Geochemical Journal, Vol. 24, pp. 105 to 121, 1990

Gas concentration in aquifer fluid

Oku-aizu geothermal system,

prior to boiling in the

Fukushima, Japan

YOJI SEKI

Mineral Resources Department, Geological Survey of Japan

Higashi 1-1-3, Tsukuba, 305, Japan

(Received December 19, 1989; Accepted July 20, 1990)

The gas and other solute concentrations have been estimated for the aquifer fluid of the Oku-aizu

geothermal system prior to discharge-induced boiling. The model takes into consideration the excess enthalpy (i.e. two-phase) reservoir conditions which developed at production depths following depressurization. The model consists of two end-member types of boiling. One is a "high flow-low temperature drop

type" and the other is a "low flow-high temperature drop type". The first is a process which could be

present in an aquifer with high permeability, and is characterized by a large total discharge, accompanied by a small temperature and pressure drop around the well. The fractionation of gases into vapor phase in the downhole feed zone may be smaller than predicted for equilibrium conditions, due to single step steam separation under dynamic conditions. The second type is a process which could occur in an aquifer with low permeability, and is characterized by a low flow rate and a high temperature and

pressure drop. The net gas fractionation into vapor phase in the feed zone is very large, resulting in almost all the gases fractionating into the vapor phase, due to multi-step steam separation. Based on this model, the concentration of gases and other solutes are estimated for the reservoir liq

uid of the Oku-aizu geothermal system. Calculated ranges of gas concentrations in the reservoir liquid

(prior to flashing) are 0.3 to 1.0 wt% for CO2 and 150 to 250 mg/kg for H2S. The estimates of gas concentrations in the original (pre-boiled) fluid are necessary to calculate mineral-fluid equilibria and to estimate such development-related factors as the potential for scaling.

INTRODUCTION

All ten geothermal wells in the Oku-aizu

geothermal system for which production tests have carried out show excess enthalpy conditions

(unpublished data by the Okuaizu Geothermal Co. Ltd.). "Excess enthalpy" is defined here as being a situation where the measured enthalpy of

discharge exceeds (often by a large amount) the enthalpy of liquid at the temperature of the feed zone (the latter estimated from direct measurement or chemical geothermometry; Truesdell, 1984). Therefore, excess enthalpy conditions indicate two-phase, liquid plus vapor, feed to a discharging well from the reservoir aquifer

(Henley, 1984a). For normal enthalpy wells where there is a single phase liquid feed, the total discharge composition is equal to the reservoir

fluid chemical composition (assuming no mass exchange during upflow). In this case, it is possible to calculate the high temperature fluid chemistry directly from the total discharge com

position using the thermodynamic treatment such as described by Truesdell and Singers

(1974), Glover (1982), Henley (1984b), Ichikuni and Tsurumi (1988) and Takeno (1988). On the other hand, for geothermal wells with an excess enthalpy, two-phase feed, we have to know the

gas distribution between the two phases and the physical process accompanying aquifer boiling, in order to estimate the chemical composition of reservoir fluid prior to boiling. The purpose of this paper is to propose a model which explains the physical process of local aquifer boiling adjacent to the feed zone for a geothermal well; these results are then used

105

106 Y. Seki

to estimate the reservoir fluid composition prior

to boiling in the Oku-aizu geothermal system.

Based on this reservoir fluid composition, we can

calculate the high temperature fluid chemistry,

determine the mineral-fluid equilibria and

predict the potential of fluid to deposit scale.

NORMAL ENTHALPY WELLS AND

EXCESS ENTHALPY WELLS

Figure 1 shows schematically the two types of

geothermal wells with regard to enthalpy. For excess enthalpy wells, the steam fraction at a feed

point (or zone) in a geothermal well will often be larger than the steam fraction in the aquifer where boiling commences; this may be due to both a pressure gradient and the higher mobility of vapor phase in the formation. Therefore, in order to estimate the chemical composition of the reservoir fluid, one must know 1) the steam fraction in the aquifer after boiling begins, 2) the

steam fraction at the feed point of the well, and 3) the distribution coefficient for each component between liquid and vapor phases at the feed zone temperature. An appropriate model of reservoir boiling is necessary to determine these factors.

A MODEL OF AQUIFER BOILING

There are two types of geothermal systems in terms of aquifer boiling; 1) those with aquifer boiling in the natural state (i.e. showing a hydrostatic or hydrodynamic temperature profile with depth), or 2) those where aquifer boiling starts after exploitation (or test production) of

geothermai fluid. The second type is considered in this discussion. A geothermal system may change from a state of no aquifer boiling to one with aquifer boiling when exploitation causes a

pressure drop in the aquifer adjacent to a well (or wells). Under this condition, there are two possible end-member processes; one is a "high flow-low temperature drop type" and the other is a "low flow-high temperature drop type". The high flow-low temperature drop type

may occur when the aquifer has a high permeability to the migration of geothermal fluid, for example, a fracture-controlled aquifer with good continuity (Fig. 2(a)). A large amount of geothermal fluid flows into the well due to high

permeability, accompanied by a relatively low pressure drop. The temperature drop is also very low because of the low pressure drop (related by saturation conditions). The rapid inflow and low

o,

2 phase

e g flow

liq 1 phas

. flow

oilingront

a

-'4. 'fer ---t _rB.H.

1 boiling front

0

~a e. N

er

NORMAL ENTHALPY

WELL

(a)

B.H.

EXCESS ENTHALPY

WELL

(b)

Fig. 1. Normal enthalpy well (a) and excess enthalpy well (b).

Gas concentration in aquifer fluid 107

d

w

OIC

F1

1

rivao

41

0

N N t

a

N1

a

O CL

B.H.

e4 a

1/

~Q

a

F2 T

1

va

1

-A

0

N CO t a N

vapor entry

1\ 1 In

U B.H.

I

1

1

1

4T1CI O

,

pDI

1

I

1

1

I

AP1

I

I

I

1

I I

I I

I I

CI OI

CI .51

I

1

-j

I

I

I

I

I

I

I

I

I

1

I I

1

J

I

I

J

To

A T2

I

step wise de~rxleI I

J _

I

I

AP2

I

I

HIGH F LOWAT type LOW F HIGHAT type

(a) (b)

Fig. 2. High flow-low temperature drop type (a) and low flow-high temperature drop type (b). F.• flow rate, T: temperature, To: original aquifer temperature before boiling and P: pressure. F1 > F2, A TI <d T2 and AP1 <4P2.

temperature drop lead to boiling with single step steam separation (i.e. vapor and liquid are separated at one point, cf. Henley (1984c)). The apparent gas distribution coefficient between vapor and liquid phases may be smaller than that under equilibrium condition, due to the highly dynamic flashing process and the short period of fluid flow. That is, k is smaller than 1 in the

following equation,

B' =kB, (1)

where B' is apparent (or observed) distribution

coefficient of gas between vapor and liquid

phases., B is the equilibrium distribution coefficient, and k is non-equilibrium factor. This type of process may occur in the Broadlands

108 Y. Seki

0.

C 0

cD L

C 0 0 C 0

0 N

N

0 0 0 Ira

CO cc

100000

10000

N

V

V 1000

U

V .?

a J C

CD s H

0 4-.

100

10

Temp.Step for MSSS

To= 280 °C

:5°C4

40 41P Ot/

SSS~

,1)

SSSS115)

280 260 240 220 (°C)

Temperature

Fig. 3. Ratio of CO2 gas concentration in vapor to that in liquid vs. temperature. SSSS: single-step steam separation, MSSS: multi-step steam separation, and k: non-equilibrium factor in the equation B' =kB, where B and B' are equilibrium and apparent (or observed) distribution coefficients of CO2 gas, respectively, between vapor and liquid phases. In equilibrium condition, k=1. The equilibrium CO2 distribution coefficient (B) is taken from Giggenbach (1980).

Ohaaki geothermal system, New Zealand, as dis

cussed by Hedenquist (1990). The low flow-high temperature drop situa

tion may occur in a low permeability aquifer, for example, a fracture-controlled aquifer with poor

continuity, or a porous media (Fig. 2(b)).

Geothermal wells of this type are relatively poor

producers due to low permeability. The total

pressure and temperature drop is much larger than in the former, high permeability type. Step

wise pressure and temperature drops toward the well may exist, especially when the aquifer is frac

ture-controlled and cut by other minor fracture

systems. In the case of step-wise pressure and temperature drops, boiling occurs at each step. The vapor phase which is produced at each boiling step may separate from the liquid phase along minor fractures and flow towards the well due to its higher mobility (in this model all vapor

produced at each step enters the discharging well). This process is multi-step steam separation

(cf. Henley (1984c)). The k factor of eq. (1) for each step might be smaller than unity for the same reason as previously discussed. Most of the

gas components fractionate into the vapor phase as a result of this multi-step steam separation, as

Gas concentration in aquifer fluid 109

shown in Fig. 3.

CALCULATION

The calculation to estimate the reservoir fluid

composition prior to boiling is based on the

following assumptions.

1) One liquid phase in the original aquifer. 2) One feed zone for a well. 3) No heat and mass exchange during upflow

through a well. 4) No heat and mass exchange during migra

tion in an aquifer and in fractures after boiling

starts.

5) The process of aquifer boiling follows the single or multi-step endmember models discussed above. At first, some chemical and physical values

have to be determined based on analytical or ob

served well data.

Concentration of each component in total

discharge (C;,,d):

(Ci,td = (Ci,liq X (1 SFSep)) + (Ci,vap X SFsep), (2)

where Ci,liq is concentration of component (i) in liquid after separation at the surface, Ci,vap is that in vapor, and SFsep is steam fraction at the separator.

Excess enthalpy (Hex):

Hex = Htd Hliq,tdh, (3)

where Htd is total discharge enthalpy and Hliq,tdh is enthalpy of steam-saturated water at the tem

perature of the feed point of a well.

Steam fraction in aquifer just after boiling (SF,,,), and steam fraction at the feed point to the well

(SFdh):

SFaq = (Hliq,taq Hliq,tdh) / (Hvap,tdh Hliq,tdh), (4)

and

SFdh = (Htd Hliq,tdh) / (Hvap,tdh Hliq,tdh), (5)

where Hliq,taq is enthalpy of steam-saturated

water at the temperature before boiling (Taq) and Hvap,tdh is the enthalpy of water-saturated steam at the temperature of the feed point of the well

(Tdh) Using these values, an equation can be derived to determine the concentration of each component in the original aquifer (C1,0). Provided the assumption 4), Ci,o can be expressed as follows;

Ci,o = Ci,vap,aq X SFaq + Ci,liq,aq X (1-SFaq), (6)

where Ci,vap,aq is the concentration of component

(i) in vapor just after aquifer boiling and Ci,liq,aq is the concentration of component (i) in the remaining liquid just after aquifer boiling. Ci,td can also be expressed as

Ci,td = Ci,vap,dh X SFdh + Ci,liq,dh X (I SFdh). (7)

where Ci,vap,dh is the net concentration of component (i) in vapor produced during aquifer boiling and Ci,liq,dh is the concentration of conponent (i) in the remaining liquid after aquifer boiling. The ratio (f) of net concentration of component (i) in vapor to concentration in liquid is defined as

f = Ci,vap,dh / Ci,liq,dh. (8)

Then, by assuming Ci,vap,aq ~' Ci,vap,dh and Ci,liq,aq Ci,liq,dh, the following equation for Ci,o is deriv

ed from eqs. (6), (7) and (8);

Ci,o = Ci,td X (SFaq X (f -1) + 1) / (SFdh X (f -1) + 0

(9)

For a component completely remaining in

the liquid phase (i.e. non volatile), f is 0, so eq.

(9) can be expressed as

Ci,o=Ci,td X (1-SFaq)/(1-SFdh)• (10)

In contrast, for a component which essential

ly migrates completely into the vapor phase (for

example, highly volatile gas components under

multi-step steam separation), eq. (9) can be sim

ply expressed as

Ci,o=Ci,td X SFaq/SFdh. (11)

110 Y. Seki

380N

370

w YONEZAWA NIIGATA El

A Mt.IIDE RAGAN

O FUKUSHIMA Mt.BANDAIAIZUWA AIi~1TU~

117L'''~~~777.

KU AIZUIINAwASHIRO

35

146

GEOTHERMAL FIELD

Mt.NASU

A Mt.NANTAI

KORIYAMA

El SHIRAKAWA

Mt.YAMIZO

IWAKI El

the PACFIC

1390E 1400 141

Fig. 4. Map showing location of the Oku-aizu

geothermal system.

ESTIMATION OF RESERVOIR FLUID COMPOSITION

IN THE OKU-AIZU GEOTHERMAL SYSTEM

In the Oku-aizu geothermal system, geother

mal wells equivalent to the two end-member

types in the model are recognized. For these

wells, it is possible to estimate the reservoir fluid

chemical composition before boiling by a calcula

tion based on the model. These wells were drilled

in 1985 to 1987, and were tested for a total of

about 10 months during the period from 1985 to

early 1990. Development-related feasibility

studies are now underway.

Geology

The geothermal system is located in Yanaizu

town in Fukushima prefecture, northeast Japan

(Fig. 4). This area is in the "green tuff region" characterized by Neogene submarine volcanic ac

tivity, and is about 50 km west the present volcanic front. The basement is considered to be

pre-Tertiary granodiorite or metamorphosed sedimentary rocks, although it has not yet been found in this area (Nitta et al., 1987). Miocene

formations consisting of rhyolitic lavas and

pyroclastic rocks intercalated with clastic rocks, and lesser amounts of basaltic rocks overlie the basement. Pliocene dacitic pumice tuff inter

calated with some clastic rocks rests unconfor

mably upon the Miocene formations. Pleistocene lacustrine sediments which unconformably overlie the Pliocene formations are exposed in a limited ring-shaped area about 3 km in diameter, surrounding a rhyolite lava dome, and are also intruded by rhyolite (age of both rhyolites are 0.2 to 0.6 Ma (NEDO, 1985)). A steep-sloped unconformity with poorly sorted basal breccia from an adjacent underlying strata is present (Komuro, 1978). The distribution of the lacustrine sediments is concordant with great depths of the basement inferred from the gravity survey (Nitta et al., 1987). The hydrological system is strongly controlled by a fracture network, with the production area composed of two major fault zones called the Chinoikezawa and Sarukurazawa (Fig. 5); they are composed of swarms of open-space fractures (NEDO, 1985 and Nitta et al., 1987).

Geothermal wells modeled in this study

All ten production wells in this area (Fig. 5) have excess enthalpy discharges at present. However, wells OA-4 and 84N-2t, drilled in the first stage of exploration, appeared to have normal enthalpy discharges early in their history

(NEDO, 1985 and Ichikuni and Tsurumi, 1988). In addition, measured temperature profiles under static conditions show that downhole tem

peratures do not reach boiling temperature at any depth for the wells 85N-6T, 87N-14T and 87N-15T (Fig. 6(a), (b) and (c)). On the other hand, a few local gas-rich reservoirs were reported based on drilling records, for example at -831 m in 84N-It (Nitta et al., 1987). From these observations, the Oku-aizu geothermal system had little boiling in its natural state, though there were probably minor local zones of boiling. Data used in the present study to model the

reservoir fluid composition are from geothermal

wells 85N-6T, 87N-14T and 87N-1ST. These three wells penetrate the Chinoikezawa fault

zone, and are located about 150 to 300 m apart

from each other. Because of their close spatial distribution in the same target fracture (aquifer

feed) zone, the geothermal fluid supplying each

Gas concentration in aquifer fluid 111

37°27'N

26'

SUNf

Q

`72 °OA

•1t/

Q

14

OHAR

MSHIYAM'A.

H.S:

W.

I

6

44`r~` Y,•.I

D

-2t'

60 760

\

•6T•

A 8 85*

83°'

~Rj,~ 16T '

x

T~ 4 . T ~~ 10

:i•

22T. N1j

\

0

L

\

b'0

1km

139°41'E 42' 43'

Fig. 5. Map showing surface location of wells, major faults (broken lines) and isotherms (dotted lines with figures (°C)) at -1200 m A. S.L. • : wells discussed in text, *:other wells, ~: fault and its dip and --y -: inferred fault. (modified from Nitta et al., 1987).

well should be similar.

Adequacy of assumptions for the system Each assumption is examined as to whether

or not it is satisfied in this system.

1) One liquid phase in the original aquifer This assumption is basically satisfied. As men

tioned before, this system is considered to have

had little boiling in its natural state, i.e. a single

liquid phase in the original aquifer. The total

discharge enthalpy versus well head pressure for 85N-6T (Fig. 7) indicates that aquifer boiling

takes place around the well due to the pressure

drop caused by discharging of geothermal fluid.

The same phenomena are recognized in other

wells. Therefore, one phase liquid exists in the

aquifer while two phases are present adjacent to the geothermal wells.

2) One feed zone for a well The feed zone can probably be approximated

by a representative single zone, although the actual feed zones for each well are distributed over some hundreds of meters vertically due to the width of the fracture zone. The wells are cased above about ASL -400 m, limiting inflow to

greater depths (Fig. 6(a), (b) and (c)). 3) No heat and mass exchange during upflow

through a well

No fluid can enter the wells shallower than

ASL -400 m because of the casings. The heat ex

112 Y. Seki

85N-6T

Casing

Program

1 1 Dia= 7.00 (inch)

u

771.

806.

1655.0

1988,Feb.28 W H :ASL428.Om

Depth

0.m

200

400

600

800

1000

1200

1400

1600

0 Pressure kqf/cm 2 75

0 Temperature (°C) 350

0 Spinner (rps) 300

s

I I I I 1

I

I

i

I

N

I-p

c

WHP=27.5kg/cm2 Ftot=34.5t/h

op

C

ASL

400m

200

0

-200

-400

-600

-800

-1000

-1200

(a)

Fig. 6. Casing program and pressure, temperature and spinner logging under flowing (discharging) condition

for 85N-6T (a), 87N-14T(b) and 87N-15T(c) (compiled from unpublished data by the Okuaizu Geothermal Co. Ltd.). Measured down hole temperature under static condition (Tstatic) and boiling temperature versus depth curve (calculated assuming C02 in the original aquifer= 1.0 wt%) are also shown. Note that the down hole temperature does not reach the boiling temperature at any depth under static conditions.

Gas concentration in aquifer fluid

87N-14T 1988,Mar.6 W H :ASL392.Om

0 Pressure (kgf/cm2) 50Casing

Depth 0 Temperature (°C) 350 ASLProgram 0 Spinner (rps) 300

I I OM 400m

I

i i 200 200

I I400

0o _( 0

r

o.

I 600 -200

~1 \SN

1 IL759.7

800 -400

i i 810.0

I I .

I I1000 31

-600

I I

Dia: i I7.00-fl(inch),

1200 ('U i-800

~ tD -e1400

~' 01

r -1000

11555.0

1600 WHP=7.3kg/cm2 Ftot=43.lt/h

ro)

113

114 Y. Seki

87N-15T

Casing

Program

Dia= 7.00

(inch)

1

1 I I

I

1

1

i

I

1

1

921. 967.

1988,Mar. 2

1855.3

W H :ASL400.4m

Depth

Om

200

400

600

800

1000

1200

1400

1600

1800

0 Pressure cm 200

0 Tem erature 350

0

2000

Spinner (rps 100

I !

19.Im

i

I

WHP=58.8kg/cm2

1 r

N c

Ftot=170.0t/h

1

.

0 C)

i

ASL

400m

200

0

-200

-400

-600

-boa

-1000

-1200

-1400

-1600

(c)

Gas concentration in aquifer fluid 115

kJ/kg

a 1600rr c

W

Cs

0

1500

a

3

C y 50

O

U

1400

t/h I 100

S S

O di

' ,Zer

1987,Feb.1

0 20 40 kg/cm' Well Head Pressure

Fig. 7. Total discharge enthalpy versus well head

pressure diagram for 85N-6T (Nitta et al., 1987). Total enthalpy decreasing as the well head pressure increases indicates the presence of aquifer boiling adjacent to the well due to a discharge-induced pressure drop.

5) L

. V .N G

H 0 ::

0

u

t/h

200

100

,

High flow

low temp. drop type 87N-15T (V.O.R.1o%)

87N-17T j

T~-J

Low flow

high temp. drop type86N-11T

85N-6T87N-14T

87N-16T

86N-1OT (V.OR50%)

change through the wall of each well is negligible

after a period of sustained discharge. However,

if a gas-rich reservoir is present below 400 m,

gas-rich fluid may be added to the discharge. This problem will be discussed later.

4) No heat and mass exchange during migration in an aquifer after boiling For wells where the difference between Taq

and Tdh is small, heat exchange is negligible. For

wells where the difference is large, some heat

from the surrounding rocks may be added to the

geothermal fluid during flowing towards the feed

point. A fraction of the steam produced by

aquifer boiling may not enter the nearest well

but rather escape through fractures. This prob

lem will also be discussed later.

5) The process of aquifer boiling follows the model

The flow rate of total discharge and the

degree of temperature drop are shown in Fig. 8

for several wells. All wells can be divided into

two groups; one is characterized by a large tem

0 50 100°C Degree of Temp. Drop

Fig. 8. Relation between mass flow rate of total discharge and degree of temperature drop around down hole feed zone. V.O.R.: well head valve opening rate. All wells are 215.9 mm in diameter at bottom hole. They can be divided into two groups: "high flow-low temperature drop type" represented by 87N15T and "low flow-high temperature drop type".. including 85N-6T and 87N-14T.

perature drop (30-60°C) and low flow rate (4070 t / h), while the other has a small temperature drop (less than 51C) and a high flow rate (more

than 170t/h). These correspond to the "low flow-high temperature drop type" and the "high flow-low temperature drop type", respectively.

Estimation of reservoir fluid chemical composition Analytical and well data, provided by the Okuaizu Geothermal Co., Ltd., are listed in Tables 1, 2, and 3. Well head pressure (WHP) and separation pressure (Psep) are in bars gauge. Temperature at the main feed point (Tdh) was determined from temperature and spinner logging results carried out under the flowing conditions shown in Fig. 6(a), (b) and (c). Steam fraction in aquifer (SFaq), steam fraction at down hole

(SFdh) and aquifer temperature (Taq) were calculated from analytical and well data listed in

116 Y. Seki

Table 1. Analytical results, well data and total discharge (T.D.) composition of 84N-6T

Table 3. Analytical results, well data and discharge (T.D.) composition of 87N-15T

total

Date W.H.P. (b.g.) P-se, (b.g.) F.coc (t/h) S.F.sep W.F. Sep

stm.wat/T.D.gas/T.D. liq.wat/T.D.

Jan. 20/198834.8

6.4

55.7

0.712

0.288

0.4806

0.0741

0.4452

T.dh (°C) H.td (J/g)

B.H.diam. (mm)

245

1845

215.9

Date W.H.P. (b.g.) P•sep (b.g.) F.tot (t/h) S.F.sep W.F. sep

stm.wat/T.D.

gas / T.D. liq.wat/T.D.

Jan. 29/198865.1

6.5

161.1

0.554

0.446

0.5174

0.0369

0.4457

Conc.in Component liq.wat

(mg/ kg)

T.dh (°C) H.td (J/g)

B.H.diam. (mm)

291

1846

215.9

Conc.in Conc.in Conc.in stm.cond gas T.D. (mg/kg) (vol%) (mg/kg)

Conc.in Conc.in Conc.in Conc.in Component liq.wat stm.cond gas T.D.

(mg/kg) (mg/kg) (vol%) (mg/kg)

Na+ K+ Mg2+ Ca2+ A13+ Mn2+ Fe2+ CiSO4HCO3 Si02 CO2 H2S

7220

1720

11.4

1350

0.20

249

5.80

14900

17.0

28.0

824

96.7

2.7

3215

766

5.08

601

0.09

111

2.58

6634

7.57

12.5

367

72296

1564

Na+ K+ Mg 2+ Ca 2+ A13+ Mn2+ Fe 2+ C1S04 HCO3 Si02 CO2 H2S

7770

2170

10.2

1080

0.22

321

1.14

16000

12.0

25.9

969

0.13

0.18

0.01

46.2

96.30

3.00

3460

967

4.55

481

0.10

143

0.51

7130

5.35

11.5

432

35900

885

Table 2. Analytical results, well data and total discharge (T.D.) composition of 87N-14T

Date W.H.P. (b.g.) P.Sep (b.g.) F.t°t (t/h) S.F.sep W.F. Sep

stm.wat/T.D.gas/ T.D. liq.wat/T.D.

Jan. 9/198820.2

6.4

53.9

0.681

0.319

0.6572

0.0552

0.2876

T.dh (°C) H.td (J/g)

B.H.diam. (mm)

210

2109

Table 4. Steam fraction in aquifer (SFaq), steam fraction at down hole (SFd,J and aquifer temperature for each well

84N-6T 87N-14T 87N-15T

215.9

Conc.in Component liq.wat

(mg/kg)

Conc.in Conc.in Conc.in stm.cond gas T.D. (mg/kg) (vol%) (mg/kg)

Na+ K+ Mg2+ Ca2+ A13+ Mn2+ Fe2+ ClS02HCO3 Si02 CO2 H2S

7650

1760

4.71

1180

0.14

75.8

0.62

15200

21.8

0.5

668

0.13

0.31

28.9

2200

506

1.35

339

0.04

21.8

0.18

4370

6.27

0.14

192.1

53600

1310

T.aq (°C)* T•dh (°C) T•drop (°C) H.td (J/g) Hl.t .aq (J/g) Hl_t.dh (J/g) Hv.t .dh (J/g)

SFaq

SFdh

Cj.°/C5.td (f=0)

283

245

38

1845

1210

1061

2803

0.086

0.450

1.663

262

210

52

2109

1134

898

2798

0.129

0.637

2.415

299

295

4

1846

1305

1289

2766

0.011

0.377

1.588

96.40

3.00

* Silica geothermometer (Fournier and Potter, 1982) was

used to determine aquifer temperature.

Table 4. The silica geothermometer (Fournier

and Potter, 1982) was used to determine the aquifer temperature.

Steam fraction in the aquifer, an important

parameter of this model, is calculated using the estimated aquifer temperature. However, the

Gas concentration in aquifer fluid 117

C

--o

0 O 0 V

0)

iT N

V M ,v C

co 0

V C ca 0

Wt%

1.0

0.1

. `~ t<8

s ~ . S ss~ ire

f=Bf>B 85N-6T

f=B

Msss

87N-14T

estimated C02 in orig.aq.0.3 1.0 wt%

f=B \,`

fZ_~ e N.

----------

(To=sot°Cj

87N-15T (To=299°c)

8'71V T (To`296 -C)

10 100 1000

Ratio of C02 Gas Concentration in Vapor to That in Liquid (f)

Fig. 9. Calculated CO2 gas concentration in original aquifer based on eq. (4) vs. CO2 gas concentration ratio of vapor to liquid. Gas distribution coefficient (B) is from Giggenbach (1980). SSSS: single step steam separation, MSSS: multi-step steam separation and f.• the ratio of net concentration of CO2 gas in vapor produced during boiling to concentration in remaining liquid. Three lines for 87N-15T are calculated by taking an error of plus or minus 3°C in the quartz geothermometer for the original aquifer. For the other wells, such an error affects the calculation to a much smaller degree. For 87N-15T, where SSSS may occur, the calculated CO2 concentrations in the original aquifer may be greater than 0.3 wt%, if an f value smaller than B is appropriate due to the dynamic process. For 85N-6T and 87N-14T, where MSSS may occur, the calculated CO2 concentration is about 1.0 wt%, using an f value greater than B being consistent with the repeated fractionation of gases from the liquid to the vapor phase. As a result, the most plausible value for the CO2 concentration in the original aquifer is in the. range of 0.3 to 1.0 wt%, and possibly closer to the upper value.

geothermometer used to estimate the aquifer tem

perature could have an error of a few degrees due to non-equilibrium, sampling method and

analytical accuracy, etc. If the difference be

tween Taq and Tdh is small, an error in Taq will se

riously affect the estimation of SFaq, and conse

quently affects the estimation of the reservoir fluid composition. Figures 9 and 10 show the

results of the model calculation with a Taq error

of plus or minus Y C.

Components which remain in the liquid

phase are calculated by eq. (10) based on the model. The calculated concentrations of the

non-volatile components in the reservoir fluid agree between the three wells (Table 5). For Cl

and Na+ agreement within 6% and for K+ and

Ca" agreement of <25% were obtained. The estimated values for Mn2+ and Si02 show a wider distribution. Both Mn2+ and Si02 decrease in the order of 87N-15T, 85N-6T and 87N-14T. This, as well as some scatter of K+ and Cat', can be ex

plained by the temperature decrease corresponding to that order probably as a result of heat loss into the formation (aquifer temperature determined by silica geothermometer is 283°C (84N-6T) 262°C (87N-14T) and 299°C

(87N-15T)). Figures 9 and 10 show calculated concentra

tions of CO2 and H2S gases in the original

aquifer. From the earlier arguments, the geother

mal fluids which flow into the three wells are most likely quite similar in composition prior to

118 Y. Seki

mg/kg

c 0

coN

C N

V O O OV

V

4)

C3 c N Q

.0 C

0. CD U

000

~~ f=B

frB

f>B 85N-6T

f=B T estimated H2S 87N-14Tin orig.aq. 150-250 mg/kg

100 MSSS

87N-15T (To=302°c)

87N-1ST fTo=2ss°C-)

11 .all-_. . . l 1

7 r jTo=?ss0~).. . 1 . . . . I -. -r

10 100 1000

Ratio of H2S Gas Concentration in Vapor to That in Liquid (f)

Fig. 10. Calculated H2S gas concentration in original aquifer based on eq. (4) vs. H2S gas •concentration ratio of vapor to liquid. Gas distribution coefficient (B) is from Giggenbach (1980). SSSS: single step steam separation, MSSS: mufti-step steam separation and f:the ratio of net concentration of H2S gas in vapor produced during boiling to concentration in remaining liquid. Three lines for 87N-15T are calculated by taking an error of plus or minus 3°C in the quartz geothermometer for the original aquifer. For the other wells, such an error affects the calculation to a much smaller degree. For 87N-15T, where SSSS may occur, the calculated H2S concentration in the original aquifer may be greater than 150 mgl kg, if an f value smaller than B is appropriate due to the dynamic process. For 85N-6T and 87N-14T, where MSSS may occur, the calculated H2S concentration is about 250 mg lkg, using an f value greater than B being consistent with the repeated fractionation of gases from the liquid to the vapor phase. As a result, the most plausible value for the H2S concentration in the original aquifer is in the range of 150 to 250 mg/kg, and possibly closer to the upper value.

Table 5. Estimated chemical composition of original aquifer other than gas component

Component 84N-6T 87N-14T 87N-15T

Na+

K+

Mg2+

Ca 2+

A13+

Mn2+

Fe 2+

C1

S04 Si02

5345

1273

8.44

999

0.15

184

4.29

11030

12.6

610

5310

1220

3.27

820

0.10

52.7

0.43

10600

15.1

464

5500

1540

7.22

764

0.16

227

0.81

11300

8.49

686

boiling and temperature decrease. If so, the esti

mated gas concentrations for the three wells

should agree with each other as long as the

assumptions of the model are satisfied.

However, the estimated gas concentrations for

the three wells differ from each other as shown in Figs. 9 and 10. For 87N-14T, the CO2 concentra

tion in original reservoir fluid is calculated to be

1.1 wt% assuming that the CO2 concentration

ratio (f) of vapor to liquid phase at down hole is identical to the gas distribution coefficient (B).

But the well is considered to be "low flow-high

temperature drop type", in which f can be much larger than B. However, even using much larger

f (>I 000), the CO2 value is only reduced to 1.0

wt%. The difference between the two values is negligible. For 85N-6T, a C02 concentration of

Gas concentration in aquifer fluid 119

1.4 wt% is obtained using a f value larger than B. The difference in the estimated CO2 concentrations between these two wells is probably greater

than that expected for sampling and analytical er

rors.

On the other hand, the calculated C02 con

centration in the original aquifer fluid for 87N

15T is 0.3 to 0.5 wt% (using f=B). Because this

well is considered to be a "high flow-low temper

ature drop type", in which single step steam

separation takes place, the adoption of B for the

f value is reasonable. The estimated CO2 concen

tration for 87N-15T is significantly different from those of the other two wells.

There are possible reasons for the difference in the estimated CO2 concentrations between 87N-15T and the other two wells. 1) The actual f value is smaller than B for 87N-15T, 2) A portion of the steam produced in aquifer boiling does not enter into well 87N-15T, but escapes through fractures (voiding assumption 4.), or 3) A gas-rich fluid enters into 85N-6T and/or 87N14T from an isolated gas-rich reservoir (voiding assumptions 2. and 3.). The first is very likely. The total discharge

flow of 87N-15T is more than 3 times that of 85N-6T and 87N-14T. On the other hand, the temperature drop of 87N-15T is only around one-tenth that of 85N-6T and 87N-14T. From this observation, the boiling adjacent to 87N15T may be single step steam separation and much more dynamic than in 85N-6T and 87N14T. If so, the actual f value is likely to be smaller than B, as suggested for the BroadlandsOhaaki geothermal system based on mineral fluid equilibria observations (Hedenquist, 1990). This means that the upper range of gas concentration in the diagram is closer to the true reservoir value.

A portion of the steam produced during

aquifer boiling around 87N-15T may actually

migrate to the vicinity of well 84N-2t. The sur

face location of 84N-2t is about 100 m from

87N-15T, and the feed zone of 84N-2t is ASL

800 to 900 m, about 400 m above the main

feed zone of 87N-15T. Because the steam frac

tion of 84N-2t increased after 87N-15T began

discharging, there is a possibility of steam migration from deeper boiling zone of 87N-15T to the shallower entry zone of 84N-2t. Furthermore, there has been a recent development of surface

gas discharges adjacent to the well head of 84N2t. This possibility also favors the higher gas concentration determined from 85N-6T and 87N14T.

If multi-step steam separation occurs for

85N-6T and 87N-14T, and single step steam separation occurs for 87N-15T, the gas concen

tration in steam at the feed zones of 85N-6T and

87N-14T should be much lower than that of

87N-15T because of the difference of net steam

volume generated. However, the actual concen

trations of CO2 in steam at the feed zone are

16.1 wt% for 85N-6T, 8.4 wt% for 87N-14T and

9.5 wt% for 87N-15T. This indicates the

possibility of entry of a gas-rich fluid into 87N14T and 85N-6T. Gas concentrations in steam at

the feed zone are also concordant with the fact

that the calculated CO2 concentration in the

original aquifer for 85N-6T is higher than 87N

14T.

In conclusion, the most reasonable value for the CO2 concentration in the original aquifer of the Chinoikezawa fracture zone is 0.3 to 1.0 wt%. For H2S, a similar calculation results in a range of concentration from 150 to 250 mg/kg. These ranges of concentrations are most likely due to a combination of the three factors mentioned above, though with the higher end of the range most likely.

CONCLUSIONS

A model of boiling composed of two end

member processes is proposed for excess en

thalpy wells, where the excess enthalpy occurs

from excess steam produced by aquifer boiling

around wells due to a discharge-induced pressure

drop.

The first end-member is the "high flow-low

temperature drop type": This process exists in

aquifers with a relatively high permeability. A

large flow rate and small temperature and

pressure drops around geothermal wells are char

120 Y. Seki

acteristic of this process. The gas concentration ratio between the vapor and liquid phases at the downhole feed zone (f) may be smaller than the equilibrium gas distribution coefficient (B), due to single step steam separation under dynamic conditions (i.e. less gas fractionates into the vapor formed during rapid boiling than one would predict from equilibrium conditions). The second endmember is the "low flow-high

temperature drop type" : This is a process ex

isting in aquifers with a relatively low permeabil

ity. A small flow rate and large temperature and

pressure drops are characteristic. Due to

possibility of local changes in the permeability of this type of aquifer, a step-wise temperature and

pressure drops could exist. The net gas concentration ratio between the vapor and liquid phases at

the downhole feed zone is very large, as a result

of gas migration into the vapor phase through

multi-step steam separation.

Gas concentrations, as well as components which stay in the liquid phase, are calculated for the Oku-aizu geothermal system based on the model. The results indicate 0.3 (for 87N-15T assuming f = B) to 1.0 wt% (for 87N-15T assuming f < B and for 85N-6T and 87N-14T) CO2 and 150 (for 87N-15T assuming f = B) to 250 mg / kg

(for 87N-15T assuming f < B and for 85N-6T and 87N-14T) H2S in the original aquifer. Because the f value for 87N-15T is likely to be smaller than B due to the single step steam separation under dynamic conditions, the upper range of

gas concentration may be closer to the true reservoir value. Concentrations of major components other than gas were calculated to be; Cl-: 10600 to 11300 mg/kg, Na+: 5310 to 5500 mg/kg, K+: 1220 to 1540 mg / kg, Ca2+ : 764 to 999 mg / kg and Si02: 464 to 610 mg/kg. The variations can be explained by the difference of reservoir fluid temperature adjacent to each well and the resulting chemical equilibration. In that case, the calculated values for 87N-15T (Cl-: 11300 mg/kg, Na+: 5500 mg/kg, K+: 1540 mg/kg, Ca2+ : 764 mg/kg, Si02: 686 mg / kg) showing the highest geochemical temperature may be closer to the true reservoir value.

The model proposed here is not quantitative,

and needs to be adjusted for conditions existing in each system. However, the model is useful to estimate the chemical composition of original aquifer liquid prior to aquifer boiling and the development of two phase, excess enthalpy conditions resulting from discharge-induced depressurization. This study also points to the dynamic nature of boiling reservoirs (both natural or induced), and problems inherent in determining the gas composition of the reservoir liquid under these conditions.

Acknowledgments-I like to thank the Okuaizu

geochermal Co., Ltd. for granting permission to use analytical and other well data. Helpful discussions

with Dr. J. W. Hedenquist, Dr. Y. Matsuhisa, and

Dr. M. Aoki are gratefully acknowledged. I am great

ly indebted to Dr. O. Matsubaya, Dr. R. B. Glover

and Dr. J. W. Hedenquist for their critical reading of

the manuscript and helpful suggestions.

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