove excess salts from the root zone) due to inherent slow infiltration and percolation characteristics.

Total metals analysis provides a good indication for all metals except barium, which is best analyzed under the protocol set forth by the Louisiana Department of Natural Resources. Total metals include arsenic, barium, cadmium, chromium, mercury, lead, selenium, and zinc. Although seldom a significant problem, elevated concentrations of certain metals in soil or waste materials are leachable. The metals of most concern in drilling muds are barium, chromium, lead, and zinc.

The presence of petroleum hydrocarbons in drilling muds or waste are typically due to the introduction of crude oil from a producing formation and/or diesel or mineral oil that is added to drilling muds. Although diesel is likely to be the most common contaminant, diesel‐affected soil and waste materials can be easily remediated via a variety of options.

5.6.7 Impacts from Phase 4: Well Completion and Hydraulic Fracture Stimulation

Phase 4 includes well completion, well testing, and the hydraulic fracture stimulation process with the associated injection of large volumes of frac fluids with chemical additives. Testing the well could include drill stem testing (DST) as a way to evaluate the target zones for the potential presence of petroleum hydrocarbons and pressure ‘conditions’ in the borehole prior to installing casing. Some of the impacts relate to the use of water and the hazardous nature of some of the backflow constituents.

Examples of direct impacts include water use, hazardous compounds in the frac fluids and backflow, well completion and hydraulic fracture stimulation noise, vehicle and equipment noise, air emissions, silica dust exposure, worker activity, hydraulic fracturing‐derived waste material and disposal, fuel spills, timing and duration of activities on nearby residents, and number of jobs created field wide due to these activities. Indirect impacts described as in Section 5.6.3 include non‐point pollution, and higher use of structural and social infrastructure.

Although many of the impacts listed above for drilling apply to the hydraulic fracture stimulation phase, additional environmental impacts include the use of large volumes of water, potential for spillage of hazardous materials and waste fluids and sludges, and silica dust exposure during proppant injection.

The overall well completion process can take a dozen to two dozen workers one to two months to perform, which includes hydraulic fracture stimulation that can take about one to two weeks, depending on the depth of the well and number of completion zones.

5.6.8 Impacts from Phase 5: Fluid Recovery and Waste Management

A variety of well‐ or field‐specific chemical additives are used in the hydraulic fracturing process to clean the borehole, enhance fracturing, increase permeability, and optimize production (Table 5.9). Chemicals can spill not only during phase 4 (that includes the injection of the fracturing liquids) but also during phase 5, when the fluids are recovered. Secondary and tertiary methods of production generally require the use of injected fluids that may contain various production enhancing chemicals, such as surfactants and polymers. Production in marginally producing, generally older oil and gas fields becomes more attractive as the price of oil and gas moves upward. With a major increase in the price of oil and gas, enhancements in field production are evaluated. One common enhancement in older oil and gas fields is the cleanup and stimulation within individual wells as part of a field workover program. This type of production enhancement program usually requires the use of chemicals, including a variety of acids.

Acidizing operations require the use of a variety of chemicals for pH adjustment and for associated precipitation issues. The use of acids can create a number of production problems, including the release of fine particles that can plug a formation as well as the corrosion of the steel drill pipe and casing. Highly corrosive produced waters require the use of corrosive resistant tools and chemical inhibitors. These corrosion inhibitors, such as oil‐wetting surfactants, slow down the reaction time of acid on the metal drilling and production pipe. Fluid loss control agents (silica flour and oil‐soluble resins with natural gum) are added to reduce ‘leak off’ in fracture acidizing operations. Diverting or bridging agents (graded salt, wax beads, sand) in fracture acidizing may be used as materials to prop up the newly created fractures. Particularly in dry gas wells, alcohol has been used as an additive to reduce the time required for well cleanup. Clay stabilizers are used to fix clays in situ, thereby minimizing migration of clays and subsequent plugged permeability. Iron sequestering agents (acetic, citric, and lactic acids) are used to inhibit the precipitation of iron after the acids are spent from an acidizing operation.

Hydraulic fracturing in the oil and gas fields uses nitrogen in well stimulation. Nitrofied fracturing and acidizing uses a foam on fluid‐sensitive wells for improved fluid loss control and cleanup operations (for better production). Frequently used with carbonate reservoirs, such as limestone and dolomite, there are five acid systems: mineral acids (hydrochloric and hydrofluoric/hydrochloric), organic acids (acetic and formic acids), powdered acids (sulfamic and chloroacetic acids), retarded acids (gelled acids, oil‐wetting surfactants, and emulsified acids), and mixed acids (combinations of acids). Typically used strengths of acids will range from a few percent to <30% by weight in water.

5.6.9 Impacts from Naturally Occurring Radioactive Materials (NORMS)

Naturally occurring radioactive material (NORM) is found at levels exceeding the background at many oil and gas production and processing facilities. NORM originates in subsurface oil and gas formations and is usually brought up to the surface with produced fluids and gases, including brine water, natural gas, and other oil field fluids. NORM forms as scales and it precipitates on tubing and equipment. Sludges and sands with isotopes of radium, thorium, uranium, and radon gas are emitted from radium‐contaminated materials and soils; deposits of lead Pb‐210 have been found on the interior of pipes from the transmission of natural gas. Produced waters can contain NORM (Veil et al. 1998).

Isotopes of uranium and thorium, which originate in hydrocarbon‐bearing formations, are parent isotopes of radium and radon. Occurring primarily as Ra‐226 of the uranium U‐238 decay series and radium Ra‐228 of the thorium Th‐232 decay series, thus, with half‐lives, the long‐term potential for disposal is of concern. Oil wells that produce large quantities of produced water will also tend to accumulate the greatest amount of radium‐bearing materials as a result of (i) radium solubility and (ii) its chemical similarity to certain ions such as calcium, strontium, and barium. Gas wells precipitate radon daughters from natural gas streams and fluids. These wells tend to accumulate materials containing larger quantities of lead‐210, polonium‐210, and bismuth‐210.

5.6.10 Impacts from Other Miscellaneous Hazardous Compounds

There are a variety of hazardous compounds, associated with oil and gas facilities that are indirectly related to the produced hydrocarbons. These hazardous compounds are typically found in equipment maintenance and chemical storage areas in oil and gas fields: hydraulic fluids, painting wastes, used equipment lubrication oils, unused free fluids and acids, radioactive tracer wastes, waste solvents, biocides for vegetation control, and pesticides. In addition, PCBs, a dielectric fluid, are common in transformers built prior to 1979. Unless a transformer has a label stating “PCB‐free,” transformer oils are assumed to contain PCBs.

Lead, a durability agent, was added to paint and is commonplace in industrial paints and coatings. Lead may be present in the paint surfaces of rigs, tanks, and production equipment. Lead paint was phased out in the United States by December 1980. Unless tested, all metal surfaces older than December 1980 are presumed to contain lead. Metal products containing lead paint are still being imported into the United States on painted products as of today. Torch cutting on metals containing lead paints such as pipelines, tanks, or production equipment can release lead fumes exposing workers to airborne lead. Lead in dust from cutting lead painted surfaces in oil and gas fields is also an employee exposure risk.

Asbestos has been used for a variety of industrial uses since the 1920s. In oil and gas fields, asbestos has been used in tar wrap for corrosion control of metal surfaces, such as tanks and pipelines. The fibrous nature of asbestos acts likes straw in bricks, adding strength to the wrap. Thermal insulation on tanks, pipes, or equipment containing asbestos may be present in oil and gas fields. In steam injection plants for the production of heavy oil, steam lines may contain thermal wrapping containing asbestos. Unless tested, all suspected asbestos‐containing materials older than 1980 are presumed to contain asbestos. Nonetheless, importation of asbestos or use of stored asbestos‐containing materials may exist to the present.

5.6.11 Impacts from Phase 6: Oil and Gas Production

During the production phase, the field activities that may cause environmental impacts include constructing more access roads, installing pipelines, storage tanks, additional production wells, and other ancillary facilities such as gas compressor stations or fluid pumping stations. Potential impacts from the drilling and development of an oil or gas field affect much of the project area. Although most of the impacts from phase 3 (drilling phase) and phase 4 (well completion and hydraulic fracture stimulation) are temporary in nature, much of the production site and ancillary facility areas are altered for the full production period, which can be several decades. Direct impacts include the land being occupied by the facility footprint, a change in the number of jobs created, air emissions, particulate and dust generation, noise, water use, coproduced water production, timing and duration of production, fuel spills, hazardous materials and wastes generated from production operations and maintenance, and site runoff and erosion. Indirect impacts include sediment runoff; herbicide and pesticide runoff; creation of service jobs to serve increased population; decrease in tourism; overuse of local infrastructure and emergency services such as roads, water and wastewater plants, schools, hospital, fire, and police services; and decline in visits for local outdoor activities such as camping, hiking, hunting, and fishing.

Ongoing production activities – Localized land‐disturbing tasks are anticipated during oil or gas production. Other activities include the operations and maintenance or replacement of production equipment components. After primary production declines in an oil or gas field, drilling secondary and enhanced oil recovery wells may occur. Other hazardous chemicals may be used during the production optimization phase, and thermal treatments may also be used, mostly for heavier oil production. Production workers inspect and monitor the production wells and associated equipment for optimal operation and for signs of spills and leakage. As needed, vegetation management and erosion control efforts should be continuously performed at the production pad, access road, and pump or compressor stations.

Spills and Leaks – Small motor oil and liquid fuel spills are very common especially during transfer. Spills of compounds as varied as crude oil and herbicides require assessment clean up, and disposal.

Surface Footprint – An average oil or gas field has about 4–16 wells per square mile. Some coalbed methane fields have wells located every 20 acres, but typical gas methane well spacing varies from one per 40–320 acres (TEEIC 2017).

Utility Requirements – Oil, gas, or electricity are required to power the engines, pumps, or compressors. Hooking up to the electrical grid would lower noise and local air emissions. Use of on‐site generators may be required for some aspects of repair or replacement of facility components.

Waste Generation – Coproduced water is the largest volume of waste generated during the production phase. The volumes of coproduced water vary widely depending upon the type of formation and age of production. Small amounts of metal degreasers, cleaners, lubricating oils, and fuels are generated (during production) from engines, pumps, and vehicles. Paints or coatings for corrosion control are generated on a regular basis. Vegetation maintenance and control can generate large volumes of woody debris. Other wastes include human sanitary wastes, pipe scale, waste paints, spent catalysts, separator sludge, tank bottoms, used equipment, and vehicle filters. Some fluids and proppants from the hydraulic fracture process, including potentially toxic acids and hazardous compounds, are coproduced with the crude oil or gas. Produced water can contain toxic metals, radionuclides, dissolved solids, salts, biocides, lubricants, corrosion inhibitors, and diesel fuel, if used in the drilling or hydraulic fracturing process. Produced sands and other particles can contain crude oil and NORM.

Water Needs – Potable water is required for the inspection and maintenance workforce and for staff working at pump and compressor stations. Water could also be required for cleaning of equipment or vehicles and as a contingency for firefighting. Large quantities of water may be used to stimulate or enhance production from a well.

Workforce and Time – On average, over a 10‐year production period, oil and gas production could require up to about 2–3 months of one full‐time worker to perform operations and maintenance per well per year. Remote cameras and wireless data collection methods allow for remote inspections and data evaluation. An additional 35–70 worker days per well would be required for workovers. Workover events at production wells could occur at a frequency of once every 3 years to once every 10–20 years, depending on site conditions. The level of work per well would correspond to about two to three months of one full‐time worker for each workover event performed. Oil and gas wells can produce product for 20–50 years or more, but the length of production is largely dependent upon both economic and technological conditions. The highest production usually occurs in the early years. For pipelines and access roads, about one to two dozen construction‐ and supply‐related workers are needed to install new sections of a pipeline gathering system. Access roads would take about 1 day to construct ~1–2 mi of road on flat areas with a crew of 6–10 workers. The same crew working for about two to three days could construct 1–2 mi of access road on steep terrain.

5.6.12 Impacts from Drilling Fluids and Production Wastes

Spent drilling fluids, coproduced fluids and sludges, and other products used on‐site that are no longer needed are designated as wastes. In 1980, Congress conditionally exempted oil and gas E&P wastes, including produced water, from the hazardous waste management requirements of Subtitle C of RCRA, Sections 3001(b)(2)(A), 8002(m). In addition to directing the US Environmental Protection Agency (the US EPA or the Agency) to study these wastes and submit a report to the Congress on the status of their management, Congress required the Agency either to promulgate regulations under Subtitle C of RCRA or make a determination that such regulations were unwarranted. In 1988, the US EPA published its regulatory determination in the Federal Register (53 FR 25447, 6 July 1988) and, along with it, lengthy lists of wastes determined to be either exempt (e.g. produced water, drilling fluids, drill cuttings and pit sludge) or nonexempt (unused fracturing fluids or acids, used lubricants, waste solvents, and hydraulic fluids). The US EPA rearticulated the exemption in the Code of Federal Regulations (40 CFR §261.4(b)(5)). In 1993, the US EPA published a clarification of its regulatory determination in the Federal Register (58 FR 15284, 22 March 1993). And, in 2002, the US EPA published an information booklet on the subject. The US EPA explained that wastes uniquely associated with E&P operations were exempt. With respect to petroleum production, primary field operations include activities occurring at or near the wellhead or production facility, but before the point where the custody of the petroleum is transferred from an individual field activity or centrally located facility to a carrier for transport to a refiner. Without a transfer of custody, the primary field operation ends at the last point of separation. Crude oil stock tanks are considered separation devices.

Wastes derived from treatment of an exempted waste generally remain exempt, and off‐site transportation does not negate the exemption. However, some wastes derived from treatment of an exempt waste may not be exempt. Nonexempt E&P wastes, independent of where generated, include those wastes that are not uniquely associated with an E&P activity. All wastes that are not associated with primary field operations are nonexempt and subject to further scrutiny for purposes of classification. A checklist of examples of some exempt and nonexempt E&P wastes has been compiled (see Table 5.10, Appendix I).

The chemical characteristics of compounds used at a drilling or production facility (specific density, viscosity, vapor pressure, solubility, etc.) are important in planning assessment and cleanup, should these compounds be released into the environment. The federal RCRA Subtitle C exemption for E&P wastes, however, does not preclude these wastes from control under other federal regulations and state regulations including oil and gas conservation programs and some hazardous waste programs. For example, E&P exemption was also incorporated into the California Code of Regulations (22 CCR, Sections 66261.4(b)(2) and 66261.24(a)(1)), but it is limited in scope. The exemption applies in California in cases where the waste is hazardous solely by meeting the federal characteristic for toxicity under the toxicity characteristic leaching procedure (TCLP). Thus, a waste that is hazardous solely by meeting or exceeding the maximum contaminant concentration for constituents extracted by TCLP, and for which federal regulatory thresholds have been established, may be exempted from regulation as hazardous waste in California. The exemption does not apply if toxicity is determined based on criteria other than TCLP, or the waste meets any of the other three characteristics of hazardous waste: ignitability, corrosivity, and reactivity (22 CCR, Article 3, Sections 66261.20 et seq.).

Water and waste management (in connection with oil and gas E&P) involves discharge and injection operations. The main laws governing these activities include the CWA and the SDWA. The US EPA may authorize willing and able states to take the lead responsibility for day‐to‐day program implementation and enforcement of CWA and SDWA. Otherwise, the US EPA Regions run the programs in direct implementation. The CWA requires that all discharges of pollutants to surface waters (streams, rivers, lakes, bays, and oceans) must be authorized by a (general or individual) permit issued under the National Pollutant Discharge Elimination System (NPDES) program. Facilities are responsible for taking the steps necessary to demonstrate compliance with NPDES permit limits. Permits instruct each facility operator relative to the frequency for collecting wastewater samples, the location for sample collection, the pollutants to be analyzed, and the laboratory procedures to be used in conducting the analyses. Detailed records of these “self‐monitoring” activities must be retained by the facility for at least three years. Furthermore, each facility is required to submit the results of these analyses to the regulators on a periodic basis. For most facilities, the reporting frequency is monthly or quarterly, but in no case may it be less than once per year. NPDES permits may also require operational or environmental effects monitoring. This includes the preparation of best management practice plans or spill prevention plans. Numerical effluent limits present the primary mechanism for controlling discharges of pollutants to receiving waters. The US EPA’s effluent limits describe the pollutants subject to monitoring as well as the appropriate quantity or concentration of pollutants. Permit writers derive effluent limits from the applicable technology‐based effluent limitation guidelines and water quality‐based standards. The more stringent of the two will be written into the permit (Pruder and Veil 2006).

Per SDWA the US EPA has the authority for Underground Injection Control (UIC) regulation. The UIC program is designed to protect underground sources of drinking water (USDW). For regulatory control purposes, underground injection is grouped into five classes of injection wells. An injection well is defined as any bored, drilled, or a driven shaft or a dug hole, where the depth is greater than the largest surface dimension that is used to inject fluids underground. Class I wells are used for the emplacement of hazardous and nonhazardous fluids (industrial and municipal wastes) into isolated formations beneath the lowermost underground source of drinking water. Class II wells are permitted for operators to inject brines and other fluids associated with oil and gas production. Class III wells are permitted for operator to inject fluids associated with solution mining of minerals. Class IV wells, which involve the injection of hazardous or radioactive wastes into or above an USDW, are banned unless authorized under other statutes for groundwater remediation. Class V wells include underground injection wells not included in classes I through IV. Wells used for injecting oil field waste materials associated with E&P operations are considered class II wells. Class II subclasses include disposal wells (class II‐D) and enhanced recovery wells (class II‐R).

The US EPA’s regulations establish minimum standards for state programs prior to receiving primary responsibility (primacy) for the UIC program under Section 1422 of the SDWA. The federal requirements governing application, construction, operating, monitoring, and reporting for class II wells are found in 40 CFR parts 144 and 146. It should be noted that a state program can always be more stringent than the federal blueprint. In 1981, Congress added Section 1425 to the SDWA, which relieves oil‐ and gas‐related injection well programs in the states from having to meet the technical requirements in the federal UIC regulations. Instead, the demonstration must be made that the state has an effective program (including adequate oversight, record keeping, and reporting) in place to prevent the endangerment of USDW by underground injection operations. Because the Section 1425 approval route offers greater flexibility, most states have obtained UIC primacy in this way (Pruder and Veil 2006).

Federal laws and regulations generally establish minimum federal standards. States have the lead role in the regulation of E&P and general industrial waste disposal. In light of the varying geological, climatological, ecological, topographic, economic, geographic, and age differences among oil and gas drilling and production sites across the country, the laws and regulations of authorized states relative to oil and gas waste management operations exhibit differences in detail and scope when compared with the federal blueprints or other state programs.

Historic waste management procedures, identification of E&P activities and associated hazardous wastes, and options for waste reduction, recycling, treatment, and responsible disposal were documented (The E&P Forum 1993). Earthen or lined skim pits were common in many oil fields and were an integral part of E&P waste management operations. Historically, these on‐site pits have been used for the management of drilling solids, evaporation and storage of produced waters, management of workover and completion fluids, and emergency containment of produced fluids. Unfortunately, many of the skim pits were unlined, and although the skim pits are an accepted historical component of E&P operations, the pits represent an environmental liability if managed improperly. In unlined pits, surface water and groundwater drinking resources can be impacted by subsurface migrations of oil and gas production wastes.

Once the on‐site assessment at an oil or gas field has determined that impacted soil requires remediation, there are a variety of cleanup methods used at the drill sites, in production facilities, along pipelines, and at refineries and bulk storage terminals. Once released into the environment, crude oil and gas, depending on the specific chemistry and properties, can partition between various phases: soil gas, groundwater, and soil. Detailed national studies on cost of drilling and production wastes are described (NETL 2014; Pruder and Veil 2006; Veil et al. 2004). Later in the chapter, a variety of remediation methods for aboveground soil treatment and subsurface treatment of impacted soil and groundwater at onshore oil and gas fields is discussed. A checklist of waste disposal and treatment options is provided (see Table 5.11, Appendix I).

5.6.13 Impacts from Specific Oil and Gas Field Locations

Surface releases of production or waste fluids or sludges can occur in many locations, including well cellars, well sumps, piping ratholes, storage pits, and underground or aboveground storage tanks. Minimizing the impacts of accidental fluid release is directly related to control measures used in fluid management and regular inspection of fluid storage locations.

5.6.14 Impacts from Historic and Abandoned Oil, Gas, and Water Wells

Due to improper abandonment or a lack of a competent cement seal, or cracked cement, many historic wells have the potential to create vertical conduits for surface fluids or subsurface fluids and/or gases to migrate into drinking water supplies. Locating historic and abandoned wells is difficult but can be done by performing local interviews, inspecting low‐altitude aerial photography, reviewing regulatory documents and well permits, using metal detectors to locate iron or steel well boxes, and performing rigorous field inspections. There are estimated to be over a million abandoned wells in depleted oil and gas fields in the United States. Many old oil and gas wells were not initially adequately plugged upon abandonment and have the potential to leak well fluids (methane, oil, brines) to local groundwater and ground surface. Historic water wells also have the potential to create vertical conduits for surface or subsurface fluids to migrate into drinking water supplies. Damaged and corroded casing of abandoned wells can degrade water resources (Figure 5.4).

Historic and improperly abandoned or damaged oil, gas, or water wells are possible conduits that can impact shallow groundwater resources, with probable conduits for oil and brine contamination into shallow water‐bearing zones. Poorly cemented annular spaces in oil and gas wells can allow production fluids, both brines hydrocarbons, and methane to act as a conduit into possible shallow groundwater‐bearing zones. Channeling within the well’s annular space is caused by the incomplete displacement of the drilling mud by the injected cement slurry, resulting in washed out sections of annular space. Secondary channeling is caused when annular voids are created after the cement slurry is in place. Shattering in perforation zones can create additional annular damage and possible leakage to contaminants or brines into groundwater‐bearing zones. Poor cement bonding between the interface of the casing and cement, or cement and the well bore wall, create leakage problems as well. Poor quality cement may be result if the wrong cement additives are used or if they are prepared improperly. The failure of the cement can cause void spaces and cement failure, providing conduits into the subsurface of production fluids. Leakage can occur at the interface between the casing and cement and can cause conduits to form between the casing and the cement interface.

Cement can also fail and crack over time. Large oil and gas blowouts can be associated with cement and annular failures. Government and industry investigations into the BP oil spill of 2010 in the Gulf of Mexico indicated that the precipitating cause of the blowout was the failure of the cement to isolate the reservoir, which was under extremely high pressure. The incomplete sealing of the borehole by the cement permitted hydrocarbons to enter the wellbore. Confirmation of cement and annular sealing activities is based on cement testing and other observations.

The Martha oil field in eastern Kentucky provides an example of shallow aquifers in and near oil and gas fields that have long been used as sources of drinking water. In 1919, the Martha oil field produced from the Devonian–Weir sands and the main field area was about 4500 acres (1821 ha). The historic wells in the area predated modern well construction standards and the age of the metal casings far exceeded normal life expectancy. Water flooding activities within almost 3200 acres (1295 ha) in the Weir sands started in 1955 by the operator, Ashland Oil Company, and an additional six million barrels of oil were recovered between 1955 and 1970.

The freshwater injection not only was designed to increase production within the oil zone but also caused an increase in the potentiometric head within injection wells in the upper Weir and lower Weir oil sands. The upwelling of coproduced brines and oil through corroded and breached well casings, uncemented annular spaces, and improperly plugged and abandoned wells in the area resulted in the widespread groundwater contamination of three aquifers designated as USDW: Alluvium, Breathitt, and Lee Formations (Eger and Vargo 1989). Some fluids reached the surface, impacting shallow soil. Complicating aquifer management in the area, cones of depression in the Lee aquifer resulted from pumping of industrial water supply wells.

The target Devonian rock units (weir sand) contain low‐level concentrations of radium‐226, a highly water‐soluble, naturally occurring radioactive element that has been brought to the surface with the brines, contaminating shallow groundwater in the oil field and leaving a radioactive signature on scrap metal pipe that was first detected by a Geiger counter at a nearby scrap metal yard in 1988. When a NORM is concentrated on the surface due to human activities, such as oil or gas production, the NORM takes a new name as it becomes technologically enhanced naturally occurring radioactive material (TENORM). Clean up at the Martha oil field included the removal of 145 000 tons of TENORM‐contaminated soils and millions of feet (meters) of NORM‐contaminated pipe that were placed in nearby landfills.

The US EPA and the US Army Corps of Engineers confirmed the widespread nature of the groundwater contamination in 1986, and US EPA Region IV determined that the responsible party was in violation of the Safe Drinking Water Act (SDWA) and the UIC regulations, including violations that the operator allowed for the movement of fluids to enter the USDW, failed to properly pug or abandon injection wells that were deemed temporarily abandoned, and injected at a pressure that resulted in contaminants migration into a USDW (Eger and Vargo 1989).

5.6.15 Impacts from Transportation Activities

Impacts from transportation activities of products are widespread and international in impact, as natural gas and crude oil are transported to market. The main forms of transportation in the oil and gas industry include pipelines, train tanker cars, truck tankers, and barges and ships with tanks. Pipelines are an integral part of transportation of natural gas or crude oil from the wellhead to market (Figure 5.5). Different types of pipelines are used for transporting hydrocarbons from the source to the end user (Table 5.12). Each of the types of pipeline networks varies with diameter, characteristics, and function. Pipeline failure can represent a site of a potential release or explosion far from the source area (Table 5.13).

Other transportation impacts relate to shipping by rail or highway of the chemicals, proppant sands, bentonite clay, construction gravel and sand, and other supplies. Drilling‐derived wastes and production wastes when disposed of at off‐site facilities rely on highway, rail, and waterways for transportation corridors.

5.6.16 Impacts from Phase 7: Well Decommissioning and Site Restoration

The well decommissioning process is initiated at the end of production and consists of closure of the production wells, removal of the production facilities, and restoration of the site to predrilling condition. Equipment, pipelines, pits, pads, and debris are removed. Oil‐stained surface materials such as gravels or soils contaminated from spills or leaks can be treated on‐site using biofarming techniques to reduce toxicity. Alternate approaches include the use of the impacted materials in a recycling process to make cold mix asphalt (Testa 1997), or the materials can be transported off‐site for treatment and disposal. Well abandonment relies on plugging the casing with cement and packers. After the surface of the production facility has been cleaned, the well pad and access roads are regraded and recontoured. Fill material may be compacted, and pads and roads may be replanted with native plants. The direct impacts of the well abandonment process include land disturbance, site runoff, soil erosion, heavy equipment and vehicle noise and exhaust, fuel spills, dust, worker activity, and excavated material and waste disposal. Some of the indirect impacts include sediment runoff.

Emissions/Exhaust – Dust would increase, as compared with the production phase, as a result of increased worker and vendor vehicle travel on unpaved access roads. Criteria pollutants would be generated from the operation of vehicles and construction equipment. Volatile organic chemicals could be released from the storage and dispensing of fuels for vehicles and equipment. Decommissioning wells could release methane, VOCs, PAHs, particulate matter, sulfur compounds, carbon dioxide, and carbon monoxide.

Vehicles, cement pumps, and well destruction equipment generate exhaust emissions. Volatile organic chemicals would be released from the storage and dispensing of fuels for vehicles and equipment. Abandoned wells could release fugitive gas emissions including natural gas that is mostly methane and other VOCs, PAHs, BTEX, carbon dioxide (CO₂), carbon monoxide (CO), and hydrogen sulfide (H₂S). Improperly stored fuels can contribute to fugitive gas emissions. Monitoring fugitive gases is performed using multigas detection meters.

Surface Footprint – About the same amount of area disturbed during the development of the oil and gas field would be impacted by decommissioning and reclamation activities. Overall acreage of the oil or gas field would decrease as individual wells, pipelines, access roads, and other ancillary facilities are removed and the area is restored.

Waste Generation – Equipment and fixtures are to be decontaminated, if possible. Some of the decontaminated components could be recycled. Human sanitary wastes would be produced by work crews. Removal of production equipment and excavation of the subsurface fixtures will generate industrial wastes.

Water Needs – Water would be needed for dust suppression, firefighting contingency, and potable supply for the workforce.

Workforce and Time – Fewer workers would be required than during the production phase. About 8–12 workers would be needed for 1–2 weeks to remove equipment and buried pipes from a well pad site. The estimated duration of the project is highly variable due to surface and subsurface conditions, the amount of leakage and spillage on the site, the amount of equipment decontamination required, the proximity of recycling centers, and regulatory requirements regarding future use.

Utility Requirements – Utility requirements vary, but if the facility is not on the electrical grid, portable electric generators will be needed.

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