07 Project Description RMM Comments

Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

7. Description of the Project 7.1 Introduction As described in EIR Chapter 4 (Scope and Intent of the Environmental Impact Report), SB 4 requires the preparation of an EIR “to provide the public with detailed information regarding any potential environmental impacts of well stimulation in the State” (PRC Section 3161(b)(3) of Division 3, Chapter 1, as amended). Further, SB 4 requires that the EIR address those stimulation treatments for oil and gas wells “that may occur at oil wells in the state existing prior to, and after, January 1, 2014” (PRC Section 3616(b)(3)(B)(ii) of Division 3, Chapter 1, as amended). PRC Section 3157 of Division 3, Chapter 1, as amended, defines oil and gas well stimulation as “any treatment of a well designed to enhance oil and gas production or recovery by increasing the permeability of the formation. Well stimulation treatments include, but are not limited to, hydraulic fracturing treatments and acid well stimulation treatments. Well stimulation treatments do not include steam flooding, water flooding, or cyclic steaming. Additionally, such treatments do not include routine well cleanout work, routine well maintenance, routine removal of formation damage due to drilling, bottom hole pressure surveys, or routine activities that do not affect the integrity of the well or the formation. Con- sequently, this EIR also does not evaluate high rate gravel packing1 when it is used to control sand within a well. Hydraulic and Ggravel (i.e., sand) packing treatments (“frac packing”) that are performed for well stimulation with the intent for the purpose of fracturing the formation are covered under the description of hydraulic fracturing in EIR Section 7.4.1 (Hydraulic Fracturing). For the purposes of this EIR, the “Project” focuses on the physical acts that are associated with hydraulic fracturing, acid fracturing, and acid matrix stimulation as they apply to both existing and future oil and gas wells within the State. The physical activities associated with these stimulation treatments are described below in EIR Section 7.4 (Oil and Gas Well Stimulation Treatments). In this EIR they are analyzed with consideration of DOGGR’s implementation of the proposed permanent regulations that would amend California Code of Regulations Title 14, Division 2, Chapter 4, Subchapter 2 (see EIR Chapter 2 [Regula- tory Framework for the Division of Oil, Gas and Geothermal Resources]). This EIR’s analysis assumes that these well stimulation treatments could occur either within or outside of existing oil and gas field boundaries, as further described in EIR Chapter 9 (Overall Approach to the Environmental Analysis). 7.2 Project Objectives Section 15124(b) of the State CEQA Guidelines requires that an EIR’s “Project Description” include a clearly written statement of a proposed project’s objectives to help a Lead Agency develop a reasonable range of alternatives, and aid its decision making body when preparing Findings of Fact and a Statement of Overriding Considerations, if necessary. Unlike most EIRs, which are typically prepared in response to a specific project proposal such as a permit application or proposed legislative action, this EIR has been prepared in response to the mandate set forth in PRC Section 3161, Subdivisions (b)(3)(A) and (B), as enacted pursuant to SB 4 from the 2013 legislative session and later amended by SB 861 in 2014 (Stats. 2014, ch. 35). Accordingly, this EIR has not been prepared in response to a specific project proposal, but rather is an informational document regarding the potential impacts of well stimulation which may serve

1 High rate gravel packing is a technique where the annulus (the space between the casing and the drilled hole or wellbore) of a well is packed, at a high pumping rate, with gravel, water, and additives to limit the entry of fines and sand from the formation into the wellbore. The size of the gravel is similar to the size of the proppant (sand) described in EIR Section 7.4.1 for hydraulic fracturing.

June 2015 7-1 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT to inform other CEQA documents. The statute (as amended) adds that section 3161 “does not prohibit a local Lead Agency from conducting its own EIR.” SB 4 also directs other State, regional and local agencies, in collaboration with DOGGR, to establish their respective authority, responsibility, notification and reporting requirements as related to various aspects of well stimulation treatments. Although the execution of some of SB 4’s requirements are independent and exclusive of each other, they are all inter-related in the sense that they all serve the overall objective of SB 4 of requiring the State to rigorously evaluate well stimulation treatments and determine whether they can be conducted safely and with minimal impacts to the environment. To this end, the over-arching objectives of this EIR are not limited to oil and gas well stimulation treatments alone, but also include the objectives of the proposed permanent regulations, as listed below. 1. Objectives of Oil and Gas Well Stimulation Treatments a. To increase the recovery of oil and gas resources by increasing the reservoir permeability to create an economically feasible production rate from presently unusable formations. b. To minimize the number of new wells required for the recovery of hydrocarbon resources. c. To maximize the efficiency and production capacity of existing and planned oil and gas wells. d. To allow continued development of the State’s hydrocarbon resources. e. To conduct well stimulation treatments safely to minimize impacts to the environment and natural resources. f. To reduce the State’s and nation’s reliance on foreign oil and gas resources. 2. Objectives of the Environmental Impact Report a. To comply with PRC Section 3161, Subdivision (b)(3)(A) and (B), by providing the public with detailed information regarding the practice of well stimulation. b. To provide DOGGR and other applicable regulatory agencies with information which may be necessary to efficiently and effectively evaluate future permit applications for proposed oil and gas well stimulation practices, during or following well completion, in order to ensure a consistent approach to CEQA compliance. c. To identify and develop impact avoidance and mitigation strategies to address any significant environmental effects directly, indirectly or cumulatively resulting from well stimulation practices that are not already sufficiently addressed by the proposed regulations addressing well stimulation treatments to be adopted by DOGGR pursuant to PRC Section 3160, Subdivision (b)(1). d. To facilitate on-going coordination between DOGGR and other federal, State, regional and local agencies having regulatory authority over well stimulation practices. 3. Objectives of the Regulatory Process Mandated by SB 4 a. To ensure cooperation and communication among regulatory agencies to expressly regulate the practice of well stimulation through the imposition of certain standards, to require the collec- tion of data regarding well stimulation in California, and to require notification to those potentially affected by well stimulation practices. b. To prevent, as far as possible, damage to life, health, property, and natural resources resulting directly or indirectly from well stimulation, consistent with State statutes authorizing the efficient recovery of hydrocarbon resources, and consistent with impact avoidance and mitigation concepts of CEQA.

Final EIR 7-2 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

c. To prevent damage to underground and surface waters suitable for irrigation or domestic purposes by the infiltration of, or the addition of, detrimental substances resulting directly or indirectly from well stimulation, consistent with State statutes authorizing the efficient recovery of hydrocarbon resources, and consistent with impact avoidance and mitigation concepts of CEQA. 7.3 Overview of the Lifecycle of an Oil and Gas Well As discussed in EIR Chapter 2 (Regulatory Framework for the Division of Oil, Gas and Geothermal Resources), DOGGR supervises the drilling, operation, maintenance and plugging and abandonment of oil, gas, and geothermal wells within California onshore and offshore within three nautical miles of the coastline, as mandated by the California Laws for Conservation of Petroleum and Gas (PRC Section 3000 et seq. [Division 3]) and California Code of Regulations Title 14, Division 2, Chapters 2 and 4 (Title 14). DOGGR’s general regulatory responsibilities are set forth under PRC Section 3106 of Division 3. This statute requires the Oil and Gas Supervisor to “so supervise the drilling, operation, maintenance, and abandonment of wells and the operation, maintenance, and removal or abandonment of tanks and facilities attendant to oil and gas production, including pipelines…so as to prevent, as far as possible, damage to life, health, property, and natural resources; damage to underground oil and gas deposits from infiltrating water and other causes; loss of oil, gas, or reservoir energy, and damage to underground and surface waters suitable for irrigation or domestic purposes by the infiltration of, or the addition of, detrimental substances” (Section 3106(a)). At the same time, however, Section 3106 also sets forth general State policy regarding the recovery of underground hydrocarbons. The “waste” of such resources is generally to be avoided. The Supervisor “shall also supervise the drilling, operation, maintenance, and abandonment of wells so as to permit the owners or operators of the wells to utilize all methods and practices known to the oil industry for the purpose of increasing the ultimate recovery of underground hydrocarbons and which, in the opinion of the supervisor, are suitable for this purpose in each proposed case. To further the elimination of waste by increasing the recovery of underground hydrocarbons, it is hereby declared as a policy of this State that the grant in an oil and gas lease or contract to a lessee or operator of the right or power, in substance, to explore for and remove all hydrocarbons from any lands in the State, in the absence of an express provision to the contrary contained in the lease or contract, is deemed to allow the lessee or contractor, or the lessee's or contractor's successors or assigns, to do what a prudent operator using reasonable diligence would do, having in mind the best interests of the lessor, lessee, and the State in producing and removing hydrocarbons, including, but not limited to, the injection of air, gas, water, or other fluids into the productive strata, the application of pressure heat or other means for the reduction of viscosity of the hydrocarbons, the supplying of additional motive force, or the creating of enlarged or new channels for the underground movement of hydrocarbons into production wells, when these methods or processes employed have been approved by the supervisor, except that nothing contained in this section imposes a legal duty upon the lessee or contractor, or the lessee's or contractor's successors or assigns, to conduct these operations” (Section 3106(b), italics added). The general laws and regulations to which DOGGR is subject include requirements regarding the protection of underground and surface water, and specific regulations regarding the integrity of the well casing (steel pipe inserted into the borehole), the cement used to secure the well casing inside the bore hole, and the cement and equipment used to seal off the well from underground zones bearing fresh water and other hydrocarbon resources. (See California Public Resources Code Sections 3106, 3203, 3211, 3220, 3222, 3224, 3255; Title 14 of the California Code of Regulations, Division 2, Chapter 4, Sections 1722.2, 1722.3, 1722.4, etc.) In addition, local agencies have jurisdictional authority over energy resources and development primarily through adopted land use and environmental protection plans, regulations,

June 2015 7-3 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT standards and policies adopted pursuant to the local agencies’ police powers or State statutes granting them regulatory authority. Therefore, two permits are usually required to drill a well on private land in California. The well owner/ operator needs to obtain a Conditional Use Permit (or similar discretionary land use permit) from the local agency, such as a city or county, and a drilling permit from DOGGR. In many counties, however, most wells drilled in existing oil or gas fields do not require a local land use permit and only a DOGGR permit is required. In other counties, land use permits are required and can be obtained from the applicable local planning department (or otherwise named local land use agency with similar permitting responsibilities). Depending on the well’s location and proposed operations, additional permits may be required from the Bureau of Land Management (for wells located on public land), the State Lands Com- mission (for wells located on State-owned land), and/or other agencies such as the State Reclamation Board, the U.S. Department of Agriculture, USDA Forest Service, Air Pollution Control Districts, Regional Water Quality Control Boards (RWQCBs), California Department of Fish and Wildlife (CDFW), and U.S. Fish and Wildlife Service (USFWS). Figure 7.3-1 shows the location of existing oil and gas wells in California and Figure 7.3-2 shows a typical vertical well. “Casing” as shown on the figure would consist of multiple nested strings of casing. From the outer edge inward, the sequence of progressively smaller-diameter casing would consist of the conductor pipe, surface casing, intermediate casing, and production casing, generally with each interior casing progressively extending to greater depths. Individual casing strings are cemented consistent with applicable regulations. Wells within these fields can be located in open space and agricultural areas as well as within urban areas. The use of horizontal drilling technology in some locations has reduced surface disturbance by requiring fewer wells to reach an oil and gas reservoir with as much as 15 to 20 times more production when compared to a vertical well (Getches Wilkinson Center, 2013). 7.3.1 Pre-Drilling Procedures To initiate the permitting process with DOGGR, the well owner/operator submits a “Notice of Intention (NOI) to Drill New Well” to DOGGR in compliance with PRC Section 3203, Division 3. The form requires text and related maps and diagrams specifying a proposed well name, well type, site location/property information, mineral and surface lease information, proposed drilling and production techniques and equipment information, well depth and pressures encountered, proposed casing program, the zone (geologic strata) of completion, and well proximity, if applicable, to any sensitive land uses (i.e., “critical wells”). Every owner/operator must designate an agent who resides in California and serves as the company contact for all correspondence, including well permits. If an environmental review document for the well has been prepared for a local Lead Agency for compliance with CEQA, the NOI to Drill New Well application must identify the Lead Agency responsible for directing the document’s completion, review, and approval and the type of document required by the Lead Agency. If the well is exempt from CEQA review per Chapter 2 (“Implementation of the California Environmental Quality Act of 1970”) of Division 2 of Title 14, or the local jurisdiction does not require CEQA review for its approval process, it must be indicated on the form. CEQA exemptions fall into four primary categories: statutory; categorical; general rule; and disapproved project. A categorical exemption, which is the most common exemption for oil and gas projects, is for a class of projects that the Secretary of Resources determines generally will not have a significant effect on the environment. The Natural Resources Agency has established 32 classes of categorical exemptions, many of which have special limitations. The most common categorical exemptions for oil and gas projects are Class 1 (Exist- ing Facilities) and Class 4 (Minor Alterations to Land).

Final EIR 7-4 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

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Well Status as of April 2014 EIR Study Region Boundaries Figure 7-1 ! Active County Boundaries I ! Idle Counties excluded fromEsri, SB 4DeLorme, EIR analysis GEBCO, NOAA NGDC, and other contributors ! New Existing Oil and Gas Wells 0 50 100 ! Unknown Miles Within Active Fields in California Source: DOC, ESRI Final EIR June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

The surface casing is cemented from the shoe of the casing to the surface. Subsequent casing strings are cemented only as required through the oil and gas zones and anomalous pressure Figure 7.3-2 intervals and 500 feet above and 100 feet above the base-of-fresh-water (BFW). Not all casings are cemented entirely. Typical Well Source: DOGGR, 2014b.

June 2015 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Upon submittal of the NOI to Drill New Well, the owner/operator must also file a bond (or a blanket bond for proposals to drill multiple wells) with DOGGR. The dollar amount of an individual well bond is contingent upon well depth. The conditions of the bond require that the well owner/operator “shall well and truly comply with all the provisions of Division 3 (commencing with Section 3000) of the PRC and shall obey all lawful orders of the State Oil and Gas Supervisor or the District Deputy or Deputies…” (PRC Section 3204). The bond covers drilling, redrilling, deepening, or other operations permanently altering the casing in oil, gas, geothermal, or service wells in California. The purpose of a bond is to secure the State against losses, charges, and expenses incurred to obtain compliance by operators. Generally, a bond is forfeited when an operator fails to plug and abandon a well; but it can also be forfeited for other reasons, such as a failure to clean up a spill or screen a sump associated with a well. An operator may request confidential status for exploratory wells and certain other wells where there may be extenuating circumstances, such as when an owner/operator is pursuing a deeper formation, a zone not explored, or one that does not have commercial production, or when an owner/operator has not solidified contracts on all of its leases for land for reserves. The request must be in writing and provide sufficient justification. DOGGR approval must be received before well records can be made confidential. The period of confidentiality is finite and expires after two years. Extensions are available, but are limited. An example of an extension may be when an owner/operator has found a play that looks promising, but its extent is not known and the owner/operator may want to drill another well nearby without alerting competing owner/operators. DOGGR has ten days to review and respond to the NOI to Drill New Well once it has been received. If DOGGR does not respond within ten days of receipt, the application is considered approved (PRC Section 3203). Use permits from local agencies can take longer depending on the local agency and the level of environmental review required. For Kern, Kings, and Sutter Counties, DOGGR acts as the CEQA Lead Agency. Wells drilled outside administrative field boundaries, wells drilled infield of administrative boundaries that do not have rules, or wells drill infield of administrative boundaries in ways contrary to rules may require 30 to 60 days to permit. DOGGR will send a letter of abeyance within ten days of receiving a NOI to Drill a New Well notifying the subject operator that CEQA compliance is necessary (DOGGR, 2014a). Following DOGGR’s initial review of the NOI to Drill New Well, additional review and information requests may be required. Upon completion of all necessary review, DOGGR approves or conditionally approves the NOI to Drill New Well and issues a Permit to Conduct Well Operations (Permit). DOGGR may delay or deny a Permit under certain circumstances, such as:  When the owner/operator-provided information in the Form 105 (NOI to Drill a New Well) is insufficient, incomplete, or incorrect.  When the owner/operator fails to post a bond for the period of the well from drilling until the well is considered operational; this would be an incomplete NOI.  If the Lead Agency under CEQA denies project approval.  If the owner/operator has a compliance history of failing to pay a civil penalty and other charges that are required, such as the oil and gas production assessment.2  For new wells, approval of a Permit is subject to the following requirements:

2 Oil and gas producers must pay an annual assessment computed on the amount of oil and gas produced during the preceding year. The assessment, paid to DOGGR for inclusion in the State’s General Fund, is used only for the support of DOGGR.

June 2015 7-7 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

 Protection of all hydrocarbons and surface and subsurface fresh waters by using adequate casing and cementing practices and by following proper drilling procedures.  Adequate blowout prevention equipment.  Proper well spacing (as defined by Chapter 3 of Division 3, PRC Sections 3600 through 3609). Additionally, the review and approval procedures for the drilling and operation of new oil and gas wells are subject to compliance with the requirements stipulated by Chapter 4 (“Development, Regulation, and Conservation of Oil and Gas Resources”) of Division 2 of Title 14. For the purposes of this EIR, it is assumed that this includes DOGGR’s proposed permanent amendments to Chapter 4, as required by SB 4 (see Draft EIR Appendix B). Upon issuance of the Permit, the well owner/operator is then provided with one year to commence drilling operations; should the owner/operator fail to commence drilling within one year from the date of submittal, the approval is canceled (PRC Section 3203). Some districts provide the operator an option for an addition one-year approval, provided all conditions of the original approval still apply. In these instances, this is considered an approval, just as the original permit was approved. If an operator makes the request prior to expiration, the district office normally approves it, unless there are extenuating circumstances. Permits are not automatically extended. Permits may also be extended for one year for a total of two years from the date of issuance. Permits automatically expire after two years. 7.3.2 Site Preparation Construction activities begin with well pad preparation. Improvements and grading to the site are generally approved through a land use/grading permit issued by the applicable local jurisdiction. A well pad generally ranges from one to three acres in size outside of urban areas with one or possibly two wells per pad. However, the total well pad site could reach five acres with access roads and staging areas. In highly developed urban areas, the size of a well pad can range from 8,000 to 16,000 square feet (0.2 to 0.4 acres) per well. In the concentrated diatomite fields in Kern County, there is one well per pad and the wells are between 80 to 120 feet apart with 2,000 to 4,000 wells in a one square-mile section, if all of the section is productive. Well pad development of the Monterey Formation would depend on how deep the formation is and where the wells are located. Where exploration efforts may be concentrated, four-acre well pads would be about 0.5 to one mile apart, with three to 10 wells per pad. If development of the Monterey Forma- tion reaches a level where a township-sized area (six by six miles) is productive, the well owner/operator would likely construct a centralized processing or production facility (oil dehydration, gas compression, etc.), which would occupy approximately 20 acres. DOGGR does not issue permits for the production facilities associated with a production well; these permits and approvals are issued by local and regional agencies through building, grading, and discretionary land use permits. The well pad site is cleared of vegetation and graded to level the surface area. Equipment used for this operation is typically a bulldozer or backhoe. The soil is then cut or filled, watered and compacted. In some cases gravel is also used to stabilize the site. Although tanks are most commonly used to collect drilling fluids, a temporary pit or sump may be constructed to contain drilling fluids under the terms of Statewide General Order No. 2003–0003–DWQ (Statewide General Waste Discharge Requirements for Discharges to Land with a Low Threat to Water Quality) from the State Water Resources Control Board. The pit would need to comply with all applicable Basin Plan provisions, including any prohibitions and water quality objectives governing the discharge, as well as other requirements that may be imposed by the State Water Resources Control Board or RWQCBs. The Central Valley RWQCB has, in Resolution R5-2013-0145 (Approv-

Final EIR 7-8 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT ing Waiver of Reports of Waste Discharge and Waste Discharge Requirements for Specific Types of Dis- charge Within the Central Valley Region), approved waivers of reports of waste discharge and waste discharge requirements for specific types of discharge within the Central Valley Region, but these waivers do not include discharge of drilling muds/boring wastes from oil and gas operations. A pit is typically about 600 square feet (approximately eight feet deep, 15 feet wide, and 40 feet long). DOGGR regulates only the screening of the sump for the protection of wildlife as implemented in 1973 under Assembly Bill 2209, which provided for a legally mandated, full-scale sump inspection and correc- tion program for sumps that were hazardous or immediately dangerous to wildlife. Furthermore, in order to ensure that wildlife is protected from these sumps, California Fish and Game Code Section 1016 states, “(a) whenever the department determines that an oil sump, as defined by Section 3780 of the Public Resources Code, is hazardous to wildlife, but does not constitute an immediate and grave danger to wildlife, the department shall forthwith notify the State Oil and Gas Supervisor of such condition in order that he may take action pursuant to Section 3783 of the Public Resources Code to have such condition cleaned up or abated…(b) Whenever the department determines that an oil sump, as defined by Section 3780 of the Public Resources Code, constitutes an immediate and grave danger to wildlife, the department shall forthwith notify the State Oil and Gas Supervisor of such condition in order that he may take action pursuant to Section 3784 of the Public Resources Code to have such condition cleaned up or abated…” As related to DOGGR’s revised permanent regulations for well stimulation treatments (as of October 10, 2014), California Code of Regulations Section 1786 (a)(4) prohibits the storage of well stimulation fluids in sumps or pits; all such fluids, including additives and produced water, must be stored in containers; and well owners/operators must conduct all activities that relate to storage and management of fluids in compliance with all applicable requirements of the Regional Water Board, the Department of Toxic Sub- stances Control, the Air Resources Board, the applicable Air Quality Management District or Air Pollution Control District, the Certified Unified Program Agency, and any other State or local agencies with jurisdiction over the location of the well stimulation activity. After drilling the well, the sump is closed in accordance with Title 27 of the California Code of Regula- tions, Section 20090. Water and/or non-toxic soil stabilizers are used during site preparation to control dust, as required by the local air district. Site preparation, including construction of a sump (if necessary), typically takes seven to 10 days with crews ranging from two to five people. Use of existing roads and development of temporary access roads may also be needed to access the well pad. If an existing road cannot be used, a new road is constructed from adjacent existing roads. Approval for the construction of new roads is governed by the affected local jurisdiction unless it affects a State’s highway right-of-way. The California Streets and Highways Code Sections 660–734 grant the authority to the California Department of Transportation (Caltrans) to permit improvements and other activities on the State’s highway system rights-of-way by others. An encroachment permit is required for use of State highways for other than normal transportation purposes, including construction of highway frontage improvements, such as driveways and new road intersections (Caltrans, 2013). With the exception of exploratory wells, most wells in existing oil and gas fields do not require the construction of a new road. The temporary access roads vary across jurisdictions, but are typically about 12 to 32 feet wide to accommodate drilling equipment and site worker vehicles, as well as emergency vehicles. The length of the access road varies significantly depending on the distance of the well pad from existing roads. In general, a temporary access road could be as long as three miles in length. Both the

June 2015 7-9 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT roadbed and shoulder areas may be maintained to provide a smooth surface and adequate drainage. Repairs occur as needed to correct normal wear and tear or storm damage such as culvert repairs and replacements. Extending existing electric power lines for the long-term operation of the well is sometimes necessary. Since a new distribution power line ties into an existing distribution line or substation, the tie-in location generally occurs in previously disturbed areas and along existing rights-of-way (ROWs) or roads where the existing line or substation is located. Electric transmission line extensions consist of the installation of new power poles, and may include cross-country vehicular travel for power pole installation in undis- turbed areas. Electric distribution lines would be built by the developer or retail utility provider, and would be regulated by the California Public Utilities Commission (CPUC). The local retail electricity utility provides the electric power supply, through the electric power load serving entities, which are electrical corporations regulated primarily by the CPUC and Federal Energy Regulatory Commission (FERC). The CPUC has full authority over the operations of the investor-owned utilities. The local electricity service providers are obligated to maintain and extend electric distribution facilities and services to new customers upon request. The CPUC (under CPUC General Order 131-D) specifically exempts installation of electric distribution and transmission lines less than 50 kilovolts from review under CEQA (State CEQA Guidelines Sections 15301, 15302, and 15303). Like any categorical exemptions, however, these exemptions may not apply on a case-by-case basis where “exceptions” to the use of exemptions come into play (see State CEQA Guide- lines Section 15300.2). Under Government Code Section 53091(d), city and county “building ordinances” do not apply to the “location or construction of facilities for the production, generation, storage, treatment, or transmission of...electrical energy by a local agency.” Under Subdivision (e) of the same statute, city and county “zoning ordinances” do not apply to the “location or construction of facilities...for the production or generation of electrical energy, facilities that are subject to Section 12808.5 of the Public Utilities Code[3], or electrical substations in an electrical transmission system that receives electricity at less than 100,000 volts.” Zoning ordinances of a county or city shall apply, however, to the location or construction of facilities for the storage or transmission of electrical energy by a local agency, if the zoning ordinances make provision for those facilities.” Under both of these provisions, “local agency” means “an agency of the state for the local performance of governmental or proprietary function within limited boundaries.” "Local agency" does not include “the state, a city, a county, a rapid transit district, or a rail transit district whose board of directors is appointed by public bodies or officers or elected from election districts within the area comprising the district, or a district organized pursuant to Part 3 (commencing with Section 27000) of Division 16 of the Streets and Highways Code” (Government Code Section 53091(a)). 7.3.3 Drilling Operations Well drilling is the process of drilling a hole in the ground for the purpose of either extracting crude oil or natural gas resources, or for the injection of a fluid from surface to a subsurface reservoir or formation. A typical drilling rig is shown in Figure 7.3-3. As discussed in EIR Chapter 2 (Regulatory Framework

3 Public Utilities Section 12808.5 requires a Municipal Utility District to hold a public hearing prior to approval of facilities “for the transmission or distribution of electrical energy, including poles and other accessory structures,” but not including “[a]ny electrical distribution lines of less than 100,000 volts.” The District must also make certain findings at the time of project approval. Such findings must address, among other things, general plan consistency. The statute also allows such a District to override a general plan inconsistency by a supermajority vote if no alternative other than the one proposed is feasible, as defined.

Final EIR 7-10 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Figure 7.3-3

Typical Drilling Rig Source: DOGGR, 2014c.

June 2015 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT for the Division of Oil, Gas and Geothermal Resources), well construction standards and drilling operation requirements are specified by DOGGR in Chapter 4, Sections 1722.2–1722.6 of the California Code of Regulations. Drilling requirements for offshore wells, including offshore exploratory and initial development wells, are regulated in California Code of Regulations Chapter 4, Section 1744. None of these regulations would be changed as the result of DOGGR’s proposed permanent amendments to Chapter 4, as required by SB 4. If the well is not productive, it may be shut-in for a period of time (if over 6 months it become “idle”) and further evaluated. If a well does not have potential as a producer in a different subsurface or strata, it may be converted to an injection well, or it may beis plugged and abandoned (see EIR Section 7.3.6 [Well Plugging and Abandonment]). Oil wells are drilled using a drill string which consists of a drill bit, drill collars (heavy weight pipes that put weight on the bit), and a drill pipe. The drill string is assembled and suspended at the surface on a drilling derrick and run into the hole in the ground (see Figure 7.3-3). It is then rotated using a turntable, or motor, in order to cause the drill bit to advance downward through the formations and thereby extend the hole deeper into the ground. An initial “spud hole” is drilled, to a depth of about 30 feet, with a “rat hole driller,” and conductor pipe set. The conductor pipe is used to hold the initial “spud hole” open. While drilling, drilling fluid (i.e., mud, water and soil) is pumped down the inside of the drill string and pushes the drill cuttings up the space between the casing and the drilled hole (wellbore), which is called the annulus, to the surface, where the cuttings are removed from the drilling fluid (drilling mud) by the “shale shakers.” As the well is drilled and drilling fluid is removed by the cementing process, a series of steel pipes known as casings are inserted and cemented to prevent the boring from closing in on itself. The annulus is filled with cement, permanently holding the casing in place and further sealing off the interior of the well from the surrounding formation. Each length of casing along the well is commonly referred to as a casing string. Cemented steel casing strings are a key part of a well design and are essential to isolating the formation zones and ensuring integrity of the well. A cement barrier around the casing strings protects against migration of methane, fugitive gas, and any formation fluid and protects potential groundwater resources by isolating these shallow resources from the oil, gas, and produced water inside of the well. When initial drilling extends just below the base of fresh water, the casing is placed into the drilled hole. The surface casing is cemented from the shoe of the casing to the surface. Subsequent casing strings are cemented only as required through the oil and gas zones and anomalous pressure productive intervals and 500 feet above and 100 feet above the base-of-fresh-water (BFW). Not all casings are cemented entirely. As surface casing is set and cemented, blowout prevention equipment is installed at the wellhead and tested. DOGGR staff witnesses testing operations. All drilling activities occur on a well pad that has been constructed to support drilling the well. Drilling equipment and materials are brought onsite once well pad site preparation has been completed. This equipment includes a drilling rig, which is approximately 100 to 150 feet in height (depending on the depth of the well), diesel powered mud pumps, trailers for drill workers, storage racks for drill pipe and casing, oil storage tanks, water tanks, and drilling mud tank. Drilling rigs generally require 500 to 3,000 horsepower, supplied by one or more gas or diesel engines. The rig and pump are either powered directly by the engines, or indirectly by on-site electrical generators. Drilling is continuous until the target depth is reached. In general, approximately 100 barrels (4,200 gallons) of water, which is typically fresh water, are used per day for the drilling process. Water is used for drilling the well, mixing mud, mixing cement, and dis- placing cement inside the casing of the well once the annulus has been filled. Although it varies between

Final EIR 7-12 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT wells, the overall quantity of water required for drilling is based on the volume of the drilled area, which is calculated with the size of the hole and the depth of the well. Additional water is also required to replace water lost into the formation. The water is brought to the site by 5,000-gallon trucks. Facilities are also required for crews that provide mud and cement services, and for well-logging crews. Approximately eight workers per shift are on site at any one time during the drilling process. Drilling activities and the transport of labor and materials occurs on a 24-hour basis due to the complexity and associated hazards with leaving a well in the process of being drilled unattended. The drilling site is lit at night to allow for 24-hour operation of the drill rig and the rig mast is lit for aircraft safety. An exploratory well requires 15 to 30 days to drill, although deeper wells can require several months. The well depth may range from less than 1,000 feet to more than 17,000 feet, with a typical exploratory well being 5,000 to 10,000 feet. The well may be tested, if it has the potential to be productive, which requires an additional 30 to 90 days. As such, the total drilling operation (site preparation, drilling and testing) can take as much as 180 days or six months to complete. Containments (temporary pits, operations sumps and/or portable tanks) are used to store drilling fluids, wellbore cuttings, and waste, which are a result of the drilling process. Portable tanks may be used to mix and store other needed liquids or slurries, such as drilling fluids, resin-coated sand, and completion fluids. Drilling fluids, generally bentonite mud, are used in the drilling process. Although portable tanks are used most often, when using sumps or pits, the operator must comply with all requirements of Water Quality Order No. 2003–0003–DWQ (as also discussed under EIR Section 7.3.2, Site Preparation). As required by Water Quality Order No. 2003–0003–DWQ, prior to commence- ment of drilling, a Notice of Intent to Comply and a Discharge Monitoring Plan would be submitted to the RWQCB (Notice of Applicability). Also, proof of CEQA compliance and other conditions are included as part of the Order requirements. If subsurface water is encountered, an enclosed above ground system would be used in place of sump(s). The bottom of the sump(s) would meet requirements of the RWQCB to be at least five feet above the highest groundwater elevation and at least 100 feet from the nearest surface water. Although sumps are currently regulated, as noted above, DOGGR’s revised permanent regulations for well stimulation treatments (as of October 10, 2014), California Code of Regula- tions Section 1786 (a)(4) prohibits the storage of well stimulation fluids in sumps or pits; all such fluids, including additives and produced water must be stored in containers. Chemicals are stored at drill sites in containers that include secondary containment to prevent leaks from reaching the ground. All hazardous materials, such as diesel fuel, are stored and managed according to current State and local regulations. Material Safety Data Sheets are also on site to ensure materials are used and handled properly. Hazardous substances are defined in the Comprehensive Environ- mental Response, Compensation, and Liability Act (CERCLA) Section 101(14), and hazardous wastes are defined in California Code of Regulations Title 22, Chapter 11, Article 1, Section 66261.3. Spills of hazardous chemicals (e.g., fuel and lubricants) at the well drilling sites are cleaned by the site operator under the oversight of the Department of Toxic Substances Control (DTSC) and possibly the RWQCB. DOGGR field engineers may be onsite to provide technical support related to oil and gas components, assist the incident commander, and document the spill. The well owner/operator is responsible for reporting all releases as required by federal, State, and local regulations. Additionally, California Code of Regulations Section 1786 (DOGGR’s proposed permanent regulations for well stimulation treatments as of October 9, 2014) mandates the following: (a) Operators shall adhere to the following requirements for the storage and handling of well stimulation treatment fluid, additives, and produced water from a well that has had a well stimulation treatment:

June 2015 7-13 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

(1) Fluids shall be stored in compliance with the secondary containment requirements of Section 1773.1, except that secondary containment is not required under this section for portable or temporary production facilities that are in one location for less than 30 days. The operator’s Spill Contingency Plan shall account for all production facilities outside of secondary containment and include specific steps to be taken and equipment available to address a spill outside of secondary containment. (2) Operators shall be in compliance with all applicable testing, inspection, and maintenance requirements for production facilities containing well stimulation treatment fluids. (3) Fluids shall be accounted for in the operator’s Spill Contingency Plan. (4) Fluids shall be stored in containers and shall not be stored in sumps or pits. (5) In the event of an unauthorized release, the operator shall immediately implement the Spill Contingency Plan; notify the Regional Water Board and any other appropriate response entities for the location and the type of fluids involved, as required by all applicable federal, state, and local laws and regulations; and shall perform clean up and remediation of the area, and dispose of any cleanup or remediation waste, as required by all applicable federal, state, and local laws and regulations. (6) Within 5 days of the occurrence of an unauthorized release, the operator shall provide the Division a written report that includes: (A) A description of the activities leading up to the release; (B) The type and volumes of fluid released; (C) The cause(s) of release; (D) Action taken to stop, control, and respond to the release; and (E) Steps taken and any changes in operational procedures implemented by the operator to prevent future releases. (7) Operators shall conduct all activities that relate to storage and management of fluids in compliance with all applicable requirements of the Regional Water Board, the Depart- ment of Toxic Substances Control, the Air Resources Board, and the Air Quality Manage- ment District or Air Pollution Control District, the Certified Unified Program Agency, and any other state or local agencies with jurisdiction over the location of the well stimulation activities. (8) An operator who generates a waste, as defined in Health and Safety Code section 25124 and California Code of Regulations, title 22, section 66261.2, in the course of conducting well stimulation activities, including but not limited to well stimulation treatment fluid, additives, produced water from a well, solids separated from well stimulation treatment fluid, remediation wastes, or any other wastes generated from the processing, treatment or management of these wastes, shall determine if the waste is a hazardous waste by sampling and testing the waste according to the methods set forth in California Code of Regulations, title 22, division 4.5, chapter 11, article 3 (section 66261.20 et seq.), or according to an equivalent method approved by the Department of Toxic Substances Control pursuant to California Code of Regulations, title 22, section 66260.21, except where the operator has determined that the waste is excluded from regulation under Cali- fornia Code of Regulations, title 22, section 66261.4 or Health and Safety Code section

Final EIR 7-14 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

25143.2. Notwithstanding any other section in this article, wastes that are determined by the operator to be hazardous wastes shall be managed in compliance with all hazardous waste management requirements of the Department of Toxic Substances Control. Wastes related to oil and gas well drilling consists of earth formation materials (drill cuttings) mixed with the drilling fluid consisting of water and bentonite clay and other additives. Additionally, biocides, anti- corrosives, clarifiers, heavy metals, petroleum hydrocarbons, and brine can be found in the produced water associated with drilling operations. Occasionally a barite additive is used to increase the weight of the fluid, or a polymer is added to enhance other fluid characteristics. These polymer additives are degradable. These wastes are tested for toxicity against the California Assessment Manual for Hazardous Wastes. Non-hazardous waste would be recycled or disposed of at an appropriate landfill or recycling facility. All hazardous waste materials, including contaminated soil, would be handled and disposed of by a licensed waste disposal contractor and transported to an appropriate disposal or recycling facility to meet federal, State, and local requirements. 7.3.4 Well Completion Operations Well completion follows the drilling phase. It is a separate phase that takes place after the well is drilled and cemented. This operation can include perforations followed by other types of well stimulation techniques, as summarized below and further described in EIR Section 7.4 (Oil and Gas Well Stimulation Treatments). Well completions may occur with the drilling rig on site, or the drilling rig may be removed and, if required, specialized well stimulation equipment is brought in. A workover rig sometimes replaces the drilling rig for well completion, or the completion design may be rigless. Well completion, including the location of perforation, must be in accordance with the conditions identified on the Permit to Drill New Well that is issued to the owner/operator by DOGGR. Perforation. The first step to complete a well is to perforate the casing to allow hydrocarbon fluid from the producing formation to enter the well. Perforations are simply holes that are made through the casing. Perforation uses a series of small, specially designed shaped charges, which are lowered to the desired depth in the well and activated by a perforating gun. These shaped charges create the holes in the steel production casing that connect its inside to the targeted geological formation, or production zone. This step is usually performed whether or not well stimulation (discussed below) is required to create a channel between the producing formation and the wellbore. Each individual perforation is isolated by the cement surrounding the hole through which the perforation was cut. Additionally, the producing zone itself is isolated outside the production casing by cement above and below the zone. This isolation ensures that hydrocarbons and other fluids are unable to migrate anywhere except between the perforations and the wellbore. Figure 7.3-4 depicts a wellbore, casing, and perforations in a typical well. Another type of well completion that is often used in California for formations that have fine particles, such as clays and silts, is the use of landed liners. that are gravel packed. A slotted liner is a steel casing that is prefabricated (instead of perforated in the wellbore) to have tiny slots or holes along almost the whole length of casing all the way around. The liner is set (hung) in place and usually gravel packed across the productive interval. Rarely, a slotted liner may be cemented above the slotted interval to anchor it into the next larger casing string. Slotted liners also may be run inside other liners that have failed. Perforated liners and screens also are used in formations having fine particles.then “landed” or anchored with gravel around it instead of cement.

June 2015 7-15 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

steel pipe and cement layers

Surface

Surface Casing steel pipe Depth of deepest area domestic water well Cement

Surface casing depth below deepest area domestic water well Cement

Production Casing Top of completion zone steel pipe

Perforations

Production Tubing steel pipe

Plastic Plug Bottom of completion zone Concrete Plug

Production Casing Depth below completion zone

The surface casing is cemented from the shoe of the casing to the surface. Subsequent casing strings are cemented only as required through the oil Figure 7.3-4 and gas zones and anomalous pressure intervals and 500 feet above and 100 feet above the base-of-fresh-water (BFW). Not all casings are cemented entirely. Wellbore, Casings, and Perforations Source: Energy Council, 2014.

June 2015 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Well Stimulation. Once the casing is perforated, and depending on the type of formation and the current state of the wellbore, well stimulations, such as acid fracturing, acid matrix, or hydraulic fracturing, may be required. Only one of these treatments for the purposes of well stimulation is used on any given well as a part of well completion. Hydraulic fracturing is discussed in greater detail in EIR Section 7.4.1, acid matrix stimulation is discussed in EIR Section 7.4.2.2, and acid fracturing is discussed in EIR Section 7.4.2.1. While drilling a well, the productive intervals are exposed to the drilling mud and possibly cement. The drilling mud and cement are pushed into the near bore pore spaces reducing or eliminating the relative permeability (the capability for fluids to flow through a porous media). Occasionally chemicals in the mud will react with constituents in the formation fluids, resulting in precipitation of solids. This will also result in permeability reductions. These situations may be corrected by circulating various acids into the near well bore area to dissolve the precipitates, cement and drilling mud to reclaim much of the native permeability. This type of acid treatment to remove scale and solids buildup may also be required routinely over the life of a well, as discussed in EIR Section 7.3.5 (Testing and Production). 7.3.5 Testing and Production Following well completion, well testing occurs. Testing and production are specified by the conditions of the Permit to Drill a New Well or the Permit to Rework a Well by DOGGR. The testing phase involves onsite separation of oil, gas and water via gravity or centrifugal separation and measurement of their respective percentages of total production. For an exploratory well, oil and produced water are typically extracted into temporary tanks and any associated gas is burned off using a temporary flare at the well site in accordance with local air district regulations. For an “in-field” or “development well,” these hydrocarbons and associated water are piped into an existing production system during the testing phase. Bottom hole pressure surveys are performed prior to initial oil and gas production and during the life of a well. Typically, a pressure reading at the surface and the well bore fluid weight can be used to determine the reservoir pressure. The weight of the fluids in the wellbore can be calculated as a pressure gradient; pressure per foot of depth. Multiplying the pressure gradient by the reservoir depth and (if necessary) adding any pressure on a pressure gauge at the surface will provide the reservoir pressure. If a well does not have fluid at the surface, it is necessary to determine the top of the column of the fluid over the reservoir. The reservoir pressure can be determined by multiplying the height of the fluid column over the reservoir by the fluid gradient to provide a reservoir pressure. Several types of pressure measuring devices have been used to directly measure the pressure at the bottom of wells over a period of time. One kind uses a stylus to scratch a smoked surface on a metal sheet to create a visual chart of pressures versus time. More modern digital recorders store pressure readings taken several times per minute. An oil well is completed with a pumping unit (unless it is free flowing), and connected by pipeline (flow lines and gathering lines) to production facilities. A gas well is completed with a separator and connected by pipeline to production equipment. Production facilities typically include tanks, testing facilities, and shipping facilities. Depending on the type of recovery method used, there may also be facilities for chemical treatment and heaters, as well as facilities for generating and distributing steam, and injection wells for injecting steam and/or water. Produced wastewater may be injected into water disposal/enhanced recovery wells, or in surface pits, and there may be waste handling systems for treatment chemicals and products (see also EIR Section 7.4.1.6, Wastewater Disposal). Additionally, there may be natural gas handling and flaring facilities.

June 2015 7-17 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

DOGGR issues permits only for construction of the well itself; other production facilities would be permitted through the appropriate local land use and resource agencies. During the life of a well, rework may be necessary to restore production from an existing formation when it has fallen off substantially or ceased altogether. In compliance with Section 3203, Division 3, PRC, operators proposing to deepen or permanently alter the casing in a well must submit a Notice of Intention to Rework/Redrill Well (OG107) and receive a Permit to Rework/Redrill Well from DOGGR prior to commencing operations. All operations other than drilling new wells and abandoning existing wells are under the general classification “rework.” Typical routine well maintenance consists of repair or replacement of wearable parts that have a limited service life or maintaining the tubing, wellbore or other downhole devices to maintain optimum efficiency. This routine maintenance includes the following types of activities:

 Pump or rod replacement for production wells;  Sand or fill removal from the wellbore or tubing;  Replacement of downhole pumps and downhole power systems (electric or hydraulic);  Tubing or packer replacement for injection or production wells;  Scale or wax removal from tubing or casing;  Adding a liner to an existing well; and  Reperforating the existing zone(s). More complex well maintenance activities involve significant alteration of the casing, such as:

 Plugging back a well and recompleting the well into a different production or injection zone;  Plugging back a well and sidetracking the well into the same zone;  Repairing casing collapsed or damaged casing; and  Plugging back and redrilling the well into a different target location. Converting a well from an injection well to a production well or vice versa is considered maintenance as long as it conforms to an injection project approval and required testing is done and approvals are granted. In addition to downhole operations discussed above, there are numerous activities that regularly take place at the surface that do not affect the integrity of a well or formation, such as:

 Stuffing box4 seal replacement for a beam pump (pumpjack);  Pressure testing of the tubing/casing annulus to determine casing integrity;  Measurement of the top of the fluid in the tubing/casing annulus by using sonic techniques in order to estimate reservoir pressure; and

4 A stuffing box is a chamber that houses a gland seal containing compressed packing. It is used to prevent leakage of fluid, such as oil, water or steam, between sliding or turning parts of machine elements, such as a piston or rod that passes through its hole. When wells are artificially lifted by means of a sucker rod pump, the polished rod operates through a stuffing box, preventing escape of oil and diverting it into a side outlet to which is connected the flow line leading to the oil and gas separator or to the field storage tank. For a bottom hole pressure test, the wireline goes through a stuffing box and lubricator, allowing the gauge to be raised and lowered against well pressure (Oil Gas Glossary, 2014).

Final EIR 7-18 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

 Various well logs (e.g., recording temperature, noise, cement bond, radioactive tracer, caliper5 and other factors) that are run from the surface into a well to determine the condition or mechanical integrity of the well. Production operations would vary from field to field, but most are 24 hours per day, seven days per week and 365 days per year. From the production facility, most oil and gas is piped through a large network of existing crude oil pipelines to refineries clustered in the Los Angeles area, the San Francisco Bay Area, and the Central Valley near Bakersfield. Refineries are listed in Table 7.3-1.

Table 7.3-1. California Oil Refinery Locations and Capacities Capacity Refinery Name (barrels/day) BP West Coast Products LLC, Carson Refinery 240,000 Chevron USA Inc., El Segundo Refinery 276,000 Chevron USA Inc., Richmond Refinery 245,271 Tesoro Refining & Marketing Company, Golden Eagle Martinez/Avon Refinery 166,000 Shell Oil Products U.S., Martinez Refinery 156,400 ExxonMobil Refining & Supply Company, Torrance Refinery 149,500 Valero Benicia Refinery 132,000 ConocoPhillips, Wilmington Refinery 139,000 Tesoro Refining & Marketing Company, Wilmington Refinery 103,800 Valero Wilmington Refinery 78,000 ConocoPhillips, Rodeo San Francisco Refinery 78,400 ALON USA, Bakersfield Refinery 66,000 Paramount Petroleum Corporation, Paramount Refinery 50,000 ConocoPhillips, Santa Maria Refinery 41,800 Edgington Oil Company, Long Beach Refinery 26,000 Kern Oil & Refining Company, Bakersfield Refinery 26,000 San Joaquin Refining Company Inc., Bakersfield Refinery 15,000 Greka Energy, Santa Maria Refinery 9,500 Lunday Thagard, South Gate Refinery 8,500 Valero Wilmington Asphalt Refinery 6,300 Source: CEC, 2012. Pipeline infrastructure in California is controlled by a combination of common carrier and private companies and operates on a continuous basis. Likewise, refineries operate on a continuous basis at or near maximum capacity, except during periods of planned maintenance or unplanned outages. In 2013, California refineries processed over 1.6 million barrels per day of crude oil, with 627,000 barrels per day coming from California via pipelines. San Francisco Bay Area refineries processed nearly 40 percent of

5 A caliper is a well logging tool that uses two or more articulated arms that push against the borehole wall to provide a continuous measurement of the size and shape of a borehole along its depth. The measurements that are recorded can be an important indicator of cave-ins or shale swelling in the borehole, which can affect the results of other well logs.

June 2015 7-19 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT the total crude oil; Bakersfield and southern California refineries processed approximately 60 percent of the crude oil (CEC, 2014). Although pipeline is the primary method of transport, some product may be transported up to approximately 300 miles in 5,000-gallon tanker trucks or by railroad to these locations from less established fields. A single tank car can hold 550 to 725 barrels (23,100 to 30,450 gallons) of crude oil. In the first few years of development of the Monterey Formation (i.e., before infrastructure is built) and depending on location, the product would likely be transported in tankers on roadways and/or rail up to approximately 300 miles to the refineries shown in Table 7.3-1. If the Monterey Formation is economically productive over the longer term, it is likely that production facilities and pipelines would be built to transport the oil and gas to the refineries and transport by tanker truck would be reduced. The existing refineries in California are running close to capacity; however, the permitting, environmental compliance, and construction of new refineries in California are difficult and costly, and for these reasons, such construction is not anticipated to occur. Nonetheless, increased production of oil and gas from the Monterey Formation at existing refineries would likely increase the amount of product refined from California and displace product from other sources, such as from Alaska and other foreign countries, including Saudi Arabia, Ecuador, and Iraq. Once oil has been processed into gasoline or diesel, the fuel is shipped from the refinery, usually through a pipeline, to over 60 refiner or wholesaler terminals where it is sold, either directly or indirectly (CEC, 2014). However, breakdowns in the methods of transport, the transportation routes, and the final destinations after the refineries are too speculative to predict for this EIR analysis. 7.3.6 Well Plugging and Abandonment In general, when a well is no longer capable of commercial production or service, it is plugged and abandoned with a combination of cement plugs, bentonite, and drilling mud. However, there are thousands of existing idle wells in California that have not been plugged or abandoned. Occasionally, a production well must be plugged and abandoned because mechanical conditions, such as collapsed casing, have developed. Abandonment requirements are specified by DOGGR, and DOGGR staff witnesses abandonment operations. Chapter 4, Section 1723 of the California Code of Regulations includes the requirements for the plugging and abandonment of wells. 7.3.7 Well Incidents and Oil Spills During the operational life of a well, unanticipated incidents can occur that may cause an oil spill. Typic- ally these incidents are related to either corrosion or a mechanical failure of the well, although other causes can also occur, such as attendant equipment failures, pipeline failures, natural disasters and worker errors. The Comprehensive Environmental Response, Compensations, and Liability Act (CERCLA), the Emergency Planning and Community Right-to-Know Act (EPCRA), and California law require responsible parties to report hazardous material releases if certain criteria are met. Based on data provided by DOGGR, oil spills between 2009 and 2014 ranged in size from 0.0006 barrels (0.025 gallons) to 1,500 barrels (63,000 gallons). The data provided by DOGGR is generally derived from the Office of Emergency Services (OES) and covers oil spills within existing oil fields. It is additionally noted that this data is considered incomplete due to differences in how reporting is logged and variations in local regulations for when reporting is required. As an overall frame of reference, Table 7.3-2 provides the total number of spill notifications submitted to the OES between the years 1993 and 2014 (up to October 27th). Most of these spills are unrelated to

Final EIR 7-20 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT the oil and gas industry and may include spills at residences, commercial businesses, highways, and other locations. Table 7.3-2 also gives the number of spills reported as occurring in oil fields, and by their presence there are most-likely related to the oil and gas production industry. Spills in oil fields range from about two percent to 16 percent of the total reported spills in a given year, and have been generally declining since about 1998. A review of the OES data reveals that approximately 85 percent of the oil field spills during the past six years (2009 to 2014) were spills of crude oil or produced water, or both. Oil and produced water spill quantities ranged from a few ounces to 1,500 barrels, averaging 32 barrels, with a median spill of 5 barrels. Approximately 15 percent of the spills in oil fields were of other material, and included such items as drilling mud, acids (hydrochloric, hydrofluoric, sulfuric), ammonia, antifreeze, chlorine, gasoline and diesel, ferric chloride, motor oil, hydraulic oil, transformer oil, hydrogen sulfide, diatomaceous earth, mineral oil, sewage, solvents, triethylene glycol, wastewater, paint, and vegetable oil. In the 22 years of OES records listed in Table 7.3-2, there were no spills found that could be directly related to the well stimulation activities covered in this EIR three reported spills (in 2011, 2012, and 2014) that may have been directly related to the well stimulation activities covered in this EIR. These included a 2014 spill of drilling brine and zinc salts in Ventura County, a 2012 spill of an unknown substance in the Los Angeles Harbor, and a 2011 spill of crude oil in Santa Barbara County. Approximately 97 percent of the oil field spills reported to OES for the years 2009 to 2014 were contained at the time of the report. About 13 percent were in unspecified waterways, of which 92 percent were contained. There were nine reports of uncontained spills in waterways between 2009 and 2014. These were all spills of crude oil, produced water, or drilling mud. Most (54 percent) of the OES-reported oil field spills were in Kern County, followed by Santa Barbara County (16 percent), Los Angeles County (11 percent), Ventura County (8 percent), Orange County (3 percent) and Monterey and Fresno Counties (1 percent each). Fourteen other counties each had less than 1 percent of the reported incidents.

Table 7.3-2. California Office of Emergency Services Hazardous Materials Spill Notifications Year Number of Spill Notifications* Spills in Oilfields 1993 3,146 177 1994 5,842 757 1995 5,207 765 1996 5,126 621 1997 5,135 723 1998 5,733 919 1999 5,374 521 2000 6,038 359 2001 7,424 291 2002 6,846 245 2003 6,535 216 2004 6,680 221 2005 7,317 278 2006 7,423 268 2007 7,767 260 2008 8,806 263 2009 8,390 208

June 2015 7-21 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Table 7.3-2. California Office of Emergency Services Hazardous Materials Spill Notifications 2010 7,713 167 2011 7,358 197 2012 7,686 146 2013 7,629 138 2014 [to October 27] 5,775 93 * Total reported spills. Most spills within the State are unrelated to the oil and gas production industry.

In addition to the oil spills reported to the OES, Table 7.3-3 provides breakdown of oil spills reported to DOGGR between the years 2009 and 2014 (up to October 1st) and their causes.

Table 7.3-3. Breakdown of Oil Spills Reported to DOGGR (2009-2014)1 Property DOGGR Number of Cause: Cause: Cause: or Water District Spills Corrosion Mechanical Other Damage Injuries Pipe Leak Well Leak Tank Leak Other Leak 1 333 20 18 34 3 0 39 4 6 0 2 21 7 2 7 0 2 10 4 3 0 3 272 51 76 70 5 2 75 24 19 150 4 613 148 180 277 11 1 177 87 91 9 5 18 2 8 3 2 1 4 1 4 0 6 1 0 0 1 0 0 1 0 0 0 Total 1,258 228 284 392 21 6 306 120 123 59 1 - January 3, 2009 to October 1, 2014 Additional detail and information related to oil spills can be found in EIR Section 10.21 (Risk of Upset/Public and Worker Safety). 7.3.8 Probable Future Production in California Probable future production over the next 25 years is described by study region below based on business plans from members of the Western States Petroleum Association (WSPA). In general, California is anticipated to experience declining production with the management of older reservoirs. As shown in Figure 5-9 (see EIR Chapter 5), the Monterey Formation occurs within existing fields and also extends beyond existing fields into undeveloped areas. Well stimulation treatments are necessary to recover oil and gas in Monterey source rock within the formation, but the technology to do so is currently in the research and development phase, as described in EIR Section 6.3 (Potential Future Oil and Gas Resources). The analysis in this EIR assumes that, with adequate advances in well stimulation technology, future production in the Monterey Formation would primarily occur within existing fields in the Monterey Formation plays, but could occur essentially anywhere within the Monterey Formation. The production estimates from WSPA below include a moderate growth buffer to factor in the potential for development of the Monterey or another new find that could be brought into production. However, current expert opinion, including that of the California Council on Science and Technology (CCST), is that evidence is not available to predict with any reasonable certainty the location, quantity, or production potential of new wells in the Monterey Formation at this time. Accordingly, WSPA did not specify any future production in the Monterey Formation in the projections below.  Study Region 1. Well stimulation activities covered in EIR Section 7.4 are proposed only at the Wilm- ington Oil and Gas Field and the Inglewood Oil and Gas Field in the future, as described below.

Final EIR 7-22 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Wilmington Oil and Gas Field. Production and drilling of new wells is anticipated to decline over the next 10 years at the Wilmington field. No more than approximately 100 wells will be drilled in any given year. Zero to fewer than 20 wells would be hydraulically fractured annually, all of which would be at Oxy’s THUMS/Long Beach Unit. Acid matrix stimulation and acid fracturing are not anticipated to be used for well completion during future operations at the Wilmington field. Well stimulation of existing wells would also occur on a limited basis at the THUMS/Long Beach Unit, but is not anticipated to occur elsewhere in the field. Inglewood Oil and Gas Field. Over the next 25 years, over 50 new production and injection6 wells would be drilled in any given year and up to 25 wells would be abandoned annually. Hydraulic fracturing and high rate gravel packing7 combined (“frac packing”) would be used for well completion on zero to nearly 70 percent of new production wells, and none of the new injection wells. Of these new production wells, it is projected that no more than 25 percent would be hydraulically fractured. Acid matrix stimulation and acid fracturing are not anticipated to be used for well completion during future operations in the Inglewood field. Well stimulation treatments would also be used on fewer than 15 already existing wells per year.  Study Region 2. Over the next 10 years, fewer than 20 new production and injection wells would be drilled in any given year and up to 30 wells would be abandoned annually. Hydraulic fracturing would be used for well completion on 10 to 100 percent of new production wells and none of the new injection wells. Acid matrix stimulation and acid fracturing are not anticipated to be used for well completion during future operations in Study Region 2. Well stimulation treatments would also be used on fewer than 15 already existing wells per year. Sespe Oil and Gas Field. It is anticipated that a similar or slightly reduced level of production, well stimulation, and abandonment will occur in the next 25 years. Only a few wells (typically between two and four) will be drilled per year in the Sespe field, all of which would be hydraulically fractured. The field operator has indicated that Nno well stimulation treatments will be requested for any already existing wells within the field. Acid matrix stimulation and acid fracturing are not anticipated to be used for well completion during future operations within the Sespe field.  Study Region 3. Up to approximately 400 new production and injection wells are anticipated to be drilled per year within Study Region 3 over the next 25 years. None of these new wells will be in the Monterey Formation. However, no well stimulation activities covered in EIR Section 7.4 are anticipated to be used for well completion on these new wells or on any existing wells.  Study Region 4. In general, production and drilling of new wells is anticipated to gradually decline over the next 25 years within Study Region 4. In any given year, up to 3,300 new production, cyclic producer, injection, and other miscellaneous wells (e.g., observation, water supply, etc.) would be drilled and approximately 1,100 would be abandoned. Hydraulic fracturing would be used for well completion on approximately 40 to 55 percent of new production wells and 40 to 62 percent of new injection wells. Acid matrix stimulation would be used for well completion on a few wells per year as well. Well stimulation treatments would also be used on up to 200 existing wells per year.

6 For the purposes of this EIR, injection wells include dedicated steam injection, water injection, and disposal wells. 7 As discussed in EIR Section 7.1, this EIR also does not evaluate high rate gravel packing when it is used to control sand within a well. Gravel (i.e., sand) packing treatments that are performed for well stimulation with the intent of fracturing the formation are covered under the description of hydraulic fracturing and have been incorporated into the hydraulic fracturing projections.

June 2015 7-23 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

 Study Region 5. Up to over 200 new production and injection wells are anticipated to be drilled per year within Study Region 5 over the next 25 years. None of these new wells will be in the Monterey Formation. No well stimulation activities covered in EIR Section 7.4 are anticipated to be used for well completion on these new wells. However, well stimulation is projected to occur over the next five years on up to a few existing wells per year. It should be noted that confidential and exploratory wells have not been reported in Kings County.  Study Region 6. No well stimulation activities covered in EIR Section 7.4 are anticipated in Study Region 6 in the future. Production within Study Region 6 is predominantly dry natural gas. With the declining price of natural gas, there is little exploration nor new production coming online within Study Region 6 at this time.

Projected Future Water Use for Hydraulic Fracturing The future water use for hydraulic fracturing was estimated based on the greatest anticipated number of conventional wells that will be hydraulically fractured in each study region; it is summarized in Table 7.3-4. The estimated water use for exploratory operations, including well stimulation, at a potential well in the Monterey Formation is presented in Table 10.14-5 6 (see EIR Section 10.14, Groundwater Resources). Water use estimates for well drilling in the Monterey Formation are not included in Table 7.3-4, because it is not possible to project the number of wells per year in the formation. The EIR assumes that water use for wells drilled in the Monterey Formation would be much greater than is necessary for conventional wells.

Table 7.3-4. Projected Water Use for Future Hydraulic Fracturing in Conventional Wells Maximum Projected Number of Wells per Range of Water Use per Range of Year for Hydraulic Hydraulic Fracturing Job Projected Water Use Fracturing¹ (acre-feet [AF3])² (AFY) Study Region Oil & Gas Field New Existing Total Minimum Maximum Mean Minimum Maximum Mean 1 Wilmington 20 5 25 0.01 1.87 0.29 0.25 46.75 7.25 Inglewood 6 14 20 0.01 1.87 0.29 0.20 37.40 5.80 2 Other fields 10 14 24 0.01 1.87 0.29 0.24 44.88 6.96 Sespe 4 0 4 0.01 1.87 0.29 0.04 7.48 1.16 3 All fields 0 0 0 0.01 1.87 0.29 0 0 0 4 All fields 1,650 200 1,850 0.01 1.87 0.29 18.50 3,459.50 536.50 5 All fields 0 3 3 0.01 1.87 0.29 0.03 5.61 0.87 6 All fields 0 0 0 0.01 1.87 0.29 0 0 0 1 - Assumptions for the number of wells used for hydraulic fracturing were made based on Industry projections, as follows: Study Region 1, Wilmington Oil and Gas Field New wells: 0 to 20 would be hydraulically fractured annually, maximum assumed. Existing wells: well stimulation would occur on a “limited basis,” five per year assumed. Study Region 1, Inglewood Oil and Gas Field New wells: over 50 production and injection wells drilled per year, 25 percent production wells and no injection wells would be hydraulically fractured. Assumed 25 new production wells. Existing wells: less than 15 wells per year, assumed 14. Study Region 2 New wells: less than 20 production and injection wells drilled per year, hydraulic fracturing on 0 percent to 100 percent of production wells and 0 percent of injection wells. Assumed 10 new production wells, 100 percent hydraulically fractured. Existing wells: less than 15 existing wells per year, assumed 14.

Final EIR 7-24 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Study Region 2, Sespe Oil and Gas Field New wells: a few wells per year would be hydraulically fractured, assumed 4 based on current well drilling application with Los Padres National Forest. Study Region 4 New wells: 3,300 new production, injection and other miscellaneous wells would be drilled per year and 40 percent to 55 percent of new production wells and 40 percent to 62 percent of new injection wells would be hydraulically fractured. Assumed 50 percent of 3,300 wells. Study Region 5 Existing wells: a few wells per year, assumed 3. 2 - Estimated water used based on Interim Well Stimulation Treatment Disclosures for 448 hydraulic fracturing jobs completed between January 7, 2014 and September 30, 2014. The disclosure data were downloaded from the DOGGR website on December 2, 2014. 3 - 1 AF = 7,758 barrels (bbl) 7.4 Oil and Gas Well Stimulation Treatments In California, oil and gas well stimulation treatments may be used during well completion or within weeks or months after a well is put into production in order to keep it economically viable. Hydraulic fracturing, which is one type of well stimulation treatment, is the injection of water, a proppant (usually sand or ceramic beads) and carrier fluids (typically proprietary chemicals designed to enhance recovery yields) into a wellbore over one or two days at pressures sufficient to fracture the reservoir rocks. This increases the flow of hydrocarbons into the wellbore up to several hundred feet from the well. In Cali- fornia, it is typically applied in sandstone, limestone, or dolomite formations. Please refer to EIR Chapter 6 (Overview of California’s Oil and Gas Resources) for a discussion of California’s geology as related to oil and gas production. Other well stimulation techniques place various chemicals into a well to react with wellbore scale or the productive formation to allow increased well production. Well stimulation can be repeated during the well’s productive life. In California, a well is fractured on average one or two times over its productive life, but may have acid treatments on a regular basis. EIR Section 7.3 (Overview of the Lifecycle of an Oil and Gas Well) provides an overview of how a well is developed, including how and when well stimulation occurs during the well completion stage. The timeline of a well outside of an existing oil and gas field prior to production includes exploration (three to five years), planning (12 to 18 months), site and well construction (two to three months), and well completion (one to two days). Producing wells are generally planned for a 20- to 30-year life, but some existing wells in California are over 100 years old. In addition to hydraulic fracturing, as described in EIR Section 7.4.1, the other well stimulation treatments addressed in this section include acid fracturing (EIR Section 7.4.2.1) and acid matrix stimulation (EIR Section 7.4.2.2). The description of hydraulic fracturing provided in EIR Section 7.4.1 encompasses gravel (sand) packing treatments that are performed for well stimulation with the intent of fracturing the formation. 7.4.1 Hydraulic Fracturing Hydraulic fracturing for the stimulation of oil and gas wells was first used in the United States in Kansas in 1947, and a few years later, it was first used commercially. The method was rapidly adopted because of increased well performance and increased yields of oil and gas from relatively impermeable rock units (please refer to EIR Chapter 6 [Overview of California’s Oil and Gas Resources] for a discussion of impermeable formations). It is now used worldwide in tens of thousands of oil and gas wells annually. A traditional formation’s production rate may increase by three to five times when it is hydraulically fractured, and this increase is significantly higher in impermeable formations, such as the Monterey Formation (Halliburton, 2014). Fewer than 25 percent of all wells drilled within the State are hydraulically fractured (Halliburton, 2014). As of May 2014, there are 11 counties where hydraulic fracturing has occurred, including: Colusa,

June 2015 7-25 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Fresno, Glenn, Kern, Kings, Los Angeles, Orange, San Bernardino, Santa Barbara, Sutter, and Ventura. Figure 7.4-1 displays the location of wells in California where hydraulic fracturing was reported to DOGGR in either 2012 or 2013. During this period, 80 to 90 percent of hydraulically fractured wells occurred in Kern County. As noted previously, the depth of wells in California that target traditional oil and gas reservoirs ranges from approximately 500 to 15,000 feet, and the average diameter of a wellbore for a production wells is 4.5 to 8 inches (DOGGR, 2014a). The average true vertical depth (TVD) of wells that were hydraulically fractured in California from February 2011 through 2013 was 2,688 feet, with a TVD range of 890 feet to 14,343 feet and fractures extending tens to hundreds of feet away from the wellbore (DOGGR, 2014a). However, much of the current and planned hydraulic fracturing operations in Cali- fornia occur at depths of less than 1,000 feet below the ground surface (CCST, 2014). Hydraulic fracturing is not part of the drilling process. As noted in in EIR Section 7.1.4, it is a well completion technique applied after the well is drilled, sealed, and perforated to stimulate the well and maximize the extraction of underground resources from the target zone. Initial design of the well takes into consideration whether the well is planned to be hydraulically fractured. After the well is drilled and casing is cemented through the producing interval, perforations are made through the casing with small, specially designed charges to allow hydrocarbon fluid from the producing formation to enter the well (see EIR Section 7.3.4). Once the casing is perforated, and depending on the type of formation and the current state of the wellbore, well stimulation, such as hydraulic fracturing or acid fracturing, may be implemented. In other cases, well stimulation may not be used until months or years after a well’s production has been started. At the request of well owners/operators, service companies perform hydraulic fracturing treatments, often on more than one well at a time within an oil and/or gas field. Service companies design hydraulic fracturing procedures based on the rock properties of the prospective hydrocarbon reservoir. Figure 7.4-2 depicts the general process of hydraulic fracturing. For any given area and formation, hydraulic fracturing is an iterative process. That is, it is continuously being improved and refined as development progresses and more data is collected. Fracturing fluids are tailored to site-specific conditions, such as formation thickness, stress, compressibility, and rigidity. As such, the chemical additives used in a fracture treatment vary. Although most of the oil and gas fields in California are well understood (“mature”), in a new area, the hydraulic fracturing process will begin with computer modeling to simulate various fracturing designs and their effect on the height, length and orientation of the induced fractures. During a hydraulic fracturing treatment, the length of the fractures, which is usually about 200 feet depending on the field and formation, are engineered beforehand based on the existing stresses of the targeted formation, including reservoir parameters and characteristics, rock mechanics, well design, and the location of other existing wells in the field, among other factors. The direction of the fractures will generally be in the same direction as the minimum stress or perpendicular to the direction of maximum pressure. After the procedure is actually performed, the data gathered is used to optimize future treatments. Data to define the extent and orientation of fracturing may be gathered during fracturing treatments by use of microseismic fracture mapping, tilt measurements, tracers, or proppant tagging, which are all highly accurate and will be used to assist future computer modeling.

Final EIR 7-26 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Hydraulically Fractured Wells Figure 7-4 within Active Fields as of May 2014 I EIR Study Region Boundaries Esri, DeLorme, GEBCO, NOAA NGDC, and other contributors County Boundaries 0 50 100 Location of Hydraulically Fractured Wells Counties excluded from SB 4 EIR analysis Miles Within Active Fields in California June� 2015 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT Oil and natural gas flow out of well Injection Natural gas is Vertical Well Flowback and Well* piped to market Oil & Gas Water Chemical Fracturing Produced Water Well Acquisition Mixing Injection (Wastewaters) Waste Disposal

Storage Tanks

Oil and natural gas flow from fissures into well

*The depth of a hydraulically fractured well or traditional well Figure 7.4-2 is formation dependent. On average, injection wells in California are about 5,000 feet deep Hydraulic Fracturing Process Source: Modified from US EPA, 2014.

June 2015 7-5 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

In California, lengths of fractures can range from tens to hundreds of feet. Widths of fractures are a fraction of an inch wide. Available research indicates 1,970 feet is likely the maximum distance for vertical propagation of hydraulic fractures (CCST, 2014). This propagation has occurred in states other than California where fracture lengths are contained within a relatively homogenous rock layer. Fracture lengths are typically much shorter in California due to the layered geological environment and other physical parameters, such as an area’s history of seismic activity and resulting movement of geologic features, shallower depths of well stimulation treatments than in other states, and lower volumes of fracturing fluids injected. For instance, in the South Belridge Oil and Gas Field where most hydraulic fracturing operations are currently occurring, fracture lengths are generally 180 feet vertically to 200 feet horizontally. The vertical extent that a created fracture can propagate is controlled by the upper confining zone or formation, and the volume, rate, and pressure of the fluid that is pumped into the well. The confining zone limits the vertical growth of a fracture because it either possesses sufficient strength or elasticity to contain the pressure of the injected fluids or an insufficient volume of fluid has been pumped (FracFocus, 2014). Although a horizontal well can be much longer than a vertical well in the same formation, the hydraulic fracture completion targets an individual zone; as such, the amount of water, sand, and additives used are the same, stage8 for stage (see EIR Section 7.4.1.2 [Hydraulic Fracturing Activities]). A longer, horizontal well also results in a greater number of stages, which in turn, results in greater water and chemical use than a vertical well. In general, traditional oil and gas resources in California refer to sandstones and potential future resources refer to shales (see EIR Chapter 6 [Overview of California’s Oil and Gas Resources]). Due to the inherent physical attributes of shales, these resources require more pressure for fracture initiation and propagation.

7.4.1.1 Hydraulic Fracturing Site Preparation At the request of a well owner/operator, hydraulic fracturing is performed by a service company that brings all of the necessary equipment onsite, except for water and flowback9 tanks, which are provided by the well owner/operator. All onsite work is performed within an existing well pad. A well pad may contain more than one well that is hydraulically fractured during the same operation. Wells located up to approximately one mile from a central set-up location can be treated via manifolds (pipelines) brought in by the service company. The size of the well pad varies depending on the oil field and local topography; however, well pads in California generally range from one to three acres outside of urban areas and contain one or possibly two wells per pad. In highly developed urban areas, the size of a well pad can range from 8,000 to 16,000 square feet (0.2 to 0.4 acres) per well. Well pads set up for future drilling in the Monterey Forma- tion, are expected to be approximately four acres with three to 10 wells per pad. With the use of deeper wells and horizontal drilling, approximately five to 10 wells could be located within a one square-mile area. Prior to arrival of the service company, site preparation is completed by the owner/operator and may include disassembly (“rig down”) and removal or repositioning of the drilling and other treatment equip-

8 A stage is a segment of the wellbore. 9 Flowback is a water-based solution that flows back to the surface during and after the completion of hydraulic fracturing. The fluid contains clays, chemical additives, dissolved metal ions and total dissolved solids (TDS).

June 2015 7-29 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT ment, delivery of water, and set-up of tanks to capture flowback fluids following the hydraulic fracturing process. The majority of treatments in California are pumped without a drilling rig (“rigless”) down the casing. However, some treatments are pumped down through tubing and require a workover or completion rig for running tubing into and out of the well hole. Site preparation takes one or two days per well, or per well pad if multiple wells are treated during one treatment operation. The service company brings proppant, additives, and fracturing equipment to the site by truck. Exact fracturing equipment varies by service company, but it generally includes pumps, gel hydration unit, blender, monitoring vehicle, crane, manifold10 and treating iron11 trailer, chemical additive trailer/tanker, sand storage, and crew vans. The water and proppant are typically on location for several days prior to the treatment. The acid (if required) and other components used to make the stimulation fluids are handled by the crew performing the actual treatment, and are onsite only for the duration of the treatment (typically one to two days). The exact equipment used varies depending on the service company performing the work. Generally, water used for a hydraulic fracturing treatment is stored in 500-barrel (21,000-gallon) tanks, as discussed in EIR Section 7.4.1.3 (Water and Proppant Use). Proppant is stored primarily in “sand chief” or “sand king” containers with a capacity of 150 tons (300,000 pounds) each. Acid, if applied, is stored in lined transports. Stimulation fluids are mixed during pumping, but the components used in making the fluids are stored in portable totes, buckets, and super sacks onsite. Additional onsite equipment is discussed further in EIR Section 7.1.7 (Equipment and Well Site Plan). Figure 7.4-3 shows a typical existing hydraulic fracturing operation in California and the location of the fracturing equipment on the well site. Figure 7.4-4 shows a typical hydraulic fracturing operation into the Monterey Formation.

7.4.1.2 Hydraulic Fracturing Activities There are several steps during the hydraulic fracturing process that together make up one “stage.” The fracturing treatments are delivered, one section or “stage” at a time, starting at the deepest extent in a vertical well, or at the farthest end of a horizontal well, and then working back towards the top of the producing zone, or where a directional well curves from horizontal to vertical (e.g., a well’s “heel”) and the entire horizontal length of the well has been fractured. Stages are not completed simultaneously, and the length of each well section fractured varies, but is typically from one hundred feet to several hundred feet in length. After each stage is complete, the pressure in the well is reduced, and the downhole equipment is moved along the wellbore to set up the next stage. When ready, the well pressure is increased again for the next stage. A cement or cast iron bridge plug is put in place between each stage to keep the well from producing until each stage has been fractured. In California, a typical hydraulic fracturing “job” contains one to five stages, but there may be up to 20 stages, especially during exploration of the Monterey Formation. Each stage takes between 30 to 60 minutes. For a typical job, the total on location time is approximately 16 hours. This includes two to four hours each for both setting up and disassembling the rig, two to four hours for pumping (20 minutes to one hour per stage), and the remaining time for a crew to set bridge plugs and perforate prior to each

10 A manifold is a wide pipe, or channel, into which, or from which, smaller pipes or channels lead. 11 Treating iron is the temporary surface piping, valves and manifolds necessary to deliver a fluid treatment to the wellbore from the mixing and pumping equipment.

Final EIR 7-30 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Figure 7.4-3 Example Hydraulic Fracturing Operations in California

June 2015 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Figure 7.4-4 Typical Hydraulic Fracturing Operations at a Monterey Formation Exploration Site

June 2015 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT stage. Pumping is the loudest activity during the hydraulic fracturing process and the output noise is typically about 107 decibels (dB) in between the pumps. Depending on the size of the well pad, the noise attenuates to 80 to 90 dB at the edge of the site. The service companies have hearing protection plans in place for the crew, including use of noise cancelling headphones during pumping. Table 7.4-1 lists the steps after site preparation that are conducted during a hydraulic fracturing stage, including the estimated duration of each. Each step is also described in greater detail below. At the conclusion of all stages, the plugs are removed or drilled out, and fluids begin to flow out of the well in a process known as “flowback.”

Table 7.4-1. Hydraulic Fracturing Treatment Steps Step / Treatment Compound Purpose Duration 1 Acid Treatment* Hydrochloric acid (HCl) (diluted with Cleans out wellbore and perforation 3 minutes to water to a 15 percent acid solution) holes; dissolves carbonate minerals 1 hour and extra cement (if performed) 2 Pad (fluid without Water plus additives Opens fissures in the formation 2 to 30 minutes proppant) 3 Proppant Water and progressively coarser natural Holds open the new fissures 30 minutes to 2 or synthetic (ceramic) sand plus additives hours depending on volume 4 Flushing Water Flushes excess proppant back up the 2 minutes to well 1 hour 5 Flowback Fracturing fluid then oil/gas over time Removes fracturing fluid and begins 3 to 14 days pumping of oil/gas Source: DOGGR, 2014; Halliburton, 2014; Schlumberger, 2014; Baker Hughes, 2014. * The Acid Treatment step is not generally used in California. Its use depends on the well and formation being treated. During a standard hydraulic fracturing operation, there are up to approximately eight to 15 employees on each shift and usually no more than one shift is needed per day. Additional personnel from the owner/ operator may be onsite to observe and run ancillary equipment, as necessary. The flowback of a well is the responsibility of the owner/operator, not the service company. At the conclusion of the final flush stage, the fracturing crew bleeds the pressure off of the treatment lines, break down and remove their equipment, and leave the site. The pumping pressure is modeled and monitored on the well’s annulus.12 Monitoring of the annulus pressure is key to assess the condition and integrity of the well tubulars and to detect downhole problems. If the pressure rises above pre-set pressure limits, or in the event of an unexpected spike in pressure, operations automatically shut down. Likewise, in the event of an emergency or a leak on the surface, operations are immediately shut down.

Step 1: Acid Treatment Acid treatment is based on the characteristics of a well and the targeted formation and not generally performed in California, because formations receptive to acid treatment, such as carbonate reservoirs, are rare in California. In an acid treatment, the sealed wellbore may first be cleaned out with water mixed with a dilute acid, such as hydrochloric acid (HCl), to dissolve carbonates or cement debris. The acid treat-

12 The annulus of a well is defined as any void between any piping, tubing or casing and the piping, tubing, or casing immediately surrounding it, such as the void between the drill string and the surrounding formation. The annular void forms the principal barriers between the produced oil and gas and its surroundings, thus providing pressure containment.

June 2015 7-33 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT ment provides an open conduit for other hydraulic fracturing fluids by dissolving carbonate minerals and opening fractures near the wellbore. The volume of acid used is low, typically up to 15 percent HCl, or a “mud acid” combination of up to 12 percent HCl and 3 percent hydrofluoric acid (HF). The HCl is spent (used up) within inches of the fracture entry point and yields calcium chloride, water and a small amount of carbon dioxide (CO2). No acid returns to the surface, because the spent acid remains in the targeted formation and becomes inert. Reacted acid mixes with the formation water and other fluids injected into the well and is managed as part of flowback fluids and produced waters. However, this reacted acid may still exhibit a characteristic of a hazardous waste (in the event, for example, that fluorides are present in excess of the hazardous waste regulatory threshold). When acid treatment is performed, typical volumes of diluted 15 percent HCl are approximately 2,500 gallons per stage.

Step 2: Fluid without Proppant (Pad) In general, 20 to 30 percent of total fluid in a hydraulic job is “pad” (fluid without proppant). The amount of fluid is dependent on the formation, the fracture design lengths, and depth of the well. For each stage, approximately 1,260 to 25,000 gallons (30 to 600 barrels) of pad at 25 to 30 bpm is then injected at high pressure to create fissures, or fractures, in the formation rock. This step helps initiate and then propagate the fractures and assist with the placement of proppant material within the fracture. Seismic receivers or geophones are placed within a nearby well or wells at a depth within the range of the treatment’s depth to measure any microseismic events that may occur during the fracturing of the rocks. Microseismic monitoring can detect the small slippages or microseisms induced in natural fractures, bedding planes, faults, and other weak features in the reservoir formation; it additionally helps with the tracking of the fracture location and any interaction with existing natural fractures and other geologic features.

Step 3: Proppant Proppant consists of small granular solids such as sands and ceramic beads. In this step, proppant is pumped into the well with water to hold the new fractures open. This step can collectively use 80,000 to over 200,000 gallons of water and 200 to 500 tons of proppant, and is pumped into the well at an average slurry rate of 20 to 45 bpm. These proppant-filled fractures allow oil and gas to flow from reservoir formations that are otherwise too “tight” to allow flow. If proppant does not enter a new fracture, then the pressure of the overlying rocks forces the fracture to close once the pressure applied from the pumped fluid is stopped, typically in less than one hour. The particle size of the proppant material varies is generally uniform, but may also vary from fine to coarse throughout this sequence, and proppant concentrations vary during the treatment, starting with low concentrations and finer particle size and then increasing to higher concentrations and coarser particles size. Ninety percent of the proppant pumped is between a 10 to 40 mesh size (0.4 to 2.0 millimeters). The service company will track how much proppant material is needed, how much has already been pumped and how much remains on location. For this step, water is mixed with a polymer, such as guar gum powder, as well as non-emulsifiers and other agents to increase the water’s viscosity to approximately 10 to 40 centipoise (cp). For comparison, water viscosity is one cp. When the mixed water is ready to pump into the well, the water and polymer blend, referred to as the “base gel,” is blended further with a liquid additive that binds the polymer chains in the base gel thereby further increasing the viscosity to several thousand cp, which aids in the suspension of the solids (e.g., the proppant). This process is referred to as “cross-linking” the base gel.

Final EIR 7-34 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

The cross-linked gel is mixed with the proppant and pumped into the well as slurry13 in the next step (see Step 3 below). Approximately 1,000 gallons of water is added per one to two gallons of the chemical polymer mix. Use of a chemical polymer with proppant is preferred in California to use of “slickwater,”14 due to the soft nature of the State’s geologic formations, which require the placement of proppant to retain fracture width following treatment. Additives are calculated based on clean fluid volume (i.e., without additives or proppant). Therefore, once proppant is added to the fluid, compensations are made to the additive rates to account for the amount of proppant in the slurry. Proppant concentrations on the surface may be measured with densi- tometers, which contain a radiation source. However, evaluation of microseismic events, as discussed above, is now the more common method for determining the geometry of the fractures created during a treatment.

Step 4: Flushing During Step 4 (Flushing), approximately 65 to 300 barrels (2,730 to 12,600 gallons) of fresh water or brine is used per stage to flush out the excess proppant from the wellbore over a period of a few minutes or up to one hour.

Step 5: Flowback Flowback is the process by which the well operator brings the fluids from the hydraulic fracturing treatment (fracturing fluids), as well as the fluids from the reservoir formation, to the surface. At the conclusion of all stages, the service company slowly reduces (i.e., “bleeds”) the pressure off of the treating lines and disassembles its equipment, and the owner/operator takes control of the well head/flowback system. Usually within a day or so, the well plugs are drilled out by the owner/operator, well pressure is released, and “flowback” fluids rise up through the wellbore to the surface. Equipment (including pipes, manifolds, a gas-water separator and tanks) is connected to the “frac tree” and this portion of the flowback system is pressure tested prior to commencing with flowback by the owner/operator. Some of the fluid used for hydraulic fracturing heats within the targeted formation by natural processes, thereby becoming less viscous and allowing them to flow more readily back up the well to the surface where it is recovered. Naturally occurring enzymes and/or oxidative breakers, such as diammonium perox- idisulphate, are often used to “break” the long polymer chain and return the “cross-linked” guar polymer gel to a lower viscosity (similar to water) so that it can be recovered more easily. The enzymes and/or oxidative breakers are mixed at one gallon per 1,000 gallons of base fluid (usually water with potassium chloride [KCl]).15 With injectors, the intent is to have the broken gel flow with the injectant (water or steam), leaving the proppant in place. Approximately 15 to 80 percent of the fracturing fluid typically flows back up the well over the course of three to 12 days (Baker Hughes, 2014; Halliburton, 2014). Remaining fracturing fluid that does not flow back immediately is recovered from the well along with oil, gas and produced water slowly over time.

13 For hydraulic fracturing operations, the “slurry” is a semi-liquid mixture of water, proppant and chemical additives. 14 “Slickwater” as used in slickwater fracturing is water with chemical additives used to reduce friction and increase fluid flow. Slickwater may be pumped into the wellbore at up to 100 barrels per minute. 15 As defined by SB 4, “base fluid” means “the continuous phase fluid used in the makeup of a well stimulation treatment fluid, including, but not limited to, an acid stimulation treatment fluid or a hydraulic fracturing fluid. The continuous phase fluid may include, but is not limited to, water, and may be a liquid or a hydrocarbon or nonhydrocarbon gas. A well stimulation treatment may use more than one base fluid.”

June 2015 7-35 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

The goal of a hydraulic fracture treatment is to leave the proppant inside the fractures and flow back as much of the other products as possible. At first, most of the flowback is made up of the fracturing fluid, but eventually, more and more of the flowback is made up of oil and/or gas along with produced water. The composition and amount of flowback recovered depends on the characteristics of the targeted formation and the specific fluid used for hydraulic fracturing job. Typical components that may be found in flowback fluid include:  Dissolved solids (chlorides, sulfates, and calcium);  Metals (calcium, magnesium, barium, strontium);  Suspended solids;  Mineral scales (calcium carbonate and barium sulfate);  Bacteria (acid producing bacteria and sulfate reducing bacteria);  Friction reducers;16  Iron solids (iron oxide and iron sulfide);  Dispersed clay fines, colloids & silts; and  Acid gases (carbon dioxide, hydrogen sulfide). Flowback fluids are either temporarily stored in tanks onsite, or flowed directly into a production pipeline where hydrocarbons and produced water are subsequently separated at a processing facility. These and other disposal methods of flowback fluid and wastewater are discussed in EIR Section 7.4.1.6 (Wastewater and Solid Waste Disposal). At some point, the water that is recovered from a well makes a transition from flowback water to produced water as the well enters its production phase. This transition point can be hard to discern, but it sometimes is identified according to the well’s rate of return and/or by looking at the water’s chemical composition using water quality testing. Flowback water produces a higher flow rate over a shorter period of time in comparison to produced water, and is typically greater than 50 barrels per day (bpd). Pro- duced water produces lower flow over a much longer period of time, typically from two to 40 bpd. The chemical composition of flowback and produced water is very similar; consequently a detailed chemical analysis is needed to distinguish the transition between flowback and produced water (IEER, 2014).

7.4.1.3 Water and Proppant Use Water and proppants make up approximately 99.5 percent of the fluid used in hydraulic fracturing. Of that, in California, 75 percent is typically water and 25 percent is typically sand. This proportion of water is based on the targeted formation and is much less than used elsewhere in the United States for hydraulic fracturing stimulation treatments. Much of the water and sand used remains in the hydrocarbon formation and is recovered slowly over time during production. The portion that flows back out of the well is typically either transported to water treatment facilities for recycling with produced water, or otherwise disposed of as further described in EIR Section 7.4.1.6 (Wastewater Disposal). Water. Water is provided by the well owner/operator and is typically supplied by groundwater wells or municipal water sources. While well operators and their contractors can use recycled produced water, most water used in hydraulic fracturing operations in California is from fresh surface or subsurface supplies.

16 Friction reducers are typically high-molecular weight polymers of acrylamide in an oil external emulsion. They can be partially hydrolyzed and react with other chemicals to yield anionic or cationic products. They function to reduce friction pressures in all types of fluids from acids to hydrocarbons. They allow fracturing fluids and proppant to be pumped to the target zone at a higher rate and reduced pressure than if water alone were used.

Final EIR 7-36 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

If not available via pipeline, water is transported to the treatment site by contractors in 4,000- to 5,000- gallon tanker style tractor trailer units. Approximately 50 to 63 round trip trucks trips are required over several days prior to the hydraulic fracturing treatment to deliver up to 250,000 gallons (almost 6,000 barrels) of water. This water estimate is a maximum quantity; average water use for current hydraulic fracturing treatments in California is approximately 130,000 gallons per well (CCST, 2014). At the well site, water is commonly stored in 500-barrel (21,000-gallon) laydown tanks. If space is constrained at the site, 400-barrel upright tanks may be used instead. Based on two exploratory case studies, approximately 15 to 30 acre-feet (approximately five to 10 million gallons) of water is typically required for both exploratory drilling and hydraulic fracturing stimulation of one well in the Monterey Formation (five to 10 acre-feet for drilling and 10 to 20 acre-feet of water for hydraulic fracturing). If not available via pipeline, approximately 1,000 to 2,500 round-trip truck trips would be required to deliver water to the site for drilling and stimulation. To minimize the use of water during a hydraulic fracturing job, produced water may be reused if the flowback is treated and the chemicals are removed. Similarly, but depending on the fluid components being used, saline (salty) groundwater can also be used in place of freshwater. Proppant. The quality of the proppant has a direct impact on the conductivity of the fracture. In Cali- fornia proppant consists of one of the following: (1) silica sand, which is a white-colored sand when mined from the Midwest, and a darker colored sand when mined from Texas and Arizona, but both are of a similar quality; (2) sands coated with resin, which increases the sand’s strength and causes it to bond with itself and not flow back as readily; or (3) manmade sands, which are made of lightweight ceramics or fired bauxite ore. Manmade proppant has high strength, is hard, and is perfectly round; it additionally has the highest conductivity per pound, but it is expensive and rare in California. The service companies in California generally receive sand in bulk on railcars (approximately 100 tons per rail car) from Texas, Wisconsin and Arizona at facilities in Bakersfield. From there, the sand is delivered to the well site by truck. Each truck is able to haul approximately 25 tons (50,000 pounds [lbs]) of proppant, resulting in approximately eight to 20 round-trip truck trips to the well site to deliver 200 to 500 tons of proppant. The 2,500-cubic-foot sand storage units at the well site each hold 150 tons (300,000 lbs) of proppant.

7.4.1.4 Stimulation Fluid and Chemical Additives Chemical additives used in the stimulation fluid consist of a blend of common chemicals that increase water viscosity, help extend the fracture, and suspend/transport the proppant and water mixture farther out into the fractures. Additives also control bacterial growth, minimize swelling of clay particles in the formation, and inhibit corrosion to help maintain the integrity of the well. Additives include gels, foams, and other compounds. These other liquid and solid additives that may be incorporated in the fracturing fluid consist of the following: surfactants, a soap-like product designed to enhance water recovery; friction reducers; biocides to prevent microorganism growth; oxygen scavengers and other stabilizers to prevent corrosion of metal pipes; and acids to remove drilling mud damage (Cardno ENTRIX, 2012). Table 7.4-2 lists the typical fluids used in hydraulic fracturing. Typically no more than three to eight chemical products are present at one time at any given site, and unused products are removed from the site by the service company when the operation is complete.

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Table 7.4-2. Typical Fracturing Fluid Additives Additive Type Typical Main Compound Purpose Activator EDTA/Copper Chelate Agent used to degrade viscosity Biocide Propionamide Prevents or limits growth of bacteria Breaker Sodium Persulfate Agent used to degrade viscosity Ammonium Persulfate Crosslinker Borate Developing viscosity Gel Polysaccharide Gelling agent for developing viscosity Naphtha hydrotreated heavy Clay Control Potassium Chloride (KCl) Clay-stabilization additive which helps prevent clay Alkylated quaternary Chloride particles from migrating in water-sensitive formations Acid/base (pH) Adjusting Agent Acetic Acid Adjusts pH to proper range for fluid Potassium Carbonate Sodium Hydroxide Proppant Silica Holds open fracture to allow oil and gas to flow to well Surfactant Ethanol Aids in recovery of water used during fracturing Water Water Base fluid creates fractures and carries proppant, also can be present in some additives Source: Halliburton, 2014. Of the chemicals reported for well stimulation treatments in California for which toxicity information is available (compiled from the voluntary industry database, FracFocus), most are considered to be of low toxicity or non-toxic. However, a few reported chemicals present concerns for acute toxicity. These include biocides (e.g., tetrakis [hydroxymethyl] phosphonium sulfate; 2,2-dibromo-3-nitrilopropionamide; and glutaraldehyde), corrosion inhibitors (e.g., propargyl alcohol), and mineral acids (e.g., hydrofluoric acid and hydrochloric acid). Potential risks posed by chronic exposure to most chemicals used in well stimulation treatments are unknown at this time. A list of chemicals used for hydraulic fracturing was developed from disclosures in FracFocus. These data are not required to be either complete or accurate (CCST, 2014). Information on acute oral toxicity was available for some of these chemicals. This toxicological assessment is limited, because it considers only oral toxicity as an indicator of potential impacts to human health, and does not consider other effects such as biological responses to acute and chronic exposure to many of the stimulation chemicals, eco-toxicological effects of fluid constituents, overall toxicological effects of fluids as a mixture of compounds (compared to single-chemical exposure), and potential time- dependent changes in toxicological impacts of fluid constituents, due to their potential degradation or transformations in the environment. Thus, the Independent Review of Scientific and Technical Informa- tion on Well Stimulation Technologies in California, prepared by the California Council on Science and Technology, concluded that further review of the constituents of injection fluids used in well stimulation jobs in California is needed, which additionally considers information that is now required to be submitted to DOGGR by operators, and some of the above mentioned toxicological effects (CCST, 2014). As discussed in EIR Section 7.4.1.2 (Hydraulic Fracturing Activities, Step 5: Flowback), some of the additives are recovered in the water that flows back after the hydraulic fracture (15 to 80 percent, depending on the specific treatment job), and the remainder is recovered once the oil well is brought into production.

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The hydraulic fracturing product additives that may be used for fracturing the Monterey Formation in the future would likely contain chemical constituents similar to the types of products that have been used to date for the hydraulic fracturing of traditional oil and gas reservoirs in California.

7.4.1.5 On-Site Storage and Handling of Hydraulic Fracturing Additives In addition to water and proppant storage, the major storage containers at any given site during the period of time between delivery and completion of continuous fracturing operations typically consist of all or some of the following:  Stainless steel vessels or plastic poly totes encased in metal cages, ranging in volume from 220 gallons to 375 gallons, which are strapped on to flatbed trucks pursuant to federal and State regulations;  Tank trucks;  Palletized 50 to 55 gallon bags, made of coated paper or plastic (40 bags per pallet, shrink-wrapped as a unit and then wrapped again in plastic);  One-gallon jugs with perforated sealed twist lids stored inside boxes on the flat-bed; and  Smaller double-bag systems stored inside boxes on the blending unit. At the well site, the tote tanks on a flatbed trailer are used to store the stimulation fluid, which is blended by a “frac blender” before being pumped into the wellhead. These chemical storage trucks hold the chemical additives before they are mixed into the stimulation fluids. All hazardous materials, including diesel fuel, are stored and managed according to current State and local regulations, as discussed in EIR Section 7.3.3 for drilling operations. Material Safety Data Sheets are also on site to ensure materials are used and handled properly. The duration of materials that are stored onsite is generally less than a week for economic and logistical reasons; materials are not typically delivered to the site until fracturing operations are set to commence, and only the amount of material needed for scheduled continuous fracturing operations is delivered at any one time. When the hydraulic fracturing operation commences, hoses are used to transfer liquid additives from storage containers to a truck-mounted blending unit. The flatbed trucks that deliver plastic or stainless steel totes to the site may be equipped with their own pumping systems for transferring the liquid additive to the blending unit when fracturing operations are in progress. Flat-beds that do not have their own pumps rely on pumps attached to the blending unit. Additives delivered in tank trucks are pumped to the blending unit or the well directly from the tank truck. Dry additives are poured by hand into a feeder system on the blending unit. The blended fracturing solution is not be stored, but is immediately mixed with proppant and pumped into the cased and cemented wellbore. This process is conducted and monitored by qualified personnel from the service company, and devices such as manual valves provide additional controls when liquids are transferred. Lined containments and protective barriers are used where chemicals are stored and blending takes place. The storage and blending equipment are engineered to prevent spills. Hose covers and drip trays are also used for containment and as protective barriers during the transfer of materials. The hoses are checked and replaced annually, and workers wear face shields, helmets, goggles and chemical resistant suits when handling acids. Because the fluid is not pre-mixed, there is a low probability of any residual hydraulic fracturing fluid left over following operations. However, in those instances when there is remaining hydraulic fluid, it is

June 2015 7-39 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT placed in the same storage tanks that collect the flowback fluid, and is disposed of in a similar manner as the flowback fluid, which is described below. Pursuant to Section 1786(a)(8) of the permanent regulations, an operator that generates a waste shall determine if the waste is a hazardous waste. Products used during the well stimulation activities that are no longer needed and will not be used for their intended purpose are wastes. If the waste meets the regulatory criteria of a hazardous waste, it would have to be managed in accordance with California’s hazardous waste control laws.

7.4.1.6 Wastewater and Solid Waste Disposal

Wastewater Disposal Flowback and produced water, collectively known as wastewater, is typically handled in the following ways: (1) injected (with or without treatment) into water disposal/enhanced recovery wells; or (2) recycled (with or without treatment) for use in future oil and gas operations, including hydraulic fracturing or injection into the target hydrocarbon formation. Additionally, some produced water is permitted to be recycled for irrigation and livestock watering (CCST, 2014). Wastewater may also be trucked or piped to an offsite private or municipal wastewater treatment plant, but this method is rarely used because it is more costly. Flowback water and produced water are not permitted by the State Water Resources Control Board to be discharged into surface waters unless the water is treated to the point where all contaminants are removed and the salinity level is made to be compatible with the receiving waters. Currently, the cost of treatment is very high in comparison to other disposal methods and therefore, in practice, chemical treatment in waste handling systems followed by disposal into surface water does not occur. Disposal methods are described in more detail below. Wastewater Injection. Currently and in the past, injection into underground reservoirs via disposal wells is used the majority of the time. Close to 42,000 oil and gas field injection wells are operating in the State for waterflood, steamflood, cyclic steam, and water disposal (DOGGR, 2014d). According to the U.S. Environmental Protection Agency (EPA) regulations, produced water injection wells are classified as Class II wells, and subdivided into II-R wells for enhanced recovery17 and II-D wells for disposal. In Cali- fornia, the operation of all Class II injection wells are regulated by DOGGR, under provisions of CCR Sec- tions 1724.6, 1724.7, 1724.9 and 1724.10, and the federal Safe Drinking Water Act. Under a 1983 Primacy Agreement with the EPA, DOGGR received primary authority and primacy to regulate Class II underground injection in California. Class II injection wells also fall under the DOGGR's Underground Injection Control (UIC) program, which is monitored and audited by the EPA. Based on a 2010 audit by the EPA and other concerns identified by industry and DOGGR staff, DOGGR is working with the EPA and expected to begin a rulemaking process in early 2015 that will revise the UIC program. The main features of DOGGR’s UIC program include permitting, inspection, enforcement, mechanical integrity testing, plugging and abandonment oversight, data management, and public outreach (DOGGR, 2014d). Prior to well injection, an application is submitted by an owner/operator for UIC project approval and individual well approval to DOGGR. The application includes an analysis of the locations of existing wells, wells that have plugged and abandoned, and the geology of the area to ensure that the water will be confined and maintained within the intended zone and there is no conduit for the injected

17 Enhanced recovery increases the amount of oil that can be extracted and extends a field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore. Thermal recovery, which is one method that is common in California, involves the introduction of heat such as the injection of steam to lower the viscosity, or thin, the oil, and improve its ability to flow through the reservoir.

Final EIR 7-40 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT water to leave the zone. DOGGR also requires a step rate test to determine at what pressure the formation would fracture to ensure that the pumping rate will remain below a formation’s fracture pressure. An injection zone is usually sandstone, which is a rock porous and permeable enough to accept injected fluids. Rock beds chosen for injection zones are covered by impermeable beds, like shale, that act as cap rocks and confine injected liquids in the porous beds. Current State and federal regulations allow nonhazardous fluids produced from oil and gas wells, and several other nonhazardous fluids associated with the production process, to be injected into a Class II well. These other fluids include diatomaceous earth- filter backwash, thermally enhanced oil recovery cogeneration plant fluid, water-softener regeneration brine, air scrubber waste, drilling mud filtrate, naturally occurring radioactive materials (NORM), slurrified crude-oil, saturated soils, and tank bottoms. NORM is naturally present in rocks as uranium, thorium, their radioactive progeny, and potassium. The more soluble materials (i.e., radium and its progeny) are dissolved selectively in groundwater. The degree of dissolution depends on water chemistry. The majority of the less soluble materials, such as uranium and thorium, remain in the rocks. In oil and gas fields, NORM may occur as radioactive material that has been concentrated through the production process. Pipe scale (hardened salts precipitated on the surfaces of pipes used for oil and gas extraction), residue, and sludge are areas where NORM can be found. NORM can be brought to the surface in produced water (DOGGR, 1996). In 1987, the California oil and gas industry conducted a statewide survey of production facilities to determine the extent of NORM. Of the 10,000 measurements taken using external gamma radiation meter readings, about 93 percent were at background levels. The remaining readings were above background levels, but low enough that only routine safety measures were considered necessary to minimize employee exposure and protect human health and the environment. In 1993, California underwent a peer review of its oil and gas exploration and production waste-management regulatory programs. The review was coordinated by the Interstate Oil and Gas Compact Commission, in cooperation with the EPA and other interested groups. One recommendation of the review team called for a thorough evaluation of the industry NORM survey data by the appropriate State agencies to verify the extent of oil and gas field NORM in California (DOGGR, 1996). As a result, DOGGR and the Department of Health Services, Radiologic Health Branch, conducted a more comprehensive survey of selected sites at 70 oil and gas fields in cooperation with the oil and gas industry. The sites chosen for the study were not random. All six of DOGGR’s districts were sampled and they were selected because the sites were points where NORM was expected to occur. The results of the study confirmed the 1987 study and concluded that NORM is not a serious problem in California’s oil and gas producing operations (DOGGR, 1996). Seventy-eight (78) percent of the measurements were at background levels; however, a few sites did have elevated NORM. Radiation protection programs were recommended at certain oil and gas fields to prevent unnecessary exposure to workers, to control possible spread of NORM contamination, and to minimize potential health impacts to workers during cleanup and decommissioning activities (DOGGR, 1996). Although NORM may be present in produced water during conventional oil and gas operations, there is no information about radioactive element concentrations in flowback or produced waters from stimulation operations in California (CCST, 2014). Section 1788 of DOGGR’s proposed permanent regulations requires public disclosure of the radioactivity of the of the recovered well stimulation fluids. NORM is addressed in further detail in EIR Section 10.13 (Hazards and Hazardous Materials). Wastewater Recycling. Another wastewater disposal method used less frequently is recycling of wastewater. Wastewater may be treated prior to reuse or simply blended with fresh water to bring the levels

June 2015 7-41 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT of total dissolved solids and other constituents down to an acceptable range (CCST, 2014). It may be used in oil and gas operations, including well stimulation treatments or injection into the target hydrocarbon formation, or for other purposes, such as irrigation, livestock watering, and some industrial uses. Recycling flowback and produced water reduces the total annual output of wastewater, but ultimately the recycled wastewater will need to be properly disposed of as well. Wastewater Surface Disposal. Finally, one other method of disposal has been used: surface disposal into unlined evaporation/percolation ponds (sumps). Current management practices in California allow for the disposal of produced water, including co-mingled well stimulation fluids, into unlined pits if the electrical conductivity (EC) is less than or equal to 1,000 micromhos per centimeter (μmhos/cm), chloride concentration is less than or equal to 200 milligrams per liter (mg/l), and boron concentration is less than or equal to 1 mg/l, with no testing required for, or limits on, other contaminants (CCST, 2014). Although unlined ponds may currently be used to collect produced water, DOGGR’s interim regulatory requirements prohibit the disposal of fracturing fluids in any unlined sump. This mandate is fully expected to bewas carried forward into DOGGR’s proposed permanent regulations. If soTherefore, no sumps or pits would be allowed for use during hydraulic fracturing operations in the future. As these units are phased out, the operator will need to test the sumps to determine if they exhibit a characteristic of a hazardous waste and appropriately dispose of materials removed from the site. Future Methods of Wastewater Disposal. It is difficult to project which methods will be used for wastewater disposal in the future, but based on available information, it is projected that injection into disposal wells would remain the primary method of disposal. Sumps would not be allowed for the disposal of fracturing fluids. However, it is also predicted that more wastewater would also likely be recycled. Wastewater recycling is expected to increase due to an increase in the use of recycled water for well stimulation treatments, and as a result of MM GW-1a (Use Alternative Water Sources [such as recycled water or saline water] to the Extent Feasible), as required by the Water Recycling Standards that would be implemented as part of the project. The Water Recycling Standards, which are described in EIR Section 7.5.1, would apply outside of existing oil and gas fields and at new wells within existing fields. Based on the results of a feasibility study on the use of recycled water (including reusing the flowback and produced water), the well owner/operator/ service provider shall be required, through conditions of permit approval, to use recycled or saline water to the maximum extent feasible, as determined by DOGGR.

Solid Waste Disposal Solid waste generated during hydraulic fracturing activities would be minimal since the majority of proppant would remain in the formation. The 2008 Baldwin Hills Community Standards District Final EIR reported that 3.8 tons of non-hazardous oil debris, including drill cuttings, was generated weekly by the Inglewood Oil and Gas Field (Los Angeles County, 2008). At the time of that analysis in 2006, there were 436 active producing wells drilled from within the active surface boundary at the Inglewood Oil and Gas Field, 207 active water injection wells, 177 shut-in wells, 643 abandoned wells for a total of 1,463 wells within the current surface lease boundary of the oil field (Los Angeles County, 2008). During drilling operations, drill “cuttings” are the rock chips and fine-grained rock fragments removed by the drilling process and returned to the surface in the drilling fluid. The volume of drill cuttings is generally based on the volume of the cylinder of the well minus any cuttings that may dissolve. Therefore, the total volume of drill cuttings produced from a hydraulically fractured well in the Monterey Forma-

Final EIR 7-42 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT tion would be greater than for typical, existing wells based on the depth and size of the well. During drilling, cuttings go into the mud tank and then into a shaker to filter out bigger rocks. From there they are stockpiled or stored in portable tanks or drums prior to testing for hazardous constituents, and then disposed of either on the site or trucked offsite. Additionally, solid waste is generated by oil field employees and general operations. Typically, 200 employees may generate 8 tons of solid waste per week (Los Angeles County, 2008). Non-hazardous waste would be hauled offsite by the service company or the owner/operator at the completion of hydraulic fracturing operations to the nearest permitted landfill or recycling facility. Although not expected, any hazardous solid waste materials would be handled and disposed of by a licensed waste disposal contractor and transported to an appropriate disposal or recycling facility to meet federal, State, and local requirements.

7.4.1.7 Equipment Required Table 7.4-3 lists the equipment used on a typical onshore or offshore hydraulic fracturing job in Cali- fornia and the estimated duration of its use. The duration of use may be longer for well stimulation in the Monterey Formation. Aside from water and proppant (sand) delivery, each vehicle is assumed to have one round trip to the site. However, for a multi-day operation, pickup trucks, vans, or personal vehicles typically deliver the crew to the site each day.

Table 7.4-3. Equipment Required for Existing Hydraulic Fracturing Activities Duration of Use Equipment Activity Number (days) Control Van Fluid Quality and Data Monitoring* 2 1 or 2 Pump Truck Pumping 4 1 or 2 Flatbed Chemical Storage (holds approximately 1 1 or 2 10 tote tanks) Manifold/Treating Iron Trailer Hauls Pipes 1 1 or 2 Tanker/Mixer (5,000 gallon) Gel Storage and Hydration Unit 1 1 or 2 Blender Blend Fluid and Proppant 1 1 or 2 Crane Lifting Heavy Equipment 1 1 or 2 Sand Chief (150 ton capacity) Sand Storage 1 to 4 5 to 7 days Pickup Truck or Van People/Tools Transport 2 1 or 2 Water Tanks (500 barrel laydown tanks or Water Storage 8 to 15 5 to 7 days 400 barrel upright tanks) Water Trucks (4,000 or 5,000 gallon) Supplies Water ~50 to 63 Prior to hydraulic (if not available via pipeline) round trips** fracturing activities Sand Trucks (25 ton capacity) Hauls Sand 8 to 20 Prior to hydraulic round trips fracturing activities Source: DOGGR, 2014; Halliburton, 2014; Schlumberger, 2014; Baker Hughes, 2014. * Workers in the monitoring van include individual personnel responsible for: (1) status of equipment; (2) monitoring blending; (3) engineering; (4) quality control of the fluid being pumped; and (5) observation (from the operator company). ** Approximately five to 10 million gallons of water is typically required for both exploratory drilling and hydraulic fracturing stimulation of the Monterey Formation, which would result in 1,000 to 2,5000 round-trip truck trips to deliver water to the site.

June 2015 7-43 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

The equipment required for well stimulation treatments in the Monterey Formation would be generally similar, but would be used for a longer duration. During exploratory drilling and well stimulation treatments in the Monterey Formation, a much greater volume of water would be required per well. As discussed in EIR Section 7.4.1.3 (Water and Proppant Use), five to 10 million gallons would be used, which would result in 1,000 to 2,000 2,500 round-trip truck trips to deliver water to the site for drilling and stimulation, and up to 477 water tanks would be needed for storage (the tanks would be refilled so the number of tanks onsite would be less). In addition, the total drilling operation (site preparation, drilling and testing) could take as much as six months to complete. Fracturing additives are transported typically in flat-bed trucks that carry a number of various strapped- on plastic or stainless steel totes which contain the liquid additive products. Liquid products used in smaller quantities are typically transported in one-gallon sealed jugs carried in the side boxes of the flatbed. Some liquid constituents, such as raw hydrochloric acid, are transferred in tank trucks that are lined and vented. Dry additives are transported on flat-bed bulk style tractor trailer units in 50- or 55-pound bags which are set on pallets containing 40 bags each and shrink-wrapped, or in five-gallon sealed plastic buckets. When smaller quantities of some dry products, such as powdered biocides, are used, they are contained in a double-bag system and may be transported in the side boxes of the truck that constitutes the blender unit. Hazardous materials are transported in accordance with State and federal regulations. The number of pumps used on any given job varies and is dependent primarily on the rate and pressure required for the treatment. In general, the same pumps are used for each of the treatment steps. The pumps generally range from 2,000 to 2,700 hydraulic horsepower (HHP) units and are able to pump up to 15,000 pounds per square inch (psi). Average dimensions of a 2,250 HHP pump and the fracturing and acid blenders, which are currently the largest features in use during hydraulic fracturing operations, are both approximately 43 feet in length, 8.5 feet in width, and 13 feet in height. The pump, blenders, and other hydraulic fracturing equipment are either powered directly by the diesel or gas engines, or indirectly by onsite electrical generators or distribution lines.

7.4.1.8 Offshore Well Stimulation Treatments As addressed in EIR Section 6.4 (Existing State Offshore Oil and Gas Resources), offshore well stimulation treatments in State waters and tidelands may be conducted either from (1) an onshore well horizontally drilled to an offshore location, (2) an island or pier constructed and operated for the purposes of offshore oil and gas production, or (3) an offshore platform. When on- to offshore well stimulation occurs, the process is exactly the same and the equipment is set up on or by the pier to perform the treatment. When a well stimulation treatment is performed on an offshore island to an offshore or onshore well (e.g., THUMS at the Wilmington Oil and Gas Field; see EIR Section 11), the process itself is the same. How- ever, all equipment is transported to and from the island via barge by a third party operator, as is done during the offshore drilling process. On average two barges are needed for equipment, one barge transports the fluid and additives, and one barge carries proppant. In general, each barge can carry five tractor trailers or eight body loads (i.e., trucks that do no separate, such as the control van). Personnel are transported to the island in a crew boat. All equipment is offloaded onto the island to perform the operation (Oxy, 2014; Baker Hughes, 2014).

Final EIR 7-44 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Typically the time required for offshore hydraulic fracturing operations is similar to onshore operations; however, a day is needed for mobilization to the island as well as a day for demobilization from the island. In general, produced water is used for fracturing fluid, which is sourced by the operator on location and stored in tanks prior to the wells stimulation treatment. All fluids, including flowback and hydrocarbon product, are transported onshore by pipelines from the islands. Produced water is then recycled and injected into the produced strata for secondary waterflood recovery and in order to control subsi- dence (Oxy, 2014). For offshore platforms, the steps required for a well stimulation treatment are nearly identical to those required for an island/pier treatment. However, hydraulic fracturing from platforms is performed from large ships or from “frac skids” that are offloaded onto the platform. The regulatory requirements for hydraulic fracturing and other well treatments in State waters and tidelands are identical to the requirements for onshore production or production federal waters. Platform operators are required to maintain an inventory of data about fluids used in well treatment operations and to report data to the RWQCB about discharges of well treatment fluids. If the fluids are discharged, the platform’s National Pollution Discharge Elimination System (NPDES) permit requires that operators report that information with their quarterly discharge monitoring reports (DMRs). If well treatment fluids are not discharged and therefore not reported with DMRs, the inventory information would be available to RWQCB inspectors at the platforms during inspections, or pursuant to an information request. The NPDES permit also requires whole effluent toxicity (WET) tests for produced water discharges. Those tests are designed to ensure that all pollutants in the discharges are not toxic to aquatic life in the ocean environment. If well treatment fluids are discharged, they are normally discharged with produced water. The WET tests help provide information on the potential toxicity to marine life from chemicals used for well treatment. 7.4.2 Acid Well Stimulation Treatments Section 3158 of Division 3, Chapter 1, as amended, defines acid well stimulation as a “treatment that uses, in whole or in part, the application of one or more acids to the well or underground geologic formation. The acid well stimulation treatment may be at any applied pressure and may be used in combination with hydraulic fracturing treatments or other well stimulation treatments. Acid well stimulation treatments include acid matrix stimulation treatments and acid fracturing treatments. Acid matrix stimulation treatments are acid treatments conducted at pressures lower than the applied pressure necessary to fracture the underground geologic formation.” Acid fracturing is discussed in EIR Section 7.4.2.1, and acid matrix stimulation is discussed in EIR Section 7.4.2.2, below.

7.4.2.1 Acid Fracturing Acid fracturing, also called fracture acidizing, is used primarily in carbonate reservoirs, which do not generally occur in California. Therefore, this method is rarely used within the State. A few instances of acid fracturing in Kern County were reported in SB 4 well stimulation notices to DOGGR. However, these treatments may not have actually been performed or they may be cases of misreported acid matrix stimulation (CCST, 2014). Essentially this treatment is similar to hydraulic fracturing (see EIR Section 7.4.1), except that acid replaces the proppant used to create permanent fractures in the formation. Acid fracturing creates flow channels by pumping mixtures of water and HCl and HF acids at high pressure into all portions of fractures created in the formation to dissolve the rock and increase the permeability of the formation, thereby allowing the oil and gas to move more freely. After the fractures have been created, the surfaces of the fractures are etched with acid so that when the formation is returned to production and the fractures close, high capacity flow channels remain in the faces of the fractures through which hydrocarbon fluids contained in the formation flow to the wellbore.

June 2015 7-45 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

A preflush fluid, normally HCl, is first introduced into the fracture or fractures with a density effectively equal to the density of the treating fluid to be used. One of the purposes of a preflush is to displace formation brines that contain potassium (K), sodium (Na), calcium (Ca) ions away from the wellbore, decreasing the possibility of crystallizing alkali-fluosilicates that could plug the pores. The other purpose of a preflush is to dissolve calcareous materials to minimize calcium fluoride [CaF2] precipitation, and to dissolve iron scale or rust to avoid the precipitation of the gelatinous, highly insoluble ferric hydroxide [Fe(OH)3]. Multiple preflush stages using brines such as ammonium chloride [NH4Cl] or solvents are used when multiple damage types are present (Schlumberger, 2014). The treating fluid, normally a mixture of HF and HCl or organic acids, is then injected into the fracture (or fractures) and is essentially distributed over the entire area of the fracture faces (i.e., it is not segregated into the lower portion of the fractures only). This is different than the typical acidizing procedures wherein the acid treating fluid is of relatively high density, and the preflush fluid is of relatively low density, causing the treating fluid to be segregated and to gravitate to the bottom of the fracture (Halli- burton, 1974). Additionally, during acid fracturing, the acid is injected at a high pressure that physically fractures the rocks as it dissolves, as compared to acid matrix stimulation, which is done at a lower pressure (see EIR Section 7.4.2.2). Acid fracturing, which uses powerful acids to extract oil from rock, requires less water than hydraulic fracturing; the acid must generally be diluted below 15 percent concentration in water, but at much lower volumes (Orford, 2013). In order to protect the integrity of the already completed well, inhibitor additives are also introduced to the well to prohibit the acid from breaking down the steel casing in the well. A sequestering agent can additionally be added to block the formation of gels or the precipitation of iron, which can clog the reservoir pores during acid fracturing or acid matrix stimulation (see EIR Section 7.4.2.2) (Rigzone, 2013).

7.4.2.2 Acid Matrix Stimulation Unlike acid fracturing, which is discussed in EIR Section 7.4.2.1, acid matrix stimulation or matrix acidizing is practiced in California and involves pumping acid into a well at a pressure low enough to prevent a reservoir rock from fracturing. Acid matrix stimulation is smaller in scope than hydraulic or acid fracturing, and is performed in one day or less. Acid matrix stimulation is generally used on a formation that has a production rate that is high enough such that fracturing is not necessary; it can be repeated on a weekly or even daily basis. There are two types of matrix acidizing. One type of matrix acidizing, which sometimes called an “acid wash,” has a volume of fluid less than the Acid Volume Threshold18 and typically affects an area less than five feet from the wellbore. Acid wash, is used to remove damage from drilling or scale that has built up over several years of production. This acid treatment is not used for well stimulation and is not subject to SB 4,. and is tTherefore, it is not considered in this EIR. Beyond three to five feet from the wellbore, matrix acidizing is used as a well stimulation technique and is analyzed in this EIR. It is described in the following paragraphs. The Acid Volume Threshold in DOGGR’s proposed permanent regulations that is used to distinguish between acid matrix stimulation treatment and the use of acid for wellbore cleanout,

18 According to DOGGR’s proposed permanent regulations that would amend California Code of Regulations Title 14, Division 2, Chapter 4, Subchapter 2, Article 2 (Definitions), “Acid Volume Threshold” means a volume, in gallons, per treated foot of well stimulation treatment, calculated as follows: (((Size of the drill bit that was used in the treated zone/2)(inches) + 36(inches))2  3.1416  12(inches)  treated formation porosity) – wellbore volume of treated zone(inches3) / 231(inches3/gallon). The lowest calculated or measured porosity in the zone of treated formation shall be the treated formation porosity used for calculating the Acid Volume Threshold.

Final EIR 7-46 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT maintenance, and removal of formation damage is further discussed in EIR Section 2.2.32 (Chronology and Content of the Proposed Permanent Regulations for Well Stimulation TreatmentsFuture Regulatory Setting). In California, the majority of acid matrix stimulation occurs in Kern County. As of May 2014, DOGGR has only received notification for acid matrix stimulation in the Elk Hills Oil Field in Kern County (DOGGR, 2014a). During matrix acidizing as a well stimulation treatment, approximately 200 to 300 gallons of total fluid per foot of interval treated is pumped into the well and the pores of the targeted reservoir to dissolve the sediments and mud solids that inhibit the permeability of the rock, thereby enlarging the natural pores of the reservoir and stimulating the flow of hydrocarbons. In general, the fluid includes water, an acid base (hydrochloric, hydrofluoric, acetic, citric, organic), an inhibitor (to treat corrosion, iron, scale, asphaltenes, paraffin), and surfactants (solvents, emulsifiers, non-emulsifiers, penetrating agents, dispersants). In order to protect the integrity of the already completed well, inhibitor additives are typically introduced to the well to prohibit the acid from breaking down its steel casing. Additionally, a sequestering agent may be added to block the formation of gels or precipitation of iron, which can clog the reservoir pores during an matrix acidizing job (Rigzone, 2013). The types of acid used (or not used) are dependent on the formation. The amount of acid used will depend on the length of treatment from the wellbore and the porosity of the formation (in California, average porosity is approximately 32 percent). A common type of acid used to stimulate well production is HCl, which is useful in removing carbonate reservoirs or limestones and dolomites from the rock. For 15 percent HCl, approximately 62 percent of the total volume is water. Therefore, for 1,000 gallons of 15 percent HCl, 379 gallons of 36 percent HCl would be combined with 621 gallons of water. Also, HCI can be combined with a mud acid, or HF acid, and used to dissolve quartz, sand, and clay from the reservoir rocks. Under this scenario, HCl is diluted to 15 percent or lower concentration or is blended at a ratio of 12:3 (i.e., 12 percent HCl and 3 percent HF). Although most acid stimulation jobs use HCl and/or a mud acid, other acids may be used, such as citric acid and formic acid. Typically service companies take diluted final-strength acid to the well to be treated; as such, it is mixed before arriving at the site. For instance, raw acid (36 percent HCl) would be delivered to the service company’s facility. It is then diluted at the facility to 15 percent prior to transport to the well site. The diluted acid is typically transported to the well site in a lined 5,000-gallon tanker transport, and stored in the transport or in plastic poly tanks at the site until used. At the site, water would be blended with the diluted acid at a 50:50 or higher ratio as it is pumped into the well bore (e.g., at least 500 gallons of water with 500 gallons of the acid blend). A slightly greater than 50 percent ratio of water is used for jobs designed to reach farther into the formation from the well bore. In this case, the reaction between the acid and the minerals happens at a slower rate and can pen- etrate farther into the formation before the acid is “spent.” Similar to hydraulic fracturing, water is supplied by the well owner/operator. Planned water use listed in notices submitted to DOGGR in December 2013 and January 2014 for such treatments ranged between 8,000 to 140,000 gallons (CCST, 2014). To perform the treatment, the crew hooks a pump to the well head and the tankers to the pump and to the water tank. The fluid is then pumped down at 0.5 bpm to 5 bpm. The pumps used for acid matrix stimulation typically range between 250 HHP to 850 HHP, with a noise range between 75 to 100 decibels. Although the pump used for hydraulic fracturing operations has greater HHP, the average pump dimensions are similar and are approximately 43 feet in length, 8.5 feet in width, and 13 feet in height. Both are capable of up to 15,000 psi maximum pressure. The engines for the pumps are engaged at high RPMs approximately 50 percent of the time.

June 2015 7-47 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

After an acid treatment is performed, the spent acid and sediments are removed from the reservoir and are flushed out of the well by “overflush,” which is a fluid pumped behind the main treating fluid. The overflush is typically formulated from a weak acid solution or brine to maintain a low pH environment in the near-wellbore formation that prevents the precipitation of reaction products as the treatment fluids are flowed back. The purpose of the overflush is to displace non-reacted mud acid into the formation, displace mud-acid reaction by-products, such as amorphous silica, and eliminate potential oil-wet relative-permeability19 problems caused by some corrosion inhibitors. On average and depending on the job’s design, an acid matrix stimulation treatment takes up to eight hours and requires up to two to three shifts of three to 10 workers. Typically each worker is assigned to a vehicle for the duration of the job; therefore, three to 10 vehicles are needed. Typically each job requires one roundtrip to the well site for each vehicle to complete the treatment. Wastewater and solid waste disposal methods would be similar to those described for hydraulic fracturing in EIR Section 7.4.1.6. 7.5 Project Standards for Resource Protection The following proposed standards would be implemented as part of the project to avoid and minimize impacts to sensitive resources. For the purposes of the impact analysis in this EIR, these standards are considered part of the project. Consistent with the programmatic character of this EIR, and as is the case with most of the proposed mitigation measures set forth in later chapters of this EIR, the proposed standards described in this section represent general approaches to avoiding and minimizing certain categories of environmental impacts. DOGGR intends to impose and enforce these standards in the future both when acting as a Lead Agency in conducting site-specific environmental analyses for proposed well stimulation treatments and when acting as a Responsible Agency in communicating with other agencies that are acting as Lead Agency with respect to the site-specific environmental analyses of proposed projects involving well stimulation treatments. When relevant, the standards would apply even where DOGGR determines that approval or a particular well stimulation treatment permit is exempt from CEQA. Except where site- specific circumstances require refinement in the specific approaches and language set forth below, DOGGR would incorporate the standards without change into conditions of approval for well stimulation treatment permits, or would encourage other agencies that are acting as Lead Agencies to adopt or to recommend that DOGGR adopt mitigation measures or conditions of approval that meet or are substantially consistent with the standards. Where modifications to the standard language are necessary to address site-specific circumstances, DOGGR would ensure that the resulting conditions of approval will be at least as environmentally protective as conditions that did not diverge at all from the standard language set forth below. 7.5.1 Water Recycling Standards The Water Recycling Standards would apply outside of existing oil and gas fields and at new wells within existing fields. Under the proposed Water Recycling Standards, the applicant for a well stimulation treatment permit shall be required to prepare and submit, as part of a complete application for the permit, a draft study on the feasibility of using recycled water (including reusing the flowback and produced

19 Absolute permeability is the ability of the porous media (i.e., the formation) to transmit fluids. Relative permeability is the ratio of the permeability of a given fluid when more than one fluid is present (i.e., its effective permeability) to the base permeability of the formation.

Final EIR 7-48 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT water20) and/or saline groundwater. Based on the results of the final version of the study, prepared to DOGGR’s satisfaction, the well owner/operator/service provider shall be required, through conditions of permit approval, to use recycled or saline water to the maximum extent feasible, as determined by DOGGR. After the issuance of a well stimulation treatment permit and completion of well stimulation treatment, the permittee shall document and report the actual amount of recycled water or saline groundwater used and the reasons for any deviation from the conditions of approval derived from the final Study. The permittee shall integrate this information into the Post-well Stimulation Treatment Report, which is required by California Code of Regulations [CCR], Title 14, Section 1789 et seq. The primary objective of the draft Study submitted with the permit application is to demonstrate all of the following: that the applicant has made good faith efforts to identify any recycled water or saline groundwater potentially available for use in well stimulation treatment; that the proposed well stimulation treatment will use any such available source to the maximum extent feasible; and that the proposed strategy would not cause adverse effects on drinking water sources or the environment. At a minimum, the draft Study must identify: (1) the amount of recycled water or saline groundwater that the applicant has determined could be feasible to use for well stimulation; (2) whether the recycled water or saline groundwater under consideration would likely be used for future drinking water supplies; and (3) whether any saline groundwater aquifer being considered as a source is connected to freshwater aquifers. The draft Study shall be integrated into the proposed Water Management Plan, which is required by the SB 4 Well Stimulation Treatment Regulations (14 CCR Section 1783.1(a)(23)). The Study shall be finalized after review and input by DOGGR as part of the process by which DOGGR considers issuance of a well stimulation treatment permit. In making its own determination regarding how much recycled or saline groundwater may feasibly be used for well stimulation, DOGGR shall consider all relevant economic, legal, social, and technological factors, consistent with the concept of “feasibility” as it occurs in CEQA, the State CEQA Guidelines, and CEQA case law. Where an agency other than DOGGR (e.g., a local government or another State agency) is the CEQA Lead Agency for a proposed project including well stimulation treatment while DOGGR is acting as a Responsible Agency, DOGGR shall encourage the Lead Agency to include in the draft environmental document circulated for public review both (i) the final version, satisfactory to the Lead Agency, of a Study meeting the description set both above and (i) any mitigation measure(s) or condition(s) of approval based on the final Study. Such suggestions from DOGGR can be communicated to the Lead Agency through the following means: informal consultation on a pending Negative Declaration or Mitigated Negative Decla- ration; comments on a publicly circulated Negative Declaration or Mitigated Negative Declaration; comments on a Notice of Preparation; comments on a Draft or Final EIR; or comments on a draft or final document prepared by a State Lead Agency as the “functional equivalent” of a Negative Declaration, Mitigated Negative Declaration, or Draft or Final EIR pursuant to a certification granted under PRC Sec- tion 21080.5. When acting as a Responsible Agency in the issuance of well stimulation treatment permits, DOGGR shall impose as conditions of approval any proposed mitigation measure(s) or condition(s) of approval recommended to DOGGR by the Lead Agency that meet or are substantially consistent with the Water

20 The amount of reused produced water and drilling wastewater would be site-specific and would depend on the number of wells drilled, amount of flowback and produced water, and the proximity of these sources for aggre- gation. It may be possible in some instances to reuse nearly 100 percent of the produced water and drilling wastewater. An example of a well that recycles nearly 100 percent of the produced water is the Chesapeake well in the Eagle Ford play in Texas; however, this accounts for only 10 to 30 percent of the volume of water needed for the Chesapeake operation (CERES, 2014).

June 2015 7-49 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Recycling Standards described above, though DOGGR may modify the proposed language in order to better achieve the Standards. Alternatively, where the Lead Agency has already imposed mitigation measure(s) or condition(s) of approval that meet or are substantially consistent with the Water Recycling Standards described above, DOGGR need not impose duplicative condition(s) of approval in the well stimulation treatment permit, and may conclude that the Lead Agency’s adopted measure(s) or condition(s) are sufficiently effective and protective. When warranted by circumstances, DOGGR shall also include condition(s) of approval requiring compliance with the Standards even where DOGGR determines that approval of a particular well stimulation treatment permit is exempt from CEQA. In preparing the Post-well Stimulation Treatment Report required by CCR, Title 14, Section 1789, the permittee shall document and report the actual amount of recycled water or saline groundwater used and the reasons for any deviation from the conditions of approval derived from the final Study. The permittee shall submit the Post-well Stimulation Treatment Report to DOGGR within 60 days after the cessation of a well stimulation treatment or within the timeframe required by CCR Title 14, Section 1789 et seq. If the Report finds minor violations of conditions of approval requiring compliance with the Water Recycling Standards, the Report shall propose for DOGGR’s consideration recommendations regarding how such violations can be avoided in the future during similar well stimulation treatments. If the Report finds major violations of conditions of approval requiring compliance with the Water Recycling Standards, the Report shall propose for DOGGR’s consideration recommendations regarding how the permittee can undertake environmental restitution so as to achieve indirectly the practical equivalent of the water savings or efficiencies that the Water Recycling Standards are intended to achieve. DOGGR shall exercise its independent judgment in determining which, if any, recommendation to follow or whether to formulate its own approach for requiring the permittee to undertake environmental restitution so as to achieve indirectly the practical equivalent of the water savings or efficiencies that the Water Recycling Standards are intended to achieve. 7.5.2 Habitat Protection Standards The Habitat Protection Standard would apply outside of existing oil and gas fields and for new wells within existing fields. Depending on the potentially affected habitat type, the Standard would require owner/ operator/service providers, when performing well stimulation treatments, either to avoid effects on the habitats entirely or to mitigate effects on the habitats so as to avoid any net loss of habitat values and functions. The petroleum resource may be accessed below the surface of these sensitive habitats through directional drilling or other methods that would not result in surface disturbance. Sensitive habitats requiring avoidance are illustrated in Figures 7.5-1 through 7.5-6 and described below. Figures 7.5-1 through 7.5-6 illustrate the sensitive habitats within the Inglewood, Sespe, and Wilmington Oil and Gas Fields. These figures provide only a broad overview of the sensitive habitats, and each well owner/operator/service provider who proposes a new well would need to determine if the proposed location occurs within a sensitive habitat type. DOGGR would then review the information submitted and reach its own conclusions in determining whether a proposed well stimulation treatment could adversely affect sensitive habitat types, and what sort of mitigation, if any, is necessary or appropriate. Sensitive habitats as defined under these proposed standards are:  Designated Critical Habitat for Federally Listed Species. The term “Critical habitat” is a term of art under the federal Endangered Species Act (ESA) (16 USC Section 1531 et seq.) that refers to specific geographic areas formally designated by the U.S. Fish and Wildlife Service or the National Marine Fisheries Service through a federal rulemaking process. These areas contain features essential to the conservation of species listed as threatened or endangered under ESA that may need special management or protection (USFWS, 2013). As part of this standard, well stimulation treatments shall not be

Final EIR 7-50 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

permitted in critical habitat unless mitigation can be provided to avoid any net adverse effect on the functions and values of such habitat. In determining whether potential mitigation may be sufficient to meet this standard, DOGGR may consult with the California Department of Fish and Wildlife, the U.S. Fish and Wildlife Service, and/or the National Marine Fisheries Service.  Recovery Areas for Federally Listed Species. A recovery unit is a management sub-unit of the listed entity, geographically or otherwise identifiable, that the U.S. Fish and Wildlife Service or the National Marine Fisheries Service has determined is essential to the recovery of the entire listed species, and conserves genetic or demographic robustness, important life history stages, or other feature for long- term sustainability of the entire listed species (USFWS, 2013). As recovery units are typically large areas complete avoidance may not be feasible. As part of these standards, well stimulation treatments shall not be permitted in recovery areas unless mitigation can be provided to avoid any net adverse effect on the functions and values of such habitat. In determining whether potential mitigation may be sufficient to meet this standard, DOGGR may consult with the California Department of Fish and Wildlife, the U.S. Fish and Wildlife Service, and/or the National Marine Fisheries Service.  Federal and California Protected Areas and California Conservation Easements. These areas include all parks and preserves that are protected as permanent open space and lands protected under conservation easements (GreenInfo Network, no date; GreenInfo Network, 2014). Some of these areas would not be open to well drilling and stimulation due to their protected status, such as National Parks, National Monuments, or Environmentally Sensitive Habitat Areas (ESHAs) identified by the Cali- fornia Coastal Commission. Other areas, such as Bureau of Land Management Areas of Critical Envi- ronmental Concern, may allow well drilling and well stimulation treatment under certain conditions or depending on their management plans. Still other areas, such as wetlands or similar habitat types protected as waters of the United States under the federal Clean Water Act or as waters of California under the Porter-Cologne Water Quality Control Act, may be subject to well drilling and well stimulation treatment only if it is authorized by agencies other than DOGGR (e.g., the U.S. Army Corps of Engineers or Regional Water Quality Control Boards). As part of these standards, well stimulation treatments shall not be permitted in protected areas or areas subject to conservation easements unless (i) such activities are permissible under the rules governing the protected areas, the existing regulatory permits governing use of the areas, or the terms of applicable conservation easements, and (ii) feasible mitigation can be provided to avoid any net adverse effect on the functions and values of such habitat. In determining whether potential mitigation may be sufficient to meet this standard, DOGGR may consult with the California Department of Fish and Wildlife, the U.S. Fish and Wildlife Service, the National Marine Fisheries Service, the U.S. Army Corps of Engineers, or the relevant Regional Water Quality Control Board.  California Marine Protection Areas. The Marine Life Protection Act established a statewide network of Marine Protection Areas to protect the diversity and abundance of marine life, the habitats they depend on, and the integrity of marine ecosystems (CDFW, 2013). As part of these standards, well stimulation treatments shall not be permitted in a manner that causes adverse effects on marine protection areas.  Areas of Special Biological Significance. Areas of Special Biological Significance were established in the 1970s by the State Water Resources Control Board and are regulated through the California Ocean Plan. Areas of Special Biological Significance include 34 ocean areas, which cover much of the length of California's coastal waters and are a subset of State Water Quality Protection Areas. Areas of Special Biological Significance are monitored and maintained for water quality by the State Water Resources Control Board and the California Ocean Plan prohibits the discharge of waste into these designated areas (SWRCB, 2005). As part of the resource protection standards in this EIR, well stimu-

June 2015 7-51 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

lation treatments shall not be permitted in a manner that causes adverse effects on Areas of Special Biological Significance. Under these proposed standards, as part of the application for a well stimulation treatment permit, the applicant shall submit to DOGGR maps and other information that show or describe both the proposed surface disturbance areas and any of the above-defined types of sensitive habitats potentially affected by such disturbance areas. If the proposed well stimulation treatment would adversely affect one of these types of sensitive habitat areas, the applicant shall submit a proposed mitigation strategy intended to be sufficient to avoid any net adverse effect on the functions and values of such habitat, or, in the case of California Marine Protection Areas, to avoid adverse effects on the habitat entirely. DOGGR shall not issue a well stimulation treatment permit for any such proposals unless DOGGR independently determines, based on substantial evidence, that the mitigation (with or without modifica- tion) will be effective in avoiding any net adverse effects on the functions and values of the affected habitat, or, in the case of California Marine Protection Areas, to avoid adverse effects on the habitat entirely. Where an agency other than DOGGR (e.g., a local government or another State Agency) is the CEQA Lead Agency for a proposed project including well stimulation treatment while DOGGR is acting as a Responsible Agency, DOGGR shall encourage the Lead Agency, in the draft environmental document circulated for public review, to include as proposed mitigation measure(s) or condition(s) of approval the above-described limitations on well stimulation treatment activities conducted in Designated Critical Habitat for Federally Listed Species, Recovery Areas for Federally Listed Species, Federal and California Protected Areas and California Conservation Easements, and California Marine Protection Areas. Such suggestions from DOGGR can be communicated to the Lead Agency through the following means: informal consultation on a pending Negative Declaration or Mitigated Negative Declaration; comments on a publicly circulated Negative Declaration or Mitigated Negative Declaration; comments on a Notice of Preparation; comments on a Draft or Final EIR; or comments on a draft or final document prepared by a State Lead Agency as the “functional equivalent” of a Negative Declaration, Mitigated Negative Decla- ration, or Draft or Final EIR pursuant to a certification granted under PRC Section 21080.5. When acting as a Responsible Agency in the issuance of well stimulation treatment permits, DOGGR shall impose as conditions of approval any proposed mitigation measure(s) or condition(s) recommended to DOGGR by the Lead Agency that meet or are substantially consistent with the Habitat Protection Standards described above, though DOGGR may modify the proposed language in order to better achieve the Standards. Alternatively, where the Lead Agency has already imposed mitigation measure(s) or condition(s) of approval that meet or are substantially consistent with the Habitat Protection Standards described above, DOGGR need not impose duplicative conditions of approval in the well stimulation treatment permit, and may conclude that the Lead Agency’s adopted measure(s) or condition(s) of approval are sufficiently effective and protective. When warranted by circumstances, DOGGR shall also include condition(s) of approval requiring compliance with the Standards even where DOGGR determines that approval of a particular well stimulation treatment permit is exempt from CEQA. After the issuance of a well stimulation treatment permit and within 60 days after the cessation of a well stimulation treatment, the applicant shall submit to DOGGR a Report that includes a map of, and data regarding, the sensitive habitats and the actual surface disturbance areas in order to document the extent of disturbance, if any, in sensitive habitats and the extent to which any required mitigation has been implemented and has been successful in avoiding any net loss of the functions and values of the affected habitat or, in the case of California Marine Protection Areas, in avoiding adverse effects on the habitat entirely. If the Report finds minor violations of conditions of approval requiring compliance with the Habitat Protection Standards, the Report shall propose for DOGGR’s consideration recommenda-

Final EIR 7-52 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT tions regarding how such violations can be avoided in the future during similar well stimulation treatments. If the Report finds major violations of conditions of approval requiring compliance with the Habi- tat Protection Standards, the Report shall propose for DOGGR’s consideration recommendations regarding how the permittee can undertake environmental restitution so as to achieve indirectly the practical equivalent of the level of habitat protection that the Habitat Protection Standards are intended to achieve. DOGGR shall exercise its independent judgment in determining which, if any, recommendation to follow or whether to formulate its own approach for requiring the permittee to undertake environmental restitution so as to achieve indirectly the practical equivalent of the level of habitat protection that the Habitat Protection Standards are intended to achieve. 7.5.3 Surface Water Protection Standards The proposed Surface Water Protection Standards would apply outside of existing oil and gas fields and at new onshore wells within existing fields to protect surface and groundwater in areas where future well stimulation would occur. California Code of Regulations Title 14 defines a “critical well” as any oil or gas well within 100 feet of any navigable body of water or watercourse perennially covered by water, and requires additional well safety devices to be used under certain conditions (see Section 1724.3). The proposed 100-foot setback for onshore wells is designed to provide pollutant reductions in the event of a spill from the well. In Cali- fornia, the majority of streams and some coastal water bodies are intermittent but are often just as important from an ecological standpoint as perennial systems. Regardless of whether water is present at the moment, fluvially active water bodies, particularly the channels of streams, will be preferential pathways and transportation corridors for any materials released into them. In order to provide protection to surface water sources, this standard would require all future well pads where stimulation would occur to be at least 100 feet from any navigable body of water or watercourse perennially covered by water and any intermittent water bodies regardless of the presence or absence of water. Where it is not feasible to impose such a 100-foot setback, however, DOGGR could approve a shorter setback if DOGGR finds, based on substantial evidence, that the proposed well stimulation treatment would not cause significant effects on any nearby navigable body of water or watercourse perennially covered by water. Under the proposed standards, as part of the application for a well stimulation treatment permit, the applicant shall submit to DOGGR maps and other information that describe or show (i) any perennial and intermittent water bodies within 500 feet of the proposed well stimulation treatment and (ii) the proposed surface disturbance areas. The application shall also include information explaining or depicting the expected drainage patterns at the location of the proposed well stimulation treatment. If the applicant contends that a setback of 100 feet from these surface water resources cannot feasibly be achieved or is unnecessary to avoid significant effects on potentially affected water bodies, the applicant shall submit a written justification for a proposed narrower setback, along with any proposed mitigation measure(s) intended to avoid any significant effects on such surface water resources. The justification shall explain why the proposed narrower setback is as wide as is feasible or as is necessary under the circumstances. DOGGR shall not issue a well stimulation treatment permit for a proposal with a setback of less than 100 feet unless DOGGR independently determines, based on substantial evidence, both that a 100-foot setback is infeasible or unnecessary, and that the proposed well stimulation, with or without any relevant mitigation measure(s) or condition(s) of approval, will not cause a significant effect to the potentially affected water bodies. In making its own determination regarding whether a 100-foot setback or a relevant potential lesser setback is infeasible, DOGGR shall consider all relevant economic, legal, social, and technological factors, consistent with the concept of “feasibility” as it occurs in CEQA, the CEQA Guidelines, and CEQA case law.

June 2015 7-53 Final EIR Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT

Where an agency other than DOGGR (e.g., a local government or another State Agency) is the CEQA Lead Agency for a proposed project including well stimulation treatment while DOGGR is acting as a Responsible Agency, DOGGR shall encourage the Lead Agency, in the draft environmental document circulated for public review, to include proposed mitigation measures or conditions of approval imposing the above-described Surface Water Protection Standards on proposed well stimulation treatment on sites located within 100 feet of the above-described types of water bodies. Such suggestions from DOGGR can be communicated to the Lead Agency through the following means: informal consultation on a pending Negative Declaration or Mitigated Negative Declaration; comments on a publicly circulated Negative Declaration or Mitigated Negative Declaration; comments on a Notice of Prepara- tion; comments on a Draft or Final EIR; or comments on a draft or final document prepared by a State Lead Agency as the “functional equivalent” of a Negative Declaration, Mitigated Negative Declaration, or Draft or Final EIR pursuant to a certification granted under PRC Section 21080.5. When acting as a Responsible Agency in the issuance of well stimulation treatment permits, DOGGR shall impose as conditions of approval any proposed mitigation measure(s) or condition(s) of approval recommended to DOGGR by the Lead Agency that meet or are substantially consistent with the Surface Water Resource Protection Standards described above, though DOGGR may modify the proposed language in order to better achieve the Standards. Alternatively, where the Lead Agency has already imposed mitigation measure(s) or condition(s) of approval that meet or are substantially consistent with the Surface Water Resources Protection Standards described above, DOGGR need not impose duplicative conditions of approval in the well stimulation treatment permit, and may conclude that the Lead Agency’s adopted mitigation measure(s) or condition(s) are sufficiently effective and protective. When warranted by circumstances, DOGGR shall also include condition(s) of approval requiring compliance with the Standards even where DOGGR determines that approval of a particular well stimulation treatment permit is exempt from CEQA. After the issuance of a well stimulation treatment permit and within 60 days after the cessation of a well stimulation treatment, the operator shall submit to DOGGR a map and other information depicting or describing surface water resources and the actual surface disturbance areas to document the actual setback or the extent of disturbance, if any, in surface waters. Where the extent of surface disturbance encroached into the minimum setback required by the condition(s) of approval, the permittee shall propose for DOGGR’s consideration recommendations regarding how such violations can be avoided in the future during similar well stimulation treatments. Where the extent of surface disturbance substantially encroached into the minimum setback required by the conditions of approval, the permittee shall also propose for DOGGR’s consideration recommendations regarding how the permittee can undertake environmental restitution so as to achieve indirectly the practical equivalent of the level of surface water protection that the Surface Water Protection Standards are intended to achieve. DOGGR shall exercise its independent judgment in determining which, if any, recommendation to follow or whether to formulate its own approach for requiring the permittee to undertake environmental restitution so as to achieve indirectly the practical equivalent of the level of habitat protection that the Surface Water Pro- tection Standards are intended to achieve. 7.5.4 Groundwater Protection Standard The Groundwater Protection Standard would apply outside of existing oil and gas fields, to existing wells, and to new wells within existing fields to protect surface and groundwater in areas where future well stimulation would occur. As a frame of reference, all groundwater contains dissolved constituents; the types and concentrations of these constituents depend on the source, environment, and movement of the groundwater. A measure of the general mineral quality of groundwater is total dissolved solids (TDS) expressed in milligrams per liter (mg/L). Typically, groundwater has higher concentrations of dissolved

Final EIR 7-54 June 2015 Analysis of Oil and Gas Well Stimulation Treatments in California 7. DESCRIPTION OF THE PROJECT constituents than surface water because of its greater exposure to soluble materials (salts) in rocks or sediments. Additionally, groundwater salinity tends to increase with depth in a groundwater basin, reflecting the long, slow pathways that groundwater travels at depth, or in some cases, the presence of ancient seawater that has not been flushed from deep marine sediments. Most of the groundwater used in California contains TDS concentrations of less than about 3,000 mg/L. The U.S. Geological Survey (USGS) defines fresh water as containing less than 1,000 mg/L TDS, slightly saline water as having TDS concentrations between 1,000 mg/L and 3,000 mg/L, and moderately saline water as having TDS concentrations between 3,000 mg/L and 10,000 mg/L. This standard would require that the annular space between the well casing and the subsurface be sealed with cement to fill the annular space to a confining unit below groundwater with 10,000 mg/L TDS water. This is consistent with the recommendations for the Class II Underground Injection Control (UIC) Program made by a 2011 U.S. Environmental Protection Agency (EPA) peer review (Horsley Witten Group, 2011) and the UIC definition of Underground Source of Drinking Water (40 CFR Section 144.3). If a well is subject to well stimulation treatments and does not contain a sufficient annular seal, the well would be required to be re-worked to add a seal down to a confining unit below groundwater with 10,000 mg/L TDS water. For any well that is to be stimulated, DOGGR would require that the applicant provide evidence that the mechanical integrity of the annular cement seal will prevent unintended migration of fluid. Where an agency other than DOGGR (e.g., a local government or another State Agency) is the CEQA Lead Agency for a project including well stimulation treatment while DOGGR is acting as a Responsible Agency, DOGGR shall encourage the Lead Agency to include in the draft environmental document circulated for public review a proposed mitigation measure or recommended condition of approval, to be imposed by DOGGR as a Responsible Agency and not by the Lead Agency, requiring achievement of the standard described above. Such suggestions from DOGGR can be communicated to the Lead Agency through the following means: informal consultation on a pending Negative Declaration or Mitigated Negative Declaration; comments on a publicly circulated Negative Declaration or Mitigated Negative Declaration; comments on a Notice of Preparation; comments on a Draft or Final EIR; or comments on a draft or final document prepared by a State Lead Agency as the “functional equivalent” of a Negative Declaration, Mitigated Negative Declaration, or Draft or Final EIR pursuant to a certification granted under PRC Section 21080.5. When acting as a Responsible Agency in the issuance of well stimulation treatment permits, DOGGR shall impose as condition(s) of approval any proposed mitigation measure(s) or condition(s) recommended to DOGGR by the Lead Agency that meet or are substantially consistent with the Groundwater Protection Standard described above, though DOGGR may modify the proposed language in order to better achieve the Standard. Alternatively, where the Lead Agency has already imposed mitigation measure(s) or condition(s) of approval that meet or are substantially consistent with the Groundwater Protection Standard described above, DOGGR shall nevertheless impose its own condition(s) of approval requiring essentially the same outcome. When warranted by circumstances, DOGGR shall also include condition(s) of approval requiring compliance with the Standard even where DOGGR determines that approval of a particular well stimulation treatment permit is exempt from CEQA.

June 2015 7-55 Final EIR