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
-------
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
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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, \blume 1 provides an
overview of the study methods, the USEPA UIC Program, and general findings, \blumes 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 (>100°C (212°F)) 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/1 at The Geysers (in northern California)
but about 250,000 mg/1 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
September 30, 1999 1
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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 n
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.
1 Uncontrolled release of gas and/or fluids from a well.
September 30, 1999
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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.
2 Geothermal injection wells used in association with recovery of geothermal energy for purposes
other than electric power generation are covered separately in Wume 18 of this document.
September 30, 1999
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Figure 1. Geothermal Well System at Caithness Power Inc.'s
Steamboat Springs, Nevada, power plant
A 3iJutllwest-N«rtliea5t flchemHti* Crwft SecUori of the Steamboat Spring* Geatharmel gysbem
Source: Goranson, 1990
September 30, 1999
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Figure 2. Geothermal System at East Mesa Field, Imperial County, California
OWES* KOTffilWHL FACILITIES
MEfUNDSASH
UET HCM.UE WT
mm M
51ESUEFMI BTAtFl
NELL
-UMKKIW
HlirtDU tttiMWW.
PTOWKI1W mil
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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 \blume 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 '
Number
USEPA Region 1 -
USEPA Region 2 -
USEPA Region 3 -
USEPA Region 4 -
USEPA Region 5 -
USEPA Region 6 -
USEPA Region 7 -
USEPA Region
UT
4
Source of Estimate and Methodology
None
None
None
None
None
None
None
8
4 Best professional judgment.
USEPA Region
CA
HI
NV
174
3
53
174
3
53
USEPA Region 10 -
9
N/A
N/A
N/A
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.
September 30, 1999
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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 >100°C (212°F)) 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.
Source: Geo-Heat Center, 1998
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
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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).
• 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).
• 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).
• 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; Freeport-
McMoRan, 1989; GEO Operator Corp., 1987 and 1989;
September 30, 1999
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Table 2. Injectate Characteristics at the Puna Geothermal Field
Concentration
r»_:_i,:__ (mg/l unless otherwise noted)
Constituents
IDS
pH (Std. units)
Arsenic
Barium
Boron
Cadmium
Calcium
Chloride
Chromium
Copper
Fluoride
Hydrogen Sulfide (H2S)
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Nickel
Potassium
Silica (s^)
Silver
Sodium
Sulfate (SO;2)
Vanadium
Zinc
Water Health
Standards Advisory Levels
mg/l P/S* mg/l N/C** Mean
500 S - 5680
6.5-8.5 S - 4.85
0.05 P 0.002 C 0.08
2 P 2 N 2.45
0.6 N 2.59
0.005 P 0.005 N 0.03
49.65
250 S - 3099
0.1 0.1 N 0.01
1.3 - 0.005
4.0 - 0.02
538
0.3 S 0.64
0.015 P 0.001
0.82
0.25
0.05 S - 0.2
0.002 P 0.002 N 0.001
0.003
397
286
0.1 S 0.1 N 0.001
1740
500 P - 10.5
0.001
5 S 2 N 0.01
95 % Confidence
limits
Lower
4521
4.67
0.06
1.77
2.3
0
38.27
2469
0.005
0
0
465
0.49
0
0.64
0.16
0.16
0
0
316
234
0
1383
7.49
0
0
Upper
6839
5.02
0.1
3.13
2.87
0.09
61.03
3731
0.02
0.13
0.03
611
0.79
0.001
1
0.33
0.24
0.002
0.008
479
336
0.002
2099
13.51
0.001
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
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Table 3. Constituent Data for Selected Geothermal Wells in Nevada
(concentrations in mg/1 except as noted)
1!
51
*O Constituent
IDS
pH(std units)
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chloride
Chromium
Cyanide
Copper
Fluoride
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Nickel
Nitrate
Potassium
Selenium
Silica
Silver
Sodium
Strontium
Sulfate
Thallium
Zinc
Drinking Water Health Ac
Standards * Level:
me/I P/S me/1
500 S
6.5-8.5 S
0.006 P 0.003
0.05 P 0.002
2 P 2
0.004 P 0.0008
0.6
0.005 P 0.005
250 S
0.1 P 0.1
0.2 P 0.2
1.3 P
4.0 P
0.3 S
0.015 P
0.05 S
0.002 P 0.002
0.1 P 0.1
10 P
0.05 P
0.10 S 0.1
17
500 P
0.002 P 0.0005
5 S 2
N/C 6/16/94
9,840
8.03
N NR
C 0.167
N 0.27
C NR
N 22.4
N <0.05
154
5,170
N <0.01
N NR
<0.01
6.14
1.91
<0.02
NR
<0.01
<0.01
N <0.0003
N NR
<24
331
NR
NR
N <0.05
3,550
N NR
102
N NR
N <0.01
Desert Peak
Injectate
3/14/95
9,296
8.18
NR
0.1
0.49
NR
20
<0.002
160
5,300
<0.05
NR
<0.02
6
1.3
<0.01
NR
0.7
0.85
<0.01
NR
<0.45
360
<0.001
110
<0.005
3,100
NR
100
NR
<0.02
12/31/96
10,541
8.50
NR
0.2
0.72
NR
NR
<0.02
160
5,600
<0.02
NR
<0.02
6.8
0.65
<0.02
NR
<1.00
0.09
0.0016
NR
<1.0
370
<0.02
NR
<0.02
3,000
NR
110
NR
<0.2
10/21/97
9,728
8.49
NR
0.21
0.67
NR
20
0.02
190
5,000
0.08
NR
<0.02
6.2
<1.0
0.02
4.2
<2.00
0.08
<0.0005
NR
<2.25
320
<0.02
95
<0.02
3,000
NR
99
NR
<0.2
Formation
12/18/76
7,500
7.90
NR
0.08
NR
NR
18
NR
101
4,000
NR
NR
NR
3.8
NR
NR
NR
0.35
NR
NR
NR
0.12
227
NR
198
NR
2,400
NR
122
NR
NR
Beowawe
Injectate
12/31/96
930
9.38
NR
NR
NR
NR
NR
NR
NR
62
NR
NR
NR
15.14
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
371.34
NR
233.67
NR
NR
NR
NR
Formation
6/20/86
1,946
7.29
0.73
<0.61
<0.61
NR
1.29
<0.06
10.49
808
<0.05
NR
<0.06
7.4
<0.02
<0.24
1.32
0.6
0.32
NR
NR
NR
15.84
NR
86.18
<0.05
718.6
0.26
102
NR
<0.12
YanKee/
Caithness
Injectate
5/28/93
2,607
8.85
NR
2.96
0.08
NR
48.3
<0.001
9
938
<0.005
NR
NR
2.9
0.02
<0.005
NR
NR
NR
0.0005
<99.999
0.8
78
<0.01
402
<0.005
716
NR
143
NR
NR
Formation
5/1/81
2,090
NR
NR
NR
NR
NR
39
NR
7.2
655
NR
NR
NR
2.3
NR
NR
6.8
0.29
NR
NR
NR
NR
50
NR
301
NR
566
NR
123
NR
NR
Stillwater/Amor IV
Injectate
6/30/95
4,493
7.91
NR
0.075
NR
NR
14.34
NR
67.68
2,385
NR
NR
NR
4.16
NR
NR
NR
0.82
NR
NR
NR
NR
121.41
NR
193.87
NR
1,476
NR
183
NR
NR
7/12/96
4,460
7.53
NR
0.021
NR
NR
20.24
NR
81.65
2,302
NR
NR
NR
3.92
NR
NR
NR
NR
NR
<0.0005
NR
NR
107.04
<0.0006
173.91
NR
1,475
NR
177
NR
NR
2/1 3/97
4,390
7.44
NR
0.032
NR
NR
19.69
NR
75.06
2,368
NR
NR
NR
4.12
NR
NR
NR
0.78
NR
<0.0005
NR
NR
104.27
<0.0005
193.75
NR
1,552
NR
194
NR
NR
10/31/97
4,490
7.45
NR
0.05
0.094
NR
15.61
NR
73.32
2,325
NR
NR
NR
4.07
0.159
NR
2.084
0.31
4
<0.0005
NR
NR
99.15
<0.0005
143.678
NR
1,422
NR
201
NR
NR
Formation
8/22/88
5,000
8.76
NR
<0.49
0.35
NR
NR
<0.05
67.31
2,520
<0.12
NR
<0.06
6.2
<0.02
<0.24
2.01
0.33
<0.24
NR
NR
NR
149.94
NR
NR
<0.05
1,669
NR
214
NR
NR
10/30/89
7,440
8.3
NR
<0.49
0.36
NR
38.34
<0.05
101.27
4,270
<0.12
NR
<0.06
2.72
<0.02
<0.24
6.71
0.42
<0.24
NR
NR
NR
76.88
NR
160.36
<0.05
2,900
NR
294
NR
0.2
Source: Nevada Bureau of Water Pollution Control, 1999
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Table 3. Constituent Data for Selected Geothermal Wells in Nevada — Con't
(concentrations in mg/1 except as noted)
1!
Oo
Constituent
IDS
pH (std units)
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chloride
Chromium
Cyanide
Copper
Fluoride
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Nickel
Nitrate
Potassium
Selenium
Silica
Silver
Sodium
Strontium
Sulfate
Thallium
Zinc
Drinking Water Health Advisory
Standards * Levels **
mg/1 P/S mg/1 N/C
500 S
6.5-8.5 S
0.006 P 0.003 N
0.05 P 0.002 C
2 P 2 N
0.004 P 0.0008 C
0.6 N
0.005 P 0.005 N
250 S
0.1 P 0.1 N
0.2 P 0.2 N
1.3 P
4.0 P
0.3 S
0.015 P
0.05 S
0.002 P 0.002 N
0.1 P 0.1 N
10 P
..
0.05 P
..
0.10 S 0.1 N
..
17 N
500 P
0.002 P 0.0005 N
5 S 7 N
Empire/Amor II
Injectate
12/18/96
4,180
7.38
NR
<0.003
0.18
NR
6.1
<0.001
150
2,131
<0.005
NR
NR
4.08
0.87
<0.005
NR
1
0.12
<0.0005
NR
NR
110
<0.001
118
<0.005
1,280
NR
180
NR
NR
12/18/97
3,974
6.79
NR
<0.01
0.23
NR
5.6
<0.01
180
2,200
<0.01
NR
<0.01
3.3
3.1
<0.01
NR
0.73
0.16
<0.0005
NR
<2.5
110
<0.01
177
0.01
1,300
NR
200
NR
0 79
Brady
Injectate
1 1/20/96
2,802
8.84
NR
NR
0.062
NR
5.1
NR
50
1,117
NR
NR
NR
6.96
0.122
NR
NR
0.08
NR
NR
NR
NR
69.47
NR
227.6
NR
841.4
NR
448
NR
NR
10/23/97
2,792
8.8
NR
0.216
0.063
NR
5.065
NR
48.153
1,148
NR
NR
NR
6.82
0.006
NR
NR
0.05
0.007
NR
NR
NR
64.8
NR
227.822
NR
895.469
NR
470
NR
007
Formation
11/25/98
1,847
8.69
0.026
0.084
0.38
<0.005
13
<0.005
110
3,800
< 0.005
NR
< 0.005
2.5
0.06
< 0.005
2.9
4.5
0.029
< 0.0005
0.0 17
<4.5
no
< 0.005
131
< 0.005
2,300
NR
100
< 0.005
<005
Dixie
Valley
Injectate
10/16/97
2,000
9.11
NR
0.98
0.06
NR
13.85
<0.005
10.09
580
<0.05
NR
<0.05
16.29
0.03
<0.05
2.61
<0.01
<0.05
<0.0005
NR
<1.0
80.56
<0.1
672.46
<0.01
520.87
NR
239
NR
<005
Soda Lake II/Amor IX
Injectate
7/18/95
5,480
6.29
NR
NR
NR
NR
12.52
NR
111.52
2,974
NR
NR
NR
0.91
3.8
NR
NR
0.57
NR
NR
NR
NR
180.66
NR
214
NR
NR
NR
70
NR
NR
10/25/95
5,425
5.81
NR
0.09
0.244
NR
12
<0.005
121
2,910
<0.005
NR
0.037
1.21
1.73
<0.04
2.92
0.75
0.4
<0.007
NR
NR
178
NR
171
0.077
NR
5.00
73
NR
<0005
7/15/96
5,390
6.38
NR
0.22
NR
NR
11.1
NR
NR
NR
NR
NR
NR
1.14
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
12/9/96
5,930
5.69
NR
<0.054
0.128
NR
10.1
<0.005
120
2,830
NR
NR
<0.011
1.05
0.283
<0.077
3.16
0.71
0.13
<0.0007
NR
<0.13
183
NR
NR
<0.003
NR
5.1
77
NR
<0075
10/29/97
5,430
6.1
NR
<0.007
0.31
NR
11.6
<0.004
104
2,940
<0.005
NR
<0.009
0.94
0.267
0.01
2.76
0.62
0.096
0.003
NR
<2.4
165
<0.011
253
<0.008
1,680
NR
67.7
NR
<0 01
Source: Nevada Bureau of Water Pollution Control, 1999
-------
1!
Oo
51
Cnnstitnpnts
IDS
EC (umhos/cm)
pH (Std. Units)
Arsenic
Barium
Boron
Calcium
Chloride
Fluoride
Iron
Lithium
Magnesium
Potassium
Silica (SI02)
Sodium
Strontium
Sulfate (SO/)
Zinc
Table 4. Constituent Data for the East
Drinking
Water
Standards *
mo/I P/S
500 S
-
6.5-8.5 S
0.05 P
2 P
-
-
250 S
4 P
0.3 S
-
-
-
-
-
500 P
5 S
Mesa Geothermal Field, California
1995 Data (1)
Concentrations in mg/1 except where noted
Advisory
Levels** Ormesa I
mo/I NIC
-
7270
6.47
0 C <0.60
2 N <0.61
0.6 N 7.34
37.69
2037.9
2.03
<0.22
3.76
2.53
78.89
158.57
1566.32
3.63
123.6
<0.07
Ormesa IE
Avpraop vnlnp«
7,680.00
12100
7.12
0.00
0.21
ND
389.00
4,090.00
1.14
15.20
209.00
24.70
2080
700
0.85
Ormesa IH
fnr nrnrlnrtinn wpll«
6,468.08
10716.67
6.09
ND
0.75
8.25
51.35
3,398.00
1.69
0.12
6.72
2.70
136.21
165.44
2357.72
5.80
95.33
ND
Ormesa II
5,997.57
9930
8.02
0.39
0.69
ND
32.51
3087.14
2.4
0.29
1.64
144
1853.67
63.57
ND
OG-I Plant
88-31 77-31
7480 5064
8.4 8.3
29.92 20.25
6
4099 2638
3.74 5.064
119.7 96.2
2790 1914.
2
97.2 111.4
1988 Data (2)
Concentrations in nig/1 except where noted
OG-II Plant
38-3(1 14-5 84-1 18-5 45-fi 7.1 -(.
1978 758 6812 6722 7794 7018
9 8.6 8.2 8.7 8.4 8.3
0.593 1.52 13.62 20.17 15.59 21.05
4
538 411 3699 3623 4248 3818
0.395 0.23 2.725 0.672 2.338 2.807
6
27.7 30.3 156.7 201.7 233.8 161.4
714.1 277 2616 2433 2923 2632
191.9 11.4 95.4 127.7 109.1 98.3
OG-IE Plant
14-3?
6632
8.6
3648
66.3
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
-------
Table 5. Constituent Data for the Salton Sea Geothermal Field, California
1!
Oo
Constituents
Temperature(°C)
Well Depth (meters)
IDS (wt %)
pH (Std. units)
Ammonium (NH4*)
Barium
Boron
Bromide
Cadmium
Calcium
Chloride
Copper
Hydrogen Sulfide (H2S)
Iron
Lead
Lithium
Magnesium
Manganese
Potassium
Silica (SI02) ***
Sodium (wt ppm)
Strontium
Sulfate (SQ,-2)
Zinc
Drinking
Standa
mg/l
-
-
500
6.5-8.5
-
2
-
-
0.005
-
250
1.3
-
0.3
0.015
-
-
0.05
-
-
-
-
500
5
Water Health
Representative Flash-corrected Brine Analysis
Concentrations in ppm unless otherwise noted
rds Advisory Levels Hvpersaline Brines (1-4)
P/S ni2/l N/C (1)
305
1,850-1,890
S - -25.6
S - 5.4
30 N 333
P 2 N 203
0.6 N 257
99
P 0.005 N 2.2
27,400
S - 151,000
5.9
15
S - 1560
P - 100
194
33
S - 1450
16700
>46\
53000
17 N 411
P - 65
S 2 N 518
(2)
330
2,500-3,22
0
-26.5
5.1
330
353 **
271
111
2.3
28,500
157,500
6.8
10
1,710
102
209
49
1,500
17,700
>588
54,800
421
53
507
(3)
300
660-1,07
0
-21.4
5.2
339
183
204
95
1.0
22,800
128,000
15
582
69
157
19
801
12,500
>336
46,200
376
-100
321
(4) (5)
295 240
700-1,07 570-720
0
-20.0 -12.7
5.3
341
156
197
78
1.4
20,900 11,000
116,000 85,000
2
20
969 65
67
152 93
33
855
11,800 5,000
>404
41,400 25,000
345 513
53
323
Low TDS Brines (5-8)
(6)
230
710-940
-6.2
6.9
103
45
92
24
ND
2,520
31,000
ND
86
2.6
55
54
>255
2,480
>255
15,000
112
53
11
(7)
190
7-520
-3.5
321
3
100
15
1,130
19,700
0.7
40
74
>120
1,250
>120
10,600
85
621
(8)
200
410-990
-1.3
7.6
0.7
32
10
ND
117
6,900
ND
25
ND
9
24
102
297
102
4,800
10
440
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 #lib
(4) Commercial Well #10
(5) Woolsey Well # 1
(6) Commercial Well #B1
(7) I.I..D. Well #3
(8) Commercial Well # 113
-------
Table 6a. Constituent Data for the SIGC Plant, Heber Geothermal Field, California
SIGC ( Second Imperial Geothermal Company) Binary
Plant
(Concentrations in ppm except as noted)
Production Wells 1
Constituents
IDS
EC (umhos/cm)
pH (units)
Antimony
Arsenic
Barium
Bicarbonate
Boron
Calcium
Cesium
Chloride
Iron
Lithium
Magnesium
Manganese
Potassium
Silica (SI02)
Sodium
Strontium
Sulfate
Zinc
Drinking Water Advisory HGU
Standards * Levels ** 210
500 S - 13,270
-
6.5-8.5 S
0.006 P 0.003 N
0.05 P 0.002 C 0.12
2 P 2 N 2.83
54
0.6 N 5.51
977.92
-
250 S - 7,662
0.3 S - 0.22
5.75
21
0.05 S - 0.13
340.09
217.29
3,957.92
17 N 38.03
500 P - 105
5 S 2 N 0.08
HGU
201
13,140
0.11
2.85
38
5.42
990.91
7,520
0.17
5.74
2.25
0.13
347.23
232.11
4,109.15
39.07
117
ND
HGU
204
12,660
0.08
2.38
37
4.82
964.82
7,343
0.25
4.82
1.89
0.12
287.96
128.88
3,745.84
34.5
142
ND
HGU
253
13,592
21,000
6.2
ND
0.1
2.99
35
243.8
995.29
7,893
0.35
5.55
1.55
0.13
329.59
243.8
3,889.33
36.98
98
0.01
Injection Wells
HGU 155
11,300
1.91
<05
0.23
52.98
4.3
1078
12.18
7,900
6.88
3.45
7.13
0.52
419
3,378
40.31
64
0.17
HGU 170
(Holtz 2)
16,330
3
12
1062
NA
8,242
0.4
4.1
23
0.9
231
187
4,720
42
148
0.1
Source: CDOG, 1998e.
* Drinking Water Standards: P= Primary; S= Secondary
** Health Advisory Levels: N= Noncancer
September 30, 1999
14
-------
Table 6b. Constituent Data for the SDG&E Plant, Heber Geothermal Field, California
Constituents
Sampling Date
pH (Std. units)
IDS
Aluminum
Antimony
Arsenic
Barium
Bicarbonate ( HC(V)
Boron
Bromide
Calcium
Carbonate (CO,'2)
Cesium
Chloride
Copper
Fluoride
Iodide
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Potassium
SDG&E POWER, Binary Plant, HEBER GEOTHERMAL FLUID
Drinking Health TYPICAL BRINE ANALYSIS
Water Advisory
Standards * Levels ** Production Wells (wt ppm)
HG
N/ HGU HGU U HGU HGU
mg/1 P/S mg/1 C Well not specified 101 102 103 104 105
8/23/7 11/18/7 10/17/7 12/4/7
4444
6.5-8.5 S - 6.60 6.30 5.80 6.45
500 S - 14,110 14,470 14,310 14,195
0.05- S - 31 15 28 1.0
0.2
0.006 P 0.00 N 0.05 0.05 0.05 0.05 0.051
3
0.05 P 0.00 C 0.167 0.207 0.14 0.106 0.119
2 6
2P2N3 5 5 5 0.155 6.536 0.05 0.216 3.734
0
64
0.6 N 7.2 5.2 5.7 4.0 6.048 9.723 5.59 2.605 6.531
2
11.7 10.9 8.4 1.9 11.1
656 859 2,063 844 810 1,004 1,00 885 915
6
0
0.600 0.881 0.62 0.583 0.654
4
250 S - 7,246 7,600 7,764 7,363 18,47 9,11 9,143 10,80
9,133 2 1 8
1.3 P - 0.5 0.6 1.1 0.8
4.0 P - 1.5 1.6 2.2 3.0
0.625 0.620 0.52 0.464 0.403
2
0.3 S - 6 14 34 68 0.100 0.161 0.35 0.100 0.276
2
0.015 P - 0.3 1.3 1.3 0.6 0.005 0.095 0.00 0.010 0.050
4
5 3.8 5 4 8.504 12.98 7.84 10.14 7.664
267
3.4 5.9 3.8 5.9 1.101 1.421 1.60 1.507 1.328
9
0.05 S - 0.6 0.9 3.1 3.1 0.130 0.123 0.15 0.121 0.102
1
0.002 P 0.00 N 2.790 0.002 3.41 2.704 0.002
2 7
250 238 250 228 415 398 402 372 393
HGU
106
0.05
0.151
0.140
6.592
11.9
864
0.672
13,926
0.762
0.301
0.089
7.021
1.304
0.050
2.799
385
September 30, 1999
15
-------
Constituents
Rubidium
Silica (SI02)
Silver
Sodium
Strontium
Sulfate (SQ,'2)
Zinc
SDG&E POWER,
Drinking Health
Water Advisory
Standards * Levels **
N/
mg/1 P/S mg/1 C Well not specified
..
214 281 281
0.1 S 0.1 N ND ND ND
3,750 4,313 4,219
17 N 39 37 36
500 P - 74 88 81
5 S 2 N 0.3 0.7 0.6
Binary Plant, HEBER GEOTHERMAL FLUID
TYPICAL BRINE ANALYSIS
Production Wells (wt ppm)
HGU
101
3.101
294 223
ND
4,312 5,052
38 28.9
80 115.2
0.3
HGU
102
1.800
240
4,397
42.2
40.5
HG
U
103
1.91
1
205
4,00
2
34.7
54.2
HGU
104
1.608
81
3,557
27.0
67.2
HGU
105
1.839
247
4,333
34.1
69.6
HGU
106
2.106
227
3,952
34.8
76.9
Source: Second Imperial Geothermal Company, 1993.
* Drinking Water Standards: P= Primary; S= Secondary
** Health Advisory Levels: N= Noncancer
September 30, 1999
16
-------
Table 6c. Constituent Data for the HGC Plant, Heber Geothermal Field, California
Constituents
Sampling Date
IDS
pH (Std. Units)
Antimony
Arsenic
Barium
Bicarbonate
Boron
Calcium
Cesium
Chloride
Chromium
Copper
Fluoride
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Potassium
Sodium
Strontium
Sulfate
Zinc
Drinking Water Health Heber Geothermal Company, Flash Plant
Standards * Advisory Concentrations in mg/1 unless otherwise noted
Levels * *
mg/1 P/S mg/1 N/C
HGU53
3/29/85
500 S
6.5-8.5 S
0.006 P 0.003 N 2.03
0.05 P 0.002 C <0.05
2 P 2 N 0.56
--
0.6 N 7.8
1022
13.28
8,650
0.1 P 0.1 N 0.66
1.3 P - 0.42
4 P - 0.65
0.3 S - 20.25
0.015 P - 1.43
8.65
5.38
0.05 S - 1.07
0.002 P 0.002 N 0.002
428
4,072
17 N 50.45
500 P - 25
5 S 2 N 0.21
Injection
HGU55
3/29/85
1.98
<0.05
1.12
8.1
756
13.3
8,756
0.58
0.17
0.55
19.50
0.35
8.13
8.50
1.46
0.011
441
4,150
58.39
26
0.15
Wells
HGU57
3/29/85
1.75
<0.05
0.74
6.3
575
12.32
7,185
0.46
0.71
0.55
6.88
1.59
8.79
1.75
0.46
0.005
313
3,494
44.47
59
1.38
HGU5
17,000
8
4.5
32.0
5.6
940
8,200
0.02
2.0
0.12
ND
7.7
1.6
0.12
310
4,300
35
68.0
Source: CDOG, 1998e.
* Drinking Water Standards: P= Primary; S= Secondary
* * Health Advisory Levels: N= Noncancer
September 30, 1999
17
-------
September 30, 1999
Constituents
EC (usiemens)
Ammonia
(dissolved)
Arsenic
(ppm/w)
Boron (ppm/w)
Nitrate
Nitrite
Sulfate
Table 7a. Constituent
Drinking Health
Water Advisory
Standards * Levels **
Unit
N/ s
nip/1 P/S nip/1 C 5&6
8,38
0
30 N 1,20
0
0.05 P 0.00 C 0.28
2
0.6 N 200
10 P - 0.05
1 P - 0.12
500 P - 1,90
0
Data
for The Geysers Geothermal
Field, California
SOUTHEAST GEYSERS: UNOCAL CORPORATION
Concentrations in mg/1 unless otherwise noted
1997 Grab Sample Analvses 1
Units
6900
800
0.28
230
<0.03
0.13
1,100
7& 8
6930
790
0.29
230
<0.03
0.11
1,300
Units
9&10
2940
12
0.62
150
<0.03
1.2
550
Units
11
1180
0
1400
0.029
140
0.08
<0.03
2,000
Unit
12
4280
560
0.19
150
0.13
0.34
1,300
Unit
14
260
51
0.01
5
17
<0.0
3
<0.0
3
38
Uni
t 17
650
0
100
0.13
96
0.05
0.13
280
Uni
t 18
181
0
180
0.5
200
0.14
0.03
660
Unit
20
600
8.6
0.38
99
1.1
0.04
170
Unit
5&6
6,808
757
0.30
202
4
0.31
852
Average Condensate Analvses 1991-1996
Unit
7&8
6,220
705
0.25
173
3
1.23
1,387
Unit
9&10
2,756
11
0.44
128
7
3
389
Unit
11
9,24
6
1,04
6
0.13
124
6
0.66
2,15
6
Unit
12
3,18
9
263
0.64
146
0.92
0.35
1,13
1
Unit
14
329
39
0.30
59
0.73
0.15
48
Unit
17
7,049
692
0.71
279
2
0.80
2,326
Unit
18
693
59
1.19
201
1
0.26
218
Unit
20
800
34
0.36
101
0.15
0.04
128
Source: UNOCAL Corporation, 1998.
* Drinking Water Standards: P = Primary, S = Secondary
** For Health Advisory Levels: N= Noncancer Lifetime; C= Cancer Risk
-------
Table 7b. Constituent Data for The Geysers Geothermal Field, California — Con't
Constituents
Sampling Date
EC (umhos/cm)
Ammonia
Arsenic
Boron
Calcium
Calcium
Carbonate
Chloride
Magnesium
Nitrate
Nitrite
Sulfate
Drinking Health
Water Advisory
Standards * Levels **
Unit 13
N/ Injectio
ni2/l P/S 1112/1 C n
12/22/92
450
30 N
0.05 P 0.00 C 0.42
2
0.6 N 77
-
ND
250 S - ND
ND
10 P - 0.76
1 P
500 P - 88
CALPINE Geysers Company
Concentrations in mg/1, unless otherwise noted
(1)
Unit 16
Injection
12/22/92
620
0.085
32
ND
ND
ND
0.37
120
SMUDGED 1
Power Plant
Annual
Injectate
Analysis (2)
12/29/93
560
45
0.32
110
0.13
0.03
97
Pacific Gas
and Electric
Unit 13
(2)
12/29/93
614
0.50
94
ND
ND
1.5
ND
ND
150
SMUDGED 1
Power Plant
Annual
Injectate
Analysis (3)
12/30/97
1.0***
ND
190
0.12
260
Aidlin
Power Plant
Reinjectate
(4)
11/23/98
8,860
1,280
0.053
95
2.3
8.5
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
19
-------
Table 7c. Constituent Data for The Geysers Geothermal Field, California — Con't
Northern California Power Agency
Concentrations in mg/l unless otherwise noted
Constituents
EC
(umhos/cm)
Ammonia
Arsenic
Boron
Nitrate
Nitrite
Sulfate
Drinking Health
Standards * Levels **
Unit
mg/l P/S mg/l N/C 1
439
30 N 56.00
0.05 P 0.002 0.06
0.6 N 64.01
10 P - 3.76
1 P - 0.242
500 P - 124
Effluent Monitoring Data (1)
1994
Unit
2
456
52.92
0.06
87.59
3.39
0.198
113
Unit
3
539
62.31
0.01
31.46
3.44
0.288
160
Unit
4
687
81.77
0.09
57.93
1.92
0.19
209
Unit
1
333
41.3
0.17
81.4
1.7
0.07
87.7
1997
Unit
2
264
37.4
0.10
132.6
0.9
0.05
64.6
Unit
3
666
82.7
0.02
43.8
1.2
0.28
265.9
Unit
4
736
92.9
0.04
53.1
1.8
0.28
290
Condensate
Analysis (2)
1988
Plant 1
108
17.17
0.128
59.5
0.071
0.027
5.61
Plant 2
384
41.95
0.033
21.9
1.54
0.08
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
20
-------
Co
^
^
i
0
TO
>!
Lo Constituents
^ Sampling Date
S§ IDS
EC (u.mhos/cm)
pH (Std. Units)
Aluminum
Ammonia
Arsenic
Barium
Bicarbonate (HCO 3-')
Boron
Calcium
Calcium Carbonate
(Total hardness)
Chloride
Chromium
Fluoride
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Nitrate
Nitrite
Potassium
Silica (SIOj)
Silver
Sodium
Strontium
Sulfate
Sulfide
Zinc
laoie /a. ^onsmuem uara lor me ^eysers *jeo
Drinking Water Health Advisory
Standards * Levels " GEO Operator Corpora
nip/1 P/S mp/l N/C Conrentra
10/15/79 11/24/80 10/13/81 10/15/81 5/19/82
500 P - 1,200
850 1,300 1,100 1,200 1,700
6.5-8.5 P - 7.3 7.3 6.5
0.05-0.2 S
30 N 96.0 115.0 130 140 150
0.05 P 0.002 C 0.44
2 P 2 N
0.6 N 160 200 160 180 140
<1.0 <1.0 3.8
12
250 S - 1.1 1.8 <2.0
0.1 P 0.1 N <0.005
4 P -
0.3 S - 0.21
0.015 P - <0.05
-
<0.5 <0.5 0.6
0.05 S
0.002 P 0.002 N 0.008
10 P - <0.10 0.25 1.6 1.9 <0.10
1 P - 0.05 0.93 6.4 1.5 0.33
0.34 0.48
2.3 2.1 2.5
0.1 N
13.0 22.0 47
17 N
500 P - 210 390 450 470 660
0.01 0.01
5 S 2 N 0.06
inermai rieia, ^amo
rnia —
^on i
ition (a.k.a. GRI Operator, a.k.a. Thermogenics)
Chemical Analysis of Condensate
10/21/82 11/1/82 10/18/83
160 1,500
1,950 1,680 2,300
6.5 7.3 5.8
0.06 0.28 0.22
230 201 280
0.62 0.41
280 133 180
<1.0 2.7
<1 6.8
4.9 <0.5
<0.005 0.012
0.35 3.1
<0.05 <0.05
<1.0
0.006 0.43
3.9 1.6
2.3 .99
2.5 0.22 <0.1
3.0 <1.4
840 696 1,100
<0.050 0.23
8/17/84
3,200
6.9
0.6
430
0.36
<0.2
12
270
1.2
10
5
0.1
3.5
<0.01
<0.01
0.5
0.10
0.0016
<0.1
0.2
4.0
2.3
1,300
<0.05
2/25/85
1,900
2,800
7.0
<0.5
280
0.19
<0.3
57
130
•0.1
47
• 1
0.1
0.29
<0.005
<0.01
0.07
0.025
0.017
•0.05
<0.2
1.8
790
<5
10/7/86
1,138
4.20
ND
240
ND
ND
114.77
1.42
16.00
ND
3.98
ND
ND
1.04
ND
ND
1.85
ND
26.99
0.01
732
0.16
11/14/88
2,660
265
0.04
115.77
<0.10
1,085
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
-------
Table 7e. Constituent Data for The Geysers Geothermal Field, California — Con't
Constituents
Sampling Date
IDS
EC (umhos/cm)
pH (Std. units)
Aluminum
Ammonia
Arsenic
Boron
Calcium
Calcium Carbonate
Chloride
Fluoride
Iron
Magnesium
Mercury
Nitrate
Nitrite
Potassium
Silica (SI02)
Sodium
Sulfate
Sulfide
Health
Drinking Water Advisory
Standards * Levels **
mg/1 P/S mg/1 N/C
..
500 S
-
6.5-8.5 S
0.05 - S
0.2
30 N
0.05 P 0.002 C
0.6 N
-
-
250 S
4.0 P
0.3 S
-
0.002 P 0.002 N
10 P
1 P
-
-
-
500 P
..
Concentration in mg/1 unless otherwise noted
West Ford Flat
The (2)
Geysers
(1) Injectate
3/27/89 -
3/30/89
640
280
7.2
0.1
14
0.95 1.4
160 105
0.5
79
1.3
0.9
1.6
O.OOl
1.2
0.07
<0.5
0.8
1.4
52 38
0.2
Bear Canyon
(3)
Steam
Condensate
1/12/89
192
200
8.4
22
54
0.1
<0.1
0.1
50
Sources:
(1) Crockett & Enedy, 1990.
(2) Freeport-M°MoRan Resource Partners / Geysers Geothermal Company. 1989.
(3) Freeport-M°MoRan 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
22
-------
Table 7f. Constituent Data for The Geysers Geothermal Field, California — Con't
„ . . . „ Southeast Geysers Effluent Pipeline Project
Water Advisory Estimates of Injection Water 1995
Standards * Levels ** (1)
Blended
WWTP Lake /
Constituents ni2/l P/S ni2/l N/C Lake Effluent Effluent
Sampling Date
Flow, MGD - - 3.38 1.84
Temperature (°C) - - 6-28 6-26 6.26
IDS 500 S - 134-390 348-390 228
Suspended Solids - - 5-50 10-30 20
EC (umhos/cm) - - 69-364
pH (Std. Units) 6.5-8.5 S - 7-9.3 6.5-8.5 7.9
Turbidity (NTU) 0.5-1.0 P
BOD 3-9 10-30 11
Total Coliforms per 100
Fecal Coliforms per 100
Alkalinity (CaCO,) - - 67-170 170-240 143
Hardness (CaCO,) - - 94-170 150-190 137
Total Salts - - 140-260 500-600 325
Aluminum 0.05 - S —
Bicarbonate (HCO,-1) - - 80-210 210-290 173
Boron - 0.6 N
Calcium - - 16-33 30-40 26
Chloride 250 S
Fluoride 4 P -
Iron 0.3 S
Magnesium - - 12-21 20-25 18
Manganese 0.05 S
Nitrate 10 P
Oxygen (dissolved) - - 0.1-17 1-10 7.2
Potassium
Silver - 0.1 N 14 14
Sodium
Sulfate 500 P
Zinc 5 S 2 N
Source:
(l)ESA. 1994.
(2) Alpha Analytical Laboratories, 1995 & 1998.
(3) Lake Labs, 1998
" Southeast Lake Intake
Treatment Plant Pump System
(SETP) Reservoir (LIPS)
(2,3) (3)
1995 2/11/98 8/28/98 9/7/98
346 232
541 362
7.9 7.1
32 20
100 3000 700
100 3000 60
171 125
61
1
209
153
33 25
54 20
ND ND
1.44 0.96
19 14
0.069 0.12
14 1.1
10 3.6
56 21
68 14
0.038
September 30, 1999
23
-------
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 24
-------
Figure 4
Example Schematic of Geothermal Injection Well Associated With
Electric Power Generation
Source: CDOG, 1998c
September 30, 1999
25
-------
Figure 5
Example Schematic of Geothermal Injection Well Associated With
Electric Power Generation
_j 3D* conductor set at 6ft'. cement to surface
2
-------
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 \etter, 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
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
-------
Figure 6. Site Plan for Heber Field Showing Well Clustering
and Directional Drilling
r^-**. ^ife-i^7^^
HEBER GEQTHenMAL HELD
IMPERIAL VALLEY, CALIFORNfA
*W *Xi Ui'ii img
•• Mrf MJ&ri .li;li h r
Source: CDOG, 1996
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
September 30, 1999
28
-------
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.
5 Based on review of selected well abandonment plans and completion reports and permits from
BLM and state agency offices in CA and NY 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., F^S) emissions, well plugging both improves safety and protects USDWs.
September 30, 1999 29
-------
Figure 7. Example of Well Plugging with Multiple Cement Plugs
25"
hole
17 1/2^
hole
121/4-
hole
casing cement
casing cement
plug cement
drilling mud
1
' /
rj;
^';
''X
'•'V
x^
xv'
wi
^
•-,
X
N
x
^x
1
x
Jx
s
NX
S
^
'
^
X
>
X
^'
x
x
X
V
X
x
x
x
>
x
X
;
•/
's
x
/
X_^-
-V
;x;
•_;>:
-•',-
"x""
•'V
X
g
^<
g
Xx
V:
>>•
--;
?
'X'.
1
k
^
X."
x:
x
x^
•<;
^
Jx;
|
|
ry\
"*''/
*'\ 2CT
rj\ casing
• ^t
W
133/fi-
casing
Tie tact
9 5/8c liner
hole
S1/2'
hole
zsr
65/8'blank/perfliner
(Perf'd 6786-7298')
.
Source: CDOG, 1998b
September 30, 1999
30
-------
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
September 30, 1999 31
-------
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 unconfmed, 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/1. Similar near-surface leaks have also occurred in Nevada at some wells constructed with cellars
around the casing wellhead (Land, 1999).
7 Chloride concentrations and Cl/Mg rations increased from about 500 mg/1 to 1,100 mg/1 and 30 to
100 mg/1 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 7°C in June 1991. Susequent
measurements indicate a long-term increase of about 10°C 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
-------
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 33
-------
Figure 8. Geothermal Well Casing Design,
Puna Geothermal Venture, Hawaii
Ground surface
26' Hole *
20' Casing >
-1000ft
17 «< Unla
rippn Annulus
Nitropn
Injwtafe
I'VI'W
QOTfednt,
T'nrfl'HangdnwrilinRr
-3700 ft
-4000 ft
1
'b
j
d
•v !
s "
v '
s •> •
\\ f
\% ^
S ^
\ '
\' '
v
^ *. *•
\ ; f
S*' f
'Q'f
'/
^
*^
111,
/
/
/
S,
| .
?'
/
li i
1 •"
/
/,^
• i .
•^
•'.;
^
ec
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/_
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Appn&x600ft.aho«HSL
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§p f -600 ft
V
•^ Unconfined Aquifer
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t. f nififiinn 7nnfil
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Source: Puna Geothermal "Venture, 1996
September 30, 1999
34
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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:
• Inj ection pressure (if any);
• Corrosivity and scaling properties of the injectate;
• Corrosivity of soils and formations that the well penetrates;
• Presence and characteristics of USDWs (if any); and
• 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 35
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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 36
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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 "Vbrk, 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
September 30, 1999 37
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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
11 May 2003 is the deadline including an 18-month extension.
September 30, 1999 38
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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 redlining, 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 39
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Well A bandonment
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 40
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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 41
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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.
• 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.
• Acid sulfate waters are low in chloride content with the constituents found in these waters
mainly leaching from surrounding reservoir rocks.
• 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.
• 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). \&por-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 42
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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 non-
condensible 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:
• steam or vapor dominated systems,
• high temperature water (liquid dominated) systems, and
• 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 200°C (400°F). 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 A-
1 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
September 30, 1999 43
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Figure A-l. Single-stage, Flashed-Steam Power Plant
Flash Stream Power Plant
Generator
i 1 A Air and
Hfwi
Water Vapor
Source: U.S. DOE, 1998b
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.
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
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Figure A-2. Typical Flow Diagram of a Binary Cycle Power Cycle
Binary Cycle Power Plant
Air and
Water Vapor
Heat Exchanger
-
Source: U. S. DOE, 1998b
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 non-
condensible 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
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• sodium sulfite,
• benzoic acid,
• sodium hydroxide,
• sodium gluconate,
• dimethyldioctylammonium chloride,
• soya amine polyethoxylate,
• cychlohexlamine,
• polyamidoamino acetate,
POE (15) tallow amine,
• sodium metabisulfite,
• cobalt compounds,
• sodium chloride,
• phosphoric acid derivative,
• magnesium nitrate,
• 5-chloro-2-methyl-4-isothiazoline-3-one,
• magnesium chloride,
• 2-methyl-4-isothiazolin-3-one,
• cupric nitrate,
• disodium ethylenebis-dithiocarbamate,
• dimethylamine,
• ethylene diamine,
• ethylene thiourea, and
• 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; Bellinger, 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 46
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steam condensate available for injection varies seasonally (due to higher evaporation rates during the
warmer summer months).
At the Dixie \&lley 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):
• steam turbine seal water,
• rinsate from water softener system,
• sulfatreat heat exchanger cooling water,
• raw/quench water,
• production well bleed system,
• abatement fluids,
• sulfatreat system vacuum pump seal water,
• condensate from the sulfatreat system,
• periodic drilling fluids, and
• fluids from the plant water storage tank and the emergency steam release facility.
September 30, 1999 47
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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. l(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
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
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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 49
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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).
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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.
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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/1, 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).
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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).
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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, (445 A.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
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
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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 (445 A.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 (445 A. 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).
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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,
534A270 NAC).
September 30, 1999 56
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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 (534A400, 534A410, 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 57
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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 58
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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-l-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-
l-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-l-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-l-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-l-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-l-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.
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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-l-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 60
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casing (UAC R655-l-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-
l-6.2(j),(k)); (UAC R655-1-6.1-thru R655-1-6.2).
September 30, 1999 61
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