Chapter 3 reviewed several instances of seismic activity that may have been induced by underground injection. Underground injection of fluids is a key component of enhanced oil recovery, development of some unconventional oil and gas resources such as shale gas, geothermal energy production, carbon capture and storage, and wastewater disposal, which is often a part of different kinds of energy technology development. Although seismic events induced by the underground injection of fluids have been recognized for many decades, few of these events have captured national attention. However, the recent debate concerning hydraulic fracturing has brought the issue of induced seismicity to a higher level of public attention. The Environmental Protection Agency (EPA) is studying this topic1 concurrently with this National Research Council study and will publish its own report on this issue. It is important to note that, although this chapter deals mainly with induced seismicity caused by or likely related to the underground injection of fluid, induced seismicity can also be caused by the withdrawal of fluid from underground geologic formations.
Four federal agencies—the EPA, the Bureau of Land Management (BLM), the U.S. Forest Service (USFS), and the U.S. Geological Survey (USGS)—and different state agencies have regulatory oversight, research roles, and/or responsibilities related to different parts of the underground injection activities that are associated with energy technologies. Understanding these roles and responsibilities is important to the future development of energy technologies in ways that preserve public safety while allowing development of energy resources. This chapter provides a brief description of each agency’s authority related to underground injection and induced seismicity. States’ roles and responsibilities are also discussed; however, the committee did not perform a comprehensive review of all the states that are active in addressing the issue.
1 EPA has been facilitating a National Technical Working Group on Injection Induced Seismicity since mid-2011 and anticipates releasing a report that will contain technical recommendations directed toward injection-induced seismicity specific to Underground Injection Control (UIC) and Class II wells. See http://www.gwpc.org/meetings/uic/2012/proceedings/09McKenzie_Susie.pdf; P. Dellinger, presentation to the committee, September 2011.
Environmental Protection Agency
More than 700,000 different wells are currently used for the underground injection of fluids in the United States and its territories.2 Underground fluid injection began in the 1930s in order to increase production from existing oil and gas fields and was used in later years to dispose of industrial waste, but it was unregulated until 1974 when Congress passed the Safe Drinking Water Act (SDWA). The SDWA ensures safe drinking water for the public and establishes regulatory authority over the underground injection of fluids. In accordance with the act, the EPA is required to set standards for drinking water quality and to oversee all states, localities, and water suppliers that implement these standards. The EPA also regulates the construction, operation, permitting, and final plugging and abandonment of injection wells that place fluids underground for storage or for disposal under its Underground Injection Control (UIC) program.3 It is important to note that the SDWA gives authority to the EPA to protect underground sources of drinking water from contamination due to underground injection and does not explicitly address the issue of seismicity induced by underground injection. UIC regulations requiring information on locating and describing faults in the area of a proposed disposal well are concerned with containment of the injected fluid, not the possibility of induced seismicity.
Developers applying for a permit to inject fluids underground must demonstrate to the EPA that the operation will not endanger any underground sources of drinking water (USDWs). This regulatory scheme allows for six classes of injection wells, which are classified by the type of fluid injected and the specific injection depth (e.g., above or below sources of drinking water). Under this program, oil and gas industry injection wells are regulated as Class II injection wells, which also generally cover enhanced oil recovery projects or projects involving the disposal of exploration and production wastes (NRC, 2010). Table 4.1 provides an explanation of the distinction among classes of wells regulated under the SDWA.
Although the number and distribution of the different classes of injection wells vary by state, Class V wells are by far the most numerous, accounting for almost 79 percent of the total number of reported UIC wells. Because Class V wells normally inject fluid into formations above USDWs, these wells are usually too shallow to be considered a source of induced seismicity. This does not hold true in all cases, however, because wells used for fluid injection associated with the extraction of geothermal energy are included in this class of injection wells and are often the source of seismic events. The total number of geothermal wells in the United States was estimated to be approximately 239 wells, with 153 of these wells located in California and 53 located in Nevada (EPA, 1999). Although Class VI wells
TABLE 4.1 Classes of Wells in the EPA UIC Program
|I||Injection of hazardous wastes, industrial nonhazardous liquids, or municipal wastewater beneath the lowermost underground sources of drinking water (USDWs) (650 wells).|
|II||Injection of brines and other fluids associated with oil and gas production and hydrocarbons for storage. Injected beneath the lowermost USDW (151,000 wells).a|
|III||Injection of fluids associated with solution mining of minerals beneath the lowermost USDW (21,000 wells).|
|IV||Injection of hazardous or radioactive wastes into or above USDWs. Banned wells unless authorized by federal or state groundwater remediation project (24 sites).|
|V||All injection wells not included in Classes I–IV. Generally used to inject nonhazardous fluids into or above USDWs and typically shallow onsite disposal systems (estimated 400,000–650,000 wells).b|
|VI||Inject carbon dioxide (CO2) for long-term storage, also known as geologic sequestration of CO2 (estimated 6–10 wells by 2016).|
aThe table provided by EPA describes Class II wells as “injected below the lowermost USDW.” Although this is correct in most cases, injection below the lowermost USDW is not required for Class II wells, according to UIC regulations.
bMost Class V wells are unsophisticated shallow disposal systems that include storm water drainage wells, cesspools, and septic system leach fields.
also inject into formations below USDWs, no commercial carbon sequestration facilities are operating at this time.
Texas, California, and Kansas have the highest number of deep injection wells4 (counting only Classes I through IV), and 15 states have no deep injection wells at all. Table 4.2 shows the number of UIC wells in each state, listed by well count.
As Table 4.2 shows, Class II injection wells represent 87 percent of the total number of Class I through Class IV wells. For this reason the oil-producing states of Texas, California, Kansas, Wyoming, and Oklahoma have higher numbers of deep injection wells than other states.
States, territories, and tribes can submit an application to the EPA to obtain primary enforcement responsibility, or “primacy,” to implement the UIC program within their borders.5 Agencies that have been granted this authority oversee the injection activities
4 A deep injection well is a well that injects fluid below all underground sources of drinking water.
TABLE 4.2 2010 UIC Well Inventory Sorted by the Total Number of Deep Underground Injection Wells
|State||Class 1 Wells||Class II Wells||Class III Wells||Class IV Sites||Total UIC Wells Class I through Class IV|
NOTE: Because fluid in Class I through Class IV wells are normally injected into formations below USDWs, these wells can be a cause of induced seismicity. Class V wells normally inject fluid above USDWs and are normally too shallow to create induced seismicity and are therefore excluded from this table. The 15 states not listed here have no deep injection wells. No Class VI wells are currently in operation; however, 6-10 are estimated by 2016.
SOURCE: EPA (2010).
TABLE 4.3 Status of EPA Regulatory Authority Across the United States
Alabama, Arkansas, Connecticut, Delaware, District of Columbia, Georgia, Guam, Idaho, Illinois, Kansas, Louisiana, Maine, Maryland, Massachusetts, Mississippi, Missouri, Nebraska, Nevada, New Hampshire, New Jersey, New Mexico, North Carolina, North Dakota, Ohio, Oklahoma, Oregon, Puerto Rico, Rhode Island, South Carolina, Texas, Utah, Vermont, Washington, West Virginia, Wisconsin, Wyoming
American Samoa, Arizona, Hawaii, Iowa, Kentucky, Michigan, Minnesota, New York, Pennsylvania, Tennessee, Virgin Islands, Virginia
Alaska, California, Colorado, Florida, Indiana, Montana, South Dakota
Fort Peck Tribe, Navajo Nation
SOURCE: EPA; available at water.epa.gov/type/groundwater/uic/Primacy.cfm.
within their state. The EPA remains responsible for issuing permits in states that have not been delegated primacy and for the UIC programs on most tribal lands. Primacy for all classes of injection wells does not need to be granted to a state in order for a state to exercise regulatory authority over a single class of wells. For example, a state may exercise primacy over only Class II wells and no other class of injection wells. In this case the EPA would retain jurisdiction over all other well classes within the UIC program except Class II wells where primacy was delegated to the state. Currently, the EPA has granted primacy over all classes of injection wells in 33 states and 2 territories. The EPA shares jurisdiction for injection regulation in 7 states and has complete regulatory authority over underground injection in 10 states and 2 territories (see Table 4.3).
Primacy allows states to permit facilities, inspect wells, enforce against violations, and otherwise regulate underground injection activity within the state. States with primacy can disperse this authority through different state agencies. Some states regulate all classes of injection wells through one state agency (e.g., the Department of Health and Environment), and others divide the regulatory authority between several state agencies such as oil and gas commissions, health departments, and the local divisions of mining. However, regardless of how jurisdiction is divided, all state regulatory agencies are required to establish regulations that, at a minimum, conform to the EPA’s UIC guidelines, which are outlined in Title 40 of the Code of Federal Regulations (CFR), Part 145.6
The authority delegated to the EPA by the SDWA is limited to technical issues involving well bore construction, allowable sources of injected fluid, and operational requirements such as maximum pressures and periodic testing that protect underground sources of drink-
6 Available at www.access.gpo.gov/nara/cfr/waisidx_02/40cfr145_02.html.
ing water and the surface environment. The EPA, however, does not grant a contractual right to inject fluids or CO2 underground by their permitting process. In the case of fluid disposal or CO2 sequestration, this right is granted by the property owner via a “surface use agreement” with the injection well operator. These agreements may include fees paid to the property owner based on a monetary charge per barrel of fluid or ton of CO2 or a charge for land rental per month. These agreements can also include requirements on how fluid is delivered (by truck or by pipeline), how site security is handled, and what type of facilities will be used on the well site (tank, pits, and offloading facilities). Property owners can be private parties and/or governmental agencies such the BLM, the USFS, or state land management organizations. Underground injection for the purpose of secondary or tertiary recovery operations in an existing oil or gas field or injection to develop geothermal resources are usually allowed via an oil and gas or geothermal mineral lease.
Specific regulations governing the requirements of the UIC program are documented in 40 CFR, Parts 144 through 149. These regulations outline the general requirements of the UIC program, the requirements for state programs, and specific standards for well construction and testing. A comparison of these regulations is summarized in Table 4.4. This table includes only those classes of injection wells that are connected with energy technologies. These classes are Class II wells (associated with oil and gas production), Class V wells (associated with geothermal energy), and Class VI wells (associated with carbon sequestration). Although Class I wells have also been proven to induce seismic events, they are excluded from this study because they have no association with energy extraction.
In practice, the well construction requirements shown above are almost always met by using standard oil and gas well construction techniques, such as setting surface casing below all underground sources of drinking water and cementing casing high above all injection horizons. This method of setting and cementing casing strings at strategic depths ensures underground sources of drinking water are protected by at least two strings of steel casing (sometimes more) and at least two barriers of cement (Figure 4.1). The ability of the tubing or casing to contain pressure is required to be continuously recorded in a Class VI well and is tested every 5 years for Class II wells.
Other governmental agencies, in addition to the EPA or a state agency, may have jurisdiction over the injection permitting process. These additional agencies include the BLM, USFS, and USGS.
TABLE 4.4 Comparison of Regulations for Wells in the EPA UIC Program
|Use||Injection of brines and other fluids associated with oil and gas production and hydrocarbons for storage. Injected beneath the lowermost USDWs (150,851 wells).a||All injection wells not included in Classes I–IV. Generally used to inject nonhazardous fluids into or above USDWs and typically shallow onsite disposal systems (estimated 640,000 wells).b Of this number, approximately 234 wells are used for the injection of fluids in association with the recovery of geothermal energy for heating, aquaculture, and production of electric power (EPA, 1999). Permits for geothermal injection wells can be issued by the BLM in addition to state agencies or the EPA.c||Inject carbon dioxide (CO2) for long-term storage, also known as geologic sequestration of CO2 (estimated 6–10 wells by 2016).|
|Siting||All new Class II wells shall be sited in such a fashion that they inject into a formation which is separated from any USDW by a confining zone that is free of known open faults or fractures within the area of review (a confining zone is a formation that is capable of limiting fluid movement above an injection zone) (see 40 CFR 146.22(a)).||Class V wells have no specific siting requirements.||Owners or operators of Class VI wells must demonstrate to the satisfaction of the Director that the wells will be sited in areas with a suitable geologic system (see 40 CFR 146.83(a)). Confining zones free of transmissive faults or fracture and of sufficient areal extent and integrity to contain the injected carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s) (see 40 CFR 146.83(a)(2)).|
|Construction||All Class II wells shall be cased and cemented to prevent movement of fluids into or between underground sources of drinking water (see 40 CFR 146.22(b)).||No specific regulations regarding well bore construction.||Surface casing must extend through the base of the lowermost USDW and be cemented to the surface through the use of a single or multiple strings of casing and cement (see 40 CFR 146.86(b)(2)). At least one long string casing … must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages (see 40 CFR 146.86(b) (3)). All owners or operators of Class VI wells must inject fluids through tubing with a packer set a depth opposite a cemented interval at a location approved by the Director (see 40 CFR 146.86(c)(2)).|
|Required information||At a minimum, the following information concerning the injection formation shall be determined or calculated for new Class II wells or projects: (1) fluid pressure, (2) estimated fracture pressure, and (3) physical and chemical characteristics of the injection zone (see 40 CFR 146.22(g)). Additional information that must be considered by the Director in authorizing Class II wells includes a map showing the injection well or project area for which a permit is sought and the applicable area of review. The map may show faults if known or suspected (see 40 CFR 146.24(a)(2)).||Minimum federal UIC requirements are defined in 40 CFR 144–147. EPA Regional Offices administering the UIC program have the flexibility to establish additional or more stringent requirements based on the authorities in parts 144 through 147 (see 40 CFR 144.82(d)).||A map showing the injection well for which a permit is sought and the applicable area of review; the map should also show faults, if known or suspected; only information of public record is required to be included on this map (see 40 CFR 146.82(a)(2)). The location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment (see 40 CFR 146.82(a)(3)(ii)). Information on the seismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment (see 40 CFR 146.82(a)(3)(v)).|
|Operational requirements||Injection pressure at the wellhead shall not exceed a maximum which shall be calculated so as to ensure that the pressure during injection does not initiate new fractures or propagate existing fractures in the confining zone adjacent to the USDWs (see 40 CFR 146.23(a) (1)). Injection between the outermost casing protecting underground sources of drinking water and the well bore shall be prohibited.||No specific injection requirements are outlined for Class V wells except that “injection activity cannot allow the movement of fluid containing any contaminant into USDWs, if the presence of that contaminant may cause a violation of the primary drinking water standards … or may otherwise adversely affect the health of persons” (see 40 CFR 144.82(a)).||Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zone(s) so as to ensure that the injection does not initiate new fractures or propagate existing fractures in the injection zone(s) (see 40 CFR 146.88(a)).|
|Termination of permits||The Director may terminate a permit during its term, or deny a permit renewal application for the following cause: a determination that the permitted activity endangers human health or the environment and can only be regulated to acceptable levels by permit modification or termination (see 40 CFR 144.40(a)(3)).||The Director may terminate a permit during its term, or deny a permit renewal application for the following cause: a determination that the permitted activity endangers human health or the environment and can only be regulated to acceptable levels by permit modification or termination (see 40 CFR 144.40(a)(3)).||The Director may terminate a permit during its term, or deny a permit renewal application for the following cause: a determination that the permitted activity endangers human health or the environment and can only be regulated to acceptable levels by permit modification or termination (see 40 CFR 144.40(a)(3)).|
aThe table provided by EPA describes Class II wells as “injected below the lowermost USDW.” Although this is correct in most cases, injection below the lowermost USDW is not required for Class II wells, according to UIC regulations.
bMost Class V wells are unsophisticated shallow disposal systems that include storm water drainage wells, cesspools, and septic system leach fields. Wells used for fluid injection in association with the recovery of geothermal resources are included in this class because they are an injection well “not included in Classes I-IV.”
cA review of geothermal injection wells performed by the EPA in 1999 notes, “The permits [for Class V wells] are issued by state agencies, US Bureau of Land Management (BLM), and/or the USEPA Regional Office, depending on the state and whether the well is located on state, federal, or private land. In general, the permits are similar to those issued for Class II injection wells” (EPA, 1999).
Bureau of Land Management
The BLM has jurisdiction over onshore leasing, exploration, development, and production of oil and gas on federal lands in the United States.7 Certain contractual property rights and responsibilities governing resource development are created when BLM issues a lease to extract oil and gas resources or geothermal energy from federal lands (NRC, 2010). The BLM regulatory framework governing oil and gas extraction operations for federal and tribal lands is contained in 43 CFR Part 3160 (Onshore Oil and Gas Operations).8 In the process of underground injection, the BLM normally has the role of a surface owner with jurisdiction over surface facilities and surface impacts. (For example, the BLM is required to take National Environmental Policy Act [NEPA] provisions in its management of surface resources.) Permitting and construction considerations for these wells are reviewed and approved by the EPA or the appropriate state regulatory agency. The permitting and oversight of geothermal wells, however, can be an exception. The “Geothermal Steam Act” (43 CFR Parts 3200, 3210, 3220, 3240, 3250, and 3260) gives the BLM authority to regulate geothermal resources on federal lands administered by the Department of the Interior and the Department of Agriculture, where geothermal resources were reserved to the United States. In these cases the BLM permits, approves, and regulates the development of geothermal resources (Box 4.1).
U.S. Forest Service
The USFS is primarily responsible for managing surface resources on national forest lands. The USFS cooperates with the Department of the Interior in administering exploration and development of leasable minerals, including the review of permit and lease applications and making recommendations to protect surface resources (USFS, 1994). As is the case with BLM, the USFS takes the role of surface owner in injection activities and exercises jurisdiction over surface facilities and surface impacts that are associated with injection operations. The USFS is also required to take into account NEPA provisions in its management of surface resources. The actual permitting and oversight of injection activities is exercised by the EPA, local state agencies, or the BLM.
7 BLM is primarily responsible for the regulation and development of federal oil and gas mineral resources under the following acts: the Mining Leasing Act of 1920 (41 Stat. 437; see BLM, 2007); the Federal Land Policy and Management Act of 1976 (43 USC 1701-1782; see BLM, 2001); the Federal Onshore Oil and Gas Leasing Reform Act of 1987 (101 Stat. 1330-256, an amendment to the Mineral Leasing Act of 1920); the National Forest Management Act (16 USC 1600-1604); and the National Materials and Minerals Policy, Research, and Development Act of 1980 (P.L. 96-479; 30 USC 1601-1605). Many of these acts are summarized in NRC (1989).
8 The BLM and USFS jointly prepared a manual, The Gold Book, which summarized surface operating standards and guidelines for oil and gas exploration and development (BLM and USFS, 2007).
BLM Regulation of Class V Geothermal Injection Wells: Seismicity Concerns
The BLM, through an informal agreement with the EPA, regulates the Class V geothermal injection wells in California. Under this arrangement the BLM has recently issued its “Conditions of Approval” for a proposed enhanced geothermal systems project that stipulated the specific procedures to be followed in the event that induced seismicity is observed to be caused by the proposed stimulation (hydraulic fracturing) operation.a As issued by the BLM, the specific procedures include the use of a “traffic light” system that allows hydraulic fracturing to proceed as planned (green light) if it does not result in an intensity of ground motion in excess of Mercalli IV “light” shaking (an acceleration of less than 3.9%g), as recorded by an instrument located at the site of public concern. However, if ground motion accelerations in the range of 3.9%g to 9.2%g are repeatedly recorded, equivalent to Mercalli V “moderate” shaking, then the hydraulic fracturing operation is required to be scaled back (yellow light) to reduce the potential for a further occurrence of such events. Finally, if the operation results in producing a recorded acceleration of greater than 9.2%g, resulting in “strong” Mercalli VI or greater shaking, then the active hydraulic fracturing operation is to immediately cease (red light).
aR.M. Estabrook, BLM, Conditions of Approval for GSN-340-09-06, Work Authorized: Hydroshear, The Geysers, January 31, 2012.
U.S. Geological Survey
The USGS provides scientific information to describe and understand the Earth; minimize loss of life and property from natural disasters; manage water, biological, energy, and mineral resources; and enhance and protect quality of life in the United States.9 It is the only federal agency with responsibility for recording and reporting earthquake activity worldwide, and it is often asked to aid state agencies in the investigation of possible induced seismicity. Its Earthquake Hazards Program serves as the USGS component of the multiagency National Earthquake Hazards Reduction Program, which develops, disseminates, and promotes knowledge, tools, and practices for earthquake risk reduction that improve national earthquake resilience. The Earthquake Hazards Program also houses the National Earthquake Information Center (NEIC), which aims to determine the location and size of all destructive earthquakes worldwide and to disseminate this information to concerned agencies, scientists, and the general public.
The USGS is continuing to enhance its earthquake monitoring and reporting capabilities through the Advanced National Seismic System (ANSS). Since 2008 the USGS has
installed approximately 300 new earthquake-monitoring instruments in the highest-risk areas. Full implementation of ANSS will result in 6,000 new instruments on the ground and in structures in at-risk urban areas (Box 4.2).
Seismic events that are thought to be induced are flagged in the USGS earthquake database. However, many or most events that USGS scientists suspect may be induced are not labeled as such, due to lack of confirmation or evidence that those events were in fact induced by human activity.10 This is often true with events in regions that have experienced natural earthquakes before any mining or extraction operations were established. The earthquake location accuracy provided by the NEIC depends primarily on the number and location of seismic stations recording the event. During the 2008-2009 Dallas–Fort Worth earthquake swarm, the accuracy of the initial NEIC locations was on the order of 10 km (6 miles), which made the events difficult to assign to a particular injection well (Frohlich et al., 2011). In areas of low historical seismicity, the NEIC network coverage tends to be sparser than in more seismically active areas, making the detection of small events (< M 3) and accurate hypocenter locations difficult (Box 4.3).
Although the concerns surrounding induced seismicity are relatively new, at least two states have now adopted, or are in the process of adopting, regulations or approval procedures to address the issue. Colorado and Arkansas are currently reviewing underground injection permits for possible problems with induced seismicity in the Raton Basin, Colorado, and Guy-Greenbrier area, Arkansas (Box 4.4). Recent seismic activity in the Raton Basin near a large coalbed methane field with active injection has prompted the Colorado Oil and Gas Conservation Commission (COGCC) to initiate a policy requiring the Colorado Geologic Survey to review all Class II injection permits for geologic features that could result in seismicity due to injection. According to a statement released by the COGCC, “if historical seismicity has been identified in the vicinity of a proposed Class II UIC well, COGCC requires an operator to define the seismicity potential and the proximity to faults through geologic and geophysical data prior to any permit approval” (COGCC, 2011). Due to apparent instances of induced seismicity in Arkansas, the Arkansas Oil and Gas Commission (AOGC) proposed regulations to establish a “Moratorium Zone” covering over 1,000 square miles where no permit for a Class II well will be granted without a hearing by the Commission (AOGC, 2012). The proposed regulations also require no Class II permit will be issued within 5 miles of a “Moratorium Zone Deep Fault” without a hearing by the Commission.
10 Bruce W. Presgrave, USGS, personal communication, March 3, 2011.
Temporary Seismic Array Acquisition and Processing Cost Estimates
In the event of a felt induced seismic event, a temporary seismic network may be installed to augment the regional network or to record the events within the temporary network. This involves installing sensitive seismic instruments around the area of interest to record small earthquakes that are typically difficult to detect on more than a few instruments within a standard regional array. By augmenting the regional seismic stations with a dense temporary seismic network, seismologists can carry out detailed analyses on the earthquake waveforms and improve the earthquake location accuracy in the subsurface. Additionally, if the data and station coverage around an induced seismic event is appropriate, a better understanding of the earthquake’s size and failure mechanism can be determined. The cost of a temporary seismic array including the array deployment, operation, and data analyses will depend on the number of stations, the location of the study area, the length of the study period, and the overall goals of the seismic monitoring project.
A variety of instruments is commercially available for recording small earthquakes. Broadband instruments specialize in recording a broad spectrum of waveforms from 120 to 175 Hz. Short-period instruments are equipped to record only high frequencies, in general > 1 Hz. A complete broadband station with recorder, geophone, and assorted auxiliary equipment costs around $25,000, and a short-period recorder is slightly less at approximately $20,000 (2011 cost estimates). Eight to 10 instruments are typically deployed for a small temporary seismic array, but as many as 20 instruments are deployed for more detailed earthquake surveys. The network sensitivity is often measured by how small an event can be recorded and located, and the array design will depend on sensitivity required for the study (for example, to record and locate an event down to M 0). Hence, for a temporary seismic array, instrumentation costs alone run from $120,000 to $370,000. The seismic instruments can be reused after the study is completed; some minor costs are associated with instrument maintenance and storage.
The expenditure associated with installing and running the temporary seismic array will depend on the location of the array and the length of the deployment. Estimated costs for a 150-day deployment are approximately $100,000, which includes the mobilization, demobilization, equipment setup, tie in with existing seismic network, and charges for data telemetry. The seismic instrumentation is very sensitive to ground motion, and geophones cannot be installed in areas with high background noise, such as freeways, busy urban areas, factories, etc., as they will be saturated with noise and unable to record seismic signal from small earthquakes. In noisy areas the seismic instruments may have to be placed in shallow boreholes (typically 200 to 400 feet deep), which will add additional cost to the array installation, which is not included in the price listed above.
Detailed analysis of the seismic data by qualified seismologists is required to determine earthquake hypocenters and magnitudes, estimate location errors, and determine the type of failure (focal mechanism or moment tensor inversion). The cost for the work will depend on the detail required; cost estimates for professional analysis for a 6-month seismic deployment is in the $200,000 to $300,000 range for a university-based project. Commercial companies—national laboratories, for example—are available to provide these types of services and prices will vary depending on the project scope. Thus the total cost, including purchasing seismic instruments and installing and operating the array for a 150-day deployment with 8 to 12 instruments is estimated at $400,000 to $800,000.
Less costly recording instruments are being developed that could significantly drive down the cost of an instrument to less than $1,000 to $3,000 per site (Hutchings et al., 2011); however, the type of instrumentation used will depend on the goal of the study. Overall instrumentation is a minor cost compared to the overall deployment and interpretation of the seismic data.
The National Earthquake Information Center
The NEIC,a headquartered in Golden, Colorado, is responsible for quickly determining the location and size of destructive earthquakes worldwide and disseminating in near real time the information to concerned national and international agencies, scientists, and the general public. NEIC produces a comprehensive catalog of earthquake source parameters and macroseismic effects for all M 4.5+ earthquakes worldwide and M 2.5+ earthquakes in the United States in coordination with USGS-supported regional seismic networks (see Figure for a map of magnitude sensitivity of the seismic network within the United States). The NEIC acquisition and processing system is designed for recording and analyzing seismic earthquakes on all scale lengths from near-real-time monitoring of aftershock sequences using dense local arrays to modeling of all damaging earthquakes worldwide.
For example, NEIC in 2011 simultaneously and seamlessly reported on the 2011 M 9.0 Japanese earthquake and its aftershocks and multiple earthquake sequences in the United States that included Guy, Arkansas; Mineral, Virginia; Prague, Oklahoma; and Trinidad, Colorado. In later cases, the existing seismic monitoring system was augmented by dense local seismic stations that enabled automatic detection and locations to magnitudes less than about 1.5.
In addition, NEIC and the Earthquake Hazards Program maintains a group of 32 portable seismic recording systems, designed for both strong (large earthquakes) and weak motion (events less than M 3), in order to respond to notable seismic sequences throughout the United States. This equipment is often loaned to
Figure Map of the minimum detectable earthquake magnitude within the lower 48 states using the ANSS array operated by the USGS/NEIC. Shading indicates the minimum-sized earthquake that can be detected and located by the NEIC, as indicated by the color bar on the right. Triangles mark seismic station locations. SOURCE: USGS/NEIC.
cooperating state geological surveys and regional seismic networks to address specific local seismic monitoring issues. NEIC’s acquisition and processing system allows them to automatically integrate near-real-time and non-real-time waveform and source parameter data from regional seismic networks and portable seismic stations to develop complete seismic catalogs of earthquake sequences. As an example, NEIC is presently integrating its existing seismic bulletin for the 2011 M 5.8 Virginia earthquake with other non-real-time data from more than 40 stations deployed by multiple universities and/or state and federal agencies.
The 2010-2011 Guy Greenbrier, Arkansas, Earthquake Swarm and Arkansas Class II Injection Well Moratorium Area
A group of Class II wastewater disposal wells started operation April 2009 in central Arkansas, near the towns of Guy and Greenbrier, Arkansas. The wells were used to dispose of wastewater associated with gas development from the Fayetteville shale. A swarm of earthquakes (M ≤ 4.7) started in September 2010 between the towns of Guy and Greenbrier (Figure 1). The close spatial and temporal correlation between the seismicity and the wastewater injection wells suggests a link between injection and seismicity. All but 2 percent of the earthquake activity occurred in the vicinity of about a 6-km (3.7-mile) radius of three specific injection wells (labeled wells 1, 2, and 5 in Figure 1) (Horton, 2012). One injection well, number 5, appears to intersect a known fault, the Enders, which may allow fluid to travel down into deeper crustal structures (Horton, 2012).
Central Arkansas commonly experiences diffuse swarm seismicity, which is thought to be associated with the New Madrid Seismic Zone (NMSZ), the largest seismic zone east of the Rocky Mountains. The NMSZ is located on the northeastern part of Arkansas, southeast Missouri, and northwest Tennessee (Figure 1). The Guy-Greenbrier area has a history of seismic activity, a series of earthquakes referred to as the Enola swarms, which occurred in the 1980s and in 2001, east-southeast of Greenbrier (Figure 2). The Enola swarms were not well located due to poor instrumentation; however, the activity tended to form elongated east-west trends from 3 to 7 km (9850–23,000 feet) in depth (Chui et al., 1984; Rabak et al., 2010).
The AOGC approved a moratorium for any new or additional Class II disposal on January 26, 2011. The injection moratorium area is approximately 5 miles surrounding the Guy-Greenbrier and Enola seismically active area and covers an area of over 1,150 square miles (AOGC, 2011).a Operators with existing Class II wells are required to report daily injection pressures and volumes to the AOGC director. The moratorium
Figure 1 Study area in Arkansas with Guy-Greenbrier seismic activity. Seismic stations installed by the Arkansas Geological Survey and the Center for Earthquake Research at the University of Memphis are marked by black squares; injection wells are marked by red dots; seismic events between October 1, 2010, and February 15, 2011, are marked by dark gray dots; and seismic events between February 16, 2011, and March 8, 2011, are marked by white dots. Named faults penetrate to the Precambrian basement (faults from AGS and AOGC). Right inset: First-motion focal mechanism for M 4.0 event on October 11, 2010, is consistent with right-lateral strike slip on a northeast-oriented fault. Left inset shows the location of the New Madrid Fault zone in northeastern Arkansas with historical earthquakes. SOURCE: Modified from Horton (2012); see also earthquake.usgs.gov/earthquakes/eqarchives/poster/2011/20110228.php.
Figure 2 Map of the historical seismicity in the Guy-Greenbrier area 1976 to 2009, including the Enola swarm. SOURCE: Horton (2012).
was placed to allow time to investigate “a potential correlation between the seismic activity and disposal well operations in the Guy-Greenbrier, Arkansas area” (AOGC, 2011). In the surrounding Fayetteville shale development area outside the Permanent Moratorium Area, the AOGC director may propose additional requirements for any new disposal wells (AOGC, 2011).
a See AOGC (2011) for a detailed map of the AOGC’s proposed Permanent Moratorium Area for disposal wells.
While the injection of fluid underground is regulated by the EPA, the BLM, and state agencies, the extraction of fluids is normally not regulated or is minimally regulated. The number of events of induced seismicity caused by the withdrawal of fluid is approximately equal to the number of events caused by the underground injection of fluids for both disposal and secondary recovery (see Box 1.1 in Chapter 1), but fluid withdrawal is usually not curtailed due to induced seismicity. This is because the pumping of fluids from underground reservoirs can be divided among many different oil companies, and states only require permits to drill oil and gas wells, not to produce fluid from them. One method of controlling the withdrawal of fluids from an underground reservoir is through “unitization.” Unitization is an order granted by the state oil and gas regulators that designates one oil and gas company to be the “unit operator” of the unitized oil and gas field, and profits and expenses from oil and gas operations are divided among operators as dictated by the unitization agreement (Box 4.5). This
In 1892 Edward Doheny and Charlie Canfield discovered the Los Angeles City oil field. By 1895 the field had produced 729,000 barrels of oil, nearly 60 percent of California’s production. The discovery was in a townlot area composed of small residential lots. Each townlot lot owner had both surface and mineral rights. California has the “Law of Capture,” which means that a “liquid mineral” can move from one property to another. Because of this each owner had to drill a well or have their oil taken by their neighbor. This resulted in runaway drilling and very inefficient and expensive oil operations. Some producers would overproduce their wells and harm the productivity of their neighbors, resulting in inefficient and expensive development.
Early in the 1900s the State of California formed the Division of Oil and Gas (now called DOGGR). In the period from 1923 to 1926, Union, Shell and Associated Oil Company under a cooperative agreement developed the Dominguez oil field. This unit proved to be an efficient way to manage the field with almost no wastage. The Subsidence Control Act of 1958 encouraged voluntary pooling and unitization and provided for compulsory unitization if needed. The individual operators of an oil field would be combined into a Unit and the oil field would be operated by one party called the Unit Operator. The other participants are called Working Interest Owners. Unit documents would define the unit and the participant’s share of the total, called the Equity Determination.
Unitization has proven to be an effective way to share the wealth and operations of oil fields fairly while protecting the environment and guaranteeing energy conservation. It is also easier to regulate because all parties share the profits and losses but one party, the Unit Operator, is in charge. DOGGR has used unitization to force efficient waterfloods and prevent environmental problems.
SOURCE: Rintoul (1990).
order is normally requested prior to initiating secondary recovery operations and is granted with the consent of the majority of the affected oil and gas operators. Because a unitization order is granted by a state’s oil and gas governing body, it can also include requirements to limit fluid withdrawal for a variety of reasons. These might include conservation of the oil and gas resource, limited injection of fluid, or induced seismic events. Although many oil and gas fields have been unitized in the United States, we know of no instance where produced fluid volumes have been curtailed to limit induced seismicity.
Although the SDWA provides a regulatory framework for the underground injection of fluids, the act does not explicitly address the issue of induced seismicity or how induced seismic events should be investigated and regulated. Currently, many different agencies have oversight of the UIC program, such as the EPA, various state agencies, the BLM, and the USFS. To date, these various agencies have dealt with induced seismic events with different and localized actions, using input from additional government agencies such as the USGS and various state geologic surveys, as well as university researchers. These efforts to respond to incidence of perceived induced seismicity have been successful but are of an ad hoc nature and can vary widely depending on the different agencies involved.
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