This Master's Project

This Master's Project Water Resources Needed to Hydraulically Fracture California s Monterey Shale for Oil [Using the Bakken Shale Oil Exploration in North Dakota as a Case Study] By Christina J. Pepino is submitted in partial fulfillment of the requirements for the degree of: Master of Science in Environmental Management at the University of San Francisco Submitted: Received:......... Christina J. Pepino Date Thomas MacDonald, Ph.D. Date

The dissertation/thesis/master's Project is a scholarly work presenting the results of the candidate s research to the scholarly community. The University of San Francisco believes a candidate should make this research available to other scholars for the benefit of the author, the University, and the scholarly community. However, under the Copyright Act of 1976 (Copyright Act), an author may reserve all rights over his/her work, and thereby limit the availability of the work to others. Furthermore, under the Family Educational Rights and Privacy Act of 1974 (Privacy Act), a thesis/dissertation/master's Project may be considered a protected, private academic record. Author contact information: Christina J Pepino Phone: 928-399-9261 Email: chrissyjopepino@gmail.com Pepino2

Table of Contents INTRODUCTION...4 Energy Consumption...4 Process of Hydraulic Fracking...4 Bakken Shale in North Dakota...7 Monterey Shale in California...9 METHODOLOGY...10 Comparing Water Requirements to extract oil from Bakken Shale and Monterey Shale...10 Surface Water Sources used for Bakken Shale Oil Extraction...12 Groundwater Sources used for Bakken Shale Oil Extraction...15 Potential Water Sources for Monterey Shale Oil Extraction...17 California State Water Project...17 Central Valley Project...19 Comparing Geology between Bakken Shale and Monterey Shale...22 Wastewater Production for Bakken Shale...23 Surface Storage of Wastewater...25 Underground Storage of Wastewater...25 Treatment Facilities...26 Recycled Wastewater...26 Contamination Risks...28 Surface Water...28 Groundwater...28 RECOMMENDATIONS...29 Water Demands...30 Reducing Water Contamination Risks...31 Fault Zones and Induced Seismic Activity...32 California s Policies on Fracking...33 Public Notice and Transparency...34 Future Research...35 CONCLUSIONS...36 REFERENCES...38

INTRODUCTION: Energy Consumption United States crude oil production increased from 5 million barrels per day in 2008 to 6.5 million barrels per day in 2012, representing a 30% increase in four years (U.S. Energy Information Administration, 2013). Increased crude oil production is a result of increased onshore crude oil extraction, specifically from shale and other tight formations (U.S. Energy Information Administration, 2013). The Annual Energy Outlook of 2013 projects the demand for oil will steadily increase over the next twenty years; primarily driven by developing nations (U.S. Energy Information Administration, 2013). The United States has the potential to be one of the world s top oil producers as the worldwide demand will reach close to 100 million barrels per day by 2035 (U.S. Energy Information Administration, 2013). Projections also estimate the United States will become 97% self-sufficient, in net energy terms, by 2035 (U.S. Energy Information Administration, 2013). Oil companies are using advanced technology to extract oil from areas previously untouched due to depth difficulties and/or geological constraints. One of the processes used to access oil is a technique called hydraulic fracturing. Hydraulic fracturing, also known as fracking, is an advanced means of extracting both oil and gas from subterranean shale rock formations. Hydraulic fracturing is considered a type of advanced unconventional extraction, requiring external pressure to extract resources. Unconventional resources include: extra heavy oil (oil with high viscosity), oil sand, oil shale, tight gas, coal bed methane, shale gas, and natural gas hydrates (Energy Technology Network, 2013). Process of Hydraulic Fracturing After a geologic formation is selected based on potentially recoverable resource extraction, well construction begins. Existing wells may be fracked and re-fracked; therefore, all fracking operations do not necessarily require a new well. Wells used for hydraulic fracturing can be horizontal, vertical, or both. Vertical wells may extend to depths greater than 8,000 feet, Pepino4

and horizontal sections of a well may extend several thousand feet away from the production pad on the surface (Hydraulic Fracturing Research Study, EPA 2010). The next steps of hydraulic fracturing are the identification, selection, and acquisition of a water source. After water has been acquired and transported to the well site, the water is used to create fracking fluid. Fracking fluid is a mixture of water, chemical additives, and propping agents. Propping agents may be sand, silica, and/or ceramic beads. The fracking fluid is then pumped into the wellbore, under high pressure. The wellbore is lined with a hollow metal casing to isolate the injected fluid from the non-productive segments of the surrounding geologic formations. When the external pressure exceeds the rock strength, fractures within the rock are created. High pressures are used to increase the permeability of the formation and enhance the flow of oil (Bakken water assessment, Phase 2, 2011). As the geologic formation is fractured and the pumping pressure decreases, the propping agents in the injected fluid keep the fractures from closing (Department of Energy, 2004). The fractures remain open; allowing previously trapped crude oil to flow into the wellbore. Some fracture fluid, mixed with oil, returns to the surface through the wellbore. The mixture of fracking fluid combined with the extracted resources is commonly referred to as flowback water or wastewater (The Hydraulic Fracturing Water Cycle, EPA 2013). Wastewater can be treated in a proper facility, left in surface storage ponds or tanks, injected back into a retired well, or recycled for another fracture job. The process of hydraulic fracturing includes water acquisition, chemical mixing, well injection, the production of wastewater, and the treatment/disposal of wastewater (Figure 1).

Figure 1: The Process of Hydraulic Fracturing (The Hydraulic Fracturing Water Cycle, EPA 2013). Hydraulic fracturing is used in over 30 states, and is identified as a technique to promote energy independence and energy security (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2009). The International Energy Administration reported that the United States would benefit from technologies such as hydraulic fracturing for the extraction of unconventional sources of energy (U.S. Energy Information Administration, 2013). Recently identified potentially recoverable oil sources could make the United States the world's biggest oil producer by 2017 (U.S. Energy Information Administration, 2013). Two of the largest potentially recoverable oil basins are in the Monterey Shale deposits in California, and Bakken Shale deposits in North Dakota. Table 1 depicts the major shale deposits in the US, corresponding with estimates of technically recoverable oil (in billions of barrels). Oil production is at an all-time high in North Dakota because of hydraulic fracturing, and now California is assessing the economic benefits of fracking Monterey Shale for oil. Pepino6

Table 1: Technically Recoverable Resources of Major Shale Deposits in the US (Review of Emerging Resources, US EIA, 2011) However, hydraulic fracking causes environmental impacts. Environmental risks include: ground water contamination, air quality degradation, wastewater production, increased seismic activity, and land-use changes. This paper explains the environmental impacts of hydraulic fracturing on water resources. Using the Bakken Shale Oil Exploration in North Dakota as a case study, projections and recommendations are given for California s Monterey Shale Oil Exploration. Water sources, water demand, wastewater production, and contamination risks are analyzed. Bakken Shale in North Dakota The Bakken Shale formation is located in Montana, South Dakota, North Dakota, and Saskatchewan, classified under EPA Region 8 (USGS, 2008). Region 8 also includes Colorado, Wyoming, and Utah. Oil and gas exploration within Region 8 states are experiencing a dramatic increase in oil production as a result of tapping into unconventional shale gas reserves. In 2007, oil development within North Dakota began growing rapidly. Oil production was at 118,000 barrels of oil per day in early 2007, and doubled within 30 months (North Dakota Department of Mineral Resources, 2010). The oil production rate continued to increase from 200,000 barrels of oil per day in 2008 to 750,000 barrels of oil per day in late 2012 (North Dakota Oil and Gas Division, 2013) as seen in Figure 2.

According to the US Crude Oil and Natural Gas Proved Reserves of 2011, the Bakken shale oil formation is the second largest shale oil play, estimated to hold approximately 3.6 billion barrels of potentially recoverable oil (U.S. Department of Energy, 2013). For Bakken Shale extraction, it is estimated that 2,500 new oil wells will be drilled per year, for the next 15-25 years (Water Appropriations Division: North Dakota State Water Commission, 2011). North Dakota is seen as an economic icon as a result of increased oil and gas exploration activities, leading to low unemployment rates and high Gross Domestic Product/capita. Figure 2: Monthly oil production in North Dakota in thousands of barrels/day (EIA, 2013). As a result of hydraulic fracturing, North Dakota s gross domestic product grew by 6.7% per year from 2008 to 2012, setting a record during that period as the nation s fastest growth rate (USC Price School of Public Policy, 2013). In addition, North Dakota is maintaining the nation s lowest unemployment rate at 3.2% as a result of oil and gas exploration activities (USC Price School of Public Policy, 2013). Figure 3 compares the GDP per capita of North Dakota versus the US, emphasizing the potential economic benefit of oil and gas exploration. Economic growth is a primary incentive for exploring the possibility of oil extraction in California, using hydraulic fracturing. Pepino8

Figure 3: GDP growth per capita for North Dakota, compared to the U.S. average (EIA, 2013). Monterey Shale in California The Monterey shale in California covers an area of approximately 1,750 square miles (U.S. Energy Information Administration, 2011). Figure 4 depicts the underground shale reserves that stretch along Central California, including both the San Joaquin and Los Angeles Basins (U.S. Energy Information Administration, 2011). Shale is fine-grained sedimentary rock formed by the accumulation of sediments including sandstone and limestone. Shale deposits have recently been identified as rich sources of oil and gas. The Monterey shale encompassing both the San Joaquin and Los Angeles Basins is estimated to hold up to two-thirds of all the United States recoverable oil from shale, with approximately 15 billion barrels of recoverable crude oil (U.S. Energy Information Administration, 2011). Decades ago, Monterey Shale oil was thought to be non-extractable due to depth constraints. Hydraulic fracturing now makes the potentially recoverable oil within Monterey Shale more accessible, showing great economic potential.

Figure 4: A map of the shale reserves in California (EIA, 2012). California produces an average of 220-230 million barrels of oil annually, while consuming 8.6% of the total energy consumption in the US (USC Price School of Public Policy, 2013). With the state s population predicted to reach 55 million by 2050, the state will need to double its energy capacity to accommodate this growth (California Energy Commission and California Council on Science and Technology, 2011). California s per-capita energy use is approximately 30% lower than the national average (USC Price School of Public Policy, 2013). Since the Monterey Shale reserves hold potentially 5 times as much crude oil as the Bakken Shale reserves, projections show California can potentially become a leader of energy production if hydraulic fracturing is used to extract potentially recoverable oil within the Monterey Shale. Although hydraulic fracturing has been used in California for over 30 years, the technique has recently been considered by the industry for large-scale oil exploration activities (California Department of Conservation s Division of Oil, Gas and Geothermal Resources, 2013). Pepino10

METHODOLOGY: Comparing Water Requirements to extract oil from Bakken Shale and Monterey Shale Water is necessary for unconventional oil extraction. Unconventional oil extraction has greater potential for adverse environmental impacts than conventional extraction (U.S. Environmental Protection Agency, 2008). Water availability is critical for the feasibility, production, and economic potential of unconventional oil extraction. The EPA s 2011 Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water estimates that hydraulic fracturing processes use 70 billion to 140 billion gallons of water each year for all operations in the United States, representing large quantities of water that may be diverted from other uses, such as agriculture and municipalities. The Bakken Shale is used as a case study to assess water demands and water quality impacts due to hydraulic fracking. The research provides projections and recommendations for Monterey Shale, if the formation is eventually hydraulically fractured. Table 2 compares important variables used to conduct this analysis, including total area, estimated ultimate recovery, depth of deposits, thickness and porosity; characteristics used to help estimate the amount of water needed to hydraulically frack shale for oil. Table 2 will be used as a tool for comparing Bakken Shale to Monterey Shale throughout this paper.

VARIABLE UNITS BAKKEN SHALE MONTEREY SHALE AREA SQUARE MILES 6,522 1,752 ESTIMATED BARRELS OF OIL 550 550 ULTIMATE RECOVERY [IN MILLIONS] PER WELL TECHNICALLY BILLIONS OF 3.59 15.42 RECOVERABLE RESOURCES BARRELS OF OIL DEPTH FEET 6,000 11,250 THICKNESS FEET 22 1,875 POROSITY % 8 11 Table 2: Comparison of Bakken Shale and Monterey Shale (US EIA, 2011) Surface Water Sources Used for Bakken Shale Oil Production Most of the water for hydraulic fracturing comes from surface water sources such as lakes, rivers, municipal water suppliers, and private water suppliers. However, when surface water availability becomes scarce, groundwater can become a primary source for water acquisition (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2013). Within North Dakota alone, the estimated annual water demand for all oil production is 22,400 acre-feet, equivalent to 7.3 billion gallons of water (Water Appropriations Division: North Dakota State Water Commission, 2011). One of the primary surface water sources for fracking in North Dakota is Lake Sakakawea, formed by the Garrison Dam. As depicted in Figure 5, Lake Sakakawea a manmade reservoir behind the Garrison Dam- is the largest of the six reservoirs on the Missouri River and is the third largest reservoir in the United States (North Dakota State Water Commission, 2012). Lake Sakakawea is a main water supply source for domestic use, irrigation, industrial use, and hydraulic fracturing (EPA Progress Report, 2012). The U.S. Army Corps reservoirs in California have smaller storage capacity compared to the Pepino12

reservoirs in North Dakota. As seen in Figure 5, the Garrison Dam has the highest relative volume (in acre feet) out of any corps reservoir in the United States (2008). Even with large water volumes in North Dakota stored behind the Garrison Dam (>10M acre-feet), getting access to fresh water sources within the state can still be a challenge for the oil and gas industry. Despite water resources being relatively abundant in North Dakota, water quality and water availability is still a problem with difficulty stemming from state and federal agencies, as well as allocation rights and distribution to other water needs. Figure 5: Storage Capacity of Reservoirs built by the U.S. Army Corps of Engineers, showing the acre-feet of water stored by the Garrison Dam along the Missouri River (U.S. Army Corps of Engineers, 2008). As a state, North Dakota is attempting to manage their own water resources; however, The Army Corps of Engineers is trying to gain rights to sell the water. Because the Missouri River flows through the boundaries of federally managed reservoirs, such as Lake Sakakawea, the Army Corps of Engineers is trying to mandate that the oil industry must pay storage fees to obtain water from the reservoirs. Water rights are spurring a large debate between the federal government and the state government, deciding which governing agency has authority over

surface waters within North Dakota. Since the oil companies must get permits from both the State Water Commission and the Army Corps of Engineers, concerns voiced by the industry include: unnecessary delays, time consuming procedures, and additional costs related to obtaining permissions of water rights. As a result of time-consuming surface water procedures, groundwater sources are now being tapped to meet the water demands from the oil industry. In 2012, the US Army Corps of Engineers approved free temporary permits for the oil and gas industry. The permits allowed the oil industry to take water from Lake Sakakawea and pipe the water to Bakken oil drilling sites (North Dakota State Water Commission, 2012). The permits were granted to reduce the drain on underground aquifers in the Williston Basin (North Dakota State Water Commission, 2012). Currently the Army Corps of Engineers are working on a multiyear study to assess the potential impacts of increased water demands on Lake Sakakawea. The study will assess impacts on existing cultural sites and endangered species dependent on the surrounding ecosystem (North Dakota Industrial Commission, 2011). Until the study is complete, access is granted to the oil industry to take up to 100,000 acre-feet of water, equivalent to approximately 32 billion gallons, from Lake Sakakawea for five years, ending in 2015 (North Dakota Industrial Commission, 2011). While the battle continues between state and federal agencies, the potential fees and access issues associated with surface water lead to significant water resource challenges. As water demands increase from energy production, agriculture, manufacturing, and growing populations [a growth correlated to energy extraction within the area], the dependence on groundwater resources continues to increase. In addition to slow permit processes and fees associated with surface water, the geographic location of Lake Sakakawea can be far away from drilling operations, depending on well-site location. High water transportation costs and expensive water acquisition fees from the government are spurring a discussion of both groundwater use and wastewater recycling as potential water sources. The North Dakota State Water Commission reported a large variability for the cost of fresh water per barrel. The cost to purchase water ranged from $5.95/1000 gallons to $25/1000 gallons (North Dakota Industrial Commission, 2011). Geographic proximity of the water source to the drilling site is the largest variable; therefore, transportation costs are the main factor of acquisition charges. Although North Dakota is not usually considered a state to have water scarcity problems, hydraulic fracturing has shown that water rights and water accessibility Pepino14

both play a role in meeting the increasing water demand associated with unconventional oil extraction. Ground Water Resources used for Bakken Shale Oil Production Water demands continue to increase within North Dakota (Water Appropriations Division: North Dakota State Water Commission, 2011). The demand for water is met by both surface water and ground water. Although common freshwater acquisitions for fracking are from water depots, municipalities, and surface water sources, permit applications for new water wells are feasible, as a result of the increased water demand. Although the North Dakota State Water Commission was reluctant to distribute new permits for groundwater wells, permits are still available for the oil industry (North Dakota Industrial Commission, 2011). The North Dakota State Water Commission s concerns originated from potential depletion of water resources as seen through declining rates from bedrock aquifers within the region (North Dakota Industrial Commission, 2011). Two aquifers in North Dakota used by the oil and gas industry are the Fox Hills Aquifer and the Kildeer Aquifer. Fox Hills Aquifer is a bedrock aquifer, and Kildeer Aquifer is part of the Glacial Aquifer System (Water Appropriations Division: North Dakota State Water Commission, 2011). The Glacial Aquifer System includes all unconsolidated aquifers north of the line of continental glaciations throughout the country the largest aquifer system used for drinking water in the United States; encompassing 25 states. Region 8 is classified by sand and gravel aquifers of alluvial and glacial origin, as compared to California s aquifers that are classified as unconsolidated sand and gravel aquifers at or near the land surface (USGS, 2013). North Dakota s glacial-deposit aquifers are considered highly productive aquifers. The groundwater flow is recharged from primarily local streams. Although hydraulic conductivity of all aquifers varies, unconsolidated sand and gravel aquifers have high hydraulic conductivity and are more susceptible to contamination (USGS, 2013). Groundwater recharge within North Dakota has been declining, further emphasizing the correlation between surface water depletion and groundwater recharge rates.

Figure 6: Extent of the Fox Hills Formation in North Dakota (North Dakota State Water Commission, Honeyman 2007). The Fox Hills Aquifer lies under more than half of the state of North Dakota, only exposed at the surface in the southern part of the state (Figure 6). The Fox Hills Aquifer runs as deep as 2,000 feet beneath the surface, but average depth is between 500 and 700 feet beneath the surface based upon screened intervals of 356 monitored wells (North Dakota State Water Commission, Honeyman 2007). Since monitoring reports began in the 1980 s, the groundwater head has been declining at rates between -0.1 ft/year to -2.6 ft/year depending on well location (Water Appropriations Division: North Dakota State Water Commission, 2011). Head declines were shown in every monitored well in 2007, and as water demands increase, the trend in head decline of the Fox Hills Aquifer will continue (North Dakota State Water Commission, Honeyman 2007). The Fox Hills Aquifer, identified as a valuable resource for not only the oil and gas industry, but also the agricultural industry, has been impacted by oil activity (North Dakota State Water Commission, Honeyman 2007). It is important to note that a decline in groundwater head levels can be attributed to declines in surface water levels within Lake Sakakawea. When lake levels rise, nearby head measurements also rise. The groundwater fluctuations observed in wells tapping the Fox Hills Aquifer have a direct correlation to water levels in Lake Sakakawea (Figure 7). The graph shows the connection between groundwater and surface water sources. If surface water levels decline in Pepino16

Lake Sakakawea as a result of increasing water use by the oil industry, the Fox Hills Aquifer will also be depleted. Figure 7: Historical water-level elevation of Lake Sakakawea (blue) correlated to historic water-level fluctuations in observed well (red) (North Dakota State Water Commission, Honeyman 2007). Potential Water Sources for Monterey Shale Oil Extraction California State Water Project The California State Water Project provides water to 25 million residents, in addition to almost one million acres of farmland (CA Department of Water Resources, 2013). This project integrates water storage with water delivery, allocating fresh water to Northern California, the San Francisco Bay Area, the San Joaquin Valley, the Central Coast, and Southern California (CA Department of Water Resources, 2013). This water project is the largest in California, making

deliveries to approximately two-thirds of California s population. Water resources required to hydraulically fracture Monterey Shale may potentially be requested from the California State Water Project, adding an additional demand on the already-coveted supply allocated to municipal suppliers and the agricultural industry. California s Department of Water Resources admits that even during years of normal precipitation, water supply shortages occur because of many competing demands from farmers, cities, and the environment, such as wildlife refuges and species sustained from seasonal water flows. California s economy relies on agriculture as a primary source of revenue, and California is known as the state leading production for 75 commodities (California Department of Water Resources, 2010). California s climate and geography is able to host a multi-billion dollar industry and produces over 250 crops. The agriculture industry relies on the ability to access billions of gallons of fresh water each year for irrigation needs. Depending on the crop produced, as well as efficiency procedures, it is estimated that agriculture consumes 33.22 million-acre feet per year, or approximately 10,824,784,500,000 gallons (California Department of Water Resources, 2010). Of the estimated 33.22 million acre-feet of water used for irrigation, this portion of water represents 80% of all water diverted from surface water or pumped from ground water within California (California Department of Water Resources, 2013). The total amount of water diverted within the state is 43 million acre-feet of water per year (California Department of Water Resources, 2013). Since California s climate dramatically varies based on geographic location, ranging from snow-packed Sierra s to the desert of Palm Springs, water distribution and water allocation rights are complex. Water allocation rights have been uncertain and inconsistent, putting a large strain on water supplies. The demand for water allocated through the California State Water Project is currently unattainable. By tapping into groundwater sources, the demand can be met. Approximately 2 million acre-feet, or 651,702,857,000 gallons of groundwater overdraft is occurring to meet state water needs (Agricultural Water Use in California, 2011). With the state Water Conservation Act of 2009, followed by conservation water plans for 2020, California has been identified as a state with water scarcity and water resource issues. Pepino18

Central Valley Project The Central Valley Project was created to mitigate localized water shortages by enhancing water distribution. Crippling water shortages in the Central Valley impact farmlands and the industry within the Central Valley. The Central Valley Project stretches from the Cascade Range to Bakersfield, encompassing some of the most fertile, yet arid croplands (Figure 8). Two of the primary water sources within the scope of this project include the Sacramento River and the San Joaquin River. The Central Valley Project provides water for over half of the agricultural counties with an estimated return on investment over 100 fold [initial investment was $3 billion] (US Department of the Interior, 2013). The Central Valley Project annually delivers drinking water to 2 million consumers, in addition to irrigating over 3 million acres of farmland (US Department of the Interior, 2013). Approximately 7 million acre-feet of water are delivered per year through the Central Valley Project. However, during recent years, the Central Valley Project had to reduce the contracted delivery amounts by almost 50%, resulting in a shortage of water deliveries. Environmental litigation ensued as a result of water diversion from the San Joaquin River after a massive salmon die-off from diminishing water sources (Natural Resources Defense Council v. Houston, 146 F.3d 1118 (1998)). Water rights and water deliveries have been revisited in the courtroom due to unquenchable demands by the state of California.

Figure 8: Map of the Central Valley Project in California. Beige regions show the Central Valley Project service areas. The Central Valley Project has already contracted its water services to agencies for projected water needs 50 years into the future. California must divert, transport, and deliver water to central valley farmlands for irrigation purposes, since the arid climate does not have sustainable watersheds for water demands within that region. Billions of dollars are allocated for water relocation and water distribution in California. If hydraulic fracturing becomes a largescale technique used to extract oil from Monterey Shale, water availability within peripheral Pepino20

states will become even more competitive. Since the Monterey Shale lies under current and prospective farmlands, hydraulic fracturing will add competition to the water market. Ceres, a non-profit organization advocating for advocating for sustainability, along with the Water Research Institute, created a map showing the competition for water in US shale energy development. Figure 9 indicates that California has been identified as a state with high water risk to extremely high water risk assessed by the ratio of water withdrawal to the mean annual available supply. The red region within California depicts the area on the baseline water stress map where a large portion of available water supply is already being used (Ceres, 2012). Pressure from the oil and gas industry for additional water resources only adds to the baseline water stress assessment. North Dakota was assessed with moderate water risk, despite water rights and water allocation struggles previously discussed in this paper. The map below indicates that water stress and water scarcity is more severe in California; therefore, the consequences of fracking Monterey Shale may be more environmentally harmful than fracking in North Dakota. Figure 9: Competition for Water in US Shale Energy Development. Map showing hydraulically fractured wells overlaid on a map of baseline water stress, showing a correlation between mean annual water supply and hydraulic fracturing (Ceres, 2012).

Comparing Bakken Shale Geology and Monterey Shale Geology Geographically, the Bakken Formation lies beneath Montana, South Dakota, North Dakota, and Canada. This geologic formation was created during the Mississippian period, and it consists of 3 layers: the lower shale, middle sandstone and siltstone, and upper shale. The Bakken formation is characterized by sedimentary rocks; composed of shale, dolomite, sandstone, and siltstone; characteristics identified as having a high potential for hydrocarbon extraction (EPA Progress Report, 2012). Table 3 depicts both the lower shale and upper shale; areas that are carbon rich and are primary sources for oil (USGS, 2008). Bakken shale thickness ranges from several feet to 140 feet (EPA Progress Report, 2012; Carlson, 1985; Murphy, 2001). To overcome the formation s low porosity and permeability, the physical process of fracturing is used to increase the porosity and permeability, thereby increasing the ability to enhance the flow and recovery of oil (North Dakota Industrial Commission, 2011). Carbon-rich shale varies in permeability, depending on porosity and composition. Since each well has an independent rate of oil production, the amount of water required to extract the resources is largely variable depending upon the geology of the formation. Table 3: Geology of the Bakken Formation (Petroleum Geology, 2010) Pepino22

The Monterey Shale Formation in California also has a high potential for hydrocarbon extraction as a result of geologic formations. Though the formations are more complex than the Bakken formation, with depths up to 11,250 feet deep, and thickness up to 1,875 feet, the Monterey Shale can still produce technically recoverable oil as a result of hydraulic fracturing (US EIA, 2011). Due to seismic activity in California, oil can migrate more easily than compared to other shale formations around the country. Since the geologic formation varies so significantly, water use would vary from well to well, depending on production. Table 2 compares Monterey shale with an average porosity of 11%, and Bakken Shale has an average porosity of 8% (US EIA, 2011). The amount of recovered water would be less for Monterey Shale oil extraction as a result of higher porosity, causing the formation to absorb and retain fracking fluid. Wastewater Production for Bakken Shale Wastewater, or produced water from oil extraction, is the largest waste stream associated with hydraulic fracturing. Depending on the well, 30-70% of the injected fluids return to the surface through the drilled well (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2009). The large variance of wastewater production returning to the surface is dependent on the amount of fluids trapped within the fractured formation. The ingredients in wastewater include: water, propping agents, biocides, friction-reducing agents, polymers, scale inhibitors, and weak acids, as well as heavy metals and minerals from the fracture job (North Dakota Industrial Commission, 2011). Examples of the additive, with their corresponding purpose, are explained in Table 2. In addition to the chemical additives mixed with water at the surface, naturally occurring substances also mix with the fluid during injection. Produced water includes naturally occurring substances such as: formation fluid [brine], gases [methane, ethane, hydrogen sulfide, and helium], trace elements [mercury, lead, arsenic], naturally occurring radioactive material [radium, thorium, uranium], and organic material [organic acids] (EPA Draft Plan, 2011).

Table 4: An Example of the Volumetric Composition of Hydraulic Fracturing Fluid (EPA Draft Plan, 2011) All substances in Table 4 have potential to migrate into drinking water sources as a result of hydraulic fracturing (EPA Draft Plan, 2011). Drinking water contamination may occur if fractures extend beyond the target formation impacting nearby geologic formations and groundwater sources. Groundwater contamination can still occur even if fracking operations are not in proximity to a water source; water migration and water seepage can transport these chemicals for miles. Additionally, since monitoring techniques and location placements can be difficult and expensive for underground wells, water contamination has occurred without the contamination source ever being identified. Water contamination may also occur if man-made barriers fail as a result of time, pressure, or human error. Pepino24

Surface Storage of Wastewater Depending on local and state regulations, wastewater disposal procedures vary. In North Dakota, surface ponds are used to store wastewater produced from fracking. Surface ponds are primarily used to assist in evaporation, but can be used as an initial storage area until treatment or disposal. The federal government will soon be drafting regulations and monitoring requirements for surface ponds. The EPA is currently evaluating oil and gas wastewater practices and will likely enforce laws pertaining to the operation, maintenance, monitoring, and closure of surface ponds, in accordance to the Resource Conservation and Recovery Act (RCRA). Regulations for the oil and gas industry have not been able to keep pace with the number of wells being drilled and leases being sold; therefore, the legal framework to mandate best practices is still being created. Underground Storage of Wastewater An economically favorable way to store and/or dispose of wastewater is the use of injection wells. An injection well is a wastewater disposal technique able to confine produced wastewater. The injected wastewater is placed underground into porous rock formations. The EPA defines an injection well under the Underground Injection Control (UIC) Program as: a bored, drilled, or driven shaft, an improved sinkhole, or a subsurface fluid distribution system (EPA, 2012). Injected fluids used or produced during oil and gas activities are categorized under Class II of injection wells (Figure 10). The EPA estimates 144,000 Class II wells are in operation in the United States, with over 2 billion gallons of water injected each day (EPA, 2012). Class II wells are divided into three categories: enhanced recovery Figure 10 (EPA, 2012)

wells (also known as production wells), disposal wells, and hydrocarbon storage wells. Enhanced recovery wells are the wells used to hydraulically fracture oil-bearing formations, increasing the recovery of oil. Disposal wells are used to dispose of fluids associated with oil and gas production, are one of the preferred methods of disposing of wastewater (Figure 10). Hydrocarbon storage wells are storage areas for liquid hydrocarbons, such as underground formations like salt caverns. In many regions of the US, including North Dakota, underground injection is the preferred method for disposing of fracking fluids after oil extraction operations (Easton, 2013). Beginning in 2002, the amount of produced water in North Dakota increased 29% within 4 years, with a baseline of approximately 9.8 million barrels of wastewater/year (EPA Regional Case Study, 2008). North Dakota had the highest percent change of produced water out of all states classified under Region 8. Although oil-only producing wells do not produce as much wastewater as oil with gas producing wells, oil-only producing wells are the second largest producers of wastewater in the oil and gas industry (EPA Regional Case Study, 2008). The disposal of produced water via UIC Program is unregulated for hydraulic fracking activities, as stated by the Safe Drinking Water Act. The Safe Drinking Water Act excludes the underground injection of fluids or propping agents pursuant to the hydraulic fracturing operations related to oil, gas, or geothermal production activities under Section 1421(d)(1) (EPA, 2012). Since hydraulic fracturing is excluded from SDWA regulation, this loophole poses an increased risk of drinking water contamination. Voluntary monitoring programs led by the oil and gas industry help reduce water contamination; however, underground injection storage techniques still have environmental risks associated with wastewater disposal. An additional variable within California s geology are active fault lines. It is possible that as a result of active fault zones within California, underground injection techniques may have an increased risk of groundwater contamination. Treatment Facilities Although a significant amount of wastewater is injected using UIC or is reused, large amounts of wastewater still require disposal. Wastewater can be transported to either publicly owned treatment works (POTWs) or private centralized waste treatment facilities (CWTs) (EPA, Pepino26

2012). Both of these indirect discharge facilities must ensure that the waste can receive proper treatment, to avoid violating rules of the National Pollution Discharge Elimination System (NPDES). However, many POTWs are designed to treat suspended solids and organic content found in household/municipal sewage, not the treatment of water with high salt concentrations or water with radionucleotides. If a treatment plant cannot treat the waste properly, the owner could face NPDES permit violations. Recently, as a result of increasing amounts of water needing to be treated from hydraulic fracturing operations, it is possible for POTWs or CWTs to refuse the waste to avoid violations. Currently, there is no comprehensive set of national standards for the disposal of wastewater discharged from hydraulic fracturing activities; therefore, much of the responsibility remains with the oil industry. Recycled Wastewater Given current water demands and water rights in North Dakota, a nontraditional water source, such as wastewater recycling, can be economical as a result of the high cost of permits, access fees, transportation, and storage for freshwater (North Dakota Industrial Commission, 2011). Reusing the produced water from previous fracking operations reduces the amount of freshwater needed for future fracking jobs. New treatment technologies are being developed to recycle water that is recovered from fracture jobs. Recycling systems that reduce the dependency on fresh water have environmental benefits as well as economic benefits. Reduced truck traffic, together with reduced road usage and road repairs, can save operators $100,000 - $400,000 per well (Dale, 2013). In 2013, several commercialized products have been put on the market to help reduce the demand on fresh water. UniStim and H20 Forward both enable operators to use 100% of the produced water from hydraulic fracturing for other oil and gas operations (PSA from Halliburton, 2013). In California, recycled wastewater would assist in the demand placed on fresh water for hydraulic fracturing operations; however, since 30-70% of water remains within the formation, additional water would still be required to accommodate the expanding energy industry. Recycling wastewater is also not yet cost-competitive; therefore, these systems would need to

become part of the national regulatory framework to ensure the industry utilizes recycled water before acquiring fresh water. Contamination Risks Surface Water Environmental risks are associated with large withdrawals of surface water. Significant impacts from large withdrawals include alterations of flow (for streams), depth, and temperature, as well as mineral chemistry, leading to larger implications for species dependent on the water source (EPA Draft Plan, 2011). North Dakota is currently studying the impacts of surface water withdrawals from Lake Sakakawea. After the produced water reaches the surface, there are several treatment options, each associated with a risk of contaminating surface water and/or groundwater. Wastewater generated during the exploration, development, and production of crude oil is labeled as special wastes under the EPA, and is therefore exempt from the federal hazardous waste regulations under the amendments to the Resource Conservation and Recovery Act (Subtitle C of RCRA, 1980). Produced water can be stored on-site in an impoundment pit. Impoundment pits are constructed depending on local, state, or tribal regulations. Depending on the construction, design and monitoring techniques for the pit, contamination risks vary. If produced water is not stored onsite in an impoundment pit, the water may be stored in tanks, waiting for treatment or disposal. Once the produced water is ready for treatment or disposal, surface contamination may occur during the transportation process. Potential leaks or spills are associated with both the storage and transportation of produced water, influencing the contamination of surface water sources (EPA Draft Plan, 2011). Groundwater Nearly half of the United States population relies on groundwater as their primary source of drinking water; rural populations rely on groundwater for as much as 95% of their drinking water. Groundwater aquifers that provide drinking water to urban areas and for agricultural use Pepino28

can range from depths of tens to thousands of feet beneath the surface; however, the majority of aquifers used are located at depths less than 300 feet below the surface (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2013). Many surface water bodies, such as wetlands, rivers, and lakes, also depend on groundwater discharge. Besides precipitation, groundwater recharge is a source for surface waters (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2013). Environmental risks are also associated with decreasing water levels in an aquifer. Water quality may be impacted as a result of low water tables by changing the mineral content and salinity of the water (EPA Draft Plan, 2011). Chemical changes may occur if water levels greatly vary, affecting the solubility, mobility, salinity, and bacterial growth of an aquifer system. Groundwater is relied upon to meet the water needs of California. If the contracted amounts of water to be delivered by the California State Water Project and the Central Valley Project are unattainable, groundwater sources are used. If hydraulic fracking operations within California further deplete groundwater sources, and/or lead to contamination of groundwater sources, drinking water for California residents would be at risk. One technique to avoid contamination risk is proper construction of new wells. Cementation of the casing, in addition to casing materials, is the first, and potentially most critical, line of defense for protecting groundwater. A physical barrier between groundwater and the fracking fluids is an important element of minimizing groundwater contamination (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2009). RECOMMENDATIONS: California s population is predicted to reach 55 million by 2050. The state will need to double its energy capacity to accommodate this growth (California Energy Commission and California Council on Science and Technology, 2011). However, with climate change and water scarcity, unconventional energy sources should not be the first option to meet the increasing demand. The first option should be conservation efforts and renewable energy generation. In recent years, the California State Water Project and the Central Valley Project have not been able to meet their contracted delivery amounts, putting stress on water sources, increasing the

probability of environmental risks. Hydraulically fracturing Monterey Shale would add to the state s water shortages. In 2012, California had less than 600 (of the U.S. total 50,000) operating wells using hydraulic fracturing techniques. However, if the 15 billion barrels of potentially recoverable oil within the Monterey Shale formation is extracted using unconventional techniques, the process will require billions of gallons of water. If fracking does begin to occur on a larger scale in California, recommendations to minimize water use and environmental impacts are listed below. Water Demands To increase water availability for hydraulic fracturing, while attempting to reduce potential impacts of water scarcity, the oil industry is beginning to take water based on seasonal flow rates. Although consequences can occur from this technique, as seen in Natural Resources Defense Council v. Houston, 146 F.3d 1118 (1998), collecting and storing water during wet years can be advantageous if it is a season of high precipitation. If stream and river water flows are greatest during spring and summer months, the industry will capture water when flow rates are high and store for future use. This technique can potentially reduce stress on municipal drinking water supplies, as well as significant impacts that would affect riparian or aquatic communities downstream (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2013). In California, high seasonal flows should not be considered a reliable source as compared to North Dakota, a state that received higher than normal precipitation in 2011 to help meet the water needs of the oil and gas industry. In addition to minimizing fresh water demands for hydraulic fracturing, treatment facilities to recycle wastewater would be recommended instead of underground injection disposal wells. Underground injection disposal wells remove the wastewater from the hydrologic cycle, adding to water scarcity in the future. By injecting wastewater into impermeable wells the wastewater cannot recharge groundwater sources therefore removing the water permanently from the hydrologic cycle. It s from the hydrologic cycle that the earth receives precipitation. If Monterey Shale extraction results in federal regulation for wastewater disposal techniques, each Publically Owned Treatment Works or Centralized Waste Treatment facility would need to be evaluated for their capacity to treat and properly dispose of wastewater, in Pepino30

addition to extra costs associated with treating fracking fluid. A recommendation would be to have pretreatment requirements for the oil and gas industry to ensure that the water is treated for salt, raidonucleotides, and other chemicals in the fracking fluid. However, wastewater recycling is often energy intensive, and may need chemicals for treatment, or additional water for dilution. There is no perfect solution for wastewater treatment. The best way to reduce wastewater is to use less water for the hydraulic fracking process. Reducing Water Contamination Risks The Bakken Shale Oil Exploration has shown a relationship between groundwater contamination and well construction. Baseline water testing is essential, and should be a requirement of the industry before exploration activities begin. Instead of taxpayers absorbing the cost of additional water quality monitoring, the oil industry should be required to test the water in areas identified as potential locations for hydraulic fracking before, during, and after development. Updated logs and monitoring reports are essential during well construction and the cementing process within the wellbore. To reduce fluid movement from deeper fracking zones to groundwater aquifers, initial cement jobs and well casings need to be constructed using best practices, as well as constant monitoring techniques to monitor ground water sources nearby. Alaska and Ohio are two states currently using verification methods to demonstrate that the quality of bonding between the cement within the well and the well casing meets quality requirements for ground water protection (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2009). Examples of these geophysical logs include Cement Bond Logs (CBL) and Variable Density Logs (VDL) (Groundwater Protection Council & Interstate Oil and Gas Compact Commission, 2009). Both the CBL and VDL measure the travel time of sound waves between the cement and the casing, measuring the bond between the two physical barriers. If California begins large-scale oil extraction using hydraulic fracturing techniques, geophysical logs would be recommended for both new and existing wells to decrease risks of water contamination. In 2010, California onshore oil and gas wells produced 2.39 billion barrels of produced water as a biproduct approximately 9 barrels of water for every 1 barrel of oil from wells