United States Office of Ground Water EPA/816-R-99-014q

Environmental and Drinking Water (4601) September 1999

Protection Agency 

The Class V Underground Injection Control

Study

Volume 17

Electric Power Geothermal Injection Wells
September 30, 1999

Table of Contents

Page

1. Summary ................................................................. 1

2. Introduction ............................................................... 3

3. Prevalence of Wells ......................................................... 6

4. Injectate Characteristics and Injection Practices .................................... 8

4.1 Injectate Characteristics ................................................ 8

4.2 Well Characteristics .................................................. 24

4.3 Well Siting ......................................................... 27

4.4 Operating Practices .................................................. 27

4.5 Well Plugging and Abandonment ......................................... 29

5. Potential and Documented Damage to USDWs ................................... 31

5.1 Injectate Constituent Properties ......................................... 31

5.2 Observed Impacts ................................................... 31

6. Best Management Practices .................................................. 33

6.1 Design and Construction ............................................... 33

6.2 Operating Pressure and Injection Rate .................................... 33

6.3 Maintenance ....................................................... 35

6.4 Mechanical Integrity .................................................. 35

7. Current Regulatory Requirements .............................................. 37

7.1 Federal Programs .................................................... 37

7.1.1 SDWA ...................................................... 37

7.1.2 Geothermal Steam Act .......................................... 38

7.2 State and Local Programs ............................................. 40

Attachment A: Factors Influencing Injectate ............................................ 42

Attachment B: State and Local Program Descriptions ..................................... 48

References ..................................................................... 62
September 30, 1999 1

ELECTRIC POWER GEOTHERMAL INJECTION WELLS

The U.S. Environmental Protection Agency (USEPA) conducted a study of Class V underground

injection wells to develop background information the Agency can use to evaluate the risk that these wells

pose to underground sources of drinking water (USDWs) and to determine whether additional federal

regulation is warranted. The final report for this study, which is called the Class V Underground Injection

Control (UIC) Study, consists of 23 volumes and five supporting appendices. Volume 1 provides an

overview of the study methods, the USEPA UIC Program, and general findings. Volumes 2 through 23

present information summaries for each of the 23 categories of wells that were studied (Volume 21 covers

2 well categories). This volume, which is Volume 17, covers Class V electric power geothermal injection

wells.

1. SUMMARY

Several dozen power plants located in four western states use geothermal energy to produce

electricity. At these power plants, hot (>100oC (212oF)) geothermal fluids that are produced from

subsurface hydrothermal systems serve as the energy source. Following the recovery of heat energy from

the produced fluids, the liquid fraction (if any) is reinjected into the same hydrothermal system through one

or more electric power geothermal injection wells. 

The temperature and chemical characteristics of geothermal fluids vary substantially. For example,

total dissolved solids (TDS) concentrations are about 1,000 mg/l at The Geysers (in northern California)

but about 250,000 mg/l at the Salton Sea geothermal field (in southern California). Despite these

variations, however, concentrations of some metals (e.g., antimony, arsenic, cadmium, lead, mercury,

strontium, zinc) and other constituents in the produced and injected geothermal fluids routinely exceed

primary maximum contaminant levels (MCLs) or health advisory levels (HALs) at one or more geothermal

fields. The specific constituents that exceed the standards and the magnitude of the exceedences varies

from site to site, with substantial variations observed within some fields. Sulfate, chloride, manganese, iron,

pH, and TDS also frequently exceed secondary MCLs. 

At some geothermal power plants, other fluids associated with power plant operation, such as

condensate and cooling tower blowdown, are injected along with the geothermal fluids. In a few

situations, supplemental water from additional sources, such as surface waters, storm waters, ground

water, and wastewater treatment effluent, is also injected. Concentrations of metals and other constituents

in these supplemental water sources are typically lower than in the geothermal fluids. An exception is

biological constituents (e.g., coliforms) that are sometimes present in injected surface water and treated

wastewater at concentrations above drinking water standards. The Geysers geothermal field in California

is the principle example of injection of surface waters and treatment plant effluent along with geothermal

fluids. Ground water is injected (in addition to geothermal fluids) to replace mass lost through condensate

evaporation at the Dixie Valley geothermal field in Nevada.

Geothermal fluids used for electric power generation are normally injected into the same

subsurface hydrothermal system from which they were produced. In fact, a majority of geothermal
1

 Uncontrolled release of gas and/or fluids from a well.

September 30, 1999 2

injection wells were drilled as production wells and subsequently converted to injection wells. Both

production and injection wells are carefully engineered because power production depends on the wells

and drilling costs are substantial, frequently exceeding $1 million per well.

Despite this care, well failures have occurred during both drilling and operation, due to the high

pressures and temperatures encountered, exposure of well equipment to the corrosive geothermal fluids,

and seismic activity that sometimes bends or breaks well casings. In some cases, well failures have

occurred at sites where no USDW is present. At a geothermal power plant site in Hawaii, however,

ground water monitoring data indicate that temperature, chloride concentrations, and chloride/magnesium

ratios increased following a blowout1 during drilling of an injection well. 

In general, electric power geothermal injection wells are not vulnerable to receiving spills or illicit

discharges because geothermal fluids are handled in closed piping systems that are managed as an integral

part of the power plant system. At some facilities, contaminants could be added to the injectate as a result

of leaks or spills of lubricants, fuels, or chemicals at the power plant site. For example, at sites that collect

and inject storm water, such as the power plants at The Geysers, injectate could include fuel, transformer

oil, lubricants, or chemicals that leak or spill on the site. To help prevent injectate contamination from such

sources, potential sources of leaks and spills are covered and/or are bermed separately from other parts of

the facility. In addition, oil/water separators are provided for some plant areas (e.g., the electric switch

yard) to provide further assurance that leaked or spilled oil is not injected.

According to the state and USEPA Regional survey conducted for this study, four states --

California, Utah, Hawaii, and Nevada -- have a total of 234 electric power geothermal injection wells,

with most of the wells reported in California (174, or 74 percent) and Nevada (53, or 23 percent). The

number of geothermal power injection wells is not expected to increase substantially in the foreseeable

future because gas-fired power plants can generally produce power at a lower cost than geothermal plants. 

However, if marketing of geothermal power as a “green” energy source is successful as the utility industry

is deregulated, a modest increase in the number of geothermal power plants and associated injection wells

may occur. Additional geothermal power plants are currently being considered in California and have

been proposed previously in Oregon. Seven additional injection wells have recently been permitted in

Hawaii.

Individual permits are required for electric power geothermal injection wells in all four states that

have this type of Class V injection well. The permits 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. They establish requirements and oversight for design and construction, operating

conditions, monitoring and mechanical integrity testing (MIT), financial responsibility, and plugging and

abandonment.
2

 Geothermal injection wells used in association with recovery of geothermal energy for purposes

other than electric power generation are covered separately in Volume 18 of this document.

September 30, 1999 3

2. INTRODUCTION

The existing UIC regulations in 40 CFR 146.5(e) define Class V wells to include “injection wells

associated with the recovery of geothermal energy for heating, aquaculture and production of electric

power.” Class V injection wells used in association with the generation of electric power using geothermal

energy sources are the subject of this information summary. These wells may inject three types of fluid: 1)

spent geothermal fluids; 2) condensate and other fluids from power plant operations; or 3) supplemental

water.

2

Injection of all three types of fluids into geothermal reservoirs is an integral part of geothermal

reservoir management and power production, because it serves to recharge the reservoir fluids, conserve

reservoir pressure to facilitate continued heat extraction, and/or prevent degradation of surrounding water

resources. An example of the features of a geothermal system is provided in Figure 1, which shows a

schematic cross section for the Steamboat Springs, Nevada, power plant of Caithness Power

Incorporated. As shown, production and injection wells tap the same geothermal zone but are separated

laterally to allow injected fluids to be re-heated by the geothermal source before they reach the production

wells. Figure 1 also shows the interconnection of ground water features and a wide range of both high and

low temperature geothermal features that are present from depth to the surface.

Figure 2 provides a second example of a cross sectional view of a geothermal system at the East

Mesa field in Imperial County, California. In this case, the geothermal fluids are extracted from a sandy

(rather than fractured rock) formation and separated from shallow ground water by a low permeability

confining clay layer. Due to the presence of ground water above the geothermal formation, injection (and

production) wells are cased from the surface to the injection zone, in contrast to Figure 1 where only the

injection well is continuously cased from the surface to the geothermal formation.
September 30, 1999 4

Source: Goranson, 1990

Figure 1. Geothermal Well System at Caithness Power Inc.’s

Steamboat Springs, Nevada, power plant
September 30, 1999 5

Source: Stollar, 1989

Figure 2. Geothermal System at East Mesa Field, Imperial County, California
September 30, 1999 6

3. PREVALENCE OF WELLS

For this study, data on the number of Class V electric power geothermal injection wells were

collected through a survey of state and USEPA Regional UIC Programs. The survey methods are

summarized in Section 4 of Volume 1 of the Class V Study. Table 1 lists the numbers of Class V electric

power geothermal injection wells in each state, as determined from this survey. The table includes the

documented number and estimated number of wells in each state, along with the source and basis for any

estimate, when noted by the survey respondents. If a state is not listed in Table 1, it means that the UIC

Program responsible for that state indicated in its survey response that it did not have any Class V electric

power geothermal injection wells.

Table 1. Inventory of Electric Power Geothermal Injection Wells

State

Documented 

Number of

Wells

Estimated Number of Wells 1

Number Source of Estimate and Methodology

USEPA Region 1 -- None

USEPA Region 2 -- None

USEPA Region 3 -- None

USEPA Region 4 -- None

USEPA Region 5 -- None

USEPA Region 6 -- None

USEPA Region 7 -- None

USEPA Region 8 

UT 4 4 Best professional judgment.

USEPA Region 9

CA 174 174 N/A

HI 3 3 N/A

NV 53 53 N/A

USEPA Region 10 -- None

All USEPA Regions

All States 234 234

1

 Unless otherwise noted, the best professional judgement is that of the state or USEPA Regional staff completing the survey

questionnaire. 

N/A Not available.
3

 Documented well information based on the California Department of Conservation, Division of Oil,

Gas and Geothermal Resources (CDOG). USEPA Region 9 inventory indicates 96 wells. Source of the

difference is not known, but the CDOG inventory is well documented.

September 30, 1999 7

Source: Geo-Heat Center, 1998

A total of 234 documented electric power geothermal injection wells exist in the United States. 

Information provided by state and USEPA Regional UIC programs indicates that such wells are currently

in use in California (174),3 Hawaii (3), Nevada (54), and Utah (4). Idaho also has geothermal wells, but

they are not active at this time.

The on-going deregulation of electric power generation and the associated effects on energy prices

and consumer choice of energy suppliers may cause either an increase or decrease the number of

operating facilities and injection wells. If demand for geothermal power declines, then existing facilities

(and wells) could close. If market prices and demand warrant the development of additional electricity

production from geothermal sources, existing geothermal fields could be developed further or additional

fields could be developed as well. Increases are anticipated for at least one current facility in Hawaii

where USEPA issued a permit (on June 16, 1999) that authorizes drilling of seven new geothermal

injection wells in addition to the three existing (permitted) wells at the facility. New fields are currently

proposed for development in northern California and additional geothermal resources potentially

appropriate for power production (with temperatures >100oC (212oF)) also exist in New Mexico,

Wyoming, Montana, Oregon, Washington, and Alaska (see Figure 3) (Geo-Heat Center, 1998).

Figure 3. Geothermal Resources in the U.S.
September 30, 1999 8

4. INJECTATE CHARACTERISTICS AND INJECTION

PRACTICES

4.1 Injectate Characteristics

This section summarizes data on the chemical characteristics of injectate. As noted in Section 1,

these wells routinely inject into the same formation from which the geothermal fluids were extracted. 

Because the characteristics of the producing geothermal resource play a dominant (although not exclusive)

role in determining the injectate characteristics, data on the characteristics of geothermal fluids are

presented for individual geothermal fields. The fields are grouped by state for consistency with other

sections of the document and not as a result of similar characteristics. In spite of the substantial variations

among fields, there are some similarities. In particular, geothermal fluids used in electric power generation

commonly exceed primary and secondary drinking water standards for TDS, fluoride, chloride, and sulfate

(USEPA, 1987).

C Hawaii. As shown in Table 2, data for the Puna geothermal project indicate that mean

concentrations of TDS, arsenic, barium, boron, cadmium, chloride, and iron exceed drinking water

standards and HALs (Puna Geothermal Venture, 1996).

C Nevada. As shown in Table 3, data from three geothermal fields in Nevada indicate that TDS,

arsenic, chloride, fluoride, and manganese concentrations and pH routinely exceed drinking water

standards. Exceedences of the primary or secondary standards have also been noted on occasion

for aluminum, lead, mercury, selenium, iron, and cadmium (Nevada Bureau of Water Pollution

Control, 1999).

C California. As shown in Table 4, data for the East Mesa field indicate that TDS and chloride

concentrations routinely exceed drinking water standards and that sulfate, iron, boron, and arsenic

concentrations and pH occasionally exceed drinking water standards or HALs (Stollar, 1989;

EMA, 1995). Data for the Salton Sea geothermal field shown in Table 5 indicate that TDS,

ammonium, barium, boron, cadmium, chloride, copper, iron, lead, manganese, strontium, and zinc

concentrations routinely exceed drinking water standards or HALs (Williams, 1989; Elders,

1992). For the Heber geothermal field, data presented in Tables 6a, 6b, and 6c indicate that

antimony, arsenic, barium, boron, chloride, lead, manganese, mercury, and strontium

concentrations and pH routinely exceed drinking water standards or HALs (SIGC, 1993; CDOG,

1998e). Data for The Geysers geothermal field (see Tables 7a-f) indicate that arsenic, boron,

sulfate, and mercury routinely exceed drinking water standards or HALs (Unocal, 1998;

CALPINE, 1994 and 1998; NCPA, 1988, 1995 and 1998; Crockett, 1990; FreeportMcMoRan, 1989; GEO Operator Corp., 1987 and 1989;
September 30, 1999 9

Table 2. Injectate Characteristics at the Puna Geothermal Field

Constituents

Drinking

Water

Standards

Health

Advisory Levels

Concentration

(mg/l unless otherwise noted)

Mean

95 % Confidence

limits

mg/l P/S* mg/l N/C** Lower Upper

 TDS 500 S -- 5680 4521 6839

 pH (Std. units) 6.5-8.5 S -- 4.85 4.67 5.02

 Arsenic 0.05 P 0.002 C 0.08 0.06 0.1

 Barium 2 P 2 N 2.45 1.77 3.13

 Boron -- 0.6 N 2.59 2.3 2.87

 Cadmium 0.005 P 0.005 N 0.03 0 0.09

 Calcium -- -- 49.65 38.27 61.03

 Chloride 250 S -- 3099 2469 3731

 Chromium 0.1 0.1 N 0.01 0.005 0.02

 Copper 1.3 -- 0.005 0 0.13

 Fluoride 4.0 -- 0.02 0 0.03

 Hydrogen Sulfide (H2S) -- -- 538 465 611

 Iron 0.3 S 0.64 0.49 0.79

 Lead 0.015 P 0.001 0 0.001

 Lithium -- -- 0.82 0.64 1

 Magnesium -- -- 0.25 0.16 0.33

 Manganese 0.05 S -- 0.2 0.16 0.24

 Mercury 0.002 P 0.002 N 0.001 0 0.002

 Nickel -- -- 0.003 0 0.008

 Potassium -- -- 397 316 479

 Silica (Si02) -- -- 286 234 336

 Silver 0.1 S 0.1 N 0.001 0 0.002

 Sodium -- -- 1740 1383 2099

 Sulfate (SO4

-2) 500 P -- 10.5 7.49 13.51

 Vanadium -- -- 0.001 0 0.001

 Zinc 5 S 2 N 0.01 0 0.21

Source: Puna Geothermal Venture, 1996

* Drinking Water Standards: P= Primary; S= Secondary

** Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
September 30, 1999 10 Table 3. Constituent Data for Selected Geothermal Wells in Nevada (concentrations in mg/l except as noted) Constituent Drinking Water Standards * Health Advisory Levels ** Desert Peak Beowawe Yankee/ Caithness Stillwater/Amor IV Injectate Formation Injectate Formation Injectate Formation Injectate Formation mg/l P/S mg/l N/C 6/16/94 3/14/95 12/31/96 10/21/97 12/18/76 12/31/96 6/20/86 5/28/93 5/1/81 6/30/95 7/12/96 2/13/97 10/31/97 8/22/88 10/30/89 TDS 500 S -- 9,840 9,296 10,541 9,728 7,500 930 1,946 2,607 2,090 4,493 4,460 4,390 4,490 5,000 7,440 pH (std units) 6.5 - 8.5 S -- 8.03 8.18 8.50 8.49 7.90 9.38 7.29 8.85 NR 7.91 7.53 7.44 7.45 8.76 8.3 Antimony 0.006 P 0.003 N NR NR NR NR NR NR 0.73 NR NR NR NR NR NR NR NR Arsenic 0.05 P 0.002 C 0.167 0.1 0.2 0.21 0.08 NR <0.61 2.96 NR 0.075 0.021 0.032 0.05 <0.49 <0.49 Barium 2 P 2 N 0.27 0.49 0.72 0.67 NR NR <0.61 0.08 NR NR NR NR 0.094 0.35 0.36 Beryllium 0.004 P 0.0008 C NR NR NR NR NR NR NR NR NR NR NR NR NR NR NR Boron -- 0.6 N 22.4 20 NR 20 18 NR 1.29 48.3 39 14.34 20.24 19.69 15.61 NR 38.34 Cadmium 0.005 P 0.005 N <0.05 <0.002 <0.02 0.02 NR NR <0.06 <0.001 NR NR NR NR NR <0.05 <0.05 Calcium -- -- 154 160 160 190 101 NR 10.49 9 7.2 67.68 81.65 75.06 73.32 67.31 101.27 Chloride 250 S -- 5,170 5,300 5,600 5,000 4,000 62 808 938 655 2,385 2,302 2,368 2,325 2,520 4,270 Chromium 0.1 P 0.1 N <0.01 <0.05 <0.02 0.08 NR NR <0.05 <0.005 NR NR NR NR NR <0.12 <0.12 Cyanide 0.2 P 0.2 N NR NR NR NR NR NR NR NR NR NR NR NR NR NR NR Copper 1.3 P -- <0.01 <0.02 <0.02 <0.02 NR NR <0.06 NR NR NR NR NR NR <0.06 <0.06 Fluoride 4.0 P -- 6.14 6 6.8 6.2 3.8 15.14 7.4 2.9 2.3 4.16 3.92 4.12 4.07 6.2 2.72 Iron 0.3 S -- 1.91 1.3 0.65 <1.0 NR NR <0.02 0.02 NR NR NR NR 0.159 <0.02 <0.02 Lead 0.015 P -- <0.02 <0.01 <0.02 0.02 NR NR <0.24 <0.005 NR NR NR NR NR <0.24 <0.24 Lithium -- -- NR NR NR 4.2 NR NR 1.32 NR 6.8 NR NR NR 2.084 2.01 6.71 Magnesium -- -- <0.01 0.7 <1.00 <2.00 0.35 NR 0.6 NR 0.29 0.82 NR 0.78 0.31 0.33 0.42 Manganese 0.05 S -- <0.01 0.85 0.09 0.08 NR NR 0.32 NR NR NR NR NR 4 <0.24 <0.24 Mercury 0.002 P 0.002 N <0.0003 <0.01 0.0016 <0.0005 NR NR NR 0.0005 NR NR <0.0005 <0.0005 <0.0005 NR NR Nickel 0.1 P 0.1 N NR NR NR NR NR NR NR <99.999 NR NR NR NR NR NR NR Nitrate 10 P -- <24 <0.45 <1.0 <2.25 0.12 NR NR 0.8 NR NR NR NR NR NR NR Potassium -- -- 331 360 370 320 227 NR 15.84 78 50 121.41 107.04 104.27 99.15 149.94 76.88 Selenium 0.05 P -- NR <0.001 <0.02 <0.02 NR NR NR <0.01 NR NR <0.0006 <0.0005 <0.0005 NR NR Silica -- -- NR 110 NR 95 198 371.34 86.18 402 301 193.87 173.91 193.75 143.678 NR 160.36 Silver 0.10 S 0.1 N <0.05 <0.005 <0.02 <0.02 NR NR <0.05 <0.005 NR NR NR NR NR <0.05 <0.05 Sodium -- -- 3,550 3,100 3,000 3,000 2,400 233.67 718.6 716 566 1,476 1,475 1,552 1,422 1,669 2,900 Strontium -- 17 N NR NR NR NR NR NR 0.26 NR NR NR NR NR NR NR NR Sulfate 500 P -- 102 100 110 99 122 NR 102 143 123 183 177 194 201 214 294 Thallium 0.002 P 0.0005 N NR NR NR NR NR NR NR NR NR NR NR NR NR NR NR Zinc 5 S 2 N <0.01 <0.02 <0.2 <0.2 NR NR <0.12 NR NR NR NR NR NR NR 0.2 Source: Nevada Bureau of Water Pollution Control, 1999
September 30, 1999 11 Table 3. Constituent Data for Selected Geothermal Wells in Nevada -- Con’t (concentrations in mg/l except as noted) Brady Drinking Water Standards * Health Advisory Levels ** Empire/Amor II Injectate Injectate Formation Dixie Valley Injectate Soda Lake II/Amor IX Injectate Constituent mg/l P/S mg/l N/C 12/18/96 12/18/97 11/20/96 10/23/97 11/25/98 10/16/97 7/18/95 10/25/95 7/15/96 12/9/96 10/29/97 TDS 500 S -- 4,180 3,974 2,802 2,792 1,847 2,000 5,480 5,425 5,390 5,930 5,430 pH (std units) 6.5 - 8.5 S -- 7.38 6.79 8.84 8.8 8.69 9.11 6.29 5.81 6.38 5.69 6.1 Antimony 0.006 P 0.003 N NR NR NR NR 0.026 NR NR NR NR NR NR Arsenic 0.05 P 0.002 C <0.003 <0.01 NR 0.216 0.084 0.98 NR 0.09 0.22 <0.054 <0.007 Barium 2 P 2 N 0.18 0.23 0.062 0.063 0.38 0.06 NR 0.244 NR 0.128 0.31 Beryllium 0.004 P 0.0008 C NR NR NR NR <0.005 NR NR NR NR NR NR Boron -- 0.6 N 6.1 5.6 5.1 5.065 13 13.85 12.52 12 11.1 10.1 11.6 Cadmium 0.005 P 0.005 N <0.001 <0.01 NR NR <0.005 <0.005 NR <0.005 NR <0.005 <0.004 Calcium -- -- 150 180 50 48.153 110 10.09 111.52 121 NR 120 104 Chloride 250 S -- 2,131 2,200 1,117 1,148 3,800 580 2,974 2,910 NR 2,830 2,940 Chromium 0.1 P 0.1 N <0.005 <0.01 NR NR <0.005 <0.05 NR <0.005 NR NR <0.005 Cyanide 0.2 P 0.2 N NR NR NR NR NR NR NR NR NR NR NR Copper 1.3 P -- NR <0.01 NR NR <0.005 <0.05 NR 0.037 NR <0.011 <0.009 Fluoride 4.0 P -- 4.08 3.3 6.96 6.82 2.5 16.29 0.91 1.21 1.14 1.05 0.94 Iron 0.3 S -- 0.87 3.1 0.122 0.006 0.06 0.03 3.8 1.73 NR 0.283 0.267 Lead 0.015 P -- <0.005 <0.01 NR NR <0.005 <0.05 NR <0.04 NR <0.077 0.01 Lithium -- -- NR NR NR NR 2.9 2.61 NR 2.92 NR 3.16 2.76 Magnesium -- -- 1 0.73 0.08 0.05 4.5 <0.01 0.57 0.75 NR 0.71 0.62 Manganese 0.05 S -- 0.12 0.16 NR 0.007 0.029 <0.05 NR 0.4 NR 0.13 0.096 Mercury 0.002 P 0.002 N <0.0005 <0.0005 NR NR <0.0005 <0.0005 NR <0.007 NR <0.0007 0.003 Nickel 0.1 P 0.1 N NR NR NR NR 0.017 NR NR NR NR NR NR Nitrate 10 P -- NR <2.5 NR NR <4.5 <1.0 NR NR NR <0.13 <2.4 Potassium -- -- 110 110 69.47 64.8 170 80.56 180.66 178 NR 183 165 Selenium 0.05 P -- <0.001 <0.01 NR NR <0.005 <0.1 NR NR NR NR <0.011 Silica -- -- 118 177 227.6 227.822 131 672.46 214 171 NR NR 253 Silver 0.10 S 0.1 N <0.005 0.01 NR NR <0.005 <0.01 NR 0.077 NR <0.003 <0.008 Sodium -- -- 1,280 1,300 841.4 895.469 2,300 520.87 NR NR NR NR 1,680 Strontium -- 17 N NR NR NR NR NR NR NR 5.00 NR 5.1 NR Sulfate 500 P -- 180 200 448 470 100 239 70 73 NR 77 67.7 Thallium 0.002 P 0.0005 N NR NR NR NR <0.005 NR NR NR NR NR NR Zinc 5 S 2 N NR 0.29 NR 0.02 <0.05 <0.05 NR <0.005 NR <0.025 <0.01 Source: Nevada Bureau of Water Pollution Control, 1999
September 30, 1999 12 Table 4. Constituent Data for the East Mesa Geothermal Field, California Constituents Drinking Water Standards * Health Advisory Levels** 1995 Data (1) Concentrations in mg/l except where noted 1988 Data (2) Concentrations in mg/l except where noted Ormesa I Ormesa IE Ormesa IH Ormesa II OG-I Plant OG-II Plant OG-IE Plant mg/l P/S mg/l N/C Average values for production wells 88-31 72-31 38-30 14-5 84-1 18-5 45-6 21-6 14-32 TDS 500 S -- 7,680.00 6,468.08 5,997.57 7480 5064 1978 758 6812 6722 7794 7018 6632 EC (μmhos/cm) -- -- 7270 12100 10716.67 9930 pH (Std. Units) 6.5-8.5 S -- 6.47 7.12 6.09 8.02 8.4 8.3 9 8.6 8.2 8.7 8.4 8.3 8.6 Arsenic 0.05 P 0 C <0.60 0.00 ND 0.39 Barium 2 P 2 N <0.61 0.21 0.75 0.69 Boron -- 0.6 N 7.34 ND 8.25 ND Calcium -- -- 37.69 389.00 51.35 32.51 29.92 20.25 6 0.593 4 1.52 13.62 20.17 15.59 21.05 Chloride 250 S -- 2037.9 4,090.00 3,398.00 3087.14 4099 2638 538 411 3699 3623 4248 3818 3648 Fluoride 4 P -- 2.03 1.14 1.69 2.4 Iron 0.3 S -- <0.22 15.20 0.12 0.29 Lithium -- -- 3.76 6.72 Magnesium -- -- 2.53 209.00 2.70 1.64 3.74 5.064 0.395 6 0.23 2.725 0.672 2.338 2.807 Potassium -- -- 78.89 24.70 136.21 144 119.7 96.2 27.7 30.3 156.7 201.7 233.8 161.4 Silica (SI02) -- -- 158.57 165.44 Sodium -- -- 1566.32 2080 2357.72 1853.67 2790 1914. 2 714.1 277 2616 2433 2923 2632 Strontium -- 3.63 5.80 Sulfate (SO4-2) 500 P -- 123.6 700 95.33 63.57 97.2 111.4 191.9 11.4 95.4 127.7 109.1 98.3 66.3 Zinc 5 S – <0.07 0.85 ND ND Sources: (1) R.L. Stollar & Associates, Inc, 1989. (2) Environmental Management Associates, 1995. * Drinking Water Standards: P= Primary; S= Secondary ** Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
September 30, 1999 13 Table 5. Constituent Data for the Salton Sea Geothermal Field, California Constituents Drinking Water Standards Health Advisory Levels Representative Flash-corrected Brine Analysis Concentrations in ppm unless otherwise noted Hypersaline Brines (1-4) Low TDS Brines (5-8) mg/l P/S mg/l N/C (1) (2) (3) (4) (5) (6) (7) (8) Temperature(oC) -- -- 305 330 300 295 240 230 190 200 Well Depth (meters) – -- 1,850-1,890 2,500-3,22 0 660-1,07 0 700-1,07 0 570-720 710-940 ?-520 410-990 TDS (wt %) 500 S -- ~25.6 ~26.5 ~21.4 ~20.0 ~12.7 ~6.2 ~3.5 ~1.3 pH (Std. units) 6.5-8.5 S -- 5.4 5.1 5.2 5.3 6.9 7.6 Ammonium (NH4+) -- 30 N 333 330 339 341 103 321 Barium 2 P 2 N 203 353 ** 183 156 45 3 0.7 Boron -- 0.6 N 257 271 204 197 92 100 32 Bromide -- -- 99 111 95 78 24 15 10 Cadmium 0.005 P 0.005 N 2.2 2.3 1.0 1.4 ND ND Calcium -- -- 27,400 28,500 22,800 20,900 11,000 2,520 1,130 117 Chloride 250 S -- 151,000 157,500 128,000 116,000 85,000 31,000 19,700 6,900 Copper 1.3 -- 5.9 6.8 2 ND ND Hydrogen Sulfide (H2S) -- -- 15 10 15 20 Iron 0.3 S -- 1560 1,710 582 969 65 86 0.7 25 Lead 0.015 P -- 100 102 69 67 2.6 ND Lithium -- -- 194 209 157 152 93 55 40 9 Magnesium -- -- 33 49 19 33 54 74 24 Manganese 0.05 S -- 1450 1,500 801 855 >255 >120 102 Potassium -- -- 16700 17,700 12,500 11,800 5,000 2,480 1,250 297 Silica (SI02) *** -- -- >461 >588 >336 >404 >255 >120 102 Sodium (wt ppm) -- -- 53000 54,800 46,200 41,400 25,000 15,000 10,600 4,800 Strontium – 17 N 411 421 376 345 513 112 85 10 Sulfate (SO4-2) 500 P -- 65 53 ~100 53 53 621 440 Zinc 5 S 2 N 518 507 321 323 11 ND Sources: Elders, et. al. 1992; Williams & McKibben, 1989 - For Drinking Water Standards: P = Primary, S = Secondary - For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk * Concentrations corrected for ~5% dilution by drilling fluid ** Probable contamination from drilling fluid *** Silica values low due to precipitation prior to sampling Samples (1) Salton Sea Scientific Drilling Project State 2-14 (12) -1985 (2) Salton Sea Scientific Drilling Project State 2-14 (3) - 1986 * (3) Commercial Well #11b (4) Commercial Well #10 (5) Woolsey Well # 1 (6) Commercial Well #B1 (7) I.I..D. Well #3 (8) Commercial Well # 113
September 30, 1999 14

Table 6a. Constituent Data for the SIGC Plant, Heber Geothermal Field, California

Constituents

Drinking Water

Standards *

Health

Advisory

Levels **

SIGC ( Second Imperial Geothermal Company) Binary

Plant

(Concentrations in ppm except as noted)

Production Wells Injection Wells

HGU

210

HGU

201

HGU

204

HGU

253 HGU 155

HGU 170 

(Holtz 2)

 TDS 500 S -- 13,270 13,140 12,660 13,592 11,300 16,330

 EC (μmhos/cm) -- 21,000

 pH (units) 6.5-8.5 S -- 6.2

 Antimony 0.006 P 0.003 N ND 1.91

 Arsenic 0.05 P 0.002 C 0.12 0.11 0.08 0.1 <.05

 Barium 2 P 2 N 2.83 2.85 2.38 2.99 0.23 3

 Bicarbonate -- -- 54 38 37 35 52.98

 Boron -- 0.6 N 5.51 5.42 4.82 243.8 4.3 12

 Calcium – -- 977.92 990.91 964.82 995.29 1078 1062

 Cesium -- -- 12.18 NA

 Chloride 250 S -- 7,662 7,520 7,343 7,893 7,900 8,242

 Iron 0.3 S -- 0.22 0.17 0.25 0.35 6.88 0.4

 Lithium -- -- 5.75 5.74 4.82 5.55 3.45 4.1

 Magnesium -- -- 2.1 2.25 1.89 1.55 7.13 23

 Manganese 0.05 S -- 0.13 0.13 0.12 0.13 0.52 0.9

 Potassium -- -- 340.09 347.23 287.96 329.59 419 231

 Silica (SI02) -- -- 217.29 232.11 128.88 243.8 187

 Sodium -- -- 3,957.92 4,109.15 3,745.84 3,889.33 3,378 4,720

 Strontium -- 17 N 38.03 39.07 34.5 36.98 40.31 42

 Sulfate 500 P -- 105 117 142 98 64 148

 Zinc 5 S 2 N 0.08 ND ND 0.01 0.17 0.1

Source: CDOG, 1998e.

* Drinking Water Standards: P= Primary; S= Secondary

** Health Advisory Levels: N= Noncancer
September 30, 1999 15

Table 6b. Constituent Data for the SDG&E Plant, Heber Geothermal Field, California

Constituents

Drinking

Water

Standards *

Health

Advisory

Levels **

SDG&E POWER, Binary Plant, HEBER GEOTHERMAL FLUID 

TYPICAL BRINE ANALYSIS

Production Wells (wt ppm)

mg/l P/S mg/l

N/

C Well not specified

HGU

101

HGU

102

HG

U

103

HGU

104

HGU

105

HGU

106

 Sampling Date -- -- 8/23/7

4

11/18/7

4

10/17/7

4

12/4/7

4

 pH (Std. units) 6.5-8.5 S -- 6.60 6.30 5.80 6.45

 TDS 500 S -- 14,110 14,470 14,310 14,195

 Aluminum 0.05 -

0.2

S -- 31 15 28 1.0

 Antimony 0.006 P 0.00

3

N 0.05 0.05 0.05 0.05 0.051 0.05

 Arsenic 0.05 P 0.00

2

C 0.167 0.207 0.14

6

0.106 0.119 0.151

 Barium 2 P 2 N 3 5 5 5 0.155 6.536 0.05

0

0.216 3.734 0.140

 Bicarbonate ( HCO3

-1) -- 64

 Boron -- 0.6 N 7.2 5.2 5.7 4.0 6.048 9.723 5.59

2

2.605 6.531 6.592

 Bromide -- -- 11.7 10.9 8.4 1.9 11.1 11.9

 Calcium -- -- 656 859 2,063 844 810 1,004 1,00

6

885 915 864

 Carbonate (CO3

-2) -- -- 0

 Cesium -- -- 0.600 0.881 0.62

4

0.583 0.654 0.672

 Chloride 250 S -- 7,246 7,600 7,764 7,363

9,133

18,47

2

9,11

1

9,143 10,80

8

13,926

 Copper 1.3 P -- 0.5 0.6 1.1 0.8

 Fluoride 4.0 P -- 1.5 1.6 2.2 3.0

 Iodide -- -- 0.625 0.620 0.52

2

0.464 0.403 0.762

 Iron 0.3 S -- 6 14 34 68 0.100 0.161 0.35

2

0.100 0.276 0.301

 Lead 0.015 P -- 0.3 1.3 1.3 0.6 0.005 0.095 0.00

4

0.010 0.050 0.089

 Lithium -- 5 3.8 5 4 8.504 12.98

2

7.84

6

10.14

7

7.664 7.021

 Magnesium -- 3.4 5.9 3.8 5.9 1.101 1.421 1.60

9

1.507 1.328 1.304

 Manganese 0.05 S -- 0.6 0.9 3.1 3.1 0.130 0.123 0.15

1

0.121 0.102 0.050

 Mercury 0.002 P 0.00

2

N 2.790 0.002 3.41

7

2.704 0.002 2.799

 Potassium -- -- 250 238 250 228 415 398 402 372 393 385
Constituents

Drinking

Water

Standards *

Health

Advisory

Levels **

SDG&E POWER, Binary Plant, HEBER GEOTHERMAL FLUID 

TYPICAL BRINE ANALYSIS

Production Wells (wt ppm)

mg/l P/S mg/l

N/

C Well not specified

HGU

101

HGU

102

HG

U

103

HGU

104

HGU

105

HGU

106

September 30, 1999 16

 Rubidium -- -- 3.101 1.800 1.91

1

1.608 1.839 2.106

 Silica (SI02) -- -- 214 281 281 294 223 240 205 81 247 227

 Silver 0.1 S 0.1 N ND ND ND ND

 Sodium -- -- 3,750 4,313 4,219 4,312 5,052 4,397 4,00

2

3,557 4,333 3,952

 Strontium -- 17 N 39 37 36 38 28.9 42.2 34.7 27.0 34.1 34.8

 Sulfate (SO4

-2) 500 P -- 74 88 81 80 115.2 40.5 54.2 67.2 69.6 76.9

 Zinc 5 S 2 N 0.3 0.7 0.6 0.3

Source: Second Imperial Geothermal Company, 1993.

* Drinking Water Standards: P= Primary; S= Secondary

** Health Advisory Levels: N= Noncancer
September 30, 1999 17

Table 6c. Constituent Data for the HGC Plant, Heber Geothermal Field, California

Constituents Drinking Water

Standards *

Health

Advisory

Levels **

Heber Geothermal Company, Flash Plant

Concentrations in mg/l unless otherwise noted

mg/l P/S mg/l N/C Injection Wells

HGU 53 HGU 55 HGU 57 HGU 5

 Sampling Date -- -- 3/29/85 3/29/85 3/29/85

 TDS 500 S -- 17,000

 pH (Std. Units) 6.5-8.5 S -- 8

 Antimony 0.006 P 0.003 N 2.03 1.98 1.75

 Arsenic 0.05 P 0.002 C <0.05 <0.05 <0.05

 Barium 2 P 2 N 0.56 1.12 0.74 4.5

 Bicarbonate -- -- 32.0

 Boron -- 0.6 N 7.8 8.1 6.3 5.6

 Calcium -- -- 1022 756 575 940

 Cesium -- -- 13.28 13.3 12.32

 Chloride -- -- 8,650 8,756 7,185 8,200

 Chromium 0.1 P 0.1 N 0.66 0.58 0.46

 Copper 1.3 P -- 0.42 0.17 0.71 0.02

 Fluoride 4 P -- 0.65 0.55 0.55 2.0

 Iron 0.3 S -- 20.25 19.50 6.88 0.12

 Lead 0.015 P -- 1.43 0.35 1.59 ND

 Lithium -- -- 8.65 8.13 8.79 7.7

 Magnesium -- -- 5.38 8.50 1.75 1.6

 Manganese 0.05 S -- 1.07 1.46 0.46 0.12

 Mercury 0.002 P 0.002 N 0.002 0.011 0.005

 Potassium -- -- 428 441 313 310

 Sodium -- -- 4,072 4,150 3,494 4,300

 Strontium -- 17 N 50.45 58.39 44.47 35

 Sulfate 500 P -- 25 26 59 68.0

 Zinc 5 S 2 N 0.21 0.15 1.38

Source: CDOG, 1998e.

* Drinking Water Standards: P= Primary; S= Secondary

** Health Advisory Levels: N= Noncancer
September 30, 1999 18 Table 7a. Constituent Data for The Geysers Geothermal Field, California Constituents Drinking Water Standards * Health Advisory Levels ** SOUTHEAST GEYSERS: UNOCAL CORPORATION Concentrations in mg/l unless otherwise noted 1997 Grab Sample Analyses Average Condensate Analyses 1991-1996 mg/l P/S mg/l N/ C Unit s 5&6 Units 7 & 8 Units 9&10 Units 11 Unit 12 Unit 14 Uni t 17 Uni t 18 Unit 20 Unit 5&6 Unit 7&8 Unit 9&10 Unit 11 Unit 12 Unit 14 Unit 17 Unit 18 Unit 20 EC (usiemens) – -- 8,380 6900 6930 2940 1180 0 4280 260 6500 1810 600 6,808 6,220 2,756 9,246 3,189 329 7,049 693 800 Ammonia (dissolved) – 30 N 1,200 800 790 12 1400 560 51 100 180 8.6 757 705 11 1,046 263 39 692 59 34 Arsenic (ppm/w) 0.05 P 0.002 C 0.28 0.28 0.29 0.62 0.029 0.19 0.015 0.13 0.5 0.38 0.30 0.25 0.44 0.13 0.64 0.30 0.71 1.19 0.36 Boron (ppm/w) – 0.6 N 200 230 230 150 140 150 17 96 200 99 202 173 128 124 146 59 279 201 101 Nitrate 10 P -- 0.05 <0.03 <0.03 <0.03 0.08 0.13 <0.0 3 0.05 0.14 1.1 4 3 7 6 0.92 0.73 2 1 0.15 Nitrite 1 P -- 0.12 0.13 0.11 1.2 <0.03 0.34 <0.0 3 0.13 0.03 0.04 0.31 1.23 3 0.66 0.35 0.15 0.80 0.26 0.04 Sulfate 500 P -- 1,900 1,100 1,300 550 2,000 1,300 38 280 660 170 852 1,387 389 2,156 1,131 48 2,326 218 128 Source: UNOCAL Corporation, 1998. * Drinking Water Standards: P = Primary, S = Secondary ** For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
September 30, 1999 19

Table 7b. Constituent Data for The Geysers Geothermal Field, California -- Con’t 

Constituents

Drinking

Water

Standards *

Health

Advisory

Levels **

CALPINE Geysers Company 

Concentrations in mg/l, unless otherwise noted

(1) SMUDGEO 1 

Power Plant

Annual

Injectate

Analysis (2)

Pacific Gas

and Electric

Unit 13 

(2)

SMUDGEO 1

Power Plant

Annual

Injectate

Analysis (3)

Aidlin

Power Plant

Reinjectate

mg/l P/S mg/l (4)

N/

C

Unit 13 

Injectio

n

Unit 16

Injection

 Sampling Date -- -- 12/22/92 12/22/92 12/29/93 12/29/93 12/30/97 11/23/98

 EC (μmhos/cm) – -- 450 620 560 614 8,860

 Ammonia -- 30 N 45 1.0*** 1,280

 Arsenic 0.05 P 0.00

2

C 0.42 0.085 0.32 0.50 ND 0.053

 Boron -- 0.6 N 77 32 110 94 190 95

 Calcium -- -- ND

 Calcium

Carbonate

-- -- ND ND ND

 Chloride 250 S -- ND ND 1.5

 Magnesium -- -- ND ND ND

 Nitrate 10 P -- 0.76 0.37 0.13 ND 0.12 2.3

 Nitrite 1 P -- 0.03 8.5

 Sulfate 500 P -- 88 120 97 150 260 1,900

Sources:

(1) CALPINE Geysers Company, 1993.

(2) CALPINE, 1994.

(3) CALPINE, 1998. 

(4) CALPINE, 1999. 

* Drinking Water Standards: P = Primary, S = Secondary

** For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk

*** Non-distilled sample
September 30, 1999 20

Table 7c. Constituent Data for The Geysers Geothermal Field, California -- Con’t

Constituents

Drinking

Water

Standards *

Health

Advisory

Levels **

Northern California Power Agency

Concentrations in mg/l unless otherwise noted

Effluent Monitoring Data (1)

Condensate

Analysis (2)

1994 1997 1988

mg/l P/S mg/l N/C

Unit

1

Unit

2

Unit

3

Unit

4

Unit

1

Unit

2

Unit

3

Unit

4 Plant 1 Plant 2

 EC

(μmhos/cm)

– -- 439 456 539 687 333 264 666 736 108 384

 Ammonia – 30 N 56.00 52.92 62.31 81.77 41.3 37.4 82.7 92.9 17.17 41.95

 Arsenic 0.05 P 0.002 0.06 0.06 0.01 0.09 0.17 0.10 0.02 0.04 0.128 0.033

 Boron -- 0.6 N 64.01 87.59 31.46 57.93 81.4 132.6 43.8 53.1 59.5 21.9

 Nitrate 10 P -- 3.76 3.39 3.44 1.92 1.7 0.9 1.2 1.8 0.071 1.54

 Nitrite 1 P -- 0.242 0.198 0.288 0.19 0.07 0.05 0.28 0.28 0.027 0.08

 Sulfate 500 P -- 124 113 160 209 87.7 64.6 265.9 290 5.61 88.5

Sources:

(1) Northern California Power Agency, 1995 & 1998.

(2) Northern California Power Agency, 1988. 

* Drinking Water Standards: P = Primary, S = Secondary

** For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
September 30, 1999 21 Table 7d. Constituent Data for The Geysers Geothermal Field, California -- Con’t Constituents Drinking Water Standards * Health Advisory Levels ** GEO Operator Corporation (a.k.a. GRI Operator, a.k.a. Thermogenics) Unit 15, Chemical Analysis of Condensate Concentrations in mg/l, unless otherwise noted mg/l P/S mg/l N/C Sampling Date -- -- 10/15/79 11/24/80 10/13/81 10/15/81 5/19/82 10/21/82 11/1/82 10/18/83 8/17/84 2/25/85 10/7/86 11/14/88 TDS 500 P -- 1,200 160 1,500 3,200 1,900 1,138 2,660 EC (μmhos/cm) -- -- 850 1,300 1,100 1,200 1,700 1,950 1,680 2,300 2,800 pH (Std. Units) 6.5-8.5 P -- 7.3 7.3 6.5 6.5 7.3 5.8 6.9 7.0 4.20 Aluminum 0.05 - 0.2 S -- 0.06 0.28 0.22 0.6 <0.5 ND Ammonia -- 30 N 96.0 115.0 130 140 150 230 201 280 430 280 240 265 Arsenic 0.05 P 0.002 C 0.44 0.62 0.41 0.36 0.19 ND 0.04 Barium 2 P 2 N <0.2 <0.3 ND Bicarbonate (HCO3-1) -- -- 12 57 Boron -- 0.6 N 160 200 160 180 140 280 133 180 270 130 114.77 115.77 Calcium -- -- <1.0 <1.0 3.8 <1.0 2.7 1.2 #0.1 1.42 Calcium Carbonate (Total hardness) -- -- 12 <1 6.8 10 47 Chloride 250 S -- 1.1 1.8 < 2.0 4.9 <0.5 5 #1 16.00 Chromium 0.1 P 0.1 N <0.005 <0.005 0.012 ND Fluoride 4 P -- 0.1 0.1 Iron 0.3 S -- 0.21 0.35 3.1 3.5 0.29 3.98 Lead 0.015 P -- <0.05 <0.05 <0.05 <0.01 <0.005 ND Lithium – -- <0.01 <0.01 ND Magnesium -- -- <0.5 <0.5 0.6 <1.0 0.5 0.07 1.04 Manganese 0.05 S -- 0.10 0.025 ND Mercury 0.002 P 0.002 N 0.008 0.006 0.43 0.0016 0.017 Nitrate 10 P -- <0.10 0.25 1.6 1.9 <0.10 3.9 1.6 <0.1 <0.10 Nitrite 1 P -- 0.05 0.93 6.4 1.5 0.33 2.3 .99 Potassium -- -- 0.34 0.48 0.2 #0.05 ND Silica (SI02) -- -- 2.3 2.1 2.5 2.5 0.22 <0.1 4.0 <0.2 1.85 Silver -- 0.1 N ND Sodium -- -- 13.0 22.0 47 3.0 <1.4 2.3 1.8 26.99 Strontium – 17 N 0.01 Sulfate 500 P -- 210 390 450 470 660 840 696 1,100 1,300 790 732 1,085 Sulfide – -- 0.01 0.01 <0.05 < 5 Zinc 5 S 2 N 0.06 <0.050 0.23 0.16 Source: CDOG, 1998d; GEO Operator Corporation, 1987 & 1989; California Regional Water Quality Control Board, 1999. * Drinking Water Standards: P = Primary, S = Secondary

** For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
September 30, 1999 22

Table 7e. Constituent Data for The Geysers Geothermal Field, California -- Con’t

Constituents

Drinking Water

Standards *

Health

Advisory

Levels **

Concentration in mg/l unless otherwise noted

The

Geysers

(1)

West Ford Flat

(2)

Bear Canyon

(3)

mg/l P/S mg/l N/C Injectate

Steam

Condensate

 Sampling Date -- -- 3/27/89 -

3/30/89

1/12/89

 TDS 500 S -- 640 192

 EC (μmhos/cm) – – 280 200

 pH (Std. units) 6.5-8.5 S -- 7.2 8.4

 Aluminum 0.05 -

0.2

S -- 0.1

 Ammonia -- 30 N 14

 Arsenic 0.05 P 0.002 C 0.95 1.4

 Boron -- 0.6 N 160 105 22

 Calcium -- -- 0.5

 Calcium Carbonate -- -- 79 54

 Chloride 250 S -- 1.3 0.1

 Fluoride 4.0 P -- <0.1

 Iron 0.3 S -- 0.9

 Magnesium -- -- 1.6

 Mercury 0.002 P 0.002 N <0.001

 Nitrate 10 P -- 1.2

 Nitrite 1 P -- 0.07

 Potassium -- -- <0.5

 Silica (SI02) -- -- 0.8 0.1 

 Sodium -- -- 1.4

 Sulfate 500 P -- 52 38 50

 Sulfide -- -- 0.2

Sources: 

(1) Crockett & Enedy, 1990.

(2) Freeport-McMoRan Resource Partners / Geysers Geothermal Company. 1989.

(3) Freeport-McMoRan Geothermal Resources Company, Geysers Geothermal Company, 1989.

* Drinking Water Standards: P = Primary, S = Secondary

** For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
September 30, 1999 23

Table 7f. Constituent Data for The Geysers Geothermal Field, California -- Con’t

Constituents

Drinking

Water

Standards *

Health

Advisory

Levels **

Southeast Geysers Effluent Pipeline Project

Estimates of Injection Water 1995

(1)

Southeast

Treatment Plant

(SETP) Reservoir

(2,3)

Lake Intake

Pump System

(LIPS) 

mg/l P/S mg/l N/C Lake (3)

WWTP

Effluent

 Blended 

Lake /

Effluent

 Sampling Date -- -- 1995 2/11/98 8/28/98 9/7/98

 Flow, MGD -- -- 3.38 1.84

 Temperature (oC) – – 6-28 6-26 6.26

 TDS 500 S -- 134-390 348-390 228 346 232

 Suspended Solids -- -- 5-50 10-30 20

 EC (μmhos/cm) – – 69-364 541 362

 pH (Std. Units) 6.5-8.5 S -- 7-9.3 6.5-8.5 7.9 7.9 7.1

 Turbidity (NTU) 0.5-1.0 P -- 32 20

 BOD 3-9 10-30 11

 Total Coliforms per 100 100 3000 700

 Fecal Coliforms per 100 100 3000 60

 Alkalinity (CaCO3) -- -- 67-170 170-240 143 171 125

 Hardness (CaCO3) -- -- 94-170 150-190 137 61

 Total Salts -- -- 140-260 500-600 325

 Aluminum 0.05 - S -- 1

 Bicarbonate (HCO3

-1) -- -- 80-210 210-290 173 209

 Boron -- 0.6 N 153

 Calcium -- -- 16-33 30-40 26 33 25

 Chloride 250 S -- 54 20

 Fluoride 4 P -- ND ND

 Iron 0.3 S -- 1.44 0.96

 Magnesium -- -- 12-21 20-25 18 19 14

 Manganese 0.05 S -- 0.069 0.12

 Nitrate 10 P -- 14 1.1

 Oxygen (dissolved) -- -- 0.1-17 1-10 7.2

 Potassium -- -- 10 3.6

 Silver -- 0.1 N 14 14

 Sodium -- -- 56 21

 Sulfate 500 P -- 68 14

 Zinc 5 S 2 N 0.038

Source: 

(1) ESA. 1994.

(2) Alpha Analytical Laboratories, 1995 & 1998.

(3) Lake Labs, 1998
September 30, 1999 24

CRWQCB, 1999). Data on the quality of the treatment plant effluent injected at The

Geysers shows no exceedences of primary drinking water standards for inorganic

constituents (Alpha Analytical Laboratories, 1995). Data for both the treated

wastewater and water from Clear Lake that is injected at The Geysers show

exceedences of the primary drinking water standard for fecal coliform (Lake Labs,

1998).

When interpreting any of these data, it is important to note that the data do not include

measurements for all constituents of potential interest at all sites. Further, the available data are based

on samples of geothermal power plant fluids collected at various (often not well defined) points

between the production well(s) and the injection well(s). As a result, there is some uncertainty with

respect to the exact concentrations of constituents in injected fluids.

The chemical characteristics exhibited by the injected fluids are primarily (although not

exclusively) determined by the characteristics of the geothermal resource, the technologies used to

produce the power, the chemicals used in conjunction with power plant operations (e.g., for treatment

of steam or geothermal fluid), and the characteristics of supplemental water sources (in any). Each of

these four factors is discussed in Attachment A of this volume.

4.2 Well Characteristics

Design, construction, operation, and maintenance of electric power geothermal injection wells is

highly dependent on site-specific conditions, such as site geology, formation pressure, and geothermal

fluid characteristics. Injection wells range from about 500 to 12,000 feet (Land, 1997). Bottom hole

completions, either open hole or with slotted or perforated casing, generally range in size from 6 to

12.25 inches in diameter and generally are located below the lowermost USDW (unless the geothermal

resource itself meets the definition of a USDW). The use and type of casings or liners often depend

upon the characteristics of the subsurface formation. If the subsurface formation may collapse when

wet, a slotted liner or perforated casing may need to be installed in the well. If the geothermal fluids are

highly corrosive, casing materials need to be corrosion resistant. In situations where it is important to

prevent leakage into unintended zones (e.g., USDWs), the well casing needs to be encased with

specialized cements able to withstand the pressure and temperature conditions found in the well (Land,

1997). Wellhead assemblies also vary depending on local geologic conditions, including the formation

pressure that must be overcome to inject fluids (USEPA, 1987). During initial well drilling and

subsequent work-overs or repairs, injection wellheads are equipped with blowout prevention

equipment (BOPE) that shuts down well operations during abnormal flow conditions caused by

malfunctions and/or unstable down-hole well conditions. The specific BOPE employed depends on

site-specific factors such as the maximum anticipated pressure, temperature, and corrosiveness of the

geothermal fluids at the wellhead.

Figures 4 and 5 show examples of geothermal injection wells associated with electric power

generation. Several features distinguish geothermal injection wells from other Class V well types. 
September 30, 1999 25

Source: CDOG, 1998c

Figure 4

Example Schematic of Geothermal Injection Well Associated With

Electric Power Generation
September 30, 1999 26

Source: Second Imperial Geothermal Company, 1993

Figure 5

Example Schematic of Geothermal Injection Well Associated With

Electric Power Generation
4

 At The Geysers, for example, some wells are routinely used for injection during the winter when

rainfall is high and more supplemental water is available. The same wells are also used for production

during the summer when the quantity of fluids available for injection is lower and the demand for electric

power output is higher (Dickerson, 1998).

September 30, 1999 27

These injection wells are typically drilled to greater depths, are cemented from the bottom of the casing

shoe to the surface, and use thicker casings than most other Class V wells.

4.3 Well Siting

On the surface, injection wells may be sited individually or on well pads along with other

injection and/or production wells (to minimize surface disturbance). For example, Figure 6, which

shows injection well locations at the Heber geothermal field in Imperial County, California, illustrates the

use of directional drilling that enables surface locations to be clustered while bottom hole locations are

distributed within the reservoir. In this example, clustering of the wells at a limited number of surface

locations minimizes the amount of land removed from agricultural production as a result of geothermal

activities and enables more cost-effective control of access to the well location.

Underground, the well locations for injection of geothermal fluids are selected to protect the

geothermal resource by recharging fluids to the formation at locations where the heat content of the fluid

will be restored before the fluid is again extracted through a production well (Stock, 1990; Crockett,

1990; Defferding, 1978; and Vetter, 1979). In practice, many wells used for injection were initially

drilled as production wells, and so siting consists not of locating the well but rather selecting which

existing well to use for injection.

4.4 Operating Practices

Injection of fluids into geothermal reservoirs used for electric power generation is an integral

part of management of the geothermal reservoir that promotes maximum energy recovery and not

simply fluid disposal. In some cases, wells are used for production during some periods and for

injection during others (Meade, 1998).4 Accordingly, injection operations receive on-going oversight

to monitor what is injected and where it is injected (i.e., into the geothermal reservoir and not into a

USDW). In addition, injection operations are also the subject of frequent study and analysis, as

reservoir characteristics (e.g., fracture flow patterns) may change.

Well integrity is monitored on a continuous or periodic (e.g., every 1 to 5 years) basis as a

routine part of injection management activities to ensure that injected fluid is reaching the intended

injection zone and is not being released to shallower formations that may be USDWs. The type of

monitoring performed is highly variable depending on site-specific characteristics.

Continuous monitoring often includes monitoring of injection pressure, flow rate, and volume for

changes that may signal a leak in the injection tubing (if used) or well casing. In some cases, annulus

pressure monitoring is also used on a continuous basis (USEPA Region 9, 1998) to detect leakage of 
September 30, 1999 28

Source: CDOG, 1996

Figure 6. Site Plan for Heber Field Showing Well Clustering

and Directional Drilling

either the casing or the injection tubing. Periodic MIT is performed before a well is put into service or

returned to service after workover or repairs, and at established intervals during normal operations. 

Specific methods used and considerations for selecting among the available methods are discussed in

Section 6.3.

Because injected fluids recharge the geothermal reservoir and normally will reappear at some

point in the future in geothermal fluid production wells, operators have an incentive to ensure that the

fluids injected will not adversely affect plant operations. At some facilities, especially those that use

binary technology, the production and subsequent reinjection of geothermal fluids occurs in what is

essentially a closed-loop system. While some limited amount of other fluids (e.g., cooling tower

blowdown) may be injected along with the geothermal fluids, the opportunities for accidental

contamination of the injection fluids is quite limited at these facilities. At other facilities, primarily those

that inject storm water or other supplemental fluids, accidental contamination of injected fluids could
5

 Based on review of selected well abandonment plans and completion reports and permits from

BLM and state agency offices in CA and NV. For additional information of the operating history of the

well shown in Figure 7, see Crockett and Enedy (1990).

6

 Many geothermal reservoirs contain sufficient pressure that injection wells drilled into the reservoirs

are artesian and would flow at the surface in the event of a piping, valve or casing failure. Because such

a failure would create a safety hazard due to the release of hot water or steam, and in some cases toxic

gas (e.g., H2S) emissions, well plugging both improves safety and protects USDWs.

September 30, 1999 29

potentially occur as a result of spills or other releases. In addition, accidental contamination or misuse

for disposal could occur where the contents of surface ponds (for emergency steam release) is pumped

to the injection wells. Measures taken to prevent accidental contamination are discussed in Section 6.

4.5 Well Plugging and Abandonment

Although electric power geothermal injection wells may function effectively for decades,

eventually use is discontinued and the wells are plugged and abandoned. Plugging and abandonment

normally includes removing injection tubing or liner (if present), plugging the well, cutting off the well

casing below (normally 5 feet) the ground surface, welding a steel plate to the top of the remaining

casing, and restoring the ground surface. Well plugging typically involves installation of one or more

cement plugs in the well. In some cases, a continuous cement plug is installed from below the bottom of

the casing in the injection zone to the surface. In other cases, multiple cement plugs are installed and the

remainder of the well is filled with drilling mud. When multiple cement plugs are used, plugs are

normally installed at or near the bottom of the casing and across any perforated intervals closer to the

surface. In addition, a cement plug, often several hundred feet or more in length, is installed at the

surface to prevent fluid migration down the well. The remaining well volume is typically filled with

drilling mud that is heavy enough to prevent fluid movement into the well bore and between zones (see

Figure 7)5. Using these approaches, plugging serves to protect both ground water and public safety.

6

As discussed in Section 7, well operators are required to prepare plugging plans for review and

approval by state or federal (e.g., BLM) agencies prior to conducting the plugging activities. In

addition, agency representatives have the opportunity to observe plugging and abandonment activities,

with particular emphasis on setting of the well plug(s), and operators and/or agency representatives are

required to report actual plugging activities. 

As a result of the characteristics of these injection wells (e.g., depth, relatively large diameter)

and the closure requirements, costs for plugging and abandonment can be substantial. While generally

much less than the cost of drilling a well, plugging and abandonment costs for a single geothermal

injection well can easily exceed $100,000 and in some cases have been greater than $1 million.
September 30, 1999 30

Source: CDOG, 1998b

Figure 7. Example of Well Plugging with Multiple Cement Plugs
September 30, 1999 31

5. POTENTIAL AND DOCUMENTED DAMAGE TO USDWs

5.1 Injectate Constituent Properties

The primary constituent properties of concern when assessing the potential for Class V

electric power geothermal injection wells to adversely affect USDWs are toxicity, persistence, and

mobility. The toxicity of a constituent is the potential of that contaminant to cause adverse health effects

if consumed by humans. Appendix D of the Class V Study provides information on the health effects

associated with contaminants found above drinking water standards or HALs in the injectate of electric

power geothermal injection wells and other Class V wells.

Persistence is the ability of a chemical to remain unchanged in composition, chemical state, and

physical state over time. Appendix E of the Class V Study presents published half-lives of common

constituents in fluids released in electric power geothermal injection wells and other Class V wells. All

of the values reported in Appendix E are for ground water. Caution is advised in interpreting these

values, because ambient conditions have a significant impact on the persistence of both inorganic and

organic compounds. Appendix E also provides a discussion of the mobility of certain constituents

found in the injectate of electric power geothermal injection wells and other Class V wells.

Based on the information presented in Section 4.1, the following constituents were found to

routinely or frequently exceed health-based standards at one or more geothermal fields: antimony,

arsenic, barium, boron, cadmium, copper, fluoride, lead, mercury, strontium, sulfate, zinc, and total

coliform. Aluminum, copper, iron, manganese, TDS, and pH also have been measured above

secondary drinking water standards at some sites.

When injection is into the producing formation, the persistence and mobility of constituents

present in spent geothermal fluids at levels above MCLs or HALs is expected to be the same following

injection as in the produced fluid, with the exception of biological constituents (e.g., coliform) the are

present in some injected surface water and treated effluent. Biological constituents are not thought to

be either persistent or mobile in the environment of a geothermal reservoir.

5.2 Observed Impacts

Failures of injection well casings and release of geothermal fluids to the surrounding formation

do sometimes occur, primarily as a result of seismic activity or corrosion of the casing. At the Salton

Sea geothermal field, for example, the highly corrosive nature of the geothermal fluids readily corrodes

steel well casings, with the result that the operator is increasingly using titanium casings to reduce casing

failures and other operational problems resulting from corrosion. At this geothermal field, as well as

some others, no USDWs are present, so geothermal fluid releases due to casing failures have not

affected a USDW.

In other instances, releases have occurred that may have affected ground water quality. At the

Puna geothermal field in Hawaii, for example, a blowout during drilling of a well (designated KS-8) on
7

 Chloride concentrations and Cl/Mg rations increased from about 500 mg/l to 1,100 mg/l and 30 to

100 mg/l respectively. Variations in chloride of this magnitude were observed in other wells, but no

consistent trend is apparent. Downhole temperatures rose and fell by about 7oC in June 1991. Susequent

measurements indicate a long-term increase of about 10oC through 1992 (USGS, 1994).

8

 Although the uncontrolled steam discharge at the KS-8 wellhead lasted for only 31 hours,

temperature measurements indicate that steam continued to leak upwards past the casing shoe until the

well was quenched (cooled) and plugged several months later on September 9, 1991 (USGS, 1994).

9

 KS-7 blewout for 15 minutes until the valve was shut down. Rock debris in the hole and

subsequent difficulties encountered in attempting to resume drilling of the well caused the operator to

cement the well back to a depth of 740 feet. KS-7, which is approximately 500 feet from KS-8, was then

used as a monitoring well to measure temperature and water level until it was permanently plugged in

1993 (USGS, 1994).

10 An excavation, usually concrete-lined and several feet deep, around the well casing.

September 30, 1999 32

June 11-13, 1991 resulted in fracturing of and release of steam to the formation at the bottom of the

casing shoe (below the lowermost USDW) at a depth of 2,103 feet. Subsequent monitoring (of well

designated MW2, about 1,000 feet from KS-8) of the USDW at a depth of approximately 630 feet

indicated that temperature, chloride concentrations, and chloride/magnesium ratios increased from June

1991 through 1992.7 The proximity of the wells and the timing of the changes in the monitoring well

indicate a possible relationship between the observed chemical changes and the blowout (USGS,

1994).8 TDS measurements in MW2 also show an increase beginning about July 16th. Earlier, TDS

had also shown a sharp increase in MW2 from March 4 through March 10, 1991, shortly after the

blowout of well KS-7 on February 21, 1991.9 In addition, KS-7 shows an increase in temperature

from June 16, 1991 through June 20, 1991, following the KS-8 blowout, with fluctuations occurring

through mid-September 1991 (USEPA Region 9, 1999). For both the KS-7 and KS-8 wells, releases

and possible impacts on ground water were associated with well construction rather than injection

activities.

At the East Mesa geothermal field (see Figure 2), near-surface casing failures (e.g., well 84-7 in

1994) below the floor of the cellars10 around casing wellheads have resulted in release of geothermal

fluids to the ground surface and presumably to unconfined, near-surface ground water (USBLM,

1998). Data on the effects, if any, of the casing failures on the quality of the near-surface ground water

are not available. In general, the quality of this near-surface ground water, which passes through a

wetland between the canal (the presumed source of the water, along with irrigation drainage) and the

East Mesa facility, is poor. As a result, the ground water is not used, although TDS is less than 10,000

mg/l. Similar near-surface leaks have also occurred in Nevada at some wells constructed with cellars

around the casing wellhead (Land, 1999).
September 30, 1999 33

6. BEST MANAGEMENT PRACTICES

A number of best management practices (BMPs) can be implemented to provide increased

protection of USDWs and, in many cases, also provide improved safety and cost performance for

electric power geothermal injection wells. The BMPs listed below are most effective when selected

and implemented in combinations that are based on site-specific factors, which are highly variable. 

Individually, each practice addresses specific challenges and problems that may occur in operating

these wells. When combined, each BMP becomes part of an integrated system that can increase the

overall effectiveness of well system operations. For instance, pressure and plugging problems can be

avoided with proper design and construction. Well failures due to stresses on well casings and

equipment can also be reduced with proper design and construction. System monitoring and MIT,

when used together, give a broad view of many operational aspects, ensuring safety and integrity across

numerous variables rather than one or two at a time. The following discussion is neither exhaustive nor

represents an USEPA preference for the stated BMPs. Each state, USEPA Region, and federal

agency may require certain BMPs to be installed and maintained based on that organization’s priorities

and site-specific considerations. 

6.1 Design and Construction

Proper design and construction of electric power geothermal injection wells is necessary to

protect USDWs (where present). To protect ground water, wells should be designed with casing that

runs from the surface to a depth below USDWs (Stock, 1990) when the geothermal reservoir occurs

below the lowermost USDW. In addition, the well should have two casing strings, each sealed (e.g.,

cemented) its entire length (Crockett, 1990). The selection of casings, cements, and other materials

used in well construction is dependent upon site-specific conditions, especially temperature, pressure,

and the corrosivity of the geothermal fluids and formations through which the well passes. Appropriate

material selection is facilitated by testing of the materials before construction (DiPippo, 1980).

Figure 8 provides an example of a well design that provides extensive provisions for prevention

and detection of leaks and protection of ground water quality. Specifically, this well provides both

multiple casing strings cemented through the USDW and a nitrogen “blanket” in the annulus. The

nitrogen blanket is pressurized, and the pressure is monitored on an on-going basis to detect leakage of

either the liner or the long string casing. While use of a cemented casing and a liner are common

practice, nitrogen blankets are only used in Hawaii.

6.2 Operating Pressure and Injection Rate

Proper injection pressure is determined by site-specific factors. In some injection wells,

injection occurs under vacuum (i.e., no pressure needs to be applied to achieve fluid injection), while

other wells must inject under pressure to overcome formation pressures. When injection is

accomplished under pressure, pressure monitoring aids in avoiding excessive pressure, thereby
September 30, 1999 34

Source: Puna Geothermal Venture, 1996

Figure 8. Geothermal Well Casing Design,

Puna Geothermal Venture, Hawaii
September 30, 1999 35

minimizing the likelihood of injection-induced seismic activity from increased subsurface pressure and

the stresses on the injection well equipment.

Similarly, appropriate injection rates are determined by site-specific factors. In general, the

maximum appropriate injection rate is less than a rate that will cause a pressure build-up in the

formation or result in reduced fluid temperature at production wells. Monitoring of injection rates aids

in avoiding the unwanted consequences of an excessively large flow volume and, in combination with

pressure monitoring, provides an indication of casing integrity (Crockett, 1990; Halliburton,1996). For

example, if flow rates increase and the injection pressure drops, this indicates that injection may have

expanded to additional zones.

6.3 Maintenance

As with operating conditions, maintenance requirements are determined by site-specific factors

such as the well design and the corrosivity of the injected fluids and the well environment. As discussed

above, well design can minimize maintenance. For example, titanium casing is now used in many wells

in the Salton Sea field to reduce the frequency of casing replacement. Some wells are designed and

constructed with cellars around the casing wellhead. Experience in California and Nevada has shown

that these cellars need to be kept dry or good drainage needs to be provided to prevent corrosion of

the casing at the soil-air-water interface. There have been a number of instances in both Nevada and

California (at the East Mesa field) where casing leaks have developed due to corrosion just below the

ground level of the cellar (Land, 1999). 

6.4 Mechanical Integrity

Well integrity is monitored on a continuous and periodic (e.g., every 1 to 5 years) basis as a

routine part of injection management activities. Monitoring may be conducted to check the ability of the

well to prevent both unintended release from within the well to the surrounding formations and

interzonal migration of fluids between the casing and the formation. The type and frequency of

monitoring performed is highly variable depending on site-specific characteristics, such as:

C Injection pressure (if any);

C Corrosivity and scaling properties of the injectate;

C Corrosivity of soils and formations that the well penetrates;

C Presence and characteristics of USDWs (if any); and

C Geothermal fluid temperatures, which may harm some instruments.

Continuous monitoring often includes monitoring of injection pressure, flow rate, and volume for

changes that may signal a leak in the injection casing. In some cases, annulus pressure monitoring is

also used on a continuous basis (Hawaii, 1998) to detect leakage of either the long string casing or

injection tubing. In other cases, on-going monitoring also includes daily observations of surface

conditions, as casing leaks may sometimes occur sufficiently close to the surface.
September 30, 1999 36

Periodic MIT is performed to detect actual and potential leaks, casing failures, and cementing

problems. MITs are typically conducted prior to initial injection, after well workovers and repairs, and

on a routine schedule during normal operations. Because geothermal injection wells are sometimes

located in areas of seismic activity, casing integrity can be compromised by ground movement. In

addition, casing and cement materials are susceptible to corrosion. Therefore, well materials and

designs can vary, even within a single field. The appropriate use of MITs depends on the specific

conditions of the geothermal field and the age and construction of the well. MITs may not be necessary

in cases where an injection well does not penetrate a USDW (Radig, 1997). 

MITs may involve performing a hydraulic pressure test or mechanic well logging to confirm that

the well is functioning correctly and that confining fluid injection is to the intended zone. Hydraulic

pressure tests check the integrity of long string casing and injection tubing by determining whether

pressure applied to a gas or liquid in the annulus is adequately maintained for a specified length of time. 

For wells constructed without tubing and packer, pressure testing may be accomplished by setting

packers above both the screen interval of the well and at the top of the casing, and pressurizing fluid in

between. Alternatively, cementing pressure may be measured and used in combination with well log

information (e.g., resistivity survey).

A wide range of well logging approaches are available for use in assessing the integrity of an

injection well, including measurements of temperature, noise, radioactive tracers, flow, and casing

thickness (using electromagnetic sensors or callipers), and inspection using a borehole televiewer or

other device. Method suitability for a specific well depends on factors such as reservoir temperature,

availability, cost, and past experience. For example, temperature, radioactive tracer, and flow (spinner)

surveys are used to check the integrity of most injection wells in the Heber field in Imperial County,

California. [Periodic pressure tests are used on some older wells instead, and all of the periodic tests

are also supplemented with pressure tests following workovers or well casing repairs for all wells.] At

the nearby East Mesa field, however, electromagnetic surveys are used instead to check integrity, due

to past occurrences of near-surface casing leaks that were not detected using the methods employed at

the Heber field, where problems with near-surface leaks have been relatively infrequent.

In contrast, measurement of static water levels is commonly used in combination with caliper

surveys (and sometimes other logging techniques) at The Geysers field to check for protection of

USDWs. At The Geysers, injection wells operate without applied pressure due to the characteristics of

the geothermal reservoir. Injected fluids meet essentially no resistance to downward flow in the well

until they reach the static water level in the well. Thus, injected fluids will flow down at least to the

static water level essentially independent of the condition of the casing, making releases to formations

above that level highly unlikely. Ground water has been found to occur in localized areas of Quaternary

landslides and stream channel deposits and generally at relatively shallow depths (i.e., a few hundred

feet) at The Geysers (Johnson, 1990). Thus, CDOG uses 500 feet below ground surface (bgs) as a

benchmark for evaluating water level survey results, such that protection of ground water is assumed if

the static water level in a well is below that depth. Caliper surveys are also used to evaluate the

integrity of well casing throughout its length to ensure that fluids are being injected into the intended zone

(Crockett, 1990).
September 30, 1999 37

7. CURRENT REGULATORY REQUIREMENTS

As discussed below, several federal, state, and local programs exist that manage or regulate

electric power geothermal injection wells.

7.1 Federal Programs

On the federal level, management and regulation of electric power geothermal wells fall

primarily under the UIC program authorized by the Safe Drinking Water Act (SDWA). Depending on

the location of the well, the Geothermal Steam Act may also apply. 

7.1.1 SDWA

Class V wells are regulated under the authority of Part C of SDWA. Congress enacted the

SDWA to ensure protection of the quality of drinking water in the United States, and Part C specifically

mandates the regulation of underground injection of fluids through wells. USEPA has promulgated a

series of UIC regulations under this authority. USEPA directly implements these regulations for Class

V wells in 19 states or territories (Alaska, American Samoa, Arizona, California, Colorado, Hawaii,

Indiana, Iowa, Kentucky, Michigan, Minnesota, Montana, New York, Pennsylvania, South Dakota,

Tennessee, Virginia, Virgin Islands, and Washington, DC). USEPA also directly implements all Class

V UIC programs on Tribal lands. In all other states, which are called Primacy States, state agencies

implement the Class V UIC program, with primary enforcement responsibility.

Electric power geothermal injection wells currently are not subject to any specific regulations

tailored just for them, but rather are subject to the UIC regulations that exist for all Class V wells. 

Under 40 CFR 144.12(a), owners or operators of all injection wells, including electric power

geothermal injection wells, are prohibited from engaging in any injection activity that allows the

movement of fluids containing any contaminant into USDWs, “if the presence of that contaminant may

cause a violation of any primary drinking water regulation . . . or may otherwise adversely affect the

health of persons.” 

Owners or operators of Class V wells are required to submit basic inventory information under

40 CFR 144.26. When the owner or operator submits inventory information and is operating the well

such that a USDW is not endangered, the operation of the Class V well is authorized by rule. 

Moreover, under section 144.27, USEPA may require owners or operators of any Class V well, in

USEPA-administered programs, to submit additional information deemed necessary to protect

USDWs. Owners or operators who fail to submit the information required under sections 144.26 and

144.27 are prohibited from using their wells.

Sections 144.12(c) and (d) prescribe mandatory and discretionary actions to be taken by the

UIC Program Director if a Class V well is not in compliance with section 144.12(a). Specifically, the

Director must choose between requiring the injector to apply for an individual permit, ordering such

action as closure of the well to prevent endangerment, or taking an enforcement action. Because
11 May 2003 is the deadline including an 18-month extension.

September 30, 1999 38

electric power geothermal injection wells (like other kinds of Class V wells) are authorized by rule, they

do not have to obtain a permit unless required to do so by the UIC Program Director under 40 CFR

144.25. Authorization by rule terminates upon the effective date of a permit issued or upon proper

closure of the well. 

Separate from the UIC program, the SDWA Amendments of 1996 establish a requirement for

source water assessments. USEPA published guidance describing how the states should carry out a

source water assessment program within the state’s boundaries. The final guidance, entitled Source

Water Assessment and Programs Guidance (USEPA 816-R-97-009), was released in August

1997.

State staff must conduct source water assessments that are comprised of three steps. First,

state staff must delineate the boundaries of the assessment areas in the state from which one or more

public drinking water systems receive supplies of drinking water. In delineating these areas, state staff

must use “all reasonably available hydrogeologic information on the sources of the supply of drinking

water in the state and the water flow, recharge, and discharge and any other reliable information as the

state deems necessary to adequately determine such areas.” Second, the state staff must identify

contaminants of concern, and for those contaminants, they must inventory significant potential sources

of contamination in delineated source water protection areas. Class V wells, including electric power

geothermal injection wells, should be considered as part of this source inventory, if present in a given

area. Third, the state staff must “determine the susceptibility of the public water systems in the

delineated area to such contaminants.” State staff should complete all of these steps by May 2003

according to the final guidance.11

7.1.2 Geothermal Steam Act

The federal BLM regulates use of geothermal resources on federal lands administered by the

Department of the Interior or the Department of Agriculture, on lands conveyed by the U.S. where

geothermal resources were reserved to the U.S., and on lands subject to Section 24 of the Federal

Power Act, as amended (16 U.S.C. 818) with concurrence from the Secretary of Energy. Guidance

on geothermal classification, leasing, exploration, operations, and resource protection and utilization is

provided in 43 CFR parts 3200, 3210, 3220, 3240, 3250, and 3260. The BLM can issue geothermal

resource operational orders, under the Geothermal Steam Act of 1970, for nationwide requirements; 

notices to lessees for statewide or regional requirements; and other orders and instructions specific to a

field or area. The BLM can also issue permit conditions or approval and verbal orders.

Permitting Requirements

In order to use federal lands for access to geothermal resources, a site license and construction

permit must be issued before starting any site activities. To get approval for drilling operations and well

pad construction the following must be submitted to BLM: a completed drilling permit application, a
September 30, 1999 39

completed operations plan, a complete drilling program, and an acceptable bond. A drilling program

describes the operational aspects of the proposed drilling, completion, and testing of the well. The

drilling program requires numerous items, including the casing and cementing program, identification of

the circulation media (mud, air, foam, etc.), a description of the logs that will be run, and a description

and diagram of the blowout prevention equipment that will be used during each phase of the drilling. An

operations plan describes how to drill and test for the geothermal resources. The BLM then reviews

these materials and decides on the issuance of a permit and license to proceed with work.

Within 30 days of completion of the well, a geothermal well completion report, form 3260-4,

must be submitted to BLM.

Operational Requirements

The rules establish general standards that apply to drilling operations. They include meeting all

environmental and operational standards, preventing unnecessary impacts to surface and subsurface

resources, conserving geothermal resources and minimizing waste, protecting public health, safety and

property, and complying with the requirements of 43 CFR 3200.4. Federal regulations 43 CFR

subparts 3260 through 3267 establish permitting and operational procedures for drilling wells,

conducting flow tests, producing geothermal fluids, and injecting fluids into a geothermal reservoir. Also

included in these regulations are redrilling, deepening, plugging back and other well re-work operations.

BLM operational requirements for drilling include: keeping the wells under control at all times,

conducting training during operation to ensure trained and competent personnel can perform emergency

procedures effectively, and using properly maintained equipment and materials. Other requirements

include employing sound engineering principles using all pertinent data, selecting drilling fluid types and

weights, providing a system to control fluid temperatures, providing blowout prevention equipment, and

providing a casing and cementing program.

Mechanical Integrity Testing

Generally, BLM requires that wells be tested once every two years unless problems have

occurred with a well. Casing failures or other problems can lead to orders from BLM specifying more

frequent MIT. 

BLM also may specify particular types of MITs, such as hydraulic pressure tests and electronic

casing log tests, or approve other methods proposed by operators on a case-by-case basis. Hydraulic

pressure tests require a bridge plug to be placed as close as possible to the injection zone and the

casing tested to a surface pressure of 1,000 psi or 200 percent of the maximum injection pressure,

whichever is greater. However, this is not to exceed 70 percent of the minimum internal yield. If

pressure declines more than 10 percent in 30 minutes, corrective action must be taken. Electronic

casing log tests are run every two years and require injection well casing thickness to be no less than 75

percent of new nominal wall thickness. If the well fails this test, it must be placed out of service until

BLM approves reactivation.
September 30, 1999 40

Well Abandonment

In order to abandon a well, a notice that documents the proposed plugging and abandonment

program must be approved before closure begins. The local BLM office must also be notified before

beginning abandonment so that they can witness the closure. Furthermore, a well abandonment report

must be submitted to BLM within 30 days after completion of abandonment. The abandonment report

should include a description of each plug, including the amount and type of cement used, the depth that

the drill pipe or tubing was run to set the plug, the depth to the top of the plug, if the plug was verified,

whether pressure testing or tagging was used, and a description of the surface restoration procedures.

Geothermal Resources Operational Order Number 3, effective February 1, 1975, states

specific requirements for well plugging and abandonment. Cement used to plug any geothermal well,

except surface plugging, must be placed into the well hole through a drill pipe or tubing. Plugging

cement should consist of a high temperature resistant admix, unless waived by the site Supervisor. In

uncased portions of the well, as well as in production perforations, cement plugs must be placed to

protect all subsurface mineral resources including fresh water aquifers. These plugs must extend a

minimum of 100 feet below and, if possible, 100 feet about the aforementioned zones. Intervals of the

hole not filled with cement must be filled with good quality heavy mud. All open annuli extending to the

surface must be plugged with cement and the innermost casing string which reaches ground level must

be cemented or concreted to a minimum depth of 50 feet measured from 6 feet below ground level. All

casing strings must be cut off at least 6 feet below the ground level and capped by welding a steel plate

on the casing stub. The surface area must be restored as specified by the site supervisor.

Financial Responsibility

Before initiating any operation, operators are required to deposit a security or personal bond,

subject to approval by BLM.

7.2 State and Local Programs

As discussed in Section 3, all the documented and estimated electric power geothermal

injection wells in the nation, under either state or federal jurisdiction, exist in 4 states: California,

Hawaii, Nevada, and Utah. Attachment B of this volume describes how each of these states currently

regulate these wells. This section summarizes the regulatory requirements for electric power geothermal

injection wells of the four states with such wells. Each of these states uses its geothermal resources in a

variety of ways, and consequently has set up a special regulatory framework for geothermal wells,

including injection wells. In California and Hawaii, USEPA Region 9 directly implements the UIC

program for Class V injection wells. However, both California and Hawaii also have enacted, and

implement, their own requirements for geothermal electric power return flow wells. Nevada and Utah

are Primacy States for UIC Class V wells. Both of these states also have special regulatory standards

for geothermal return flow wells, in addition to their UIC Class V programs. 
September 30, 1999 41

• A Memorandum of Agreement between USEPA and CDOG assigns responsibilities to CDOG

for regulating geothermal electric power return flow wells under its state-wide geothermal

regulations. CDOG individually permits geothermal electric power return flow wells, after

securing detailed information in permit applications about the entire plan of operations. 

California’s regulations also contain well construction and operating requirements; mandate the

use of MITs; contain procedural and technical requirements for plugging and abandonment; and

require the operators to file indemnity bonds with CDOG guaranteeing financial responsibility

for compliance with the requirements. In addition, Regional Water Quality Control Boards may

prescribe requirements for discharges into waters of the state.

• In Hawaii, geothermal electric power return flow injection wells are permitted by USEPA

Region 9. In addition, the Hawaii Department of Health also regulates geothermal injection

wells under rules governing the use of geothermal resources. A state permit under the

geothermal program may be issued only after a demonstration that the new or modified

geothermal well has complete integrity and effluent will be confined to the intended zone of

injection and will not impact a USDW. The geothermal requirements include monitoring of

injectate and surveys to ensure that all injected fluid is confined to the intended zone of

injection. The state geothermal well requirements also specify plugging and abandonment

requirements.

• Nevada requires electric power geothermal injection wells to satisfy both its UIC Class V

requirements and its geothermal well requirements. Geothermal wells are required to obtain an

individual permit under the UIC requirements and also are permitted by the geothermal

program. Substantial information is required in support of both permit applications, with the

geothermal program specifying a greater level of detail. Both the UIC and the geothermal

programs also have siting and construction requirements; require detailed monitoring of injection

operations; require mechanical integrity testing; and specify plugging and abandonment

requirements. Both require demonstrations of financial responsibility.

• Utah regulates wells used for geothermal energy production under its water rights code. Wells

are individually permitted, on the basis of a detailed application. The code and permits address

siting and construction; contain operating requirements; require MITs; specify the actions that

must be taken to plug and abandon a well; and require owners to supply bonds indemnifying the

state.
September 30, 1999 42

ATTACHMENT A

FACTORS INFLUENCING INJECTATE

The chemical characteristics exhibited by the injected fluids are primarily (although not

exclusively) determined by the characteristics of the geothermal resource, the technologies used to

produce the power, the chemicals used in conjunction with power plant operations (e.g., for treatment

of steam or geothermal fluid), and the characteristics of supplemental water sources (in any). Each of

these four factors is discussed in this attachment.

Composition of Geothermal Fluids

Researchers have identified four distinct water types commonly found within geothermal

resource areas: alkali chloride waters, acid sulfate waters, acid sulfate-chloride waters, and

bicarbonate waters (Ellis, 1977). In general, chloride waters are found in deeper, hotter geothermal

systems, and bicarbonate waters are found in shallow geothermal systems and ground water. The

composition of the geothermal fluid will, to a large extent, determine the composition of the injectate.

C Alkali chloride waters usually contain dissolved salts with high sodium and potassium chloride

contents. Additional compounds in these waters include silica, sulfate, bicarbonate, fluoride,

ammonia, arsenic, lithium, rubidium, cesium, and boric acid.

C Acid sulfate waters are low in chloride content with the constituents found in these waters

mainly leaching from surrounding reservoir rocks.

C Acid sulfate-chloride waters exhibit properties of both alkali chloride waters and acid sulfate

waters. Mechanisms for the formation of these waters include simple mixing of alkali chloride

and acid sulfate waters; oxidation of sulfide waters at depth, with subsequent acidification of

bisulfate ions upon rising; and interaction of high temperature chloride waters at depth with

sulfur-bearing rocks.

C Bicarbonate waters have variable sulfate concentrations, high sodium concentrations, and

neutral pH values. Bicarbonate waters of greater complexity are also common at great depths

within geothermal systems in metamorphic or sedimentary rocks.

Geochemical differences among liquid-dominated systems and vapor-dominated systems also

affect injectate quality. Hot water systems are nearly always characterized by relatively high amounts

of chlorides, silica, boron, and arsenic (White, 1971). Vapor-dominated systems usually have lower

levels of the common metal chlorides, because of their negligible volatility and solubility in low-pressure

steam. Also, vapor-dominated systems usually have lower silica concentrations, as silica is more

soluble at lower temperatures and pressures in the presence of liquid than it is in vapor.
September 30, 1999 43

Effect of Technology

The technology used to produce electric power from geothermal fluids affects the

characteristics of fluid available for reinjection in two ways. First, it affects the extent to which noncondensible gases are removed and water is evaporated from the geothermal fluids prior to injection. 

Second, technology affects the need for treatment of the produced fluid prior to injection. The

technology used is largely determined by the characteristics of the geothermal system. The three types

of geothermal systems used to generate electric power are:

C steam or vapor dominated systems,

C high temperature water (liquid dominated) systems, and

C low to moderate temperature water (liquid dominated) systems.

At steam or vapor-dominated geothermal fields, the produced steam is used to power a turbine

to generate electricity. The steam is then normally condensed and the resulting condensate is injected

back into the same formation from which the geothermal fluid was produced. Condensing and injecting

the spent steam (rather than venting to the atmosphere) serves to reduce emissions, allows for

convenient disposal of spent fluids, and extends the life of the geothermal reservoir. The amount of

condensate available for injection depends in part on the power plant technology used. Regardless of

the specific technology used, however, these types of systems result in the evaporation of a much larger

fraction (and, thus, condensation of a smaller fraction) of the produced geothermal mass than the

systems using water-dominated resources. As a result, some facilities inject water from supplemental

sources, which further affects injectate characteristics.

The second type of geothermal system used for power production is the high temperature water

or liquid geothermal system, which contains high pressure water and steam mixtures at temperatures

exceeding approximately 200oC (400oF). Steam used to power a turbine generator can be produced

from high temperature water-dominated geothermal systems by “flashing” a portion of the geothermal

fluid into steam. Flashing results from the reduction of pressure as the high temperature water is

brought to the surface, which allows a portion the water to vaporize, or “flash,” into steam. Figure A1 shows a typical example of a flow diagram for a flash-steam power cycle.

As shown, fluids that remain after flashing of the steam are reinjected along with condensate

and blowdown from the cooling tower. These spent liquids may contain higher concentrations of

dissolved solids and less gas in solution than the original geothermal fluids. Decreased temperature, in

combination with this change in concentrations, creates a need for treatment of the spent liquids at some

facilities to prevent excessive scaling of piping, injection wells, and other equipment. Treatment of the

geothermal fluid, when required, normally consists of pH reduction by addition of acid (such as

hydrochloric acid) or controlled precipitation and
12 In this context, “excess solids” are solids that precipitate due to the reduced solubility caused by

reduced pressure, temperature, and fluid mass.

September 30, 1999 44

Source: U.S. DOE, 1998b

Figure A-1. Single-stage, Flashed-Steam Power Plant

settling/clarification for removal of excess solids (e.g., carbonates, silicates) from the fluid stream.12

The third type of geothermal system--low to moderate temperature water-dominated

geothermal systems--is developed for power production using a binary cycle or system. In a binary

cycle, the hot reservoir water is kept under pressure and run through a heat exchanger, boiling a

secondary fluid with a low boiling point, such as isopentane, pentane, butane, ammonia, or a

fluorocarbon refrigerant. The geothermal waters are then re-injected after being run through a heat

exchanger. Because the geothermal fluid is not exposed to the surface environment, the composition of

the injected geothermal fluid is essentially the same as the produced fluid. Figure A-2 shows a flow

diagram for a binary power cycle.
September 30, 1999 45

Source: U. S. DOE, 1998b

Figure A-2. Typical Flow Diagram of a Binary Cycle Power Cycle

Geothermal Fluid and Gas Treatment Chemicals

Geothermal steam and fluids contain non-condensible gases to varying degrees depending on

formation pressure, temperature, and mineralogy (Mahon, 1980). The non-condensible gases most

commonly encountered in geothermal fluids are carbon dioxide, hydrogen sulfide, ammonia, hydrogen,

nitrogen, oxygen, and methane (Ellis, 1977). Gas handling practices vary by plant and affect injectate

gas composition and overall characteristics. At some geothermal power plants, especially binary plants,

these gases are not separated from the geothermal fluid and, thus, are reinjected along with the

geothermal fluid. At other plants, especially some flash plants, non-condensible gases are collected,

repressurized, and reinjected with the geothermal fluids. Other flash plants and steam plants vent noncondensible gases to the atmosphere and/or remove them through treatment . Hydrogen sulfide (H2S)

is the primary target of chemical or biological gas treatment efforts that convert H2S to elemental sulfur.

Chemicals not native to the formation are introduced into the injected fluids as a result of the

use of additives to control biofouling, corrosion, and scaling of the plant equipment. The type of

chemicals used for these purposes are illustrated by a list of active ingredients for additives provided in

the UIC permit for injection wells at Pahoa, HI, which includes (USEPA Region 9, 1998):
September 30, 1999 46

C sodium sulfite,

C benzoic acid,

C sodium hydroxide,

C sodium gluconate,

C dimethyldioctylammonium chloride,

C soya amine polyethoxylate,

C cychlohexlamine,

C polyamidoamino acetate,

C POE (15) tallow amine,

C sodium metabisulfite,

C cobalt compounds,

C sodium chloride,

C phosphoric acid derivative,

C magnesium nitrate,

C 5-chloro-2-methyl-4-isothiazoline-3-one,

C magnesium chloride,

C 2-methyl-4-isothiazolin-3-one,

C cupric nitrate,

C disodium ethylenebis-dithiocarbamate,

C dimethylamine,

C ethylene diamine,

C ethylene thiourea, and

C sulfuric acid.

Supplemental Water Sources

At most geothermal fields used for electric power generation, the injected fluids consist of spent

geothermal fluid in combination with other fluids generated onsite by plant operations, such as cooling

tower blowdown. At a few geothermal power plants, however, fluids in addition to those produced

from geothermal reservoirs are routinely injected along with spent geothermal fluids to supplement fluid

recharge in the geothermal resource.

At The Geysers, for example, fluids injected down some of the 29 active injection wells in 1997

(CDOG, 1998a) included storm water runoff from power plant sites, water from Big Sulfur Creek and

Clear Lake, treated wastewater effluent from the Lake County Sanitation District (LACOSAN), and

treated sanitary wastes generated at the power plant sites (Crocket, 1990; Dellinger, 1998). The

largest volume supplemental source of injection water at The Geysers is the 7.8 mgd from Clear Lake

and LACOSAN that is delivered to The Geysers through a 29-mile pipeline and then distributed to

selected injection wells within the field. Injection of waters from some supplemental sources occurs

seasonally (i.e., storm water runoff during the winter “rainy season” and waters from Big Sulfur Creek)

while other sources do contribute year round. The relative contribution of the various sources to

aggregate characteristics of the injected fluid varies also seasonally because the amount of geothermal
September 30, 1999 47

steam condensate available for injection varies seasonally (due to higher evaporation rates during the

warmer summer months).

At the Dixie Valley Geothermal Project in Nevada, shallow ground water is injected (in

addition to geothermal fluids) into the geothermal reservoir to counteract the loss of mass from the

geothermal system due to condensate evaporation. The ground water is not mixed with the geothermal

fluids prior to injection (Land, 1999).

Other examples of additional fluid sources are provided in the USEPA UIC permit for the

injection wells at Pahoa, Hawaii. For the wells covered by this permit, the following fluids are allowed

to be injected along with geothermal fluids (USEPA Region 9, 1998):

C steam turbine seal water,

C rinsate from water softener system,

C sulfatreat heat exchanger cooling water,

C raw/quench water,

C production well bleed system,

C abatement fluids,

C sulfatreat system vacuum pump seal water,

C condensate from the sulfatreat system,

C periodic drilling fluids, and

C fluids from the plant water storage tank and the emergency steam release facility.
13 The WQCA defines "waters of the state" as "any surface water or ground water, including saline

waters, within the boundaries of the state."

September 30, 1999 48

ATTACHMENT B

STATE AND LOCAL PROGRAM DESCRIPTIONS

This attachment addresses the four states with electric power geothermal injection wells: 

California, Hawaii, Nevada, and Utah. 

California

USEPA Region 9 directly implements the UIC program for Class V injection wells in

California. However, the State of California also regulates these wells and has substantial

responsibilities set forth in a Memorandum of Agreement between USEPA and CDOG (USEPA,

1991). CDOG is the state agency with direct responsibility for geothermal electric power return flow

wells under Chapter 4 of Division 3 of the California Public Resources Code (PRC) (Sections 3700 -

3776). The Department has enacted state-wide geothermal regulations in Title 14, Chapter 4 ,

Subchapter 4 of the California Code of Regulations (CCR). The PRC explicitly covers “any special

well, converted producing well or reactivated or converted abandoned well employed for reinjecting

geothermal resources or the residue thereof” (3703 PRC). The regulations define an injection well as

“a service well drilled or converted for the purpose of injecting fluids” (1920.1(e) CCR). They also

state that injection wells are those used for the disposal of waste fluids, the augmentation of reservoir

fluids, pressure maintenance of reservoirs or for any other purpose authorized by CDOG. New wells

may be drilled and/or old wells may be converted for water injection or disposal service (1960 CCR).

Under California’s Water Quality Control Act (WQCA), the state is divided into nine regions,

and Regional Water Quality Control Boards, which are organizations separate from CDOG, are

delegated responsibilities and authorities to coordinate and advance water quality (Chapter 4 Article 2

WQCA). A Regional Board can prescribe requirements for discharges (waste discharge requirements

or WDRs) into the waters of the state, including ground water13 (13263 WQCA). A WDR can pertain

to an injection well (13263.5 and 13264(b)(3) WQCA) and at least one Regional Board has issued a

WDR for geothermal wells. 

Permitting

Under the state geothermal regulations, injection well operators must file a Notice of Intent to

Drill, post a bond or surety prior to injection operations, and pay an application fee (3724 PRC, 1931

CCR). Operations may not commence until the CDOG reviews and approves the application (3724.3

PRC; 1931 CCR). Applicants must provide a letter setting forth the entire plan of operations that

includes analysis of reservoir conditions, method of injection (i.e., through casing, tubing, or tubing with

a packer), source of injection fluid, and estimates of the daily amount of water to be injected. The

application must include a map of the well field along with one or more cross sections showing the wells

involved and a copy of any environmental documents created in support of the operations. Notice is
September 30, 1999 49

also required when operators convert an existing well to an injection or disposal well, even if there will

be no change in mechanical condition as a result of the conversion. In addition, applicants must provide

chemical analyses of injectate and injection zone fluids. Finally, the application must contain copies of

the letter of notification sent to neighboring operators, if required by CDOG (3724, 3724.1 PRC). 

Officials set permit conditions on a case-by-case basis.

Regional Water Quality Control Boards can include special monitoring and reporting 

requirements in a Waste Discharge Requirement’s monitoring and reporting program (3724 PRC) and

at least one Regional Board has done so for a geothermal well.

Siting and Construction

The CDOG geothermal regulations contain specifications for well construction. All wells must

be cased in a manner that protects or minimizes damage to the environment, surface and ground waters,

geothermal resources, life, health, and property (1935 CCR). Conductor pipe must be cemented with

sufficient cement to fill the annular space from the shoe to the surface (1935.1 CCR). Surface casing

must provide for control of formation fluids, protection of ground water, and prevention of blowouts. 

Intermediate casing must be cemented solid to the surface whenever possible (1935.2 CCR). 

Similarly, production casing may be set above or through the injection zone and cemented above the

objective zones (1935.4 CCR). The specific casing design criteria are determined on a case-by-case

basis, depending on the hydrogeological conditions at each well field (3740 PRC).

State regulations also contain standards for blowout prevention. Each well must be equipped

with blowout prevention equipment (BOPE) that includes high temperature-rated packing units and ram

rubbers. This equipment must have a working-pressure rating equal to or greater than the lesser of (a)

a pressure equal to the depth of the BOPE anchor string in meters multiplied by 0.2 bars per meter, (b)

a pressure equal to the rated burst pressure of the BOPE anchor string, or (c) a pressure equal to 138

bars (2,000 psi). The state generally prohibits drilling in unstable geothermal areas, including areas with

fumaroles, geysers, hot springs, and mud pots. However, if drilling in these areas is approved, drilling

operations must be monitored by state officials until the surface casing has been cemented and the

BOPE has been pressure-tested satisfactorily (1941-1942.2 CCR).

Operating Requirements

Completed and operating geothermal injection wells must be maintained and tested to prevent

loss of or damage to life, health, property, and natural resources. All surface and wellhead equipment

and pipeline, and subsurface casing and tubing must be examined periodically for corrosion. Operators

must show complete casing integrity upon completion of a new injection well, when converting a

production well to an injection well, or when reactivating an idle well. The geothermal regulations also

require monitoring of injection well operations on a “continuing” basis to establish that all injectate is

confined to the intended injection zone. Casing integrity tests must be performed within 30 days after

injection starts and every two years thereafter, unless otherwise specified by CDOG. In addition,

CDOG staff (well supervisors) conduct onsite inspections periodically to note surface conditions and
September 30, 1999 50

determine action needed to address problems, if any. Operators must examine, document, and report

injection pressures to CDOG, and CDOG may rescind injection approval if it appears damage is being

done (1966 CCR).

Mechanical Integrity

State regulations mandate the use of MITs to prevent damage to life, health, property, and

natural resources; to protect geothermal reservoirs from damage; and to prevent the infiltration of

detrimental substances into underground or surface water suitable for agricultural, industrial, municipal,

or domestic use. Casing tests must be performed, which may include spinner surveys, wall thickness,

pressure, and radioactive tracer tests. Cementing tests are also required, which may include tests on

cementing of the casing, pumping of plugs, hardness of plugs, and depths of plugs. Finally, regulations

require equipment testing of gauges, thermometers, surface facilities, lines, vessels, and BOPE. The

CDOG well supervisor determines the type and frequency of these tests on a case-by-case basis

(1941, 1942, and 1966 CCR).

Financial Responsibility

Operators must file an individual indemnity bond that secures the state against losses, charges,

and expenses incurred from assuring compliance with the state’s geothermal resources regulations. The

bond must be filed with CDOG at the time operators file the Notice of Intent to Drill. Bonds must be

executed by the owner, as principal, and by an authorized surety company, as surety, on condition that

the principal named in the bond will comply with all the provisions of the state’s geothermal regulations. 

The bond’s language must substantially conform to the language provided in California’s Public

Resources Code, Chapter 4, §3725. Operators may choose to file an individual indemnity bond of

$25,000 for each well drilled, redrilled, deepened, maintained, or abandoned; or they may file a blanket

bond of $100,000 to cover all operations statewide. Individual and blanket bonds may be terminated

and canceled after the wells have been properly abandoned (3725.5 PRC). Liability for individual

wells covered under a blanket bond may be terminated by consent of the CDOG supervisor (3728

PRC); (3725 PRC).

Plugging and Abandonment

Under the geothermal requirements of PRC, an operator must file for and obtain written

approval to abandon, specifying the proposed method of abandonment. Furthermore, the operator

must file the request at least 10 days before the proposed abandonment (3747 PRC). Unless

otherwise approved, no person shall remove casing from a geothermal injection well without first giving

written notice to the state oil and gas supervisor of the intention to do so. The notice shall be given at

least 10 days before the proposed removal (PRC 3751). Within 60 days after the completion of

abandonment of any well, the owner or operator of the well must provide a written report of

completion. CDOG, in turn, must furnish the owner/operator with a written final approval or

disapproval of abandonment (3748 PRC).
September 30, 1999 51

The regulations provide detailed requirements for plugging and abandonment. They include, for

cased wells, including injection wells, a requirement that cement plugs must extend from the bottom of

the geothermal zone or perforations to 30 meters over the top of the zone or perforations. Cement

plugs must be placed from 15 meters below to 15 meters above liner tops. The requirements also

address casing salvage, plugging of stubs and laps, shoe plugs, bridge plugs, surface plugs, and other

specifications (1980 - 1981.2 CCR).

An example of a proposed plan, approval, and reporting for the well shown in Figure 9 is as

follows (CDOG, 1998b):

Proposed Plugging and Abandonment Activities

1. Install blowout prevention equipment.

2. Rig up working platform and crane equipment.

3. Pick up 1-1/4" Hydril tubing.

4. Go in hole to 3,350'.

5. Set 300' cement plug from 3,350' to 3,050'.

6. Displace drilling mud into wellbore.

7. Locate and identify top of cement plug. CDOG to witness.

8. Set 50' cement plug at surface.

9. Rig down equipment.

10. Remove wellhead. Weld steel plate onto 9-5/8" casing.

11. Remove cellar and restore location. Notify CDOG.

Agency Approval of Plan

Approved provided that CDOG shall be notified:

1. To witness the location and hardness of the cement plug at 3,050'.

2. Upon restoration of the location to near original conditions so that a final environmental

inspection can be made.

Agency Approval and Reporting of Plugging Operations

1. Plugged with cement from 3,320' to 3,105'.

2. Plugged with cement from 3,080' to 3,025'.

3. Plugged with cement 120' to surface.
September 30, 1999 52

Hawaii

USEPA Region 9 directly implements the UIC program for Class V injection wells in Hawaii. 

The Region requires that geothermal injection wells have a permit issued by USEPA. The Hawaii

Department of Health also has enacted UIC requirements and issues permits for geothermal injection

wells. Chapter 23 of Title 11 of the Hawaii Administrative Rules (HAR), effective July 6, 1984,

amended November 12, 1992, establishes the state’s UIC program. Class V wells are grouped into

six subclasses. Subclass E consists of injection wells associated with the development and recovery of

geothermal energy.

The Hawaii Board of Land and Natural Resources (HBL&NR) enacted special rules governing

the leasing and drilling of geothermal resources, which are found in Title 13, Subtitle 7, Chapter 183

HAR. Subchapter 9 of Chapter 183 addresses use of injection wells. Injection wells are defined as

those wells used for disposal of geothermal waste fluids, for the augmentation of geothermal reservoir

fluids, for maintenance of reservoir pressures, or for any other purpose authorized by the HBL&NR. 

Permitting Requirements

Underground injection through a Class V well is prohibited except as authorized by a UIC

permit. A permit for injection into USDW is based on evaluation of the contamination potential of the

local water quality by the injection fluids and the water development potential for public or private

consumption. Class V Subclass E wells are defined by Hawaii’s rules to consist of injection wells

associated with the development and recovery of geothermal energy, provided that the geothermal

effluent will be injected at a depth that will not be detrimental to USDW. For Subclass E geothermal

wells, if injection is to occur below the basal water table, the receiving water must be tested, and

injection will be allowed if the receiving water has either an equal or greater chloride concentration as

that of the injected fluid or a TDS concentration in excess of 5,000 mg/l, or an equivalent or lesser

water quality than the injected fluid (11-23-06 (b)(6)(A) HAR). Permits are issued for up to five

years. Permit applications must include specified information (e.g., facility location, ownership, nature

and source of injected fluid; description of injection system; details of proposed injection testing; well

log; elevation section; results of injection testing; water quality data; and operating plans) (11-23-12,

11-23-13, and 11-23-16 HAR).

Under the geothermal requirements administered by HBL&NR, existing wells may not be

modified for injection purposes until a permit has been applied for and received (13-183-78 HAR). 

The owner or operator of either a new or modified geothermal well must demonstrate that the casing

has "complete" integrity by approved test methods, or establish that all injection effluent is confined to

the intended zone of injection (13-183-79 HAR).

Permitting by HBL&NR is a two-step process. First, an Authorization to Construct is issued in

response to receipt of an application. Once the well is constructed and tested, a Permit to Operate is

issued by the Department of Land and Natural Resources. Under the geothermal requirements, if a

well remains idle for a period of two years or longer, the permit may be rescinded (13-183-79 HAR).
September 30, 1999 53

Siting and Construction

The UIC rules require wells to be sited beyond an area that extends at least one-quarter mile

from any part of a drinking water source, including not only the surface expression of the water supply

well, tunnel, or spring, but also all portions of the subsurface collection system. Special buffer zones are

required if the well is located in a caprock formation that overlies volcanic USDW under artesian

pressure (11-23-10 HAR).

No injection well may be constructed unless a permit has been applied for and the construction

has been approved. Construction standards for each type of well are not specified, due to the variety

of injection wells and their uses. If large voids such as lava tubes or solution cavities are encountered,

special measures must be taken to prevent “unacceptable” migration of the injected fluid (11-23-09

HAR).

Operating Requirements

A Class V well may not be operated in a manner that allows the movement of fluid containing a

contaminant into a USDW, if the presence of that contaminant may cause a violation of any national or

state primary drinking water rule or otherwise adversely affect the health of one or more persons. All

wells must be operated in such a manner that they do not violate any rules under Title 11 HAR

regulating water quality and pollution, including Chapter 11-20, relating to potable water systems,

Chapter 11-62, relating to wastewater systems, and Chapter 11-55, relating to water pollution control. 

The state may also impose other limitations on quantity and quality of injectate as deemed appropriate. 

An operator may be ordered to take necessary actions to prevent a violation of primary drinking water

standards, including cessation of operations (11-23-11 HAR).

Mechanical Integrity

All casing strings are required to be pressure tested after cementing and before commencing

any other operations on the well (13-183-76 HAR).

Monitoring Requirements

Operating records generally are required for geothermal wells, including the type and quantity

of injected fluids and the method and rate of injection (11-23-12 HAR).

Under the geothermal requirements, the operator must make “sufficient” surveys (not further

defined by regulation), within 30 days after injection commences, to demonstrate that all the injected

fluid is confined to the intended zone of injection. Subsequent surveys must be made at least every two

years (13-183-79(b) HAR). Injection pressures and rates must be recorded, maintained, and

reviewed to detect anomalies (13-183-79(d) HAR). If this process demonstrates ongoing damage, the

permit may be rescinded. Detailed well records must be kept, and monthly reports of the amount of

fluid injected must be submitted (13-183 Subchapter 12 HAR).
14 The cost of plugging injection well KS-8 at the Puna Geothermal facility in Hawaii following a

blowout in 1991 was more than $1 million.

September 30, 1999 54

Financial Responsibility

The Hawaii Department of Health does not require a bond for closure of injection wells. 

However, USEPA Region 9 issued a permit to Puna Geothermal Venture/Puna Cost, Inc. that required

a financial assurance mechanism to cover the anticipated cost of plugging and abandoning the injection

wells.14

Plugging and Abandonment

An operator wishing to abandon a well must submit an application, and the well must be

plugged in a manner that will not allow “detrimental” movement of fluids between formations (11-23-

19(a) HAR).

Under the geothermal requirements, before abandonment of a well, an operator must file for

and obtain a permit to abandon and specify the proposed method of abandonment. Unless otherwise

approved, abandonment requires that approved heavy drilling fluid be used to replace any water in the

hole, and all portions of the hole which are not plugged with cement be filled. The casing must be cut

off at least 6 feet below the surface of the ground and the surface restored. Detailed cementing

requirements are included in the rules requiring: 1) the cement to contain a high temperature resistant

admix; 2) filling of all open annuli solid with cement to the surface; 3) placement of 100 lineal feet of

cement straddling the bottom of the conductor pipe and at the shores of all casings; and 4) placement of

cement across geothermal zones and extending 100 feet above and below the zones whether in a cased

or uncased hole. Fifty feet of cement is required above the top of casing liners and below the surface of

the well (13-183-81 to 13-183-83 HAR).

Nevada

Nevada is a UIC Primacy State for Class V wells in which the Nevada Division of

Environmental Protection (DEP) administers the UIC program. Electric power geothermal injection

wells must satisfy Nevada’s UIC program requirements. Geothermal wells also must satisfy regulations

of the State Engineer and the Division of Minerals (DOM).

UIC Statutes and Regulations

Nevada Revised Statutes (NRS) §§ 445A.300 - 445A.730 and regulations under the Nevada

Administrative Code (NAC) §§ 445A.810 - 445A.925 establish the state’s basic underground

injection control program. The injection of fluids through a well into any waters of the state, including

underground waters, is prohibited without a permit issued by the DEP, (445A.465 NRS), although the

statute allows both general and individual permits (445A.475 NRS and 445A.480 NRS). 

Furthermore, injection of a fluid that degrades the physical, chemical, or biological quality of the aquifer
September 30, 1999 55

into which it is injected is prohibited, unless the DEP exempts the aquifer and the USEPA does not

disapprove the exemption within 45 days after notice of it (445A.850 NAC). The statute defines

geothermal wells used in the generation of energy as Class V wells (445A.849 NAC). 

Chapter 445A NAC, “Underground Injection Control,” defines and elaborates these statutory

requirements. First, they provide that any federal, state, county, or municipal law or regulation that

provides greater protection to the public welfare, safety, health, and to the ground water prevails within

the jurisdiction of that governmental entity over the Chapter 445A requirements (445A.843 NAC).

Permitting. The UIC regulations specify detailed information that must be provided in support

of permit applications, including proposed well location, description of geology, construction plans,

proposed operating data on rates and pressures of injection, analysis of injectate, analysis of fluid in the

receiving formation, proposed injection procedures, and a corrective action plan (445A.867 NAC). 

The DEP may, however, request additional information be supplied in support of a permit application

for a Class V well. 

Siting and Construction. The state specifies, among other siting requirements, that the well must

be sited in such a way that it injects into a formation separated from any USDW by a confining zone

free of known open faults or fractures within the area of review. It must be cased from the finished

surface to the top of the injection zone and cemented to prevent movement of fluids into or between

USDWs (445A.908 NAC).

Operating Requirements. Monitoring frequency for injection pressure, pressure of the annular

space, rate of flow, and volume of injected fluid is specified by the permit. Analysis of injected fluid

must be conducted with sufficient frequency to yield representative data. Prior written authorization

from DEP is required before an operator may use any chemicals (biocides, corrosion and scale

inhibitors, etc.) in the injection or cooling systems.

Mechanical Integrity. MIT is required once every 5 years, by a specified method.

Financial Responsibility. Class V geothermal injection wells associated with the production of

energy are charged graduated fees for permitting depending on the number of megawatts produced

(445A.872 NAC). Such wells are specifically required to satisfy bonding requirements, and must be

covered by a bond either equal to the estimated cost of plugging and abandonment of each well or, if

approved by DEP, a sum not less than $50,000 to cover all injection wells of the permit applicant in the

state.

Plugging and Abandonment. A plugging and abandonment plan and cost estimate must be

prepared for each well, and reviewed annually. Before abandonment, a well must be plugged with

cement in a manner that will not allow the movement of fluids into or between USDWS (445A.923

NAC).
September 30, 1999 56

Regulations on Geothermal Resources

In addition to Nevada’s requirements pertaining to underground injection wells, electric power

geothermal wells also must satisfy regulations of the State Engineer and DOM. These requirements are

found in Chapter 534A NAC, “Geothermal Resources.”

These regulations define a geothermal injection well as any well used to dispose of fluids

derived from geothermal resources into an underground reservoir (534A.061 NAC). They further

divide geothermal wells into three categories based on the use of the geothermal resource. Injection

wells used to dispose of spent fluids from electric power generation are considered industrial

geothermal wells, which are the most extensively regulated (534A.170 and 534A.180 NAC) and are

described below.

Permitting Requirements. The state requires a permit to drill or operate an individual

geothermal well. Geothermal operators are required to file a Notice of Intention to Drill with the State

Engineer, including descriptions of the purpose, location, estimated depth, casing, blowout protection,

and drilling rig. The application must include information concerning well ownership, including the name

of the landowner where the well will be sited, the name of the geothermal resource owner, and the

name and address of the well operator and drilling contractor. Each permit application must include the

appropriate financial assurance bond described under “Financial Responsibility.” Finally, the permit

must include a description of the location by the quarter section, section, township, and range. If the

area has not been mapped, the application must state the location by distance and direction from an

established landmark. Operators may also apply to permit wells for an entire project area, and must

submit all the information required for an individual permit (534A.190 and 534A.193 NAC).

In addition to geothermal well permit requirements that address production and injection wells

alike, applications for geothermal injection wells must provide additional information for permit

approval. This includes a description of the casings in the wells or proposed wells; the proposed

method for testing the casings before injection; the estimated maximum injection pressure and

temperature; and a description of the proposed pipelines, metering equipment, and safety devices used

to prevent accidental pollution (534A.196 NAC).

Siting and Construction. Injection wells may not be drilled within 100 feet of the boundary of

the land on which the well is sited or a public road, street or highway. Exceptions to these regulations

may be granted by DOM after considering such factors as the topographic, hydrologic and geologic

characteristics of the area; characteristics of the reservoir; protection of the environment; and any

existing rights. All wells must be cased in a manner that minimizes damage to the environment, ground

and surface waters, geothermal resources, and property. Completion equipment for the well must be

attached to the surface casing, and all casing reaching the surface must provide adequate anchorage for

BOPE. Also, surface casing must provide for control of formation fluids and protection of fresh water. 

The annular space must be filled by circulating cement up the annulus to the surface. If the cement does

not circulate or falls back, the casing must be cemented at the surface (534A.200, 534A.260,

534A.270 NAC).
September 30, 1999 57

Operating Requirements. Unless otherwise approved, all geothermal fluids must be reinjected

into the same reservoir from which they originated. Operators must take all necessary precautions to

keep wells under control and operating safely at all times. BOPE capable of shutting in the well during

blowout or failure of flow controlling equipment must be installed on the surface casing and maintained

ready for use at all times. The equipment must be made of steel and have a pressure rating equal to the

maximum anticipated pressure at the wellhead. BOPE is required for all wells where temperatures may

exceed 250°F. Immediately after installation, BOPE and the casing must be tested under pressure. 

DOM personnel must be given adequate advance notice and must witness the tests before the guide

shoe is drilled out of the casing (534A.270, 534A.420 NAC).

Industrial geothermal well operators must complete monthly reports of production and

temperature, based on continuous metering of rate of flow of water, steam, and pressure and

temperature of fluids (534A.400, 534A.410, 534A.460 NAC).

Mechanical Integrity Testing. Nevada geothermal regulations do not specify MIT. However,

the code states that all equipment used or purchased for development and production of geothermal

resources must meet the minimum standards generally accepted for geothermal well equipment. DOM

may require additional testing or repairs to prevent waste and damage to the environment.

Financial Responsibility. Nevada requires operators to provide a sufficient bond of at least

$10,000 per well to indemnify the state against costs of enforcing its geothermal regulations. Liability

ceases upon proper well abandonment. Operators may also file blanket bonds of at least $50,000 to

cover all wells to be operated statewide. Bonds must be in cash, issued by a surety authorized to do

business in Nevada, or in the form of a savings or time certificate of deposit. If the certificate is used, it

must be issued by a bank or savings and loan association operating in Nevada, and payable to the State

of Nevada. Operators who deposited a surety bond guaranteeing performance with the federal

government for wells drilled on federal land (see Section 7.1.2 above) must file a copy of the bond with

DOM (534A.250 NAC).

Plugging and Abandonment. Operators must file a request to abandon a well with DOM,

including a detailed statement of the abandonment activities. Cement used to plug the well, except for

surface plugging, must be placed in the hole by pumping through drill pipe or tubing. The cement mix

must be able to withstand high temperatures. Cement plugs must be placed in the uncased portion of

wells to protect all subsurface resources. The plug must extend a minimum of 100 lineal feet above and

below the producing formations, or the total and 100 lineal feet below the producing formations, or to

the total depth drilled, whichever is less. Where there is an open borehole, a cement plug must be

placed in the deepest casing string. 

If there is a loss, or anticipated loss, of drilling fluids into the formation or if the well has been

drilled with air or another gaseous substance, a permanent bridge plug must be set at the casing shoe

and capped with a minimum of 200 lineal feet of cement. Cement plugs must also be placed across

perforations, extending 100 lineal feet below, or to the total depth drilled, whichever is less, and 100

lineal feet above the perforations. If using a cement retainer to plug perforations, it must be placed a
September 30, 1999 58

minimum of 100 lineal feet above the perforations. DOM must approve cutting and recovering the

casing. All annular spaces extending to the surface must be plugged with cement, and the innermost

string of casing that reaches ground level must be cemented to a minimum depth of 50 feet below the

top of the casing. Any interval not cemented must be filled with good quality, heavy drilling fluids. 

Finally, the surface should be restored as near as practicable to its original condition, including cutting all

casing strings below ground level, capping casing strings by welding a steel plate on the stub, and

removing all structures and other facilities (534A.490 NAC).

Utah

Utah is a UIC Primacy State for Class V wells. Utah’s Division of Water Rights (DWR) has

regulatory authority over wells used for geothermal energy production under Chapter R655 of the Utah

Administrative Code (UAC), “Water Rights.” Geothermal injection wells are defined as any special

wells, converted producing wells, or reactivated abandoned wells used to maintain geothermal reservoir

pressure; provide new material; or re-inject any material medium, residue, or by-product of geothermal

resource exploration/development. 

Permitting Requirements

Any person or operator who wishes to construct an injection well must submit an application

form to DWR. This requirement extends to modifying an existing injection well and converting another

well type to an injection well (even in cases where mechanical condition does not change). The

application must contain information detailing location, elevation, and layout; lease identification and well

number; a list of tools and equipment to be used; expected depth and geologic characteristics; drilling,

mud, casing, and cementing plans; logging, coring, and testing plans; waste disposal plans;

environmental considerations; and emergency procedures. Information contained in permit applications

may be shared with other state agencies having interest in or jurisdiction over injection issues. To the

extent possible, DWR will eliminate duplicative application efforts with other interested agencies,

including the Bureau of Pollution Control. DWR conditions permits on a case-by-case basis (UAC

R317-7-6 thru R317-7-9).

Siting and Construction

Injection wells used in geothermal operations must be located more than 100 feet from the

boundary of the parcel on which the well is situated. In addition, injection wells must be more than 100

feet from a public road, street, or highway dedicated prior to the commencement of drilling. The State

Engineer must approve all well spacing proposals, giving consideration to topographic characteristics of

the area, hydrogeological characteristics, well interference, economic considerations, and environmental

protection. Regulations also allow DWR to approve directional drilling for parcels of one acre or more

whose surface is unavailable for drilling. In such cases, the surface well location may be on another

property that may or may not be contiguous to the property containing the geothermal resource.
September 30, 1999 59

Regulations governing well construction require that all wells be cased in a manner that protects

or minimizes damage to the environment, usable ground waters, geothermal resources, life, health, and

property. Permanent wellhead completion equipment must be attached to the production casing or to

the intermediate casing if production casing does not reach the surface. Casing strength specification is

determined on a case-by-case basis. All casing reaching the surface should provide adequate

anchorage for BOPE, hole pressure control, and protection of natural resources. In addition, casing

should reach below all known or reasonably estimated ground water levels to prevent blowouts or

uncontrolled flows (UAC R655-1-5.1).

In all areas, the operator must continuously record the drilling mud temperature, drilling mud pit

level, drilling mud pump volume, drilling mud weight, drilling rate, and hydrocarbon and hydrogen

sulfide gas volume. This information must be monitored after drilling out of the shoe of the conductor

pipe until the well has been drilled to the total depth. 

Operating Requirements

Utah’s regulations also address BOPE requirements (UAC R655-1-3). For operations using

mud as the drilling fluid in unexplored or unstable areas, the minimum annular BOPE working pressure

is 2,000 psi, and equipment must be installed on the surface casing (UAC R655-1-3.2). The well must

also have a system that shuts down all the hydraulic well components to prevent blowouts. The system

should use an accumulator of sufficient capacity and a high pressure auxiliary back-up system with dual

controls that allow operation at the driller’s station and at least 50 feet away from the well head (UAC

R655-1-3.2(c)). Operations must include a Kelly cock and standpipe valve, a fill-up line installed

below the BOPE, and a blowdown line fitted with two valves installed below the BOPE (UAC R655-

1-3.2(d), (g)). All lines and fittings should be steel and have a minimum working pressure of at least

that required of the BOPE (UAC R655-1-3.2(h)).

In areas where dry steam exists at depth or formation pressures are less than hydrostatic, a

rotating-head installed at the top of the BOPE stack is required (UAC R655-1-3.3(a)). Regulations

also require a pipe-ram/blind-ram BOPE with a minimum working-pressure rating of 1,000 psi,

installed below the rotating-head to facilitate shut-in at any time (UAC R655-1-3.3(b)). A banjo-box

or mud-cross steam diversion unit should be installed below the BOPE and fitted with a muffler to

reduce sound emissions to within state standards (UAC R655-1-3.3(c)).

In explored areas, each well must be equipped with BOPE that include high temperature-rated

packing units and ram rubbers. This equipment must have a working-pressure rating equal to or greater

than the lesser of: (a) a pressure equal to the depth of the BOPE anchor string in meters multiplied by 1

psi per foot, (b) a pressure equal to the rated burst pressure of the BOPE anchor string, or (c) a

pressure equal to 2,000 psi. Additional requirements may be set by DWR.
September 30, 1999 60

Mechanical Integrity Testing

MIT is required at the discretion of DWR to prevent damage to life, health, property, and

natural resources; to protect geothermal reservoirs; or to prevent the infiltration of detrimental

substances into underground or surface waters suitable for beneficial uses. The regulations list the

various tests that are required, including casing tests, cementing tests, and equipment tests.

Operators must conduct casing integrity testing upon completion of a new well or before

converting a production well to injection, showing that the casing has "complete" integrity (UAC R655-

5.2.1). Testing must be completed within 30 days after injection operations commence, and thereafter

every two years. The test must "prove that all injected fluid is confined to the intended zone of

injection." Operators must notify DWR 48 hours prior to testing should the department wish to observe

the testing. In addition, operators must test for corrosion of well materials. Other regulations require

operators to provide monthly reports of injection operations (UAC R655-5.2).

Financial Responsibility

Utah requires owners to file a bond with DWR indemnifying the state against costs of enforcing

its geothermal regulations and the improper abandonment of any permitted wells. Amount of the bond

is not to be less than $10,000 for each individual well, or $50,000 for statewide operations. These

bonds remain in force for the life of the well(s) and will not be released until properly abandoned or

substituted by another bond. Any person who acquires ownership or operation of any well is subject to

the bonding requirements and must tender his own bond, or assume responsibility under an existing

blanket bond.

Plugging and Abandonment

Utah’s regulations pertaining to plugging and abandonment of injection wells specify that the

actions taken must block interzonal migration of fluids that may contaminate fresh water and other

natural resources, prevent damage to geothermal resources; prevent reservoir energy loss; and protect

life, health, the environment, and property (UAC R655-1-6.1). Written notification is required 5 days

before abandonment efforts commence, as well as a history of well operations within 60 days of

abandonment completion (UAC R655-1-6.2 (b) and (n)). All abandoned wells must be monumented

by 4-inch diameter pipe 10 feet in length, of which 4 feet are above ground. Name, number, and

location of the well shall appear on the monument. When filling the wells, operators should use good

quality heavy drilling fluid to replace any water in the hole and to fill all portions of the hole not plugged

with cement (UAC R655-1-6.2 (i)). All cement plugs should be pumped into the hole through drill

pipe or tubing, and all open annuli should be filled solid with cement to the surface. A minimum of 100

feet of cement should be emplaced straddling the interface or transition zone at the base of ground

water aquifers (UAC R655-1-6.2(g)). In addition, 100 feet of cement should straddle the placement of

the shoe plug on all casings, including conductor pipe. Other requirements include a surface plug of

neat cement or concrete mix in place from the top of the casing to at least 50 feet below the top of the
September 30, 1999 61

casing (UAC R655-1-6.2(i)). All casing should be cut off at least 5 feet below land surface and

cement plugs should extend 50 feet over the top of any liner installed in the well (UAC R655-

1-6.2(j),(k)); (UAC R655-1-6.1-- thru R655-1-6.2).
September 30, 1999 62

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