U.S. Department of the Interior

U.S. Geological Survey

Open-File Report 99-304

Gas and isotope geochemistry of 81 steam

samples from wells in The Geysers geothermal

field, Sonoma and Lake Counties, California, U.S.A.

Top of Reservoir

Ground Surface

Felsite

View from the South- southeast

Vertical Exaggeration = 2X
Gas and Isotope Geochemistry of

81 Steam Samples from Wells in

The Geysers Geothermal Field,

Sonoma and Lake Counties,

California, U.S.A.

By Jacob B. Lowenstern1,Cathy J. Janik1,

Lynne S. Fahlquist2 and Linda S. Johnson3

Open-File Report 99-304

Available online at: http://wrgis.wr.usgs.gov/open-file/of99-304/

1999

This report is preliminary and has not been reviewed for conformity with U.S. Geological Survey

editorial standards or with the North American Stratigraphic Code. Any use of trade, firm, or

product names is for descriptive purposes only and does not imply endorsement by the U.S.

Government.

U.S. DEPARTMENT OF THE INTERIOR

U.S. GEOLOGICAL SURVEY

1

U.S. Geological Survey, 345 Middlefield Road, Menlo Park, CA 94025

2

U.S. Geological Survey, 8027 Exchange Drive, Austin, TX 78754-4733

3

Kaiser Cement Corporation, 24001 Stevens Creek Boulevard, Cupertino, CA 95014
1

ABSTRACT

The Geysers geothermal field in northern California,

with about 2000-MW electrical capacity, is the largest geothermal field in the world. Despite its importance as a resource and as an example of a vapor-dominated reservoir,

very few complete geochemical analyses of the steam have

been published (Allen and Day, 1927; Truesdell and others,

1987). This report presents data from 90 steam, gas, and condensate samples from wells in The Geysers geothermal field

in northern California. Samples were collected between 1978

and 1991. Well attributes include sampling date, well name,

location, total depth, and the wellhead temperature and pressure at which the sample was collected. Geochemical characteristics include the steam/gas ratio, composition of noncondensable gas (relative proportions of CO2

, H2S, He, H2,

O2, Ar, N2, CH4, and NH3), and isotopic values for δD and

δ18O of H2

O, δ13C of CO2, and δ34S of H2S. The compilation

includes 81 analyses from 74 different production wells, 9

isotopic analyses of steam condensate pumped into injection

wells, and 5 complete geochemical analyses on gases from

surface fumaroles and bubbling pools.

Most samples were collected as saturated steam and

plot along the liquid-water/steam boiling curve. Steam-togas ratios are highest in the southeastern part of the geothermal field and lowest in the northwest, consistent with other

studies. Wells in the Northwest Geysers are also enriched in

N2/Ar, CO2 and CH4, δD, and δ18O. Well discharges from the

Southeast Geysers are high in steam/gas and have isotopic

compositions and N2/Ar ratios consistent with recharge by

local meteoric waters. Samples from the Central Geysers

show characteristics found in both the Southeast and Northwest Geysers.

Gas and steam characteristics of well discharges from

the Northwest Geysers are consistent with input of components from a high-temperature reservoir containing carbonrich gases derived from the host Franciscan rocks. Throughout the geothermal field, the carbon-isotopic composition of

CO2

 is consistent with derivation of carbon from Franciscan

metasedimentary rocks. NH3 concentrations are high in most

Geysers well fluids, and are 2-3 orders of magnitude greater

than would be expected in a the gas phase exhibiting homogeneous equilibrium at normal reservoir temperatures and

pressures. Evidently, NH3

 is flushed from the Franciscan host

rocks at a rate that exceeds the reaction rate for NH3 breakdown.

Many wells show clear influence by fluids from reinjection wells where steam condensate has been pumped

back into the geothermal reservoir. Six wells were resampled

over the time period of this study. One of these six wells was

strongly affected by a nearby injection well. Three of the six

resampled wells showed some signs of decreasing liquid/

steam within the geothermal reservoir, consistent with “drying out” of the reservoir due to steam withdrawal. However,

two wells exhibited little change.

Analyses of gases from five surface manifestations (fumaroles and bubbling pools) are roughly similar to the deeper

geothermal samples in both chemical and isotopic composition, but are lower in soluble gases that dissolve in groundwater during transit toward the surface.

INTRODUCTION

The following report contains gas and isotope analyses

of fluids discharged from steam wells in The Geysers geothermal field, Sonoma, Lake and Mendocino Counties, California. These samples were collected and analyzed by a variety of USGS scientists over a period of 20 years. Though sampling and analytical methodologies were not always identical, we have made every effort to ensure that the data are

consistent and comparable, and we believe the data published

herein are accurate within the precisions reported. In addition to analytical data and locations, we have provided additional information on the wells, such as their total depth, depth

of casing, temperature, and pressure, to aid workers in their

use of the data.

ACKNOWLEDGMENTS

Gas sampling and analysis began in the mid-1970s under the guidance of Dr. Alfred H. Truesdell. USGS Menlo

Park employees involved in work on The Geysers included

Nancy Nehring, Mary Stallard, Terrie Winnett, Marianne

Guffanti, Terry Cheatham, and Julie Kennedy. In addition, a

variety of USGS people helped with sample analysis, including Carol Kendall, Bill Evans, L. Doug White, Steve Silva,

Mark Huebner (all from Menlo Park), Tyler Coplen (Reston),

and W.C. Pat Shanks III (Denver). We appreciate the assistance and cooperation of Brian Koenig, Tom Powell, and Phil

Molling (Unocal Corporation), Tom Box and Joe Beall

(Calpine Corporation), John Stackleberg and Jill Haizlip (Geo

Corporation and CCOC), Deb Bergfeld (University of New

Mexico), and Ken Stelling and Ali Khan of the Division of

Oil, Gas, and Geothermal Resources, California Department

of Conservation. This work was partially funded through the

Department of Energy-U.S. Geological Survey Interagency

Agreement No. DE-AI-01-91-CE-31020. Joe Moore (EGI)

and Julie Donnelly-Nolan (USGS) carefully reviewed the

manuscript.

BACKGROUND

ABOUT THE GEYSERS

The Geysers steam field is a vapor-dominated geothermal reservoir located in the Mayacmas Range in northern California, about 150 km north of San Francisco (fig. 1). It covers about 150 km2 on the border of Lake, Mendocino, and

1
2

N

0 1 2 3

km

Figure 1. Geysers Well Locations for OFR 99-XXX

C a l i f o r n i a

The Geysers

-122°50’ -122°55’

38°52’30" -122°45’ -122°40’

38°47’30"

38°45’

38°50’

Mendocino County

Sonoma County

Lake County

Approximate Boundary of The Geysers

Steam

F

ei dl

Northwest Geysers

Central Geysers

Southeast Geysers

Unit 15

T11N

T11N

T11N

T10N

T12N

T12N

R8W

R7W

R8W

R8W

R9W

R9WR8W

R9W

28

25

22

19 18

24

23

27

21

26 20

55

56

65

78

79

31

32

83

30 74

73 76

75

81

80

29

77

47

82

50

49 60

42

38

72

44

41

40

1

2

39

3

66

67

70

71 16

8

17

9

34

33

14

36

37

13

15 10

4 5 12 11

7

6

64

63

61

62

59

52 51

58

57

43

48

Union

Calpine

Unit 15

CCOC

Production Injection

Sonoma Counties. In vapor-dominated systems, water is

present as both liquid and steam, though vaporized water constitutes the pressure-supporting medium. Thus, these reservoirs are significantly underpressured with respect to a hydrostatic load and must be tightly sealed by low-permeability

rocks to prevent the system from being flooded by colder infiltrating ground water (White and others, 1971).

The Geysers is the most obvious manifestation of a large

heat-flow anomaly associated with the adjacent Clear Lake

volcanic field, a late Pliocene to Holocene magmatic system

(Hearn and others, 1981, 1995; Donnelly-Nolan and others,

1981). The Geysers steam field is oriented northwest-southeast, parallel to the southwest edge of the volcanic field. It is

bordered to the southwest and northeast by active NW-trending faults of the San Andreas fault system. Apparently, these

faults and associated lithology changes act as permeability

barriers that contain the geothermal system (Goff and others,

1977).

Though the total electrical generation of The Geysers

exceeded 2,000 MW in the late 1980s, current production

Figure 1.—Well locations for this study. Well symbols (see legend) correspond to the geothermal operator that operated the well at the time

of sampling. Unit 15 wells, operated at the time by GEO Corp., are listed by their unit name. Injection wells are designated by small arrows

that pass through the symbol. Latitude and longitude tics, county boundaries and some township and range boundaries are shown to give

context relative to other published maps. Gray lines indicate informal region boundaries that separate the field into Southeast, Central,

Northwest and Unit 15 sectors. They are not necessarily consistent with terminology used in other studies. The outline of the steam field is

from California Division of Oil and Gas (1992).
3

Big Sulphur Creek Big Sulphur Creek

Squaw Creek Squaw Creek

Cobb Mtn.

Geysers

Resort

N

is < 1,000 MW from 300-400 active wells. In 1998, geothermal operators began piping treated wastewater from

Lake County to The Geysers to recharge the geothermal

system. In the future, wastewater from Santa Rosa also may

be injected. Both of these projects are likely to change the

chemistry and isotopic composition of steam and gas discharges from The Geysers. As such, the analyses reported

here will be useful in tracking future changes in the composition of steam from The Geysers.

HISTORY OF THE GEYSERS STEAM

FIELD

The Mayacmas Range never contained actual geysers,

but early explorers to the region did find fumaroles, mud

pots, and steaming ground. In the late 19th century, the Geysers Resort, built where Geyser Canyon intersects Big Sulphur Creek, was popular as a spa capable of hosting 200

guests. Koenig (1992) reviewed the history of geothermal

development at The Geysers, and the following few paragraphs summarize material in his review. Though the first

attempt to generate electricity was a commercial failure, it

did provide enough power to light The Geysers Resort in

the late 1920s. B.C. McCabe established the Magma Power

Company in the early 1950s and completed 6 wells between

1955 and 1957. Magma, together with Thermal Power, signed

a contract with the Pacific Gas and Electric Company

(PG&E) to provide steam for electricity generation in late

1958. PG&E Unit 1, The Geysers first power plant, came

“on line” in June 1960, with a 12.5-MW turbine generator.

These initial wells were less than 1,400 ft (427 m) deep, but

as later exploration spread NW and SE, significant steam

resources were found at greater depth. By 1965, drilling had

spread to the northwest and southeast along Big Sulphur

Creek (fig. 2), and some wells exceeded 5,000 ft (1,524 m)

in depth. Several more powerplants were constructed in the

late 1960s, and the cumulative generating capacity of the

steam field reached 192 MW by late 1971.

Figure 2.—Perspective image of the topography of The Geysers region as seen from the south-southwest (vertical exaggeration =3X).

Contour interval is 125 meters. The two bold contour lines are at 625 and 1,250 m. The steam-field boundary, county lines, and township and

range boundaries (as in fig. 1) are overlain, as are the well locations (white dots). The white lines denote the four regions as outlined in the

text and shown in fig. 1. Scale varies throughout the diagram but can be estimated by comparison of the field outline to that in fig. 1. The

trend of the steam field clearly mimics that of the regional topography.
4

Top of Reservoir

Ground Surface

Felsite

View from the South- southeast

Vertical Exaggeration = 2X

The energy crisis of 1973-74 spurred a large increase

in geothermal exploration and development in subsequent

years, and the electrical generating capacity at The Geysers

reached 943 MW by late 1980, making it the largest powerproducing geothermal area in the world. Development continued at a rapid pace through much of the 1980s, despite

decreased steam prices and the increasingly common transfer of ownership of geothermal wells between companies.

Environmental regulations combined with the need to

increase steam pressures led to reinjection of cooled, condensed steam into former production wells. Although Unocal

(a.k.a. Union Geothermal) had begun a limited reinjection

program in the Central Geysers as early as 1969 (Gambill,

1992), it was not until the early 1980s that the Northern California Power Agency (NCPA) and Calpine, operating in the

Southeast Geysers, began to reinject condensed steam (Klein

and Enedy, 1992; Beall and others, 1992).

By 1989, the operating capacity at The Geysers had

reached over 2,000 MW. The rate of exploration finally

slowed as steam prices decreased and exploration costs increased due to the great depths (>10,000 feet: 3,048 m) that

were needed to find steam at the margins of the field

(Koenig, 1992). At the same time, pressure declines within

the field caused additional problems. Some powerplants

operated below capacity, and others were forced to close. In

1995, the steam field was producing about 1,200 MW, approximately 60% of its capacity, but still the largest geothermal field in the world. In all, ~770 deep wells have been

drilled into the geothermal system (locations for sampled

wells are shown in figs. 1 and 2).

Figure 3.—Schematic diagram of the “felsite” intrusion, overlying geothermal reservoir and surface topography at The Geysers steam field:

view is from the south-southeast (700 m beneath the ground surface). Vertical exaggeration equals 2X. The red surface is the intrusion/

pluton, which intrudes closest to the surface toward the center of the diagram, in the south-central Geysers. The blue surface represents the

top of the geothermal reservoir. Green is surface topography. Yellow lines represent the approximate location and depths of wells, with small

squares at the well bottoms. In reality, most wells are inclined (deviated), and are thus not accurately depicted by the vertical lines on the

figure. The felsite and reservoir surfaces were constructed with data from the “Top of Reservoir” and “Top of Felsite” maps in Unocal and

others (1992) and are approximate representations of the actual geometries of these features. Note the location of the wells at the left side of

the diagram, from the Unit 15 site, which are found at the edge of the geothermal reservoir. The reservoir itself is everywhere located above

the felsite and mimics its general shape. Scale varies throughout the diagram.
5

GEOLOGY OF THE GEYSERS

RESERVOIR

The Geysers geothermal field lies within the central

belt of the Franciscan Complex, an assemblage of deep oceanic deposits formed in the Mesozoic Era and early Tertiary

Period. In this region, the Franciscan assemblage consists

primarily of regionally metamorphosed graywacke, argillites, and cherts. Numerous thrust faults result in a complex

overlapping of these rock types with Franciscan melange,

serpentinite, and greenstones (McLaughlin, 1981). Most of

the thrusting occurred contemporaneously with sedimentation and subduction.

During the last 2-3 million years, northwest-oriented,

strike-slip faults have formed as part of the San Andreas fault

system and offset many of the thrust packages within the steam

field. The Colloyami and Mercuryville strike-slip faults form

the northeast and southwest edges of The Geysers field, respectively creating a geometry for the steam field that is elongate parallel to the faults of the San Andreas system.

The steam field is also coaxial with a large composite

intrusion (fig. 3), informally known as “the felsite” (Schriener

and Suemnicht, 1981). This composite intrusion of granite,

granodiorite, and microgranite porphyry was emplaced at

about 1.1-1.2 Ma (Dalrymple, 1993; Grove and others, 1998)

and is thought to be an intrusive equivalent of Cobb Mountain dacite and rhyolite, part of the Clear Lake volcanic field

(Hulen and Walters, 1993; Hulen and others, 1997b). It appears highly likely that the geothermal system was created by

intrusion of “the felsite” to create a liquid-dominated reservoir about a million years ago (Sternfeld, 1981; McLaughlin

and others, 1983; Moore and Gunderson, 1995; Hulen and

Nielson, 1996). Besides its heat, the “felsite” may have induced some of the fracturing that has created the permeability necessary to sustain an economic geothermal system

(Hulen and Walters, 1993). The liquid-dominated reservoir

was characterized by studies of fluid inclusions and oxygen

isotopes (Moore and Gunderson, 1995) and appears to have

persisted until 0.28-0.25 Ma, when venting and consequent

boiling produced the present-day geothermal system (Shook,

1995; Hulen and others, 1997a, b). More recent, underlying,

unsampled intrusions likely provide the heat that is being

“mined” by the current geothermal system (Hearn and others, 1981; Truesdell and others, 1987; Donnelly-Nolan and

others, 1993). The presence of recent intrusions is consistent

with 3

He/4He ratios in geothermal discharges (Kennedy and

Truesdell, 1996) and the very high temperatures (~340°C)

recorded in deep wells in the Northwest Geysers (Walters and

others, 1992).

The productive portion of the geothermal reservoir is

primarily located in weakly metamorphosed Franciscan rocks

but extends down into the felsite intrusion and its surrounding biotite-hornfels-grade aureole. Most of the reservoir rocks

are not highly porous, ranging from 1 to 5 percent (Gunderson,

1992a), and thus the steam appears to be located primarily in

fractures, though there is some disagreement on the orientation of the most important steam-bearing fractures (cf. Thompson and Gunderson, 1992; Beall and Box, 1992). Mapping of δD anomalies caused by reinjection of condensate

provides evidence that many steam-bearing fractures have a

NNE trend (Beall and others, 1992), consistent with WNW

regional extension.

CHARACTERISTICS OF THE GEYSERS

STEAM RESERVOIR

As noted above, The Geysers reservoir is a vapor-dominated reservoir that is underpressured with respect to a hydrostatic pressure gradient. As suggested by White and others (1971) and modeled by Pruess (1985) and Shook (1995),

vapor-dominated systems represent heat pipes wherein upward-flowing steam condenses to liquid droplets at the base

of the caprock, which then flow back down through the reservoir. Such a mechanism can account for the very high heat

flow in the region, where heat is transported up toward the

surface as steam. White and others (1971) proposed that a

deep boiling brine should underlie the geothermal system and

that pressures would therefore return to hydrostatic levels at

depth. To date, evidence for a deep water table remains elusive, though fluid-inclusion evidence shows that dense, saline liquids have existed during the history of The Geysers

geothermal system (Moore and Gunderson, 1995).

Because the reservoir contains both steam and liquid

water droplets, the compositions of well discharges are a function of the relative amounts of the two phases available for

transport to the surface (Truesdell and White, 1973; Truesdell

and others, 1987). The relative reservoir steam saturation (the

proportion of steam to liquid water + steam, or “y” value) can

be estimated by using a combination of gas equilibria and gas

solubility equations (D’Amore and Celati, 1983; D’Amore

and Truesdell, 1985). The latter authors found that well discharges from the Southeast Geysers were composed mostly

of recently boiled liquid water (y = 0.01 to 0.05), whereas

fluids from the Northwest Geysers were predominantly derived from reservoir steam (y = 0.1 to 1.0). These fieldwide

characteristics can partially be traced to different temperature reservoirs that have been identified.

The Geysers steam field is divided into two principal

reservoirs, a normal-temperature reservoir and a high-temperature reservoir (NTR and HTR), which appear to be hydrologically connected. In the NTR, temperatures are close

to 240°C, with a pressure around 35 bars. Pressures in the

HTR are only marginally higher, though temperatures normally exceed 300°C and have been measured as high as 342°C

(Walters and others, 1992). The host rock for the NTR is normally Franciscan graywacke; though the HTR is found typically in the hornfels, no obvious changes in lithology occur

as one passes from the NTR to the HTR (Walters and others,

1992). Moreover, the temperature and pressure gradients be-
6

tween the reservoirs are continuous. Wells that extend into

the HTR, such as the Prati wells from the Northwest Geysers,

pass through the NTR, and so sampled fluids represent a mixture of steam and gas from both reservoirs. Though the HTR

may reside beneath the NTR throughout The Geysers steam

field, it has only been sampled in the Northwest and NorthCentral Geysers, where wells extend below the 5,900 ft (1,798

m) bsl elevation at which the HTR is located. Kennedy and

Truesdell (1996) conjecture that the low y and absence of

evidence for the HTR in the Southeast Geysers may be due to

the greater meteoric recharge (from Cobb Mountain) and

greater heat conduction due to the shallower reservoir depths.

Geochemically, there are a number of obvious trends

that differentiate the Southeast Geysers from the Northwest

Geysers. Steam discharges in the Southeast Geysers have an

isotopic signature of slightly oxygen-exchanged meteoric

water that is similar to present-day streams and springs in the

region (Truesdell and others, 1987). In contrast, samples from

the Northwest Geysers have elevated δ18O and δD and show

far less influence of present-day meteoric water. Haizlip (1985)

suggested that this isotopically enriched water was equivalent to “connate” or formation waters (derived from ancient

seawater) that discharge from Franciscan and Great Valley

sediments and are found throughout the Clear Lake volcanic

field (White and others, 1973). Donnelly-Nolan and others

(1993) proposed that this end member is instead evolved meteoric fluid that has undergone near-closed-system, repeated

boiling episodes within Franciscan rocks in areas of high heat

flow. Whatever its origin, Gunderson (1992b) showed that

the trend in steam discharges is also accompanied by changes

in the oxygen-isotope composition of host rocks in the geothermal reservoir. In the Southeast Geysers, host rocks have

lower δ18O than in the Northwest Geysers, consistent with

higher meteoric-water/rock ratios over the history of the geothermal system. Apparently, natural recharge of meteoric water

occurs mainly in the southeast part of the field (Truesdell

and others, 1987).

The Northwest Geysers is also characterized by higher

gas/steam ratios than the rest of the field, part of which is due

to the influence of the high-gas-to-steam HTR (Walters and

others 1992). The higher gas content of the Northwest Geysers wells may be due partly to the high temperatures associated with the HTR, which causes breakdown of organic matter in Franciscan rocks, and to the lesser flushing by meteoric

water in that part of the field over the lifetime of the system

(Gunderson, 1992b). Steam from the Northwest Geysers and

parts of the Central Geysers are also high in HCl (Haizlip and

Truesdell, 1989), values of which can reach nearly 100 ppm

in bulk steam (Kennedy and Truesdell, 1996). This has caused

considerable corrosion-related problems, and the operating

companies have created mitigation systems to raise the pH of

condensing steam in the wellbore (Bell, 1989).

Gas samples from the Northwest Geysers have been

shown to have high 3

He/4He ratios (R/Ra of 6.3 to >8.3;

Torgerson and Jenkins, 1982; Kennedy and Truesdell, 1996),

up to values typical of MORB. Kennedy and Truesdell (1996)

interpreted these values to indicate modern magma degassing beneath the Northwest Geysers, possibly extending south

underneath the entire geothermal field. The degree to which

a magmatic input influences the noncondensable-gas content

(other than He) of The Geysers geothermal fluids is not clear.

SAMPLE COLLECTION

Sampling procedures, described in greater detail in

Fahlquist and Janik (1992), are summarized below. Because

The Geysers geothermal reservoir is a steam field rather than

a liquid-dominated field, samples could be directly taken from

the sampling port on an insulated steam line near the wellhead. All acid mitigation systems were deactivated to prevent

sample contamination and to ensure minimal condensation

of fluid in the wellbore before sample collection. In addition,

precautions were taken to prevent condensation at the inlet to

the sampling apparatus.

The high temperatures of well fluids required careful

cooling prior to collection in the sample bottle. A double-coil

condenser of 1/4-in.-O.D. stainless-steel tubing was connected

to the steam line by a regulating valve. The first coil was immersed in water that was allowed to boil, effectively reducing

the temperature of the sample to about 100°C. The second

coil was placed in an ice-water bath, which condensed the

water vapor and reduced the sampling temperature to about

30°C. Flow rate was regulated by a valve connected to the

end of the second coil. The steel coil was then connected to

the sample bottle with silicone tubing.

The gas sampling bottle, a modified-Giggenbach bottle

(Nehring and Truesdell, 1977) with known volume, was

weighed, 1/4- to 1/3- filled with a known amount of 4 N NaOH

solution, and then evacuated so that the internal pressure of

the bottle approximated that of the vapor pressure of the NaOH

solution. CO2, H2S, and NH3 were dissolved in the NaOH

solution, which was diluted by condensed steam. Other gases

(He, Ar, N2, CH4, and H2) filled the headspace in the bottle.

Sample collection was complete when: (1) the vacuum in the

head space had disappeared and the bottle’s internal pressure

approached atmospheric pressure, or (2) if the caustic solution had become nearly saturated with soluble gases (typically only for fumaroles), or (3) if addition of condensed steam

caused the bottle to become more than 75% full.

Steam condensate was collected from the silicone tubing at the outlet of the condenser for isotopic analysis. Samples

were collected in 60-mL glass bottles and fitted with airtight

caps to prevent evaporation.

Five samples were collected from surface manifestations. G95-01, 02, 03, and 04 were collected by inserting a

funnel into standing water in Hot Springs Creek and at Old

Geysers. Gas passing through the funnel was collected into

an evacuated gas bottle partly filled with caustic solution, as

above. This sampling configuration results in loss of soluble

gas components such as NH3

, which dissolve in the standing
7

water. Sample G96-01 was collected from a fumarole at milepost 2.51 on Big Sulphur Creek Road. A titanium tube was

placed directly in the vent, mud was packed around the tube

to prevent air entrainment, and the Ti tube was connected to a

gas bottle with silica-rubber tubing. Condensates were collected by coiling the sampling tube and placing it in a bucket

of water, causing the steam to condense before flowing into a

60-mL glass bottle with threaded top. Bubbles of noncondensable gas were allowed to escape. The condensate was

kept significantly below 100°C to prevent boiling and significant evaporative loss, which would affect the isotopic composition of the sample.

SAMPLE ANALYSIS

Gases in the sample-bottle headspace (H2, He, Ar, CH4,

N2 and O2) were analyzed by gas chromatography at Menlo

Park. After measuring the initial pressure in the headspace,

two Carle AGC 111 gas chromatographs with thermal conductivity detectors were connected to a common sampling

inlet system to allow the samples to be injected at known pressures less than 1 atmosphere (Fahlquist and Janik, 1992). One

chromatograph used Ar as a carrier gas, and the other used

He. Before the sample analyses, standards of known composition were used for calibration. Sample concentrations were

determined by reference to the peak areas for the standards.

After the gas analysis, the total volume of caustic (with

dissolved sample gases and added steam condensate) was determined. In addition, part of the caustic liquid was isolated

for a density determination that was necessary for later quantification of the total gas analysis. NH3

 within the caustic solution was determined by gas-sensing electrode. For all

samples except those collected in 1981 (G81 samples), CO2

was liberated from the caustic solution by addition of phosphoric acid on a stable-isotope-extraction line. The number

of micromoles of CO2 was noted for a given volume of caustic solution. The evolved CO2

 was then kept for later isotopic

analysis of δ13C. G81 samples had their CO2 concentrations

quantified by precipitation of carbonate as SrCO3, a technique

that is not as accurate as direct evolution of CO2 gas by addition of phosphoric acid. Earlier analyses, including those of

Nehring (1981), overestimated CO2

 because the amount of

precipitated Sr(OH-)

2

 was not accounted for and was assumed

to be SrCO3. H2S, present in the solution as sulfide, was oxidized to sulfate with H2

O2 and then precipitated as BaSO4 by

addition of BaCl2 to the solution, which first had been acidified with HCl to remove CO2

. Sulfide was quantified by determining the mass of BaSO4

 precipitated per volume of caustic. For many samples, the BaSO4

 was analyzed subsequently

for its δ34S by mass spectrometry.

The mass of water added to the sample bottle during

sample collection (as steam condensate) was then quantified

by subtracting the masses of all previously determined components. Afterwards, the mass and volume fraction of all

sample constituents was determined. Full details on sample

analysis are available in Fahlquist and Janik (1992).

RESULTS

Tables 1 through 5 contain well attributes, sample

geochemistry from production wells, mean well compositions,

characteristics of injection wells, and temporal trends for

sample geochemistry, respectively. Appendix I provides further documentation on sample acquisition, units, and context

for data interpretation. Below, we provide short summaries

of observed trends in The Geysers geochemistry data set.

Before proceeding, it is worth noting that well discharges are not substantially different in composition than

those collected in 1925 and analyzed by Allen and Day (1927).

Their analysis of Well 6, a 487-ft-deep well near The Geysers Resort (fig. 2) showed ~18,000 ppm by weight noncondensable gases, composed of 65.2% CO2

, 14.65% H2,

15.40% CH4, 3.45% N2+NH3 and 1.35% H2S (all in mol%),

within the range of compositions noted in this study.

SURFACE ELEVATION

Surface elevations of the sampled wells ranged from

506 to 1,037 m. The highest elevation in the steamfield is

over 1,400 m on the summit of Cobb Mountain (fig. 2). The

lowest elevation is about 250 m, at the confluence of Squaw

and Big Sulphur Creeks in the Northwest Geysers. The topography is highly mountainous and irregular and is deeply

dissected by numerous streams wherever the surface geology

consists of Franciscan rocks. In contrast, the drainage network is only poorly developed on Cobb Mountain and the

other highly porous Clear Lake volcanics, (Goff and others,

1977; Kennedy and Truesdell, 1996). As mentioned above,

the terrain has a distinctive northwest trend caused by Quaternary faulting.

TOTAL DEPTH

Most wells are over 2,000 m deep, with the exception

of some of the older ones, such as Sulphur Bank 8 and 15,

drilled in the early 1960s. Wells in the Northwest Geysers are

the deepest, extending up to and over 3,000 m (fig. 3).

TEMPERATURE

Temperatures measured at the wellheads were quite

consistent at 175 to 195°C. Temperatures reported to DOGGR

have a wider range, plausibly because they represent more

variable conditions (shut-in, bleed, etc.), whereas the USGS

samples were taken during normal operations. As shown in
8

figure 4, most samples fall within the steam region of a temperature versus pressure plot, but right along the saturation

line for liquid water. Samples with the highest temperatures

and pressures, presumably reported to DOGGR immediately

after being shut-in, approach the conditions expected for the

initial reservoir before to development (White and others,

1971). Such samples have pressures and temperatures close

to the maximum enthalpy of saturated steam (235°C and 30.6

bars). A few samples have high temperatures at relatively low

pressures and plot well within the steam field. Some of these

samples come from the Northwest Geysers and may have some

input from the high-temperature reservoir (HTR).

PRESSURE

Most wellhead pressures ranged from 8 to 10 bars and

reflect pressures along the univariant curve for saturated steam

(see above).

pH FIELD VERSUS pH LAB

Field measurements of pH were typically 0.5 to over

3.0 log units lower than corresponding measurements of the

same samples in the lab. This is likely due to degassing of

CO2

 between field sampling and laboratory analysis. Samples

from the Northwest Geysers appear to have had slightly higher

field pHs and lower laboratory pHs.

STEAM TO GAS (MOLAR) AND GAS/STEAM

The wells from the Southeast Geysers were consistently

higher in steam to gas than the Central And Northwest Geysers wells (fig. 5). Some of the Northwest Geysers wells contained over 5 % non-condensable gas. In contrast, most Southeast Geysers wells had less than 1000 ppm gas by weight.

NONCONDENSABLE-GAS COMPOSITIONS

CO2

CO2 concentrations in production-well fluids varied

from 23.4 to 79.2 mol% of the noncondensable gases; however, most samples had 50-70% CO2

. Some fumaroles tended

to have more CO2, presumably because they had low NH3

and H2S due to condensation of steam and loss of soluble gas

to shallow ground and surface waters. CO2 concentrations

were higher in the Northwest Geysers than to the southeast

and correlated negatively with H2S, steam/gas, and H2 (fig. 5,

12a).

[

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35

30

25

20

15

10

5

0

0 50 100 150 200 250

Pressure (Bars)

Temperature (°C)

Liquid Water

Steam

[

E

Reported to DOGGR

Measured at wellhead

Figure 4.—Temperature versus pressure for Geysers wells as measured at wellhead. Unfilled circles represent data measured at wellhead by operator on day of sampling. Small filled squares are data

reported to the California Division of Oil, Gas, and Geothermal Resources for the month that sampling took place. Most of the data fall

very close to the steam/water phase boundary, though some samples

appear to lie totally within the steam field.

Figure 5.—Mol% CO2

 vs. mol% H2S and molar steam/gas for The

Geysers wells and surface manifestations. A. The two gases show a

clear negative correlation in all parts of the steam field. Samples

from the Southeast Geysers are highest in H2

S. B. The regions of the

field are easily differentiated on a plot of molar Steam/Gas versus

mol% CO2. Steam/gas clearly increases as one proceeds from northwest to southeast. Unit 15 wells have similar CO2

 to the Central

Geysers but have lower steam/gas.

F

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0 10 20 30 40 50 60 70 80 90

Mol% CO2

Mol% H2S

5

15

20

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0 F

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á Surface Manif.

Northwest

Southeast

Unit 15

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1

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100

1000

10000

100000 Molar Steam/Gas

[

a

b

A

B
9

H2S

H2S concentrations varied from 1.6 to 24.4%, though

most sample concentrations ranged from 3 to 9%. The highest relative concentrations were found in the Southeast Geysers wells, though given the low gas/steam in those samples,

the absolute concentrations of H2

S would not be high. H2S

correlated strongly with H2 (fig. 6).

He

He concentrations were very low. Most were below detection, though a few constituted up to 0.07% of the noncondensable gases.

H2

H2 concentrations varied from about 7 to 33% of the

noncondensable gases. Most samples had between 10 and 30%

H2. As previously stated, a plot of H2 vs. H2S shows a strong

correlation between these two gases (fig. 6).

O2

As expected for a reduced geothermal system with high

H2S, H2, and CH4 concentrations, O2 concentrations were very

low, even in samples with N2/Ar ratios consistent with incorporation of air or air-saturated water. For example, G90-25

had very high N2, and N2/Ar, consistent with addition of air,

but the O2

 had been reacted out prior to sampling or analysis.

O2 reacts rapidly with steel casing and steam in the wellbore

(producing H2). Only in samples where air was introduced

during actual sampling is there likely to be any O2 entering

the sample bottle. The only samples with significant O2 were

the two surface manifestations collected as gas bubbling

through water in Hot Springs Creek.

Ar

Ar concentrations were uniformly low, and generally

below 0.1% of the noncondensable gas. The sample with the

highest Ar content, G81-15 from the McKinley 1 well, was

also unusual for having extremely low CO2 and high H2. Air

may have been entered the wellbore at some stage, diluting

the gaseous components in the geothermal fluid, and reacting

with the steel casing to produce oxidized iron and H2. In general, samples with the highest Ar concentrations had N2

/Ar

ratios between that of air and air-saturated water (fig. 7).

N2

Most samples had N2 concentrations between 1 and 5

mol% of the noncondensable constituents, though a few had

much higher values, presumably due to addition of air or large

amounts of gas from air-saturated water. In general, N2 concentrations did not correlate positively with N2

/Ar ratios.

However, they did correlate strongly with CH4 (fig. 8), as

would be expected for thermal breakdown of organic matter.

CH4

CH4 concentrations ranged from less than 1 to over 20

mol% of the noncondensable gas, though most samples tended

to fall in the range of 3 to 13%. The highest values were found

in the Unit 15 wells. CH4 concentrations generally correlated

positively with gas/steam, CO2 and N2.

Figure 6.—Mol% H2S vs. H2 in noncondensable gas from The Geysers wells. The two gases show a clear positive correlation in all

parts of the steam field. Symbols as in fig. 5.

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ Ñ

Ñ

Ñ

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á

á

á

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0 5 10 15 20 25

0

10

20

30

5

15

25

35

F

[

É

Ñ Central

á Surface Manif.

Northwest

Southeast

Unit 15

Mol% H2S

Mol%H

2

Figure 7.—Mol% Ar vs. N2/Ar ratio for noncondensable gas from

The Geysers wells and surface manifestations. Most samples with

more than about 0.02 mol% Ar have N2

/Ar similar to that expected

for atmosphere and meteoric water. Low-Ar samples often tend to

have much higher N2/Ar. Samples from the Northwest Geysers have

the highest N2

/Ar. Symbols as in fig. 5.

Ñ Ñ

Ñ

Ñ

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Ñ

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Ñ

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Ñ

á á áá

á

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0

100

200

300

400

500

600

F

[

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Ñ Central

á Surface Manif.

Northwest

Southeast

Unit 15

0.001 0.01 0.10 1.00

Mol% Ar

N2/Ar

Air-Saturated Water

Air
10

NH3

NH3 concentrations had a similar range to those of CH4,

most falling in the range of 3 to 12% of the noncondensable

gases. The highest values were found in the Northwest Geysers (CCOC and Unit 15 wells), though high values were also

found in other areas. Unlike CH4

, there was no obvious correlation between high NH3

 and high gas to steam ratios.

N2/Ar

Though samples reach ratios as low as 18, the majority of The Geysers gas samples had N2

/Ar ratios greater than

that of air (84) or air-saturated water (ASW: 38). Over 17

samples, primarily those with high gas/steam ratios had N2/

Ar over 200, and a number of others had very high values

but were unquantified because their Ar concentrations were

below the detection limit. The N2 in samples with N2/Ar less

than ASW probably has undergone partial conversion to NH3

.

δD and δ18O in steam

δD plotted against δ18O range from close to the meteoric-water line to an oxygen-shifted endmember similar to

magmatic and metamorphic fluids (fig. 9) and are consistent

with values from Truesdell and others (1987) and Beall and

others (1992). The most δ18O-shifted samples were those with

high gas-to-steam ratios, found primarily in the Northwest

Geysers. Waters pumped into injection wells was much higher

in δD, consistent with evaporative fractionation at the surface

to create isotopically heavy residual waters. Some Union

samples collected in 1990 (primarily from the Southeast and

Central Geysers) appeared to show some mixing with this

injection-derived heavy water (similar trends discussed in

detail in Beall and others, 1992). Southeast Geysers samples

showed the greatest influence of meteoric water. Samples from

the Northwest Geysers were strongly shifted towards a heavyoxygen, high-deuterium end member and showed no obvious

mixing with any reinjected fluid. The isotopically enriched

end member is discussed further below.

δ13C in CO2

Samples from throughout the field had δ13C tightly clustered between about –12 and –15‰, with no obvious trends

within this range. Values of this magnitude are significantly

lower than magmatic values (–8 to –4‰; Allard and others

1977; Allard, 1979) or carbon values from most marine carbonates (Rollinson, 1993). However, they are significantly

greater than values typically associated with the breakdown

of organic materials in sedimentary rocks, which are usually

< –20 ‰ (Rollinson, 1993).

δ34S in H2S

Though the two laboratories that provided sulfur-isotopic analyses gave values that differed somewhat, both gave

values near zero (the total range for both data sets was –3.3 to

+1.9 ‰). Such values are consistent with (but do not prove)

an igneous source of sulfur to The Geysers geothermal reservoir.

DISCUSSION

RELATIVE GAS ABUNDANCES ACROSS THE

GEYSERS STEAM FIELD

Molar steam-to-gas ratios averaged 4180 in wells from

the Southeast Geysers; in contrast, they averaged 830 in the

Figure 8.—Mol% N2 vs. mol% CH4 for noncondensable gas from

The Geysers wells and surface manifestations. The two species are

highly correlated in all parts of the field, though the slope of trends

of N2

 versus CH4 is different in the Northwest Geysers than for the

Central Geysers.

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

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Ñ

Ñ

ÑÑ

Ñ Ñ

á

á

á á

á

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É

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0

0

10

20

5

5

15

25

10 15 20 25 30

Mol% N2

Mol% CH4

F

[

É

Ñ Central

á Surface Manif.

Northwest

Southeast

Unit 15

Figure 9.—δ18O vs. δD for steam condensed from The Geysers wells.

Units in permil relative to VSMOW. Samples from wells of the Southeast Geysers plot close to the global meteoric-water line, as do some

samples from the Central Geysers. Some of these wells plot on a

trend toward injection-derived steam. Samples from the Northwest

Geysers form a trend toward an isotopically heavy end member similar to connate waters described by White and others (1973). Metamorphic and primary magmatic water boxes from Taylor (1979).

Volcanic (andesitic) gas box from Giggenbach (1992). The global

meteoric water line is from Craig (1961). Local meteoric-water (gray

box) from Gunderson (1992).

XX XX

X

X X

X

X X

X

X X

XX

-60

-50

-40

-30

-20

-10

0

-10 -8 -6 -4 -2 0 2 4 6 8

δD (per mil)

δ18O (per mil)

X

Central

Southeast

Northwest

Injection

Sulphur Bank

Wilbur Springs Global Meteoric Water Line

VSMOW

Metamorphic Waters

Taylor (1979)

Magmatic Waters

Taylor (1979)

V

o

l

c

a

n

i

c

Influence of injection-derived steam

Influence of connate or volcanic waters
11

Central Geysers, 130 in the Northwest Geysers, and 220 in

Unit 15 wells (Table 3). Central Geysers wells were more

variable, and some of these wells may receive input from the

HTR.

Looking only at the noncondensable-gas compositions,

Southeast Geysers wells had higher relative H2

S and H2 and

lower CO2

 than the other parts of the field (fig. 10). Organic

gases were highest in the Northwest Geysers: Unit 15 had the

highest proportion of CH4, though Northwest Geysers wells

had the highest relative NH3. The Northwest Geysers wells

also had the highest relative CO2

 concentrations. Fumarole

samples were different from well fluids in that they lacked

NH3

 and had higher relative proportions of CO2, N2, and other

gases (particularly O2 and Ar; figs. 7, 10, 11a).

General trends also appear in X-Y plots of

noncondensable-gas abundances and ratios. A plot of

CH4 vs. N2 shows that these two components correlate strongly

throughout The Geysers field, though the slope of the trend

for N2 vs. CH4 is different for the Northwest Geysers and

Unit 15 parts of the field as compared to that in the Central

and Southeast Geysers wells (fig. 8). Ternary diagram of CH4

or He with N2 and Ar identify strong trends away from air

and meteoric-influenced fluids toward He- and CH4-rich end

members (fig. 11a, b). The Unit 15 and Northwest Geysers

wells form a trend distinct from that shown by the Central

Geysers wells and away from a component more elevated in

Ar. Bubble diagrams, where the symbol size corresponds to

a third variable, demonstrate that the N2 and CH4-rich component in Northwest Geysers wellfluids is also high in gas/

steam and CO2 (fig. 12).

Figure 10.—Pie diagrams illustrate the relative amounts of various

noncondensable gases in The Geysers well discharges. CO2

 dominates the noncondensable fractions from all wells but is most abundant in the Northwest Geysers. Wells from the Southeast Geysers

are highest in H2

S and H2, whereas Unit 15 wells contain the highest

CH4

 concentrations.

Southeast

 Unit 15

Central

Surface Manifestations

Northwest

CO2

H2S

H2

N2

CH4

NH3

Other

Sulphur Bank- Borax Lake

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Central

Surface Manif.

Northwest

Southeast

Unit 15

H2S

CH4

CH4

N2

N2

H2

100*Ar

100*Ar

1000*He

ASW

Air

ASW

Air

Ñ

ááá

á

[

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[

[

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E

F

F

C

c

b

a

Figure 11.—Ternary diagrams for noncondensable gases from The

Geysers steam field. A. N2 – 100*Ar – 1000*He diagram shows that

samples range from air-saturated-water (ASW)- and air-derived- end

members toward a He-enriched component consistent with either

crustal or magmatic input to the system. The Geysers samples follow a trend similar to that for samples from the nearby Clear Lake

volcanic field (Sulphur Bank-Borax Lake trend of Goff and others,

1995). B. N2

 – 100Ar – CH4 diagram has a similar trend to A, but

toward a CH4

-rich organic/sedimentary endmember. C. CH4-H2SH2

 ternary figure demonstrates the high H2 and H2S of most samples

from the Southeast Geysers as compared to those from Unit 15 and

Northwest Geysers wells, which trend toward a very CH4-enriched

composition. H2

/H2S of Geysers well fluids is relatively constant.

A

B

C
12

There are two basic end members of Geysers gases.

The first end member is high in CH4, CO2, gas/steam, and

N2/Ar and is typically found in the Northwest Geysers, both

in the Prati wells (CCOC) and Unit 15 (fig. 5b, fig. 11b, fig.

12). This type of sample is typified by Prati 25 (G91-10). The

other end member is found in the Southeast Geysers. It is

lower in CO2, and CH4 and higher in H2S and H2 (fig. 11c,

13). N2/Ar values are closer to air-saturated water (fig. 7),

gas/steam ratios are low (fig. 13a), and dD and d18O values

(fig. 9) are only slightly removed from those found in local

meteoric water. A representative sample of this group is

McKinley 3 (G81-16).

Figure 12.—Bubble diagrams for wells of the Northwest Geysers. The size of the symbol corresponds to the concentration of a third variable

whose name and scale are shown as insets to each figure part. A. Mol% CO2

 vs. mol% H2S for Northwest Geysers wells with mol% H2 plotted

as bubble diameter. B. Mol% CO2

 vs. mol% H2S for Northwest Geysers wells with gas/steam (in ppm by weight) plotted as bubble size. C.

Mol% CH4

 vs. mol% N2 for Northwest Geysers wells with gas/steam (in ppm by weight) plotted as bubble size. D. Mol% H2S vs. mol% H2

for Northwest Geysers wells with gas/steam (in ppm by weight) plotted as bubble size. In general, CO2, N2, CH4, and gas/steam are positively

correlated. H2

 and H2S are positively correlated with each other and negatively correlated with the previously mentioned variables.

40 45 50 55 60 65 70 75 80 85

Mol% CO2

0 20 40

40 45 50 55 60 65 70 75 80 85

Mol% CO2

0 100000

0

0.5

1.0

1.5

2.0

2.5

Mol% N

2

Mol% CH4

0 100000

0 0 5 10 15 2468 Mol% H

2

0 100000

0

2

4

6

8

Mol% H

2

S

Mol% H

2

S

Mol% H2S

0

2

4

6

8

Bubble Size

Scales to

Mol% H2

Bubble Size

Scales to

Gas/Steam 

(in ppm)

Bubble Size

Scales to

Gas/Steam 

(in ppm)

Bubble Size

Scales to

Gas/Steam 

(in ppm)

0

5

10

15

20

25

30

a b

c Northwest Geysers d

Northwest Geysers

Northwest Geysers

Northwest Geysers

C

A B

D
13

NH3 concentrations are very high in the Northwest

Geysers (fig. 10) but tend to decrease in the samples with the

very highest gas/steam (fig. 14). In the Central Geysers, NH3

appears to correlate with δD as a result of reinjection of steam

condensate (see below). The relative abundance of NH3 relative to N2

 and H2 is much higher than would be expected at

equilibrium, as is discussed in the next section.

EQUILIBRIUM, MIXING, AND CONDENSATION IN

THE GEYSERS RESERVOIR

Numerous indicators hint that the sampled fluids from

The Geysers reservoir were not in equilibrium with each other,

and moreover, individual constituents within a single gas

sample do not typically attain equilibrium. This is complicated by the observation that Geysers well discharges are a

mixture of reservoir steam and liquid, all of which is flashed

to steam during withdrawal (Truesdell and others, 1987), and

would be unlikely to attain equilibrium.

Figure 15 displays a plot of temperature versus log H2

/

H2O, as modified from figure 4 of Giggenbach (1987). The

Geysers samples are plotted as a field (in gray) that completely includes all samples from the present study. Temperature is chosen to be 250±50°C, which brackets the downhole

temperatures measured in most parts of the field. Samples

from The Geysers plot between the Ni/NiO and magnetite/

hematite buffers. The range of H2/H2O is striking, given the

homogeneity of temperatures in the geothermal reservoir.

Most of the samples with the lowest H2/H2O values are from

the Southeast Geysers. By accounting for the higher steam

saturation in that part of the field, and calculating only that

part of the H2 and H2O introduced directly by reservoir steam,

Figure 13.—Bubble diagrams for wells from the Southeast

and Central Geysers. A. Mol% CO2

 versus mol% H2S for

noncondensable gases from the Southeast Geysers. Bubble diameter corresponds to gas/steam ratio. Samples from the Southeast

Geysers are higher in H2

S and lower in CO2 than the Central and

Northwest Geysers. As in the Northwest Geysers, samples with

low H2S are higher in CO2 and gas/steam. B. Mol% H2S versus H2

for noncondensable gases from the Central Geysers. Bubble diameter corresponds to gas/steam (in ppm by weight). There are no

strong correlations among the three variables, though the range

of gas/steam in this part of the field is considerable.

0

20 30 40 60 70

5

10

15

20

25

0 40000

0

0 2 4 6 8 10 12

5

10

15

20

25

30

0 40000

Southeast Geysers

Central Geysers

Bubble size scales to

Gas/Steam ratio

Bubble size scales to

Gas/Steam ratio

a

b

Mol% CO2

Mol% H

2

S

Mol% H2S

Mol% H

2

50

Figure 14.—Mol% NH3 vs. gas/steam (in ppm by weight) for wells

of the Northwest Geysers. Though NH3

 concentrations are quite high

in the Northwest Geysers, concentrations actually decrease with increasing gas/steam ratio.

F

F

F

F

F

F F

F

F

F F

F

F

F

F

F

F

F

F

F

F

F

F F

ÉÉF F

É

É

É

É

É

ÉÉ É

É

É

1000

10000

100000

F

É

0 4 8 12 16

Northwest

Unit 15

Mol% NH3

Gas/Steam (in ppmw)

A

B
14

the H2/H2O values are much more similar and plot between

~–2.5 and –3.0 (discussed in figure caption: solubility data

for H2 from Giggenbach (1980) and y values calculated with

method of D’Amore and Truesdell, 1985). Such values are

appropriate for a geothermal reservoir rock containing both

ferric and ferrous iron.

The Geysers data, plotted on a graph of log of the concentrations of (NH3

)2/(N2xH2O) versus the log of the concentrations of CH4

/CO2 (fig. 16) implies a very different oxidation state than that displayed in fig. 15. The reaction boundaries, taken from Giggenbach (1987), appear to show that

Geysers samples plot at more reducing conditions than the

magnetite/fayalite equilibrium and equilibrated at temperatures above 600°C. Boiling of reservoir liquid does not account for the high NH3

 concentrations because NH3 still partitions strongly into the vapor, and samples with the highest

calculated y value (as determined from fig. 4 of Truesdell

and others, 1987) have some of the highest values of (NH3)2/

(N2

xH2O). Both plots cannot be correct; and in fact, it appears that the amount of NH3

 in The Geysers samples far exceeds that which could be in equilibrium with the rest of the

geothermal fluid at geothermal temperatures and typical

crustal oxidation states.

Geochemical modeling with SOLVGAS (Symonds and

Reed, 1993) demonstrates that NH3

 from The Geysers steam

field is several orders of magnitude more abundant than would

be expected at typical reservoir temperatures and pressures

(240°C and 30 bars). SOLVGAS can calculate the equilibrium distribution of gas species, given an input composition,

temperature, and pressure. Calculated N2

/NH3 ratios are more

than 160 times greater than those actually observed. The H2

,

H2O, CH4, and CO2 were consistent with equilibrium at 30

bars and ~235°C for sample G90-11, and with an equilibrium temperature of 297°C for sample G91-10 from the Northwest Geysers. However, inclusion of NH3

 in the calculations

proved unsuccessful. Calculated NH3 concentrations would

Figure 15.—Log H2/H2O vs. T for wells from The Geysers steam

field. For simplicity, all samples are plotted at 250±50°C. Mineral

and gas buffers from Giggenbach (1987, Fig. 4). Analyses of samples

from production wells plot homogeneously throughout the gray box.

The filled circles represent samples A86-4, A86-9, G88-15, G90-7,

G90-20, G90-25, and G91-02. The unfilled circles are the same

samples corrected to account for H2

O derived from reservoir liquid

boiled during steam withdrawal. The y values (a fraction equal to

H2O from steam divided by H2O from both reservoir steam and liquid) were estimated from figure 4 of Truesdell and others, 1987).

Steam/liquid partition coefficient for H2 was from Giggenbach (1980)

and calculated for 240°C. For clarity, samples are offset along the

X-axis from their uncorrected equivalents and do not imply different temperatures. The figure demonstrates great heterogeneity of

H2

/H2O for bulk well discharges, but similar H2/H2O values calculated for the steam fraction within the reservoir. It thus appears that

H2 has an approximately equilibrium concentration within the steam

phase of the reservoir and is in equilibrium with typical crustal Febuffering assemblages.

-6

-5

-4

-3

100° 200° 400° 1000°

-2

-1

0

The Geysers

Log H2/H2O

Temperature (°C)

H2

H2O

Fayalite

Magnetite

Po

Py

Magnetite

Hematite

NiO

Ni

FeO

FeO1.5

1 bar

10 bars

H2S SO2

Adjusted

Original

Figure 16.—Plot of log(X2

NH3

/(XN2XH2O)) vs. log (XCH4/XCO2) for well

discharges from The Geysers steam field. Apparent oxidation states

are below that of the quartz-fayalite-magnetite buffer for most

samples. Accounting for gases derived from reservoir liquid (as in

fig. 15) does not significantly change the plot because both NH3

(numerator) and H2O (denominator) are important components of

the liquid phase.

XXXX X X X XXX

X

XX

X

XX

X XXXXXXX

XXX

X

X XX XXXX X

X

X

X

XXX XXX

XXXX XX

XX

XXXXXXXXX XXXXX

XXXX X X XXXX

-10

-5

0

-15 -10 -5 0

Magnetite

Fayalite

FeO1.5

FeO

25°

100°

200°

300°

400°

600°

CH4

Hematite

Magnetite

CO2

Log(X2

NH3/XN2XH2O)

Log(XCH4/XCO2)
15

not match actual concentrations except at temperatures below 100°C, resulting in poor fits for the other components.

Calculations by Eugster (1972) for conditions of 500

K (227°C) show that the relative NH3 and N2 concentrations

of typical Geysers samples such as G81-09 are consistent

with H2 fugacities of ~0.5 bars, more than 100 times those

likely at the ~30 bars total pressure of The Geysers reservoir. The NH3

 is either coming from great depth (>250 bars

pressure) or, more likely is being produced locally by thermal breakdown of Franciscan-hosted organic materials,

which also produces the abundant CH4. Evidently, the NH3

does not have sufficient time to equilibrate in The Geysers

reservoir. Giggenbach (1987) noted that NH3

 was the slowest of the geothermal gases to equilibrate.

SOURCES OF COMPONENTS IN THE GEYSERS

FLUIDS

End member #1 — Northwest Geysers: Samples from

the Northwest Geysers are unique in composition, as discussed

above, and are characterized by high CO2

, CH4,and gas/steam,

relatively high NH3, and low H2S and H2. Such characteristics imply a strong component of fluid from the HTR (Walters

and others, 1992).

As noted by several workers, there is also an obvious

trend in the isotopic composition of Northwest Geysers well

samples away from a meteoric end member towards an isotopically heavy composition that is similar to both connate and

magmatic waters (Haizlip, 1985; Walters and others, 1992;

D’Amore and Bolognesi, 1993; Kennedy and Truesdell, 1996).

The gas samples in this study, particularly from the Northwest Geysers, are consistent with this observation. Fluids with

a strong meteoric signature come from the southeast part of

the field; e.g., most Southeast Geysers samples consistently

plot with δ18O between –5 and –7‰ and with δD between –

50 and –60‰. Other Southeast Geysers samples trend toward

the composition of evaporated steam condensate that has been

pumped back into the ground (as discussed below). In contrast, the Northwest Geysers samples point toward an end

member with around –4‰ δ18O and –40‰ δD, which could

feasibly extend into the region commonly associated with

high-temperature volcanic gas or steam (shown on fig. 9).

However, these same samples have characteristics that are

inconsistent with a simple magmatic origin, and are more representative of connate (sedimentary) or metamorphic fluids,

which have compositions that can overlap with those of magmatic fluids (White and others, 1973).

One example of this connate/metamorphic signature

is the δ13C of CO2

 in the Geysers samples, which is very similar throughout the field, ranging only from –11.7 to –15.0‰

VPDB (most are between –12 and –14‰). As discussed

by Bergfeld and others (1999), such values are typical

of Franciscan carbonate veins (see also Sternfeld, 1981; Lambert and Epstein, 1992). Carbon isotopes from vein carbonate

in Franciscan graywackes, taken from a core drilled in the

bottom of Sulphur Bank 15 (SB-15) cluster around a value of

–12‰, with all values (n = 24) falling between –9 and –15‰

(Bergfeld and others, 1999). Both metamorphic veins and

younger hydrothermal veins yield values similar to those for

CO2

 from gas samples in this report. Bergfeld and others (1999)

concluded that modern gases have derived their carbon primarily from these older metamorphic calcite veins, mixed with

some carbon from organic materials in the Franciscan rocks.

There is no evidence for significant magmatic carbon input to

the system, which should have a value of –4 to –8‰ (Allard

and others, 1977; Allard, 1979; Rollinson, 1993). Analyses of

δ13C in CH4

 are also low (–29 to –33‰ VPDB, see footnote to

table 2), and imply a thermally derived sedimentary component of methane to The Geysers system (see also Shigeno and

others, 1987; Bergfeld and others, 1999).

Another characteristic inconsistent with magmatic input to The Geysers reservoir fluid is the high CH4

 and NH3

concentrations in the high gas/steam wells of the Northwest

Geysers. These two gases are unstable at magmatic temperatures and crustal oxidation states and are typically added to

geothermal and volcanic discharges by relatively low-temperature addition from sedimentary and metamorphic sources

(Symonds and others, 1994; Giggenbach, 1987). Ternary diagrams of N2

-Ar-CH4 show a clear trend from an air-saturated

meteoric water end member toward a CH4

-rich source most

obvious in the Northwest Geysers and Unit 15 (fig. 11).

Gunderson (1992b) also noted the trend toward gas-rich compositions in the Northwest Geysers and attributed it to the

greater thickness of Franciscan reservoir rock in the Northwest Geysers, relative to felsite, and the lesser flushing of the

northwest part of the field by recharge of meteoric water.

This nonmeteoric end member is also obvious in the

N2/Ar ratios of high gas/steam fluids, which exceed 300 in 7

samples and are far greater than the atmospheric ratio of 84.

High N2/Ar is also found in springs and gas vents all over the

Clear Lake volcanic field, as discussed by Goff and others

(1995) and Goff and Janik (1993). For example, Goff and

Janik (1993) reported high values at the Herman Pit of Sulphur Bank Mine (N2

/Ar = 248), at Jones Hot Spring (191),

and at the Kelseyville methane well (195). Even higher values were listed by Jenden and others (1988) for natural gases

from deep wells in the California Great Valley. These gases

had N2

/Ar ranging from >200 to several thousand, with one

sample having a ratio of 22,000. These extraordinarily high

values were attributed by Jenden and others (1988) to production of N2

 by thermal decomposition of organic matter

and/or oxidation of ammonium in sheet silicates of the

Franciscan assemblage believed to underlie the Great Valley

strata in the California Great Valley.

It is therefore reasonable to postulate that the high CH4

,

gas/steam ratios and N2

/Ar in the Northwest Geysers is from

a Franciscan sedimentary/metamorphic component to The

Geysers gases. The high temperatures and high 3

He/4He

(Kennedy and Truesdell, 1996) may also indicate an input of

magmatic heat and mantle-derived noble gases to the Northwest Geysers. The sulfur-isotopic signature from Geysers
16

steam samples (close to 0‰ CDT) are also compatible with a

magmatic origin but could conceivably be explained as the

composition of H2S in equilibrium with Franciscan-seawater-derived sulfate (~+20 to +30 ‰ CDT) that is dissolved

into the liquid phase in the geothermal reservoir. Norman and

others (1998) found excess H2S in fluid inclusions from The

Geysers reservoir and attributed it to magmatic input of sulfur-rich gases and low kinetic rates of breakdown by reaction

with rock.

End member #2 — Southeast Geysers: In comparison to end member #1 from the Northwest Geysers, the well

discharges typical of the southeast part of The Geysers field

are higher in H2

, H2S, and H2O, the latter which is relatively

unshifted in its isotopic composition. This reflects higher

meteoric recharge to the Southeast Geysers (Truesdell and

others, 1987), a greater integrated water/rock ratio over time,

and less resulting influence of gases from argillaceous

Franciscan Complex metagraywackes (Gunderson, 1992b).

The high H2 concentrations are consistent with the high

steam/gas. H2 is relatively fast at equilibrating in geothermal systems (Giggenbach, 1987), and the high H2

 values

reflect the higher steam abundances and reduction of H2O

to H2 at geothermal temperatures. As mentioned above, H2/

H2O ratios in gases from the Southeast Geysers are low due

to the addition of liquid water from the reservoir during production. H2

S values are high due to partial equilibrium sulfide (Norman and others, 1998) and lower dilution with high

CH4-CO2 Franciscan-derived gases. Compared with many

geothermal systems (Ellis, 1979), The Geysers gases are quite

low in CO2, averaging less than 50% of the noncondensable

gases in the Southeast Geysers wells. The concentrations of

carbon gases are highest in the Northwest Geysers and lowest in the southeast. Again, this likely reflects the greater

flushing of the Southeast Geysers over time by meteoric waters, resulting in most of the Franciscan-derived carbon gases

having been swept from the southeast part of the reservoir

(Truesdell and others, 1987; Gunderson, 1992b).

EFFECTS OF RE-INJECTION

The most obvious signs of reinjected steam condensate

in the samples from this study are those from the Southeast

and Central parts of the field. On a plot of δD vs. δ18O, (fig.

9), one can discern a trend from an 18O- and D- depleted end

member toward the field represented by the eight injection

wells which are considerably enriched in D and 18O due to

low temperature (<100°C) evaporation. The trend is distinct

from that shown by wells from the Northwest Geysers, which

points toward a more 18O-enriched “connate” water that is

distinct from the injected steam condensates (table 4). The

trend implies that injected fluids have migrated from injection wells to be reboiled and returned to the surface through

production wells. Simple mixing calculations (based on data

from the injection wells and those Southeast Geysers samples

closest to the meteoric water line) indicate that as much as

25-40% of the steam in some wells appears to be derived

from reinjected fluids. The sample with the most obvious

“injectate” signature also has the highest NH3

 concentration

of any sample from The Geysers that we analyzed (fig. 17).

Given the high solubility of NH3

 in liquid H2O, it is likely

that some of this gas dissolves in condensing steam in the

wellbore and then remains in the steam condensate during

cooling at the surface before reinjection. Samples with a high

proportion of “injectate” would then have higher NH3 concentrations than the typical Geysers well fluid (already very

Figure 17.—Plot of δD (‰) of steam condensate vs. mol% NH3 and

N2

/Ar from the noncondensable-gas portion of well discharges from

the Central Geysers. Samples enriched in δD also have higher NH3

concentrations and N2/Ar ratios consistent with derivation from atmosphere or air-saturated water. Such trends are consistent with significant input of reinjected, evaporated steam condensate.

ÑÑ

Ñ

Ñ

Ñ Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

ÑÑ

Ñ

ÑÑÑ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ

Ñ Ñ Ñ

Ñ

Ñ

-60 -50 -40 -30 -20 -10 0

δD (per mil)

NH

3 (mol%)

N

2/Ar 

5

10

0

20

15

0

50

100

150

200

250

300

350

Central Geysers

Central Geysers
17

high as noted above). Increased NH3 in well discharges of the

Southeast Geysers were discussed by Beall (1993), who discusses the use of NH3

 as a tracer for injectate.

Figure 17 also demonstrates that Central Geysers wells

with the highest δD also have N2/Ar ratios that are consistent

with higher contributions of air-saturated water, as would be

expected for steam condensate that had sat at the surface before reinjection.

As discussed below, the 1991 sampling of Prati 38

(Northwest Geysers) also showed obvious influence of

“injectate,” with increased NH3

 and steam/gas.

TEMPORAL CHANGES IN THE GEYSERS FLUIDS

Seven wells in the database were resampled over time

(once each: table 5). The three samples from the Southeast

Geysers, CA956#1, McKinley 3 and Abel 1 were resampled

7.5, 6 and 20 months after the original samplings, respectively. Each showed increased gas/steam and mol% CO2

, decreased NH3

,and decreased H2S. The decreases in NH3 and

H2S would indicate a lesser influence of a liquid phase in the

reservoir, as both gases are relatively soluble in any condensed

phase. If the liquid phase were still abundant but were undergoing progressive boiling, one would expect increased abundance of soluble gases over time, and decreased gas/steam

ratios, as most gases are only slightly soluble and would boil

away early. Instead, the opposite is true. Most likely, the

amount of saturated liquid feeding these two wells decreased

during the interval between sampling. Loss of this liquid phase

would increase permeability through small cracks in the reservoir where adsorbed liquids would originally reside, potentially resulting in increased migration of gas and steam through

regions previously occupied by NH3- and H2S-rich liquids.

Reduction of reservoir liquid is consistent with the progressively lower reservoir temperatures and pressures observed

as a result of production and withdrawal of reservoir fluids

over time (Truesdell and White, 1973).

Beall and Box (1993) noted a similar increase in noncondensable gas with time, as well as an increase in the mole

fraction of CO2. They attribute the change to reduction of

reservoir pressures, causing open-system flow of CO2-rich

gases into the Southeast Geysers from below the geothermal

reservoir. Their explanation is similar to that offered above,

but infers an external source of noncondensable gas to the

reservoir, rather than simply a decrease in saturation of the

system and flow of noncondensable gases already present.

There was little change in Rorabaugh A-4 (Unit 15) in

the two years between sampling. Changes in Prati State 24

(Northwest Geysers) were also small. Prati 25 (Northwest

Geysers) had increased gas/steam, which was accompanied

by an increased δD, implying a greater proportion of the

Franciscan “connate” component (discussed in previous section) over time. The composition of Prati 38 (Northwest Geysers) changed markedly over the 3 years between sampling

trips and appears to have been influenced by the nearby injection well (Prati 9). Compared with the 1988 samples of

Prati 38, the 1991 sampling is higher in Ar and has a lower

N2

/Ar ratio, indicating a greater influence of air-saturated

water. The gas/steam ratio decreased markedly between 1988

and 1991, and the NH3

 concentration increased by 250%, as

would be likely if there were a strong "injectate" signature.

FUMAROLE COMPOSITIONS AS COMPARED

WITH WELL DISCHARGES

When compared with the relative noncondensable-gas

abundances of well discharges, the fumaroles are low in H2S

and NH3. These gases have relatively high solubility in the

O2-rich meteoric waters that geothermal fluids would have to

pass through to reach the surfac e. N2

, Ar, and O2 are all higher

in the fumarolic gases, as might be expected for surface emanations. The N2

/Ar ratio is also consistent with input of airsaturated water. CH4

 and H2 are about the same as samples in

the well-discharge database and CO2 is somewhat higher. The

δ13C of CO2 from the fumaroles is the same as that of CO2

from the geothermal reservoir.

CONCLUSIONS

• This database of geothermal fluid analyses from the

Geysers contains chemical data on 81 production-well

discharges and 9 injection wells from, the Northwest,

Central, and Southeast Geysers, Unit 15 (westcentral

Geysers), and 5 surface manifestations in the Central

Geysers. Wellhead temperatures and pressures correspond

to the liquid-water/steam boiling curve or slightly superheated conditions.

• Evidence for recharge of meteoric water is most obvious in samples from the Southeast Geysers, where steam

has an isotopic composition close to that of slightly oxygen-exchanged present-day precipitation and N2

/Ar ratios are similar to or slightly higher than air-saturated

water. The noncondensable component in Southeast Geysers geothermal fluids is enriched in H2

 and H2S.

• Many of the differences between the Northwest Geysers and Southeast Geysers can be explained by higher

temperatures and considerable contributions of carbonrich gases from the host Franciscan assemblage to the

Northwest Geysers. The Franciscan component is manifested in the high concentrations of CO2

 and CH4, the

low δ13C of CO2 and CH4,and the high N2/Ar. In contrast,

there is evidence for greater input of meteoric water (recharge) to the Southeast and a longer history of meteoric

water-rock reaction, which would have depleted the local Franciscan rocks of their carbon-rich component and

caused both rock and fluid to have isotopic compositions
18

more similar to meteoric water.

• Contributions of magma-derived gas to the Northwest

Geysers has been suggested by Kennedy and Truesdell

(1996) and may be responsible throughout the field for

the near-zero values for δ34S of H2S. The high N2/Ar of

the Northwest Geysers may be explained either by a

magmatic input or a sedimentary input (the explanation

favored herein).

• The abundance of NH3

 is too high to reflect equilibrium within the geothermal reservoir, even if it were derived partially due to boiling of liquid condensate. Apparently, NH3

 enters the system due to breakdown of

Franciscan-hosted organic materials and reacts too slowly

with the other gaseous components to reach equilibrium.

• Seven wells resampled during this study show some

increases in y (steam/liquid+steam) in the reservoir and

some influence of injection-derived condensate. Several

wells showed no appreciable change in discharge composition.

• Surface manifestations are similar in chemical and isotopic composition to deep fluids but have higher CO2

and lower NH3 and H2S. N2/Ar ratios reflect air-saturated

water.

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of nitrogen-rich natural gases in the California Great Valley:

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high-temperature reservoir: Evidence for active magmatic degassing and implications for the origin of The Geysers geothermal field: Geothermics, v. 25, p. 365-387.

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steam chemistry at The Geysers field, in C. Stone, ed., Monograph on The Geysers Geothermal Field: Davis, California,

Geothermal Resources Council Special Report Number 17, p.

145-149.

Koenig, J.B, 1992, History of development at The Geysers geothermal field, California, in C. Stone, ed., Monograph on The Geysers Geothermal Field: Davis, California, Geothermal Resources Council Special Report Number 17, p. 7-18.

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and secondary minerals in a vapor-dominated hydrothermal

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Volcanology and Geothermal Research, v. 53, p. 199-226.

McLaughlin, R.J., 1981, Tectonic setting of pre-Tertiary rocks and

its relation to geothermal resources in the Geysers-Clear Lake

area, in R.J. McLaughlin and J. Donnelly-Nolan, eds., Research

in the Geysers-Clear Lake Geothermal Area, Northern California: U.S. Geological Survey Professional Paper 1141, p. 3-

23.

McLaughlin, R.J., Moore, D.E., Sorg, D.H., and McKee, E.H., 1983,

Multiple episodes of hydrothermal circulation, thermal metamorphism and magma injection beneath The Geysers steam

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v. 15, no. 5, p. 417.

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eds., Research in the Geysers-Clear Lake Geothermal Area,

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isotope and gas samples from geothermal wells: Proceedings

of the Second Workshop on sampling geothermal effluents, Las

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Publication EPA-600/7-78-121, p. 130-140.

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20

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21

APPENDIX
22

APPENDIX I: DESCRIPTION OF DATA

TABLES

TABLE 1. WELL ATTRIBUTES

Sample #: Denotes an individual visit to a particular well. All samples

collected by USGS personnel begin with the letter “G”. Unit15 wells were collected in 1986 by Geo Corporation and begin

with the letter “A”. Samples A87-1and A87-2 were collected

by Mr. Tom Box of Calpine Corporation in 1987. The number

following the initial letter represents the year in which the

sample was collected (19XX). The final number denotes the

order in which the samples were collected during that year.

Well: The full name of the well. G95 and G96 samples are from

surface manifestations rather than wells.

Region: S= Southeast; C= Central; N= Northwest; U= Unit 15. In

order to facilitate plotting of the geochemical data, the steam

field was divided into 4 regions. The boundaries of these regions are shown in fig. 1. The limits were chosen partly based

on geography and partially based on steam/gas ratios.

API Number: The official designation of the well as listed by the

California Division of Oil, Gas, and Geothermal Resources

(DOGGR).

Map #: The number assigned to the well in figure 1.

Well Type: Wells are listed as production or injection, depending on

what they were used for at the time of collection. Reinjection

became mandatory, due to environmental concerns, in the late

1960s, before the first sampling for this study. G95 and G96

samples are from bubbling pools and fumaroles rather than wells.

Year Drilled: The year that the well was first put into production.

Operator: The company utilizing the well at the time of sampling.

CGC= Calpine Geysers Corporation, CCOC=Coldwater Creek

Operator Corporation, Union= Unocal Geothermal Company.

Current Operator: All wells sampled for this study that are now

active are utilized by Calpine. The former CCPA wells are inactive and the Unit 15 wells are abandoned.

Latitude: Latitude of the well listed in decimal degrees. Data are

from varied sources, including Reed (1982), California Division of Oil and Gas (1992), and public records available through

the California DOGGR.

Longitude: Longitude of the well listed in decimal degrees. Data

are from varied sources, including Reed (1982), California

Division of Oil and Gas (1992), and public records available

through the California DOGGR.

Latitude: Latitude of the well listed in meters (Universal Transverse Mercator Zone 10). Data were generated from the latitude records above.

Longitude: Longitude of the well listed in meters (Universal Transverse Mercator Zone 10). ). Data were generated from the longitude records above.

Section-Township-Range: The section, township, and range where

the well is located.

Sample Date: The date of sampling in year/month/day.

Surface Elevation: The ground elevation, in meters, at the site of

the well.

Total Depth: The well depth, in meters, measured relative to the

surface elevation.

Casing Depth: The depth to which the well was fully cased before

sampling, relative to the surface elevation, in meters. Perforated casing is not included.

Wellhead T: The temperature of the well discharge at the sampling

point on the Earth’s surface, in °C. This is usually significantly

lower than the downhole reservoir temperature. Stated value

represents the temperature of the discharge on the day of sampling, as supplied by the operator to the USGS.

Wellhead P: The pressure of the well discharge at the sampling

point on the Earth’s surface. This is usually significantly lower

than the downhole reservoir pressure. Stated value represents

the pressure of the discharge on the day of sampling, as supplied by the operator to the USGS. Pressure in bars (absolute,

corrected from gauge pressure), with psi (lbs/in2

) in parentheses.

Wellhead T*: Because we did not obtain wellhead temperatures at

the time of collection for all of our samples, we have included

the temperature of the well discharge, in °C, as reported by the

operator to the California DOGGR for the reporting period of

the month of sampling. The temperature represents a single

individual temperature measurement during that month, and

could be strongly affected by well conditions such as shut-in,

blowoff, etc. As such, it may be different from the wellhead

temperature at the time of sampling.

Wellhead P*: Because we did not obtain wellhead pressures at the

time of collection for all of our samples, we have included the

pressure of the well discharge as reported by the operator to

the California DOGGR for the reporting period of the month

of sampling. The pressure represents a single individual pressure measurement during that month, and could be strongly

affected by well conditions such as shut-in, blow-off, etc. As

such, it may be different from the wellhead pressure at the time

of sampling, and could be different than typical operating conditions. Pressure in bars (absolute, corrected from gauge pressure), with PSI (lbs/in2

) in parentheses.

TABLE 2. GAS GEOCHEMISTRY

Sample #: Same as “Sample #” in table 1.

Well: Same as “Well” in table 1.

Region: Same as “Region” in table 1.

Sample Type: All wells in this table are production wells. G95 and

G96 samples are from bubbling pools and fumaroles rather than

wells.

Sample Date: The date of sampling in year/month/day.

pH-field: The pH of condensate as measured at the sampling site.

pH-Lab: The pH of condensate as measured in the USGS laboratory.

Steam/Gas: Ratio of moles of steam (H2

O) to moles of noncondensable gas (CO2

+H2S+H2+O2+Ar+N2+CH4+NH3) in the

bulk fluid withdrawn from well.

Gas/Steam: Ratio of mass of noncondensable gas to mass of steam

(x106

).

CO2

, H2S and other non-condensable gases: Concentrations in

mole percent of the noncondensable portion of the sampled

fluid (without H2O).

N2

/Ar molar ratio: The molar ratio of N2 to Ar in the sampled fluid.

The ratio in air is 83.6, whereas that of air-saturated water at

standard temperature and pressure is 38.

δD: The hydrogen-isotopic composition of condensed steam in units

of permil, relative to Vienna Standard Mean Ocean Water

(VSMOW) where:
23

Samples collected in 1990-91were measured in the laboratory of

Tyler Coplen in Reston, VA. Analytical precision is 1 per mil.

G78- and G81-samples were measured in the laboratory of R.

Harmon at the Scottish Universities Research and Reactor Centre, Glasgow.

δ18O: The oxygen-isotopic composition of condensed steam in units

of permil, relative to Vienna Standard Mean Ocean Water

(VSMOW) where:

Samples from 1990-91 were measured in the laboratory of Tyler Coplen

in Reston, VA. Analytical precision is 0.2 permil. G81-1 to G81-

5 were measured in the laboratory of J.R. O’Neil, Menlo Park,

CA. G78 samples were measured by L. Doug White in the laboratory of I. Barnes, Menlo Park, CA. All others were measured in

the laboratory of C. Kendall, Menlo Park, CA.

δ13C CO2

: The carbon-isotopic composition of CO2 in units of per

mil relative to the standard Peedee belemnite (VPDB). Samples

were measured in the laboratory of C. Kendall in Menlo Park.

Analytical precision is 0.2 permil.

δ34S (D): The sulfur-isotopic composition in H2

S in units of permil

relative to Canyon Diablo Troilite (CDT). Measured in the laboratory of W.C. Pat Shanks III in Denver, CO. Analytical precision is ±0.2 permil.

δ34S (M): The sulfur-isotopic composition in H2

S in units of permil

relative to Canyon Diablo Troilite (CDT). Measured by S. Silva

in the laboratory of C. Kendall in Menlo Park, CA. Analytical

precision is ±0.2 permil.

TABLE 3. MEAN COMPOSITION OF ANALYSES

This table is divided into columns that contain the mean composition of wells for the four regions of The Geysers geothermal

field and superjacent surface manifestations. The row indicators are the same as columns in table 2 and use the same units.

The mean compositions are for all wells in this compilation,

not solely those indicated as representative of initial reservoir

conditions.

TABLE 4. INJECTION WELLS

Sample #: Denotes an individual visit to a particular well. All samples

collected by USGS personnel begin with the letter “G”.

Well: The full name of the well.

Year Drilled: The year that the well was first put into production.

Sample date: The date of sampling in year/month/day.

δD: The hydrogen-isotopic composition of water in the steam condensate prior to reinjection. In units of permil, relative to Vienna

Standard Mean Ocean Water (VSMOW). Measured in the laboratory of Carol Kendall in Menlo Park, CA. Analytical precision is 1 permil.

δ18O: The oxygen-isotopic composition of water in the injectate fluid

before injection. In units of permil, relative to Vienna Standard

Mean Ocean Water (VSMOW). Measured in the laboratory of

Carol Kendall in Menlo Park, CA. Analytical precision is 0.2

permil.

TABLE 5. TEMPORAL VARIATIONS

Well: The full name of the well.

Sample #1: Same as “sample #” in tables 1 and 2. The first sampling of the well. The letter (G) indicates sampling by USGS

personnel. The first number represents the year sampled,

whereas the second number (after the dash) is for the sample

number within the year.

Sample #2: Same as “sample #” in tables 1 and 2. The second sampling of the well. The letter (G) indicates sampling by USGS

personnel. The first number represents the year sampled,

whereas the second number (after the dash) is for the sample

number within the year.

G/S #1: Gas/steam ratio (in ppm by weight) for the first sampling.

G/S#2: Gas/steam ratio (in ppm by weight) for the second sampling.

N2

/Ar #1: N2/Ar for the first sampling.

N2

/Ar #2: N2/Ar for the second sampling.

δD #1: δD (in permil relative to VSMOW) for the first sampling.

δD #2: δD (in permil relative to VSMOW) for the second sampling.

NH3

 #1: NH3 concentration in noncondensable gas (in mol%) in

first sampling.

NH3

 #2: NH3 concentration in noncondensable gas (in mol%) in

second sampling.

H2

S #1: H2S concentration in noncondensable gas (in mol%) in first

sampling.

H2S #2: H2S concentration in noncondensable gas (in mol%) in second sampling.
U. S. Geological Survey

Open File Report #99-304

Geysers Steam Field

Well Attributes

Sample# Well Region API Number Map # Well-type Year Drilled Operator Current Latitude Longitude Latitude Longitude Section Township Range Sample Date Surf

Operator Decimal Degrees Decimal Degrees UTM (meters) UTM (meters) 

G78-05 LF State 4597-18 (Lakoma Fame) C 09790114 1 Production 1973 Union Calpine 38.79852 -122.77422 4294235 519607 2 0 11N 8W 78/06/07 7

G78-06 LF State 4236-2 (Lakoma Fame) C 09790045 2 Production 1969 Union Calpine 38.79594 -122.76456 4293952 520446 2 0 11N 8W 78/06/07 9

G78-07 LF State 4597-16 (Lakoma Fame) C 09790122 3 Production 1973 Union Calpine 38.78760 -122.76429 4293026 520472 2 0 11N 8W 78/06/07 8

G81-01 D&V-A1 (Dillingham & Vought) S 03390017 4 Production 1973 Aminoil Calpine 38.77325 -122.72242 4291444 524114 2 7 11N 8W 81/01/12G81-02 Thorne 1 S 03390005 5 Production 1970 Aminoil Calpine 38.77357 -122.72243 4291479 524113 2 7 11N 8W 81/01/12 8G81-03 CA 958-37-34 (956#3) S 09790394 6 Production 1979 Aminoil Calpine 38.76279 -122.73264 4290281 523229 3 4 11N 8W 81/01/12 8

G81-04 CA 958-37A-34 S 09790395 7 Production 1979 Aminoil Calpine 38.76249 -122.73261 4290247 523232 3 4 11N 8W 81/01/12 8

G81-05 D&V-A3 (Dillingham & Vought) S 03390233 8 Production 1979 Aminoil Calpine 38.77497 -122.72968 4291633 523482 2 7 11N 8W 81/01/12G81-09 Thorne 6 S 03390025 9 Production 1975 Aminoil Calpine 38.78004 -122.71991 4292198 524329 2 7 11N 8W 81/01/12 7G81-12 CA 956A 73-34 (956#1) S 03390084 10 Production 1975 Aminoil Calpine 38.76835 -122.72384 4290900 523992 3 4 11N 8W 81/02/04 9

G81-13 Thorne 3 S 03390021 11 Production 1974 Aminoil Calpine 38.77521 -122.72376 4291661 523996 2 7 11N 8W 81/02/04 8

G81-15 McKinley 1 S 03390001 12 Production 1969 Aminoil Calpine 38.77491 -122.71848 4291629 524455 2 6 11N 8W 81/02/04 7

G81-16 McKinley 3 S 03390003 13 Production 1969 Aminoil Calpine 38.77199 -122.71724 4291306 524564 2 6 11N 8W 81/02/04 7

G81-17 MLM1 S 03390015 14 Production 1971 Aminoil Calpine 38.77232 -122.71213 4291343 525008 2 6 11N 8W 81/02/04 6G81-19 McKinley 4 S 03390004 15 Production 1969 Aminoil Calpine 38.77076 -122.71838 4291168 524465 3 5 11N 8W 81/02/04 7

G81-20 D&V-A2 (Dillingham & Vought) S 03390098 16 Production 1977 Aminoil Calpine 38.77073 -122.72833 4291163 523601 3 4 11N 8W 81/02/04

G81-21 CA 956A 56-34 (956#2) S 09790428 17 Production 1975 Aminoil Calpine 38.76320 -122.72760 4290900 523992 3 4 11N 8W 81/02/05 9

A86-1 Rorabaugh A-2 (Unit 15) U 09790095 18 Production 1971 Geo Abandoned 38.80226 -122.83213 4294639 514577 1 4 11N 9W 86/08/08 5

A86-2 Rorabaugh A-3 (Unit 15) U 09790096 19 Production 1972 Geo Abandoned 38.80236 -122.83427 4294650 514391 1 4 11N 9W 86/08/26 5

A86-3 Rorabaugh A-4 (Unit 15) U 09790097 20 Production 1972 Geo Abandoned 38.79778 -122.82858 4294143 514886 1 4 11N 9W 86/08/07 5

A86-4 Rorabaugh A-7 (Unit 15) U 09790088 21 Production 1973 Geo Abandoned 38.79839 -122.83075 4294210 514698 1 4 11N 9W 86/08/07 5A86-5 Rorabaugh A-9 (Unit 15) U 09790157 22 Production 1975 Geo Abandoned 38.80220 -122.83703 4294632 514152 1 4 11N 9W 86/08/08 5A86-6 Rorabaugh A-10 (Unit 15) U 09790158 23 Production 1976 Geo Abandoned 38.79860 -122.83350 4294234 514458 1 4 11N 9W 86/08/08 6

A86-7 Rorabaugh A-13 (Unit 15) U 09790462 24 Production 1981 Geo Abandoned 38.80111 -122.83145 4294512 514636 1 4 11N 9W 86/08/07 5

A86-8 Rorabaugh A-18 (Unit 15) U 09790512 25 Production 1981 Geo Abandoned 38.80236 -122.83732 4294650 514126 1 4 11N 9W 86/08/08 5A86-9 Rorabaugh A-22 (Unit 15) U 09790598 26 Production 1984 Geo Abandoned 38.79414 -122.83434 4293738 514387 1 4 11N 9W 86/08/08 7A86-10 Rorabaugh A-27 (Unit 15) U 09790664 27 Production 1985 Geo Abandoned 38.80117 -122.83191 4294519 514596 1 4 11N 9W 86/08/26 5A86-11 Filley1 U 09790149 28 Production 1984 Geo Abandoned 38.80472 -122.83863 4294911 514012 1 4 11N 9W 86/08/11 5A87-1 McKinley-3 S 03390003 13 Production 1969 Calpine Calpine 38.77199 -122.71724 4291306 524564 2 6 11N 8W 87/01/30 7A87-2 Abel 1 S 03390018 33 Production 1974 Calpine Calpine 38.77807 -122.71470 4291980 524782 2 6 11N 8W 87/01/30 6

G88-6 Prati State 24 N 09790714 29 Production 1987 CCOC Inactive 38.83283 -122.80486 4298036 516938 1 11N 9W 88/03/25 7

G88-7 Prati 38 N 09790687 30 Production 1986 CCOC Inactive 38.83538 -122.83161 4298315 514615 3 5 12N 9W 88/09/22 5

G88-8 Prati 25 N 09790695 31 Production 1986 CCOC Inactive 38.84102 -122.83065 4298941 514697 3 5 12N 9W 88/09/22 7

G88-9 Prati 4 N 09790678 32 Production 1985 CCOC Inactive 38.83848 -122.82066 4298661 515565 3 6 12N 9W 88/09/22 7

G88-10(1/3) Rorabaugh A-4 (Unit 15) U 09790097 20 Production 1972 CCOC Abandoned 38.79778 -122.82858 4294143 514886 1 4 11N 9W 88/09/22 5

G88-11 Abel 1 S 03390018 33 Production 1974 Calpine Calpine 38.77807 -122.71470 4291980 524782 2 6 11N 8W 88/09/23 6

G88-12 MLM-7 S 03390689 34 Production 1988 Calpine Calpine 38.77770 -122.71449 4291939 524801 2 6 11N 8W 88/09/23 6

G88-13 CA 956A 56-34 (956#2) S 09790428 17 Production 1975 Calpine Calpine 38.76320 -122.72760 4290327 523667 3 4 11N 8W 88/09/23 9

G88-14 CA 956A 73-34 (956#1) S 03390084 10 Production 1975 Calpine Calpine 38.76835 -122.72384 4290900 523992 3 4 11N 8W 88/09/23 9

G88-15 Davies Estate 7 S 03390688 36 Production 1988 Calpine Calpine 38.76461 -122.69392 4290493 526593 3 6 11N 8W 88/09/23 5

G88-16 Davies Estate 5 S 03390678 37 Production 1987 Calpine Calpine 38.76428 -122.69370 4290456 526611 3 6 11N 8W 88/09/23 5G90-00 Geysers Devel. Corp. (GDC) 88-12 C 09790026 38 Injection 1971 Union Calpine 38.80835 -122.80399 4295320 517019 1 2 11N 9W 90/12/11 7

G90-00 Geysers Devel. Corp. (GDC) 05 C 09790227 39 Injection 1980 Union Calpine 38.78355 -122.77684 4292574 519383 3 0 11N 8W 90/12/11 6G90-00 LF State 4597- 23 (Lakoma Fame) C 09790231 40 Injection 1979 Union Calpine 38.80039 -122.76887 4294444 520071 1 7 11N 8W 90/12/11 8

G90-00 CMHC 06 (Cobb Mtn. Hunting Club 6) C 09790359 41 Injection 1978 Union Calpine 38.80360 -122.78234 4294797 518900 1 8 11N 8W 90/12/11 8G90-00 D.X. (Delta Xagon) State 4596-72 C 09790539 42 Injection 1982 Union Calpine 38.81907 -122.77618 4296516 519430 7 11N 8W 90/12/11 9

G90-00 D.X. (Delta Xagon) State 4596-61 N 09790563 43 Injection 1983 Union Calpine 38.82229 -122.79139 4296869 518110 7 11N 8W 90/12/11 8

G90-00 Geysers Devel. Corp. (GDC) 26 C 09790612 44 Injection 1984 Union Calpine 38.80148 -122.80331 4294558 517080 1 3 11N 9W 90/12/11 5

G90-00 BEF 42B33 S npa - Injection 1984 Union Calpine npa npa npa npa 3 3 11N 8W 90/12/11 G90-01 Ottoboni Fed. 21A-12 N npa - Production 1983 Union Calpine npa npa npa npa 1 2 11N 9W 90/12/10 

G90-02 Ottoboni St.4596 -15 N 09790153 47 Production 1974 Union Calpine 38.82750 -122.80759 4297444 516702 1 11N 9W 90/12/10 6

G90-03 Ottoboni St.4596-14 N 09790147 48 Production 1974 Union Calpine 38.82459 -122.80080 4297123 517292 7 11N 8W 90/12/10 6

G90-04 D.X. (Delta Xagon) State 4596 -45 N 09790438 49 Production 1981 Union Calpine 38.82754 -122.78347 4297453 518796 7 11N 8W 90/12/10 1

G90-05 L'Esperance 2 (LESP-2) N 03390498 50 Production 1985 Union Abandoned 38.84235 -122.78275 4299097 518854 6 11N 8W 90/12/11 8

G90-06 GD Horner State 4596-9 C 03390519 51 Production 1986 Union Calpine 38.83180 -122.76385 4297930 520497 5 11N 8W 90/12/11 8G90-07 NE Geysers Unit (NEGU) 15 C 03390518 52 Production 1986 Union Calpine 38.83183 -122.76357 4297934 520522 5 11N 8W 90/12/11 8

G90-08 Ottoboni Fed 48-2 N npa - Production 1989 Union Calpine npa npa npa npa 2 11N 9W 90/12/11 

G90-09 Ottoboni Fed 48A-2 N npa - Production 1989 Union Calpine npa npa npa npa 2 11N 9W 90/12/11 

G90-10 Sulphur Bank -15 C 09790069 55 Production 1964 Union Calpine 38.80822 -122.81776 4295303 515824 1 2 11N 9W 90/12/12 5G90-11 Sulphur Bank -8 C 09790065 56 Production 1963 Union Calpine 38.80656 -122.81759 4295119 515839 1 3 11N 9W 90/12/12 5G90-12 CA State 92-6 N 03390484 57 Production 1984 Union Calpine 38.84221 -122.78275 4299082 518855 6 11N 8W 90/12/12 8

G90-13 D.X. (Delta Xagon) State 4596-50 N 09790454 58 Production 1980 Union Calpine 38.82757 -122.78373 4297457 518773 7 11N 8W 90/12/12 1

G90-14 NE Geysers Unit (NEGU) 17 C 03390521 59 Production 1990 Union Calpine 38.83196 -122.76338 4297949 520538 5 11N 8W 90/12/12 8

G90-15 GD Horner State 4596-7 C 03390680 60 Production 1987 Union Calpine 38.82898 -122.77496 4297615 519534 5 11N 8W 90/12/12 9

G90-16 D.X. (Delta Xagon) State 4596-64 C 09790528 61 Production 1982 Union Calpine 38.82136 -122.77151 4296770 519836 8 11N 8W 90/12/12 1

G90-17 D.X. (Delta Xagon) State 4596-87 C 03390545 62 Production 1986 Union Calpine 38.82082 -122.76771 4296711 520166 8 11N 8W 90/12/12 1

G90-18 Angeli 2 C 09790457 63 Production 1980 Union Calpine 38.79247 -122.75748 4293567 521062 2 0 11N 8W 90/12/12 1

G90-19 Angeli 3 C 09790639 64 Production 1985 Union Calpine 38.79250 -122.75738 4293571 521071 2 0 11N 8W 90/12/12 1

G90-20 Geysers Devel. Corp. (GDC) 30 C 09790704 65 Production 1986 Union Calpine 38.80407 -122.81629 4294844 515952 2 0 11N 8W 90/12/13 6

G90-21 Beigel 3 C 09790629 66 Production 1984 Union Calpine 38.78060 -122.76106 4292250 520755 2 9 11N 8W 90/12/13 8

G90-22 Beigel 2 C 09790615 67 Production 1984 Union Calpine 38.77831 -122.76308 4291995 520579 2 9 11N 8W 90/12/13 7

G90-23 GDCF (GDC Federal)14A-27 S npa - Production 1987 Union Calpine npa npa npa npa 2 7 11N 8W 90/12/13 

G90-24 BEF 85-28 S npa - Production 1985 Union Calpine npa npa npa npa 2 8 11N 8W 90/12/13 

G90-25 D&V-25 (Dillingham & Vought) S 09790774 70 Production 1988 Union Calpine 38.76680 -122.73532 4290725 522995 3 4 11N 8W 90/12/13 9

G90-26 D&V-2 (Dillingham & Vought) S 09790427 71 Production 1980 Union Calpine 38.76856 -122.73777 4290919 522781 3 4 11N 8W 90/12/13 8

G90-27 CMHC 4 (Cobb Mtn. Hunting Club 4) C 09790170 72 Production 1976 Union Calpine 38.80592 -122.79128 4295053 518123 1 8 11N 8W 90/12/14 9G91-01 Prati 37 N 09790682 73 Production 1986 CCOC Inactive 38.83532 -122.83164 4298308 514613 3 5 12N 9W 91/06/24 5G91-02 Prati 38 N 09790687 30 Production 1986 CCOC Inactive 38.83283 -122.80486 4298036 516938 3 5 12N 9W 91/06/24 5G91-03 Prati 09 N 09790526 74 Injection 1983 CCOC Inactive 38.83572 -122.82494 4298353 515195 3 5 12N 9W 91/06/24 6

G91-04 Prati State 10 N 09790597 75 Production 1983 CCOC Inactive 38.83239 -122.81524 4297985 516037 1 11N 9W 91/06/24 7

G91-05 Prati State 12 N 09790720 76 Production 1987 CCOC Inactive 38.83255 -122.81523 4298003 516038 1 11N 9W 91/06/24 7

G91-06 Prati State 24 N 09790714 29 Production 1987 CCOC Inactive 38.83283 -122.80486 4298036 516938 1 11N 9W 91/06/24 7

G91-07 Prati State 54 N 09790725 77 Production 1987 CCOC Inactive 38.83281 -122.80494 4298034 516931 1 11N 9W 91/06/24 7

G91-08 Prati 27 N 09790624 78 Production 1986 CCOC Inactive 38.84936 -122.81789 4299869 515803 3 6 12N 9W 91/06/24 9

G91-09 Prati 39 N 09790618 79 Production 1984 CCOC Inactive 38.84495 -122.82809 4299377 514919 3 5 12N 9W 91/06/24 7G91-10 Prati 25 N 09790695 31 Production 1986 CCOC Inactive 38.84102 -122.83065 4298941 514697 3 5 12N 9W 91/06/24 7G91-11 Prati State 01 N 09790486 80 Production 1981 CCOC Inactive 38.83691 -122.80570 4298489 516864 3 6 12N 9W 91/06/24 9

G91-12 Prati 02 N 09790514 81 Production 1981 CCOC Inactive 38.83691 -122.80578 4298489 516857 3 6 12N 9W 91/06/24 9

G91-13 Prati 14 N 09790761 82 Production 1987 CCOC Inactive 38.83775 -122.80828 4298582 516640 3 6 12N 9W 91/06/24 9

G91-14 Prati 50 N 09790721 83 Production 1987 CCOC Inactive 38.84004 -122.81199 4298835 516317 3 6 12N 9W 91/06/24 9

G95-01 Old Geysers† Surface Feature - Union Calpine 95/08/08 G95-02 Hot Sprngs. Cr.† Surface Feature - Union Calpine 95/08/08 

G95-04 Hot Springs. Cr.† Surface Feature - Union Calpine 95/08/08 G96-01 BSC Rdmrk 2.51† Surface Feature - Union Calpine 96/01/18 

bdl = below detection limitblank cell = not recordednpa = not publicly available† Not a well: G96-01 is a fumarole. The others are bubbling pools.* Data from file of CA Div. of Oil, Gas and Geothermal Resources

@Injection wells plugged to depths of 2804.2 (DX St. 4596-61), 2209.8 (GDC-5) and 1842.0 (GDC 88-12)
U.S. Geological Survey

Open File Report #99-304

Geysers Steam Field

Gas and Isotope Geochemistry

Sample# Well Region Sample Type Sample Date pH-field pH-lab Steam/Gas Gas/Steam CO2 H2S He H2 O2 A r N2 CH4 NH3 

(molar ratio) (ppm by wt.) mol% mol% mol% mol% mol% mol% mol% mol% mol% mo

G78-05 LF State 4597-18 (Lakoma Fame) C Production 78/06/07 593 3,062 59.2 10.3 bdl 17.2 0.003 0.050 5.23 6.24 2.06 

G78-06 LF State 4236-2 (Lakoma Fame) C Production 78/06/07 1,173 1,494 54.9 6.12 bdl 15.6 0.093 0.104 9.77 11.4 2.32 

G78-07 LF State 4597-16 (Lakoma Fame) C Production 78/06/07 1,915 1,002 66.3 7.31 bdl 12.5 0.27 0.017 3.37 7.96 2.23 

G81-01 D&V-A1 (Dillingham & Vought) S Production 81/01/12 3,870 443 51.1 15.3 bdl 18.3 bdl 0.0058 0.82 1.54 13.90 G81-02 Thorne 1 S Production 81/01/12 3,246 502 44.9 11.6 0.068 19.2 bdl 0.140 10.00 2.45 11.70 G81-03 CA 958-37-34 (956#3) S Production 81/01/12 9,311 192 54.3 17.8 bdl 17.9 0.0140 0.0093 1.47 3.97 4.92 

G81-04 CA 958-37A-34 S Production 81/01/12 11,138 143 43.2 21.4 bdl 23.8 bdl 0.0062 1.79 8.06 0.37 

G81-05 D&V-A3 (Dillingham & Vought) S Production 81/01/24 5,647 276 40.8 20.0 0.0054 24.4 bdl 0.0085 1.29 2.59 11.90 G81-09 Thorne 6 S Production 81/01/12 2,266 745 50.4 13.8 0.0037 20.1 bdl 0.030 3.08 5.83 7.76 G81-12 CA 956A 73-34 (956#1) S Production 81/02/04 8,718 176 38.6 24.4 bdl 27.3 bdl 0.0008 0.33 1.15 9.04 

G81-13 Thorne 3 S Production 81/02/04 1,724 984 51.9 10.6 bdl 18.4 bdl 0.079 5.17 8.33 5.46 G81-15 McKinley 1 S Production 81/02/04 6,849 189 23.4 18.4 bdl 32.1 bdl 0.300 15.7 0.95 8.13 

G81-16 McKinley 3 S Production 81/02/04 5,271 270 37.4 17.7 bdl 33.4 bdl 0.054 3.95 0.81 7.02 

G81-17 MLM1 S Production 81/02/04 3,894 403 46.6 13.2 bdl 26.3 bdl 0.030 3.46 5.98 4.64 G81-19 McKinley 4 S Production 81/02/04 4,314 368 45.9 15.0 bdl 28.7 bdl 0.041 3.30 1.65 9.05 G81-20 D&V-A2 (Dillingham & Vought) S Production 81/02/04 7,576 212 46.9 18.7 bdl 21.8 bdl 0.020 1.94 2.03 3.48 G81-21 CA 956A 56-34 (956#2) S Production 81/02/05 7,593 207 37.3 15.4 bdl 16.5 bdl 0.160 12.3 14.0 3.48 

A86-1 Rorabaugh A-2 (Unit 15) U Production 86/08/08 122 14,246 58.8 4.67 bdl 15.6 bdl 0.019 1.69 14.9 4.46 

A86-2 Rorabaugh A-3 (Unit 15) U Production 86/08/26 126 14,118 60.4 5.12 bdl 14.7 0.07 bdl 1.95 14.2 3.86 

A86-3 Rorabaugh A-4 (Unit 15) U Production 86/08/07 265 5,991 50.5 6.72 bdl 21.9 bdl bdl 1.34 11.5 8.40 

A86-4 Rorabaugh A-7 (Unit 15) U Production 86/08/07 158 11,177 59.1 6.14 bdl 14.7 bdl 0.0057 1.44 12.9 6.01 

A86-5 Rorabaugh A-9 (Unit 15) U Production 86/08/08 286 5,909 55.8 5.32 bdl 17.6 bdl 0.015 2.09 17.2 2.34 

A86-6 Rorabaugh A-10 (Unit 15) U Production 86/08/08 126 14,500 63.4 4.37 bdl 13.1 bdl 0.0035 1.81 14.6 3.10 

A86-7 Rorabaugh A-13 (Unit 15) U Production 86/08/07 547 2,943 50.4 6.00 bdl 18.8 0.005 0.034 1.31 8.88 15.2 

A86-8 Rorabaugh A-18 (Unit 15) U Production 86/08/08 205 8,024 49.8 5.55 bdl 12.4 bdl 0.032 2.70 22.0 7.63 

A86-9 Rorabaugh A-22 (Unit 15) U Production 86/08/08 239 7,123 55.6 5.14 bdl 14.7 bdl 0.017 1.72 16.0 6.75 

A86-10 Rorabaugh A-27 (Unit 15) U Production 86/08/26 211 8,378 61.3 3.87 bdl 16.5 bdl bdl 1.86 12.9 3.93 

A86-11 Filley1 U Production 86/08/11 6 8 25,534 58.3 4.53 bdl 15.5 bdl bdl 1.72 16.3 3.95 

A87-1 McKinley-3 S Production 87/01/30 3,143 500 52.7 9.50 0.030 31.5 0.0147 0.0164 1.00 0.28 5.36 

A87-2 Abel 1 S Production 87/01/30 2,276 668 48.5 7.68 0.0047 28.2 0.038 0.023 2.46 5.62 7.35 

G88-6 Prati State 24 N Production 88/03/25 8.3 193 9,013 60.4 6.41 0.00048 20.7 0.006 0.0046 0.831 3.83 8.10 G88-7 Prati 38 N Production 88/09/22 8.5 8 7 21,207 65.1 4.48 bdl 13.7 0.020 0.0026 1.35 8.98 6.56 

G88-8 Prati 25 N Production 88/09/22 8.4 3 1 65,324 74.8 1.63 bdl 7.4 0.013 0.0030 1.79 11.58 2.65 

G88-9 Prati 4 N Production 88/09/22 8.6 9 7 19,220 66.8 4.52 0.0023 15.1 0.0079 0.0056 1.23 6.57 5.96 

G88-10(1/3) Rorabaugh A-4 (Unit 15) U Production 88/09/22 8.2 294 5,215 48.4 6.75 0.0004 24.8 bdl 0.012 1.55 10.07 8.89 

G88-11 Abel 1 S Production 88/09/23 7.1 1,686 979 55.3 7.37 bdl 24.6 bdl 0.024 2.07 5.99 4.99 

G88-12 MLM-7 S Production 88/09/23 7.0 1,762 871 49.3 6.13 0.00036 26.8 0.0013 0.022 3.49 10.96 3.47 

G88-13 CA 956A 56-34 (956#2) S Production 88/09/23 6.8 3,093 498 44.9 8.70 bdl 22.1 0.011 0.046 4.55 13.51 6.49 

G88-14 CA 956A 73-34 (956#1) S Production 88/09/23 6.8 2,709 622 58.3 8.80 0.00054 27.2 0.0092 0.031 1.37 0.72 3.91 

G88-15 Davies Est. 7 S Production 88/09/23 6.9 2,085 871 55.6 4.65 bdl 6.96 bdl 0.095 9.84 18.83 4.00 

G88-16 Davies Est. 5 S Production 88/09/23 7.4 1,351 1,344 65.6 3.79 bdl 8.64 0.0065 0.034 4.46 1.21 5.31 

G90-01 Ottoboni Fed. 21A-12 N Production 90/12/10 5.8 8.5 136 13,024 59.9 6.41 bdl 16.8 bdl 0.043 0.771 5.12 11.3 

G90-02 Ottoboni St.4596 -15 N Production 90/12/10 5.6 8.2 207 8,255 59.6 6.17 bdl 23.4 bdl bdl 0.806 4.17 6.25 

G90-03 Ottoboni St.4596-14 N Production 90/12/10 6.0 8.6 214 8,371 61.8 6.48 bdl 17.6 0.0019 0.0041 0.714 4.23 9.38 

G90-04 D.X. (Delta Xagon) 4596 -45 N Production 90/12/10 5.8 8.6 167 11,837 74.1 4.13 bdl 13.0 0.0014 0.0029 0.4495 3.16 5.05 

G90-05 L'Esperance 2 (LESP-2) N Production 90/12/11 5.2 8.3 204 9,253 69.4 3.58 bdl 17.0 bdl 0.014 2.27 5.36 2.82 G90-06 GD Horner State 4596-9 C Production 90/12/11 4.7 4.1 849 2,057 60.0 4.12 bdl 19.5 bdl 0.019 4.37 9.30 3.17 G90-07 NE Geysers Unit (NEGU) 15 C Production 90/12/11 4.5 7.7 598 3,177 68.3 4.29 bdl 14.9 bdl 0.017 2.73 8.20 1.76 

G90-08 Ottoboni Fed 48-2 N Production 90/12/11 6.5 8.6 104 17,792 63.8 5.09 bdl 11.6 bdl 0.0038 1.18 10.1 8.54 

G90-09 Ottoboni Fed 48A-2 N Production 90/12/11 6.5 8.6 5 1 35,918 64.1 2.42 bdl 11.0 0.0076 0.010 1.56 13.3 7.71 

G90-10 Sulphur Bank -15 C Production 90/12/12 6.0 8.3 339 4,944 54.5 8.39 0.0077 19.9 0.0043 0.0051 0.744 5.78 10.8 

G90-11 Sulphur Bank -8 C Production 90/12/12 6.2 8.5 219 7,080 49.4 6.29 bdl 23.7 bdl 0.0093 0.808 4.59 15.60 G90-12 CA State 92-6 N Production 90/12/12 5.5 8.7 119 16,763 72.2 4.63 bdl 10.7 bdl 0.015 2.37 6.46 3.74 G90-13 D.X.(Delta Xagon) State 4596-50 N Production 90/12/12 6.3 8.6 8 9 23,222 79.2 3.71 bdl 10.8 bdl 0.0051 0.510 2.49 3.17 

G90-14 NE Geysers Unit (NEGU) 17 C Production 90/12/12 5.5 8.3 208 8,552 64.5 3.70 bdl 21.4 0.0046 0.0089 2.30 6.70 1.82 G90-15 GD Horner State 4596-7 C Production 90/12/12 6.0 8.1 297 5,634 57.3 5.31 bdl 23.6 bdl 0.013 2.55 7.82 3.78 G90-16 D.X. (Delta Xagon) State 4596-64 C Production 90/12/12 6.0 8.4 1,355 1,274 53.7 7.84 bdl 13.4 0.0080 0.023 2.27 4.61 18.4 

G90-17 D.X. (Delta Xagon) State 4596-87 C Production 90/12/12 6.0 8.3 450 3,822 59.5 5.17 bdl 21.8 0.015 0.013 2.86 7.29 3.71 G90-18 Angeli 2 C Production 90/12/12 5.5 8.3 472 3,658 57.2 10.3 bdl 21.8 0.012 0.0066 1.32 5.43 4.30 G90-19 Angeli 3 C Production 90/12/12 n.r. 8.1 622 2,888 62.4 7.42 bdl 19.7 bdl 0.0065 1.76 6.10 2.86 G90-20 Geysers Devel. Corp. (GDC) 30 C Production 90/12/13 5.0 7.0 1,022 1,832 65.4 4.48 bdl 13.8 0.0061 0.031 3.50 10.0 3.02 

G90-21 Beigel 3 C Production 90/12/13 4.7 7.1 1,850 952 59.0 6.43 bdl 18.1 bdl 0.050 4.02 9.99 2.61 

G90-22 Beigel 2 C Production 90/12/13 5.0 7.7 1,526 1,131 60.0 6.90 bdl 23.5 bdl 0.024 1.80 3.92 4.29 

G90-23 GDCF (GDC Federal)14A-27 S Production 90/12/13 5.0 7.7 1,584 1,173 64.2 8.44 bdl 17.3 bdl 0.035 2.33 3.03 4.90 

G90-24 BEF 85-28 S Production 90/12/13 5.0 8.0 665 2,785 65.7 6.87 bdl 17.8 bdl 0.0080 1.12 4.11 4.77 

G90-25 D&V-25 (Dillingham & Vought) S Production 90/12/13 5.0 7.2 3,858 392 37.4 9.33 bdl 25.3 bdl 0.270 20.90 2.35 4.56 

G90-26 D&V-2 (Dillingham & Vought) S Production 90/12/13 4.7 7.4 3,073 600 63.4 6.18 bdl 14.8 bdl 0.025 3.00 7.57 5.09 

G90-27 CMHC 4 (Cobb Mtn. Hunting Club 4) C Production 90/12/14 5.6 8.2 697 2,652 62.4 9.86 bdl 15.6 bdl 0.0067 0.884 3.44 8.04 

G91-01 Prati 37 N Production 91/06/24 6.5 7.0 4 2 43,034 64.8 3.29 bdl 14.6 bdl bdl 1.356 11.29 4.87 

G91-02 Prati 38 N Production 91/06/24 6.7 7.2 240 6,793 51.2 7.49 bdl 19.1 bdl 0.0065 0.749 4.83 16.84 

G91-04 Prati State 10 N Production 91/06/24 6.5 7.1 152 9,741 46.2 7.34 bdl 27.5 bdl bdl 0.760 4.75 13.69 G91-05 Prati State 12 N Production 91/06/24 6.6 7.1 142 12,298 59.8 6.09 bdl 19.1 bdl bdl 0.691 4.82 9.80 

G91-06 Prati State 24 N Production 91/06/24 6.3 6.8 176 9,557 58.1 7.12 bdl 25.2 bdl 0.0014 0.794 3.92 5.15 

G91-07 Prati State 54 N Production 91/06/24 6.4 7.0 138 13,217 64.6 5.85 bdl 17.9 bdl bdl 0.746 4.74 6.37 

G91-08 Prati 27 N Production 91/06/24 6.5 6.9 5 8 32,705 68.1 2.92 bdl 10.9 bdl bdl 1.098 6.21 10.78 

G91-09 Prati 39 N Production 91/06/24 6.7 7.3 4 5 42,766 69.0 3.38 bdl 13.1 bdl bdl 0.973 7.51 6.15 

G91-10 Prati 25 N Production 91/06/24 6.5 6.8 2 3 88,700 74.6 2.04 bdl 9.7 0.0047 bdl 1.351 9.51 2.88 

G91-11 Prati State 01 N Production 91/06/24 6.4 6.9 186 9,775 63.0 6.00 bdl 16.2 bdl 0.0025 0.556 2.96 11.36 

G91-12 Prati 02 N Production 91/06/24 6.4 6.8 195 9,644 67.7 6.35 bdl 17.3 bdl 0.0042 0.608 3.23 5.11 G91-13 Prati 14 N Production 91/06/24 6.5 7.0 149 12,671 67.7 5.09 bdl 14.4 0.0110 0.0046 0.634 3.37 8.96 

G91-14 Prati 50 N Production 91/06/24 6.0 7.0 139 12,866 63.9 4.96 bdl 20.3 0.0073 0.0026 0.959 5.12 4.96 

GYS95-01 Old Geysers Bubbling Pool 9 5 / 0 8 / 0 8 no steam - 83.6 2.19 0.00109 5.2 0.0159 0.0483 2.260 6.57 0.00026 

GYS95-02 Hot Springs. Cr. Bubbling Pool 9 5 / 0 8 / 0 8 - - 56.5 1.29 0.00294 20.6 3.170 0.191 9.40 9.39 0.00039 

GYS95-03 Little Geysers Drowned Fum. 95/08/08 347 5,429 51.2 4.68 bdl 10.9 4.210 0.4035 27.35 1.03 0.2302 

GYS95-04 Little Geysers Bubbling Pool 9 5 / 0 8 / 0 8 1,207 1,502 56.6 5.34 0.00363 15.7 4.114 0.338 15.49 1.37 0.866 

GYS96-01 BSC (Big Sulphur Cr.) Rdmrk 2.51 Fumarole 96/01/18 329 6,441 76.8 5.90 0.00057 6.91 0.0139 0.0373 2.93 5.94 1.46 

Mean Samples from Production Wells 1,592 9,355 57.4 7.74 0.0112 18.64 0.0237 0.0317 2.71 7.18 6.35 

Two sigma Samples from Production Wells 4,796 28,885 20.0 9.47 0.0413 11.56 0.1043 0.1069 6.71 9.37 7.47 Minimum Samples from Production Wells 2 3 143 23.4 1.63 bdl 6.96 bdl bdl 0.3300 0.28 0.37 

Maxiumum Samples from Production Wells 11,138 88,700 79.2 24.4 0.0680 33.4 0.27 0.30 20.9 22.0 18.4 

bdl = below detection limit CO concentrations: G90-11 = 13 ppm δ13C CH4: A87-2 = -33.5

blank cell = not recorded G90-1 = 60 ppm G78-5 = -30.1† Not a well G90-6 = 22 ppm G78-6 =-30.4

G78-7 = -29.4
U.S. Geological Survey

Open File Report 99-304

Geysers Steam Field

Mean Composition of Analyses

Southeast Central Northwest Unit 15 Surface 

Geysers Geysers Geysers Manifestations

pH-field 4.9 5.4 6.2

pH-lab 7.2 7.7 7.7 8.2

Steam/Gas 4,180 830 130 220 -

Gas/Steam 630 3,250 21,650 10,260 -

CO2 (mol%) 49.0 59.7 65.0 56.0 64.9

H2S (mol%) 12.3 6.72 4.91 5.35 3.88

He (mol%) 0.0161 0.0077 0.0014 0.0004 0.0021

H2 (mol%) 22.3 18.6 15.9 16.7 11.9

O2 (mol%) 0.0135 0.046 0.0081 0.0375 2.30

Ar (mol%) 0.058 0.0237 0.0075 0.017 0.204

N2 (mol%) 4.66 2.96 1.04 1.76 11.5CH4 (mol%) 5.14 6.99 6.06 14.3 4.86NH3 (mol%) 6.19 5.33 7.24 6.21 0.512

N2/Ar 118 157 239 169 58

δD (per mil) -53 -49 -47 -49δ18O (per mil) -5.1 -4.3 -1.4δ13C CO2 (per mil) -13.5 -13.3 -12.4 -12.7 -13.1δ34S (D) (per mil) 0.9 0.8 0.5 1.3δ34 S (M) (per mil) -0.2 -0.6 -0.5 -0.9
U.S. Geological Survey

Open File Report 99-304

Geysers Steam Field

Injection Wells

Sample # Well Year Drilled Sample Date δD 

G90-00 D.X. State 4596-72 1982 90/12/11 -29 

G90-00 D.X. State 4596-61 1983 90/12/11 -15 G90-00 Geysers Development Corp. (GDC) 05 1980 90/12/11 -13 G90-00 Geysers Devel. Corp. (GDC) 26 1984 90/12/11 -3 G90-00 Geysers Devel. Corp. (GDC) 88-12 1971 90/12/11 -7 G90-00 BEF 42B33 1984 90/12/11 -13 G90-00 LF State 4597- 23 (Lakoma Fame) 1979 90/12/11 -11 G90-00 CMHC 06 (Cobb Mtn. Hunting Club 6) 1978 90/12/11 -6 G91-03 Prati 09 1983 91/06/24 -44 
U.S. Geological Survey

Open File Report 99-304

Geysers Steam FieldTemporal Variations

Well Sample #1 Sample #2 G/S #1 G/S #2 N2/Ar #1 N2/Ar # 2 δD # 1 δD # 2 NH3 # 1 NH

ppm ppm Mol% 

CA 956#1 G81-12 G88-14 176 622 393 44 -54 -58 9.04 McKinley 3 G81-16 A87-1 270 500 73 61 -55 - 7.02 Rorabaugh A-4 A86-3 G88-10 5,990 5,220 - 132 - -49 8.40 Prati State 24 G88-6 G91-6 9,034 9,557 181 567 -49 -50 8.10 Prati 38 G88-7 G91-2 21,307 6,872 519 115 -51 -38 6.56 1Prati 25 G88-8 G91-10 65,219 88,655 597 - -49 -42 2.65 Abel1 A87-2 G88-11 668 979 107 86 - -55 7.35