Applications of gas chemistry in evaluating physical processes in the Southern Negros (Palinpinon) geothermal field, Philippines

0375~505/93 $6.00 + 0.IX) Pergamon Press Ltd © 1993 CNR.

Geothermics, Vol. 22, No. 5/6, pp. 535-553, 1993. Printed in Great Britain.

APPLICATIONS OF GAS CHEMISTRY IN EVALUATING PHYSICAL PROCESSES IN THE SOUTHERN NEGROS (PALINPINON) GEOTHERMAL FIELD, PHILIPPINES

F R A N C O D ' A M O R E , * M A Y F L O R N. R A M O S - C A N D E L A R I A , t JOS[~ S. S E A S T R E S J r , ? J O S E L I T O R. R U A Y A ? a n d S E R G I O N U T I * *CNR-International Institute for Geothermal Research, 2, Piazza Solferino, 56126 Pisa, Italy; and +PNOC-Energy Development Corporation, Geothermal Division, Merritt Road, Fort Bonifacio, Makati, Metro Manila, Philippines Abstract--Three major physical processes have occurred in the Palinpinon geothermal system due to

exploitation from 1985 to 1991. They were identified using gas compositions and equilibria involving H2 , H2S, CH 4 and CO 2 to calculate temperature and vapour fraction in the reservoir. The first process is pressure drawdown in the southern part of the field, producing a local increase in the vapour fraction, with the liquid maintaining a high measured temperature, close to 300°C. The second process is vapour loss from an original liquid phase during its ascent through fractures. Wells affected by this process show high degrees of vapour loss (> 10%) when evaluated at the original high temperature of the liquid (290-300°C). But if vapour loss is modelled to occur at much lower temperatures (220-250°C), more realistic vapour losses (1-3 %) are calculated. The last process involves mixing and cooling due to injection fluid returns to wells located in the northeastern part of the field. For some wells the fraction of injected brine in total discharge ranges from 54% to 86% depending on the current injection strategy. Computed and measured temperatures can decline from 290 to 300°C to as low as 215-220°C, corresponding to periods when most of the produced fluids are derived from injected brine. Gas geothermometry gives a more reliable temperature estimate than quartz geothermometry for fluids with high fractions of injected brine, as the gas equilibria reflects the local reservoir temperature. Key words: Philippines, Palinpinon geothermal field, gas chemistry, gas geothermometry.

INTRODUCTION G a s g e o c h e m i s t r y can b e a useful tool for a b e t t e r u n d e r s t a n d i n g o f physical p r o c e s s e s o c c u r r i n g in g e o t h e r m a l r e s e r v o i r s d u e to e x p l o i t a t i o n . T h e t o t a l d i s c h a r g e c o m p o s i t i o n s o f gases f r o m wells of b o t h liquid a n d v a p o u r - d o m i n a t e d s y s t e m s h a v e b e e n u s e d to c a l c u l a t e d e e p t e m p e r a tures a n d v a p o u r fractions in g e o t h e r m a l fluids, a n d to c o r r e l a t e t h e s e with p r e s s u r e d r a w d o w n o r c o o l i n g d u e to e x p l o i t a t i o n ( G i g g e n b a c h , 1980; D ' A m o r e a n d C e l a t i , 1983; D ' A m o r e a n d T r u e s d e l l , 1985; A r n o r s s o n a n d G u n n l a u g s s o n , 1985; D ' A m o r e a n d P r u e s s , 1986; A r n o r s s o n et al., 1990; A r n o r s s o n , 1991; D ' A m o r e , 1991). This p a p e r identifies the m a j o r p r o c e s s e s o c c u r r i n g in t h e P a l i n p i n o n r e s e r v o i r following ten y e a r s of e x p l o i t a t i o n t h r o u g h the a s s e s s m e n t of c h e m i c a l e q u i l i b r i a a m o n g c o m m o n l y m e a s u r e d r e a c t i v e g a s e o u s s p e c i e s (in p a r t i c u l a r H2, H2S, CO2, a n d CH4). T h e S o u t h e r n N e g r o s g e o t h e r m a l field lies at the s o u t h e r n tip o f N e g r o s island (Fig. 1). It consists o f t h r e e sectors, P u h a g a n , N a s u j i - S o g o n g o n a n d B a s l a y - D a u i n . T h e P u h a g a n field has b e e n p r o v i d i n g s t e a m for t h e 112.5 M W e P a l i n p i n o n I g e o t h e r m a l p o w e r p l a n t since J u n e 1983 f r o m its 22 p r o d u c t i o n wells. T e n i n j e c t i o n wells l o c a t e d in t h e i d e n t i f i e d m a j o r outflow r e g i o n n o r t h o r n o r t h e a s t o f t h e p r o d u c t i o n a r e a a c c e p t t h e s e p a r a t e d b r i n e (up to a b o u t 11,000 m g / k g 535

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Applications of Gas Chemistry in Southern Negros, Philippines

537

CI) by gravity flow through two injection lines. Injection at high pressure (average separator pressure of 0.70 MPaabs) started immediately after production. Surface exploration and early development has been summarized by Maunder et al. (1982) and Bromley and Espafiola (1982), while Harper and Jordan (1985) assessed the geochemical changes observed in response to early production and iniection. The injection strategy adopted has been described by Ruaya and Salera (1990). Attempts to trace the flow of injected fluids using radioactive 131I and the organic dye fluorescein have been made by Urbino et al. (1986), while preliminary computer modelling of the field was conducted by Sta. Ana and O'Sullivan (1988). Gerardo et al. (1993) discuss the isotopic characteristics of the reservoir fluids, and the isotopic evidence for returns of injected fluid to the reservoir. The hydrothermal system in Puhagan and Nasuji-Sogongon is a single-phase, neutral pH alkali-C1 water with less than 2.5% by weight gases, consisting mostly of CO2 (92-94% of the total). Waters near the inferred upflow region (south of Puhagan) have a reservoir CI concentration of 4200 mg/kg at a saturated water temperature of up to 330°C as determined from actual measurements and chemical geothermometry (Jordan, 1983). Typical production temperatures, however, are about 280-295°C at near saturation conditions. For most Puhagan wells, different zones contribute to total production, such as a deep zone at high pressure and temperature close to 300°C (in most cases gas-depleted), and a shallow gas-rich zone at much lower pressure and temperature, close to 240°C (Ruaya et al., 1991). From 1983 to October 1989, injection of the brine was confined to the Puhagan sector. During this period rapid return of injected brine to the production wells was observed, based primarily on an assessment of changes in CI concentration (Harper and Jordan, 1985). At the end of 1989, the bulk of injection was transferred farther away from the production area to the TicalaMalaunay sector in an attempt to reduce the return of injected fluids and check thermal decline of the production wells. With the reduced brine injection at Puhagan and increased injection in the Ticala-Malaunay sector, the field-wide returns of injected brine declined substantially. A major mass withdrawal from the field started in October 1990, due to an increase in the demand for steam upon commissioning the Negros-Panay power grid. This resulted in field pressure drawdown and an increase in the discharge enthalpy and gas concentrations of several production wells (Seastres, 1993). Physical and chemical changes due to exploitation (e.g. pressure drawdown, steam loss in addition to injection returns) have been monitored in some Puhagan wells using chemical parameters such as CI, SO4, SiO2, Na, K, Ca, Mg and B in the liquid phase and CO2 and H2S in the vapour phase. However, comparatively little use is made of the gas compositions in monitoring such changes. This paper uses variations in gas compositions up to early 1991 to model the changes due to exploitation affecting production wells in the Puhagan sector. The geochemical model described is highly simplified, due to the very limited amount of information available on the kinetics of the chemical reactions involved. However, it will be demonstrated that, through the application of gas geochemistry, it is possible to correlate easily measurable chemical variables with temperature and vapour fraction in the reservoir. This information is useful in the evaluation of geothermal field performance. THEORETICAL CONSIDERATIONS In geothermal reservoirs such as Palinpinon, which are boiling under natural conditions, a pressure drop caused by the discharge of wells leads to increased boiling in the feed zones. Wells that initially discharge fluid from such reservoirs characteristically have a discharge enthalpy equal to that expected for a saturated liquid phase at its measured temperature. However, upon

538

F. l ) ' A m o r e el al.

continued production the enthalpy often increases (Henley et al., 1984). Arnorsson et al. (199(t) described two processes that can lead to increases in discharge enthalpy. One is separation or partial separation of the flowing liquid and vapour due to their different density and viscosity. causing the vapour to move faster to the well. The other process involves evaporation of thc flowing liquid due to heat gain from the rocks. All gaseous species are assumed to be in internal chemical equilibrium in the reserw)ir. The gaseous compositions used are those measured at the discharge point computed to total discharge composition. The vapour is derived primarily from the reservoir liquid phase (in some cases gas-depleted). However, the chemical equilibria do not apply to the fluid sampled, which is pure vapour, but separately to the vapour and liquid phases in the reservoir, which are assumed to be in phase equilibrium. Therefore, by taking into account the existence of twophase conditions in the geothermal reserwfir and the vapourization of liquid during fluid production, reasonable non-empirical methods can be derived with the use of discharge gas compositions (Giggenbach, 1980; D ' A m o r e and Celati, 1983; D ' A m o r e and Truesdell, 1985). This understanding helps to elucidate physical conditions in the reservoir. The fluids stored in a geothermal reserw~ir are commonly present as a liquid together with minor fractions of a co-existing vapour phase at equilibrium conditions (Truesdell et al., 1984. 1989; D ' A m o r e and Pruess, 1986). In most high temperature geothermal systems, fluid boils during its ascent to the surface. If the system is open to fumaroles or connected in the formation to nearby wells, some vapour can be lost locally before the fluid reaches the wellhead (Truesdell, 1991). The in-situ vapour fraction (y) of the reservoir, in equilibrium with the liquid (positive values) or irreversibly lost at a given temperature from the original liquid (negative values), at equilibrium is defined as: y = nv/(nv + n0

(1)

where n represents the number of moles steam (nv) and liquid water (n0, contained in a given volume of rock. This would suggest that y provides a measure of the average vapour fraction formed in the limited part of the reservoir feeding the single well. Giggenbach (1987) noted that most of the methods used to evaluate reservoir parameters involve several gaseous, aqueous and mineral species and are based on the generally unproven assumption that the collected gas samples still contain all gaseous species in the proportions representative of those present in the reservoir. This is an important limitation to the practical use of reactive gas species to reservoir engineering. Starting from the method and theoretical equations given in Giggenbach (1980), the use of numerical gas methods in the calculations of reservoir vapour fraction and temperatures to verify reservoir performance has been amply demonstrated (Henley et al., 1984; D ' A m o r e and Truesdell, 1985; D ' A m o r e , 1991). The final equations presented in this paper are modified from these previous works. Essentially, the method is based on three gas-gas or gas-mineral chemical reactions at conditions of thermodynamic equilibrium: CH 4 + 2 H 2 0 = 4H 2 + CO:

FT

(2)

H: + 3/2FeSe + 2 H 2 0 = 3H2S + 1/2Fe304

HSH

(3)

NH3 = 1/2N: + 3/2H2

HN

(4)

Using the mass action law, suitable equations at equilibrium conditions involving the partial pressures of each gas species can be derived as functions of the concentrations at the discharge point, temperature, the distribution coefficient B i between the vapour and liquid phases, and the vapour fraction y. For equations 2, 3 and 4 these are given by the following expressions:

A p p l i c a t i o n s o f Gas C h e m i s t r y in Southern Negros, Philippines

539

H S H d = 31og(HzS/H20)d - l o g ( H z / H z O ) d

(5) (6)

H N d = 1/21og(Nz/HzO)d + 3/21og(Hz/H20)d - l o g ( N H 3 / H 2 0 ) d

(7)

FT~ = 41og(H2/H20)d - l o g ( C H J C O 2 ) d

w h e r e ( i / H 2 0 ) j is the m o l a r r a t i o m e a s u r e d at t h e total d i s c h a r g e p o i n t "d". T h e following e q u a t i o n s w e r e u s e d for p o s i t i v e o r n e g a t i v e y v a l u e s to link the c h e m i c a l with the physical p a r a m e t e r s in the r e s e r v o i r : for y > 0: F F d = - 1 5 . 3 5 - 3952.8/T ° + 4.6351ogT ° + 41ogLv° + (1 - y°)/B~,j + log[y ° + (1 - Y°)/B~o2] - log[y ° + (1 - y°)/B~n,]

(8)

H S H d = 6.449 - 6149.7/T ° - 0.4121ogT ° + 31og[y ° + (1 - y°)/B~,s] - Iog[y ° + (1 - y ° ) / B ~ ]

(9)

H N d = 0.39 - 652/T ° + 1/21og[y ° + (1 - y°)/B~,j + 3/210g[y ° + (1 -y°)/B~t2]

-

-

log[y ° + (1 - y°)/B~n~]

(10)

for y < 0: F F d = - 1 5 . 3 5 - 3952.8/T ° + 4 . 6 3 5 1 o g t ° - 41ogB~2 - logB~o2 + logB~H~ - 4log(1 + y - yBH2 ) - log(1 + y - y B c o , ) + log(1 + y - yBcH~)

(11)

H S H d = 6.449 - 6149.7/T ° - 0.4121ogT ° - 3 1 o g B ~ s + logB~_, - 3log(1 + y - y B H , s ) + log(1 + y - yBH._)

(12)

HN~ = 0.39 - 652/T ° - 1 / 2 B ~ - 3/2B~2 + B ~ . , - 1/21og(1 + y - yBN2) + 3/21og(1 + y - yBH,) + log(1 + y - yBNH~)

(13)

T h e left side o f the e q u a t i o n s a r e m e a s u r a b l e c h e m i c a l p a r a m e t e r s while t h e right side refers to physical v a r i a b l e s such as t e m p e r a t u r e a n d v a p o u r fraction in t h e r e s e r v o i r . F o r n e g a t i v e y v a l u e s t h e d i s t r i b u t i o n coefficients b e t w e e n v a p o u r a n d liquid (B~ a r e t h e c a l c u l a t e d v a l u e s at the o r i g i n a l c h e m i c a l e q u i l i b r i u m t e m p e r a t u r e T ' , while B i refers to the v a l u e s at the t e m p e r a t u r e T w h e n v a p o u r losses occur. B~ v a l u e s at d i f f e r e n t t e m p e r a t u r e s are a v a i l a b l e in D ' A m o r e a n d T r u e s d e l l (1988). T h e a p p r o x i m a t i o n o f T ° = T, t h a t is, at i s o t h e r m a l c o n d i t i o n s o f v a p o u r loss (e.g. u s e d by G i g g e n b a c h , 1980 o r by D ' A m o r e a n d T r u e s d e l l , 1985) can result in c a l c u l a t i o n s o f e x t r e m e l y high a n d unrealistic v a p o u r losses, n o t c o n s i s t e n t with the local fluid production.

APPLICATIONS

AT PALINPINON

U s i n g t h e m e a s u r e d c h e m i c a l p a r a m e t e r s c o r r e c t e d to total d i s c h a r g e ( e q u a t i o n s 5 a n d 6) a n d t h e r e l a t e d e q u a t i o n s , which a r e functions o f t e m p e r a t u r e a n d y ( e q u a t i o n s 8, 9, 11 a n d 12 with T ° = T), an F T - H S H d i a g r a m is g e n e r a t e d as in D ' A m o r e a n d T r u e s d e l l (1985). U s i n g the gas d a t a ( T a b l e 1) o f s o m e wells in the P u h a g a n s e c t o r of t h e field, F F ~ a n d H S H d v a l u e s w e r e c a l c u l a t e d a n d p l o t t e d in Fig. 2. B o t h c o m p u t e d t e m p e r a t u r e s a n d s t e a m fractions a r e q u i t e v a r i a b l e , a n d d o n o t p r o v i d e m u c h i n f o r m a t i o n in c h a r a c t e r i z i n g t h e b e h a v i o u r of e a c h well. This is t h e m a i n r e a s o n w h y wells o f the field p r e s e n t i n g typical b e h a v i o u r s h a v e b e e n c h o s e n to c o r r e l a t e t h e i r physical p e r f o r m a n c e with t i m e as a f u n c t i o n o f gas c o m p o s i t i o n s .

F. D ' A m o r e c! al.

540

l a N e 1. Gas composition in total discharge ( m m o l / m o l ) , maximum tcmpcraturc mcasurcd at wcll b o t t o m , w e l l h e a d a b s o l u t e pressure ( W H P ) and cnthalpy (H) for sclected wclls of P a l i n p i n o n g c o t h c r m a l fickt

n

Wcll

1 2 3 4 5 ¢~ 7 8 9

OK5 OKIOD PN20D PN30D PN31D PN24D OK7 PN28 PN32D

/(max)

WHP

H

Date

(X')

(MPaa)

(kJ/kg)

C()~

H~S

H~

Cf|,

N~

NH~

03 Sep 91) 04Scp90 12 Mar 91 27 Jan 9(I 05 Sep 9(1 09 M a r 91 19 A p r 911 02 Jan 91) 08 A u g 9I

310 27O 324 3115 322 316 318 303 270

3.69 0.80 0.71 2.67 1.02 11.83 I).68 1.44 0.88

21125 1552 231~3 1544 1875 1585 1350 t2113 2524

24.5 15.3 45. I I9.7 2(~.3 24.4 0.92 0.92 45.0

146.1 0.8 1.7 ().8 1.05 11.9 ().4 [). I 1.5

14.2 0. I 0.2 0.i13 0.1 11.06 0.05 0.004 0.2

0.02 11.2 0.118 O118 0.1 0.1 0. I 0.(1(, 0.2

{1. I 11.3 0.(18 11.1 0. ! 0. I 11.114 (1.03 0.2

0.1 0. I 0.2 (I.I O.2 0.1 !L I 0. I --

Some wells show quite stable chemistry and performance with time (e.g. CI, mass flow, Tand P) despite exploitation of the Puhagan field. One good example is OK-5, which is a high enthalpy well located southwest of the main upflow zone. It has a recorded maximum downhole temperature of 310°C, while the Na-K-Ca geothermometer has consistently recorded high temperature estimates of about 300°C. FTd and HSHd values for OK-5 produced a cluster of points (Fig. 2) with equilibration temperatures in the range 300-310°C and indicating a single-phase liquid reservoir, y = 0. The clustering of data points from 1985 to 1991 indicates that OK-5 draws fluid from an undisturbed

It.

-12

-11

-10

-9

-8

-7

-6

-.5

HSH Fig. 2. F T - H S H grid diagram for gas composition of wells from T a b l c 1 (circles). Values for OK-5 (triangles) arc also shown based on data from 1985 to 1991.

Applications of Gas Chemistry in Southern Negros, Philippines

541

liquid reservoir, which until the present remains unaffected by exploitation of the field. This is usually o b s e r v e d for wells located west of P u h a g a n , near the b o r d e r of the still unexploited N a s u j i - S o g o n g o n sector of the field, which is in the final stages of p r e p a r a t i o n to provide steam for an 80 M W e p o w e r d e v e l o p m e n t , to be c o m m i s s i o n e d in early 1994. In most cases, observed chemical variations from ideal equilibrium b e h a v i o u r in pure liquid, b r o u g h t about by exploitation of the P u h a g a n field, have been attributed to different physical processes. T h e wells selected in this p a p e r are representative of groups showing similar peculiar time variations, both in chemical and physical characteristics. VAPOUR

ADDITION

TO AN ORIGINAL LIQUID DUE TO PRESSURE DRAWDOWN

D u r i n g exploitation, several wells s h o w e d increases in gas c o n t e n t and discharge enthalpies ( > 2 0 0 0 kJ/kg). T h e s e wells have a relatively low c o m p o n e n t of injected brine (less than 30%) and are located south of P u h a g a n within the PN-20D sector (such as wells P N - 2 7 D , -9D, -13D and -10D). Well P N - 2 0 D , which is located within the hottest part of the system close to L a g u n a o D o m e (Fig. 1), has been selected as one of the most representative of this group. Its chemical b e h a v i o u r has b e e n described briefly in a n o t h e r p a p e r ( R u a y a et al., 1991). T h e m a x i m u m m e a s u r e d t e m p e r a t u r e at well b o t t o m is 329°C. Table 2 presents a selection of the most representative gas analyses b e t w e e n 1986 and 1992. T h e c o m p u t e d F T and H S H values (from Table 2) are plotted in Fig. 3. Well P N - 2 0 D starts with slightly negative values o f y (-> - 0 . 0 0 8 ) during a period of high wellhead pressure and low m o n t h l y cumulative mass withdrawal of about 20,000 tons. The gas composition suggests little v a p o u r loss in the deep reservoir water. With time there is a significant increase in v a p o u r fraction, a p p r o a c h i n g 0.015 in 1991 at a m o n t h l y cumulative mass withdrawal between 40,000 and 90,000 tons. T h e gas equilibrium t e m p e r a t u r e s d e t e r m i n e d f r o m the diagram are quite high, between 287 and 306°C. M o r e o v e r , the lowest t e m p e r a t u r e s are o b s e r v e d along the y = 0 line for the period 1988-89, when the a m o u n t of injected brine in the P u h a g a n sector was high. A t the end of 1989, injection was shifted to the T i c a l a - M a l a u n a y sector and injection was substantially r e d u c e d at Puhagan. A possible explanation for the o b s e r v e d trends in gas composition m a y involve two c o n t e m p o r a n e o u s processes. T h e first process affecting fluid composition seems to involve a Table 2. Selected gas compositions (mmol/mol) in total discharge, wellhead absolute pressure (WHP), enthalpy (H) and chloride total discharge (CITD) content for well PN-20D. n

Date

1 2 3 4 5 6 7 8 9 10 11 12

23 Oct 86 19 Feb 87 11 Jun 87 02Sep87 29 Sep 87 16 Mar 88 23 Aug 89 05 Ju[ 90 04Sep90 05 Nov 90 04 Feb 91 12 Mar 92

WHP H C1TD (MPaa) (kJ/kg) (mg/kg) CO 2 1.00 1.06 0.73 1.18 1.16 2.47 0.77 0.71 0.80 0.74 0.74 0.71

2096 2010 2020 2402 2402 1760 2107 1780 1780 2395 2393 2393

2559 2056 2494 1920 2027 4319 3863 5055 4960 1924 1633 994

35.8 26.1 25.7 29.0 24.0 20.5 26.7 23.5 29.2 32.6 37.6 45.1

H2S

0.09 1.0 1.0 1.1 0.9 0.6 0.8 0.7 1.0 1.2 1.3 1.7

H2

CH 4

N2

NH 3

0.05 0.05 0.06 0.10 0.06 0.05 0.08 0.07 0.l 0.1 0.2 0.3

0.12 0.04 0.02 0.02 0.01 0.02 0.1 0.03 0.06 0.03 0.06 0.08

0.2 0.09 0.04 0.1 0.04 0.09 0.03 0.2 0.1 0.06 0.1 0.08

0.2 0.2 0.2 0.3 0.2 0.1 0.2 0.2 0.2 0.2 0.2 0.2

542

F. l ) ' A m o r e et al. WELL PN-20D -12

- -

~2

zTo

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. . . .

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310"C

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-22

-24

-26

- 8.0

-7.5

-7.0

- 6.5

- 6.0

HSH Fig. 3. FT-HSH grid diagram for well PN-20D from gas compositions of Table 2.

moderate amount of injected brine recovered in this area. For example, in 1988 (Table 2, sample 6) the fraction of injected water was calculated to be about 30% at 295°C. In July 1990 (sample 8) the computed fraction declined to about 20% at the same calculated temperature. Because of the localized high heat flow in this zone, injection produces a maximum cooling of only 15°C (from 300°C to 285°C) in contrast to the central Puhagan wells (e.g. PN-26, where cooling from 280°C to 220°C occurred based on gas contents). The second process affecting the gas trends may be the drawdown of liquid in the reservoir. The following changes occurred in PN-20D, from 1990 to the first months of 1991, at constant wellhead pressure of about 0.7 MPa abs: the enthalpy increased from about 1800 to about 2400 kJ/kg while the monthly cumulative mass withdrawal decreased from about 90,000 tons to less than 20,000 tons. From 1990 to 1991, the shut-in pressure of monitoring well PN-25D decline<.! from about 9 to about 6 MPa abs, supporting the idea of drawdown in the Puhagan sector. Initially, well PN-20D was producing from two permeable zones located at about 1730-1937 m and 1215-1391 m (all depths reported here refer to vertical depth unless specified). With time, anhydrite deposited between these two production zones and blocked fluid contribution from the lower permeable zone, which had y values close to zero. The observed increase of the computed temperature can be due to the large increase in U2S concentrations. The increase in the computed steam fraction from 1988 to 1990 may be due to pressure drawdown at relatively constant reservoir temperature during massive field exploitation. This depressurization induced the inflow of acidic fluids, which enhanced anhydrite deposition. The y value is positive because steam in phase equilibrium within the local reservoir is formed in a closed system. The effect of this process is a decline in production due to decrease in liquid volume in the local reservoir, probably due to relatively low permeability. It is, therefore, recommended that injection fluids be introduced in this sector. In Puhagan acidic fluids are present in the upper shallow layer where steam condenses into

Applications of Gas Chemistry in Southern Negros, Philippines

543

local g r o u n d w a t e r . These can f o r m shallow, oxidizing waters with low p H , H2 and chloride but high contents of sulfate. Pressure d r a w d o w n in the reservoir can induce the percolation of these acid waters t h r o u g h structures to m u c h d e e p e r levels. These fluids were detected in the discharge of L G - 1 D , which was drilled to a m u c h shallower depth (total depth 1651.74 m or - 6 9 5 m b.s.l.) relative to o t h e r P u h a g a n wells. T h e total discharge composition has low p H ( 4 5), low chloride ( < 1000 mg/kg) and high sulfate ( > 200 mg/kg) in the liquid fraction. WELLS AFFECTED

BY VAPOUR

LOSSES

In the s o u t h e r n portion of P u h a g a n , some wells (e.g. P N - 2 3 D , P N - 2 7 D , P N - 3 0 D , P N - 3 1 D ) show negative values of y, based on F T and H S H chemical parameters, when they have a high wellhead pressure ( W H P ) . T h e y have a high W H P while shut-in, by-passed, or on-bleed and a low W H P after shut-in. Well P N - 3 0 D was selected to be e x a m i n e d because of the large n u m b e r of gas data available. T h e m a x i m u m t e m p e r a t u r e m e a s u r e d at well b o t t o m is 305°C. Its relatively constant chloride concentration (on average about 4100 + 400 mg/kg) and enthalpy (1400-1600 kJ/kg) indicate little influence from injected fluids. Selected gas analyses available during the period from 1985 to 1990 (Table 3) are plotted in Fig. 4. T h e position of the points show a quite high variability in y values from about zero to - 0 . 1 , while the c o m p u t e d t e m p e r a t u r e s are relatively constant b e t w e e n 280 and 295°C. T h e pre-exploitation m e a s u r e d t e m p e r a t u r e s at the main entries were a b o u t 250-260°C at 1340-1440 m and about 300°C at 2770-2865 m. T h e original fluid composition for well P N - 3 0 D prior to any v a p o u r loss can be estimated by averaging the data for the periods of m a x i m u m H 2 contents at high flow rates, during S e p t e m b e r - D e c e m b e r 1985 (Period A), O c t o b e r - D e c e m b e r 1986 (Period B) and J u n e O c t o b e r 1990 (Period C), as shown in Fig. 4. A v e r a g e values of gas composition (in mole per mole of water) t o g e t h e r with C1 c o n c e n t r a t i o n (in mg/kg) in total discharge ( T D ) , e n t h a l p y (in kJ/kg) and wellhead pressures (in M P a abs) are r e p o r t e d in Table 4. T h e c o m p u t e d t e m p e r a t u r e s and values of y at high flow rates are also reported. T h e y are derived from the values of the F T and H S H p a r a m e t e r s (Fig. 4). T h e value o f y is on the average Table 3. Selected gas compositions (mmol/mol) in total discharge and wellhead absolute pressure (WHP), enthalpy (H) and chloride total discharge (CITD)content for well PN-30D n 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

Date 12 Jan 85 27Apr85 08 Aug 85 18 Oct 85 17 Nov 85 22Feb86 15 Jun 86 12Ju186 17 Oct 86 20Apr 87 15Ju187 21 Jan 88 09Jun89 11Nov89 17 Mar 90 28Jun 90 24 Oct 90

WHP H CITD (MPa abs) (kJ/kg) (mg/kg) CO2 H2S H2 CH4 N2 NH3 1.01 2.40 1.87 1.75 1.84 2.03 1.80 1.89 1.83 2.71 2.59 2.89 3.00 2.78 3.19 1.29 1.44

1600 1235 1580 1620 1605 1475 1530 1520 1755 1400 1600 1541 1560 1521 1449 1585 1580

3520 4718 3822 3650 3684 4384 4321 4301 3610 4602 3965 4249 4095 4468 4638 3782 4158

29.2 10.7 23.4 25.8 26.9 16.4 16.1 17.9 25.5 15.8 22.1 25.3 21.8 17.3 19.8 20.1 19.0

0.9 0.4 0.8 0.9 0.8 0.7 0.6 0.7 0.9 0.6 0.9 0.9 0.7 0.6 0.7 0.8 0.8

0.07 0.02 0.06 0.08 0.1 0.02 0.04 0.05 0.1 0.02 0.05 0.06 0.03 0.03 0.05 0.I 0.1

0.I 0.05 0.09 0.1 0.1 0.07 0.8 0.08 0.1 0.07 0.1 0.1 0.04 0.08 0.1 0.07 0.07

0.1 0.07 0.2 0.2 0.2 0.1 0.1 0.1 0.2 0.1 0.1 0.2 0.06 0.1 0.1 0.1 0.1

0.1 0.04 0.08 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

544

F. l)'/t.tore et al. WELL

-12

PN- 30D

290 270

300

510 °C

280 -0"

-14

0.05

~-/* / /

/ 0.02

,

-16

o.ol -. 0.005

-0005 •, - o . o l

-0.02

\

-18

I-I.k

8,

/-0.05 ~-o.1

-20 - - 0 2

/ f

-22

f

~-

-24

-26

-8

I

-7

1

-6

HSH Fig. 4. F T - H S H grid diagram for well PN-30D from gas compositions of Table 3. For A. B and C. refer to Table 4.

equal to zero; that is, the fluid is nearly pure liquid at a temperature close to 290°C. Temperatures for samples A, B and C using the ammonia dissociation reaction are 278°C, 280°C and 290°C, respectively, calculated at y = 0. Therefore, ammonia also seems to be equilibrated with H2 under high flow-rate conditions. Using the grid diagram, the vapour is assumed to separate from the residual liquid at the reservoir temperature. This produces very negative and unrealistic values of y. To illustrate, at 290°C a y of -0.01 (which means 10% by weight of the original liquid is converted to vapour) corresponds to volumetric steam loss of around 65% from the original reservoir liquid (Fig. 5). This is not consistent with the high production flow rates after shut-in. Volumetric liquid saturation (S 0 is a function of), and the specific volumes of steam and water (V~ and V,,), defined as:

S, = (1 - y)V,,,/[(1 - y) V,, + yV~]

(14)

A more realistic alternative is that vapour loss occurs at a lower temperature than the original Table 4. Gas composition (mmol/mol), chloride content in total discharge (CITD), enthalpy (H) and wellhead absolute pressure (WHP) for well PN-30D; computed values o f y and temperature from Fig. 4; n is the number of gas samples used in the given period (see text) Period

n

CO~

HxS

NH 3

H~

CH4

N,

A B C

5 5

24.7 _+ 2.1 25.4 _+ 1.1 21.9 ± 2.2

0.85 ± 0.06 I).926 ± 0.066 0.870 ± 0.073

0.096 + 0.1117 0.106 + 0.(1119 0.095 _+ 0.019

0.080 ± (t.014 0.096 ± 0.006 (). 110 ± 0.007

0.110 ± I).1116 0.108 ± 0.010 0.102 + 0.035

0. 189 ± 0.1t39 0. 172 _+ 0./138 0. 159 ± 11.I154

A B ("

8 5 5

Cl,iD(mg/kg ) 3676 + 79 3682 ± 87 4105 ± 308

H (kJ/kg) 1604 ± 14 1692 ± 87 1614 ± 42

WHP (MPa abs) 1.80 ± 0.114 1.73 ± 0.29 1.40 ± 0.12

y -0,001 0 +0.0(11

t(°C) 288 291 287

Applications of Gas Chemistry in Southern Negros, Philippines

545

100 !

8O

o

'

10

'

20

30

'

4'o

'

Percentmolarsteam saturation(y %) Fig. 5. Volumetric liquid saturation Sl(°/,,) computed as a function of vapour fraction y (%) at selected tempcraturcs.

reservoir t e m p e r a t u r e . A m e t h o d b a s e d o n gas c o n c e n t r a t i o n s ( e q u a t i o n s 11,12 and 13) is used to calculate the original t e m p e r a t u r e ( T °) of the reservoir before boiling, the t e m p e r a t u r e (T) at which the v a p o u r separates, a n d the c o r r e s p o n d i n g a m o u n t of v a p o u r lost. T h e r m o d y n a m i c data used are listed in T a b l e 5. T w o e x a m p l e s are given here to illustrate the m e t h o d for e x t r e m e c o n d i t i o n s of very negative values of y: gas samples 6 ( F e b r u a r y 1986) a n d 10 (April 1987) of T a b l e 3 for well PN-30D. Both s a m p l e s were t a k e n at very high w e l l h e a d pressures. T h e s e samples indicate t e m p e r a t u r e s of 295°C a n d 300°C, respectively, c o r r e s p o n d i n g to y values of - 0 . 0 6 a n d - 0 . 1 0 (Fig. 4). A n initial reservoir t e m p e r a t u r e 7~ = 290°C is used for y = 0, resulting in calculated values of Fq" -- - 17.65 a n d H S H = - 7 . 0 9 . F o r s a m p l e 6 the analytical values of F T a n d H S H result in c o m p u t e d values of T = 242°C a n d y = - 0 . 0 2 . F o r s a m p l e 10, c o n d i t i o n s at s e p a r a t i o n are T = 240°C a n d y = - 0 . 0 2 5 . Starting at an initial reservoir t e m p e r a t u r e 7~ = 290°C, a small p e r c e n t a g e of v a p o u r lost at lower t e m p e r a t u r e s will d e p l e t e the residual fluid of large a m o u n t s of gas, with each gas r e m o v e d from the liquid phase as a f u n c t i o n of its solubility.

Table 5. Values of distribution coefficients B i and FT, HSH, HN values for y = 0 at selected temperatures. t (°C) B(-o, B,~:s BH2 B(,H4 BN2 BNH, 200 210 22(1 230 240 250 260 270 280 290 300 310 320

375 292 227 176 137 106 83 64 50 39 31 23 18

12l 96 77 61 49 39 31 25 20 16 13 10 8

21115 1484 11193 805 593 436 321 237 183 134 96 68 47

2006 1458 1060 770 5611 407 296 215 160 117 85 62 45

3920 2856 2081 1516 1104 805 586 427 319 226 168 120 88

6.29 5.73 5.23 4.77 4.34 3.96 3.61 3.29 3.00 2.74 2.49 2.27 2.117

FF

HSH

-23.80 -10.60 -23.08 -10.17 -22.37 -9.76 -21.67 -9.35 -20.97 -8.95 -20.28 -8.57 -19.60 -8.19 -18.93 -7.82 -18.33 -7.44 -17.65 -7.09 -16.96 -6.78 --16.21 -6.41 -15.45 -6.12

HN -6.94 -6.69 -6.43 -6.18 -5.92 -5.67 -5.42 -5.17 -4.96 -4.70 -4.56 -4.15 -3.87

546

F. D ' A m o r e et al.

WELLS A F F E C T E D BY INJECTED BRINE Most wells located in the northeastern part of the field have been strongly affected by returns of brine injected in the Puhagan sector. Rapid injection returns (from one day to almost l~.o weeks), as traced by sodium fluorescein and 1311 (Urbino et al., 1986), did not allow effective reheating of the brine and have resulted in severe thermal decline of some production wells (e.g. PN-26, PN-28, PN- 19D, PN-21 D, O K-7) receiving massive amounts of injected brine (Seastrcs, 1993). Using CI and simple mass balance considerations, Harper and Jordan (1985) were able to identify wells affected by injected brine and to approximately quantify its fraction in the discharge. But a simplistic application of the CI technique has problems, since not all increases in salinity are necessarily related to injection. For instance, extensive boiling, natural recharge and continuous injection of highly saline brine (up to about 1 1,000 mg/kg CI), can contribute to the higher salinity of the total discharge. In addition, temperature decline in some wells (e.g. PN-26) was so severe that the measured temperature differed substantially from the calculated silica (quartz) temperature (Fig. 6), indicating that quartz solubility no longer controls the equilibrium concentration of silica (Seastres, 1993). Gas chemistry, however, may prove useful in monitoring injection returns, by providing more realistic temperature estimates, and in quantifying the fraction of injected brine in the total discharge. In this section we compute the fraction of injected water (X) contributing to the discharge of the well, and determine the equilibration temperature in the reservoir (70) by using discharge gas compositions. The methodology and the equations involved in the above calculations are described in the Appendix. We consider 70, at the beginning of exploitation, to be the original measured temperature. Computation of 70 in the early years of exploitation should be close to the original measured values. With time the main geothermal reservoir will cool as a result of extraction of hot fluid and input of relatively cool injected brine and/or marginal waters. As a consequence the calculated 7 ° may decrease with time. For the portion of the reservoir feeding the study wells, equilibration temperatures may start from as high as 290°C but decrease with time to 260°C and in some cases to as low as 240°C. Well PN-28 has been considered as a typical example. Table 6 reports selected gas compositions and physical data at the wellhead. The grid diagram representing these data is presented in Fig. 7. The point representing the initial condition y -< 0 (July 1983) is based on the analytical data of the adjacent well PN-26, since gas data for PN-28 at an undisturbed condition are not 3OO

~ n~ 1,1

l

T('quartz

)

i

I

I

!

!

II I

290

280

4 ...... t

Q. 27O 260 250

,4

W i

24.0

230 220

Fig. 6. Diffcrcnces in measured (dots) and Tgu,r, z (line) temperatures of PN-26.

Applications of Gas Chemistry in Southern Negros, Philippines

547

-16

-20

I-u_ - Z 2

-24

-26

-~, -11.0

-IOD

- 9.0

-IB .0

-'7.0

6.0

HSH Fig. 7. FT-HSH grid diagram for well PN-28 from gas data in Table 6.

available. An initial temperature close to 280°C is estimated for a pure liquid, consistent with the temperature calculated from the SiO 2 content. Based on computed y values, this well is little affected by vapour loss (y > -0.01). The temperature computed from the grid (Tg) indicates that returns of the injected brine progressively cooled the fluids to 215°C (from point 1 to point 14) until October 1989, during which time brine injection was confined to the Puhagan sector. This trend is consistent with the progressive increase in CI concentration and discharge enthalpy decline with time (Table 6). When the bulk of the injected brine was shifted to the TicalaMalaunay sector, a recovery in calculated temperature, Tg, was observed, up to about 250°C. For well PN-28, Table 6 shows the computed values of 7~ and X for selected examples, with the Tg and y values from Fig. 7 and the Ts used for calculations when y is less than -0.001. Figure 8 reports the values of ~ , X, Tg and the total discharge CI concentration with time. The computed 7~ is different from Tg. T ~ represents the theoretical temperature in the fractured medium where the fluid is in equilibrium with the rock. It is a function of the balance between the heat lost because of the inflow of injected brine and the heat supplied by the local rocks in that particular portion of the reservoir. The Tg value approaches the actual measured temperature after mixing. This fluid might not be in complete chemical equilibrium because of the high local permeability, as indicated by the fast return of the injected brine. For this reason Tg is usually less than 7". CONCLUSIONS The Puhagan sector of the Southern Negros geothermal field shows a large variability of gas composition between wells and over time. This may be due to three main physical processes that affect the fluids stored in the deep reservoir. The first possibility is local pressure drawdown of the original reservoir fluid feeding

548

F. D 24more ct al. ] a b l e 6. Selected gas compositions (mmol/mol) in total dischargc and wcllhcad absolutc pressure (WHP), cnthalpy (H) and chloride in total discharge {('liD) lot wcll PN-28. All gas data for July 1983 arc based on adiaccnt wcll PN-26, since gas data Ior PN-28 at an undisturbed condition arc not a,,ailablc.

n 0 1 2 3 4 5 6 7 8 9 I(I 11 12 13 14 15 16 17 18

WHP (MPaabs)

l)atc Jul 83 07 Feb 85 27 May 85 11 Nov 85 t4Jan 86 08 May 86 09 Oct 86 I1 Jan 87 09 Mar 87 28 Jul 87 27 M a r 89 16 May 89 12 Aug 89 02 Scp 89 23 Oct 89 22 Jan 90 05 N{}v 90 II Jan91 04 Nov 91

tl ('lid (kJ/kg) (mg/kg) (7()~ 5000 6404 6480 7823 7674 7627 7669 7581 7649 7501 9505 10095 l(10(t7 I0080

15.0 6.1 8.5 2.4 3.(I 3.I 2.0 3.7 4.5 2.7 2.3 1.8 1.9

t428

FI,

CH 4

N,

NH~

O.h (I.2 0.2 0.1 0.09 0.08 0.08 (t.l 0.1 0.08 0.()6 0.05 0.04 (}.04

0.1 1}.()1 0.01 0.006 (-).01 0.000 ll.0(}4 0.007 0.02 0.004 0.002 0.002 (l.002 (}.003

0.2 0.05 0.03 0.01 0.02 0.l)4 0.02 0.05 0.05 0.05 (1.02 0.02 0.02 0.(}2

. . . 0.04 0.(15 0.01 0.02 0.03 0.02 0.05 0.03 0.02 0.01 0.1 0.01 0.02

. 0.07 0.05 0.04 0.04 0.05 0.05 (L06 4).07 0.(}6 0.04 (L()4 (}.05 0.(}5

1.27 2.2~ 2.32 2. I t) 2. I9 2.37 158 1.88 1.57 1.62 1.78 1.21 1.51 1.51

1220 1315 1180 1200 1176 1210 1230 125(t 125(l 1250 113(1 1(16(/ 1123 II23

1.45

12(}3 1{}125

2.2 2.7

{}.{)4 (}.{}(}4 {).(}2 {l.{)2 {}.05

1.44 1.58 1.54 0.9I

1203 1078 I(}78 Iit0

6.(} 2.9 3.2 6.0

0.2 (}.(}{}4 0.06 0.1 0.(}1 ().H4 (}.I 0.{}1 0.(}3 {}.2 0.02 0.{}4

8193 8{}74 8902 7206

(}.03 {}.02 (}.01 0.1

().{}6 0.07 ().04 {}.06

individual wells. This process p r o d u c e s a local increase in the vapour fraction, with the liquid maintaining a high m e a s u r e d t e m p e r a t u r e (close to 300°C). This is also shown by higher values of discharge enthalpy ( > 2000 kJ/kg) with lower pressures and a l m o s t stable CI concentration. L o w local p e r m e a b i l i t y is the main factor increasing pressure d r a w d o w n , H o w e v e r , considering 300

90

280-

80-

•

•

oo

260-

70X

•

60-

24O-

290 -

5O

12,000 270 A 250-

g,

_

8po~

oeoOO •

230-

.;. o,:

5 6,000-

"It,

" "

• • ••

21084

85

86

87

YEAR

88

89

90

91

198B

84

85

86

87

88

89

90

91

YEAR

Fig. 8. Different parameters reported for selected samples of well PN-28 vs time: CI concentration in total discharge (TD); temperature, T~, computed from thc grid (Fig. 7), computed values of water-rock equilibrium, 7~, and percentage of recovered brine (X%).

Applications of Gas Chemistry in Southern Negros, Philippines

549

Table 7. C o m p u t e d fraction of recovered injected brine X (%) at the equilibration temperature T ° for selected samples of well PN-28. Tg and y values are from Fig. 7 n 1 4 8 9 11 14 16 18

Date Feb 85 Jan 86 Mar 87 Jul 87 May 89 Oct 89 Nov 90 Nov 91

7 ~(°C) X g ( % ) 280 275 275 270 265 255 260 270

67 80 76 76 82 86 65 54

Tg(°C)

y

255 235 242 235 225 215 243 253

-0.005 0.00 >-0.001 -0.ll07 - 0.(108 >-0.001 >-0.001 0.002

recent unpublished data for 1991-93, drawdown seems to induce the inflow of acidic fluids. The origin of the acidic fluids may be a shallow vapour condensation zone mixed with oxygenated groundwater. A decrease in pH, increased sulphate and H2S concentrations as well as decreased H 2 content have been recently observed in some wells affected by drawdown. Thus, in the southern sector of the field (close to the Lagunao dome), waste brine should be injected to increase reservoir pressure in an attempt to decrease the drawdown and to buffer the action of the acidic fluid. The second process is vapour loss from the original liquid at high temperature (290-300°C) when the W H P is very high or after the well has been shut-in. In a given reservoir volume with high local permeability adjacent to a well, the original liquid at high pressure and temperature ascends through fractures during periods of low production. This flow is due to the pressure differential caused by periods of high production from adjacent wells at low W H P condition. The original liquid boils at lower temperatures (e.g. 220-250°C), losing vapour (from 1 to about 3% by mass). The different gas species (H2, CO2, H2S, NH3) are affected in decreasing order as expected from their differential solubilities. The final process is cooling due to injection of brine separated at saturated pressures corresponding to 165-170°C. The return of injected brine is a function of the local fracture permeability linking the injection and production wells. This return results in local mixing and cooling in the fractured reservoir. Production wells located in the northeastern part of the field were greatly affected by returns of injected fluid (up to 80% during some periods for well PN28). The temperature of the local fluid, which affects gas re-equilibration, declined from 290300°C to as low as 215-220°C in the upper permeable zone. The lowest temperatures calculated from gas compositions are close to the measured temperatures in wells where most of the produced fluid consisted of injected brine. Using the simple model based on the grid diagram as shown in Fig. 9, where chemical parameters are related to the values of vapour fraction (positive or negative) and temperature, gas geochemistry appears to offer, despite some limitations, valuable tools to delineate the main processes occurring in the reservoir. These tools are particularly useful in field management. It is also possible to correlate pressure and flow-rate decline with increasing values of positive steam fraction for a single well. During injection, the fluid temperature in the reservoir can be calculated, and the contribution from the injected brine to the total discharge can be estimated. In contrast, the quartz geothermometer commonly used to monitor aquifer temperatures is not applicable to wells that are strongly affected by injection returns, since quartz as a mineral phase is no longer at thermal equilibrium under these conditions.

Acknowledgements--The authors would like to thank the P N O C - E D C

m a n a g e m e n t for their support and permission to publish these data, and I A E A for partly funding this study, carried out under the P N O C - I A E A Research Contract No.

F. D'Amore et al.

550

PN-20D

S CLOSED SYSTEM

LOCAL VAPOR FORMATION, y>O

i

o

~

,,¢\0~. ~ r . ~ _ _~IL~ ~

O4

UNDISTURBEDCONDITION (ie.g. ~O0"C, y~O FOR OK-5)

"r

q¢ I! Fb-

PN-28 ~ u ,

OPEN SYSTEM ~ ~J

Tg (215-280"C)

~

OPENSYSTEM IRREVERSIBLE LOSS OF VAPOR,

y
PN-:50D

HSH = 3 log ( H 2 S / H 2 0 ) - I o g ( H 2 / H 2 0 )

Fig. 9. Sketch showing the mare processes affecting the position of the points m the FF-HSH diagram, derived from gas compositions. For y < 0, T, indicates the vapour loss temperature from the original liquid.

PHI/6019/RB and Technical Assistance No. PHI/(18/016. Thanks are also extended to Drs J. W. Hedenquist, W. F. Giggenbach and one anonymous reviewer, whose comments greatly improved this manuscript.

REFERENCES Arnorsson, S. (1991) Geochemistry and geothermal resources in Iceland. In Application of Geochemistry in Geothermal Reservoir Development (edited by D'Amore, F.), pp. 145-196. UN1TAR, New York. Arnorsson, S., Bjornsson, S., Muna, Z. W. and Bwire-Ojiambo, S. (1990) The use of gas chemistry to evaluate boiling processes and initial steam fraction in geothermal reservoirs with an example from the Olkaria field, Kenya. Geothermics 19, 497-514. Arnorsson, S. and Gunnlaugsson, E. (1985) New gas geothermometers for geothermal exph)ration---ca[ibration and exploration. Geochim. cosmochim. Acta 49, 1307-1325. Bromley, C. J. and Espafiola, O. S. (1982) Resistivity methods applied to geothermal cxploration in the Philippines. Proc. Pacific Geothermal Conference, pp. 447-452. D'Amore, F. (1991) Gas geochemistry as a link between geothermal exploration and exploitation. In Application ~! Geochemistry in Geothermal Reservoir Development (edited by D'Amore, F. ), pp. 93-144. UNITAR, New York. D'Amorc, F. and Ce[ati, R. (1983) Methodology for calculating steam quality in geothermal reservoirs. Geothermi~s 12. 129-140. D'Amore, F. and Pruess, K. (1986) Correlation between steam saturation, fluid composition and steam decline m vapor-dominated reservoirs. Geothermics 15, 167-183. D'Amore, F. and Truesdell, A. H. (1985) Calculation of geothermal reservoir temperatures and steam fractions from gas compositions. Geotherm. Resour. Counc. Trans. 9, 305-310. D'Amore, F. and Truesdell, A. H. (1988) A review of equilibrium constants for gaseous species of geothermal interest. Sci. Geol. Bull. 41,309-332. Gerardo, J. Y., Nuti, S., D'Amore, F., Seastres Jr., J. S. and Gonfiantini, R. (1993) Isotopic evidence for magmatic and meteoric water recharge and the processes affecting reservoir fluids in the Palinpinon geothermal system, Philippines. Geothermics 22,521-533. Giggenbaeh, W. F. (1980) Geothermal gas equilibria. Geochim. cosmochim. Acta 44, 2021-2032. Giggenbach, W. F. (1987) Redox processes governing the chemistry of fumarolic gas discharge from White Island, New Zealand. Appl. Geochem. 2, 143-16t. Harper, R. T. and Jordan, O. T. (1985) Geochemical changes in response to production and reinjection for Palinpinon I geothermal field, Negros Oriental, Philippines. Proc. 7th New Zealand Geothermal Workshop, pp. 39-44. Henley, R. W., Truesdell, A. H. and Barton Jr., P. B. (1984) Fluid-mineral equilibria in hydrothermal systems. Reviews in Economic Geology, 1, 143-146. Soc. of Economic Geology.

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Jordan, O. T. (1983) Interpretation of the reservoir geochemistry, Southern Negros geothermal field (an update). Unpublished PNOC-EDC Internal Report. Maunder, B. R., Brodie, A. J. and Tolentino, B. S. (1982) The Palinpinon geothermal resource, Negros, Republic of the Philippines--an exploration case history. Proc. Pacific Geothermal Conference, pp. 87-92. Ruaya, J. R. and Salera, J. R. M. (1990) Reinjection strategy for Palinpinon geothermal field, Southern Negros, Philippines. Paper presented at Energy '90: International Conference and Exhibition on Energy Supply and Utilization, Jan. 23-26, 1990, Manila, Philippines. Ruaya, J. R., Solis, R. P., Solaria, R. R. and Seastres Jr., J. S. (1991) Simple interpretations of chemical transients in multifeed, two-phase geothermal wells. Geothermics 20, 135-146. Seastres Jr., J. S. (1993) Reservoir chemistry response to changes in reinjection strategy during ten years of exploitation at Puhagan sector, Southern Negros Geothermal Field. Unpublished PNOC-EDC Internal Report. Sta. Aria, F. X. M. and O'Sullivan, M. J. (1988) Computer modelling of the Southern Negros geothermal field, Philippines. Proc. lOth New Zealand Geothermal Workshop, pp. 85-93. Truesdell, A. H., D'Amore, F. and Nieva, D. (1984) The effects of localized aquifer boiling on fluid production at Cerro Prieto. Geotherm. Resour. Counc. Trans. 8,222-229. Truesdell, A. H., Terrazas, B., Hernandes, L., Janik, C. J., Quicano, L. and Rovar, R. (1989) The response of the Cerro Prieto reservoir to exploitation as indicated by fluid chemistry. Proc. Symp. in the Field of Geothermal Energy, San Diego, pp. 123-132. Truesdell, A. H. (1991) Effects of physical processes on geothermal fluids. In Application of Geochemistry in Geothermal Reservoir Development (edited by D'Amore, F.), Chap. 3, pp. 71-92. UNITAR, New York. Urbino, M. E. G., Zaide, M. C., Malate, R. C. M. and Bueza, E. L. (1986) Structural flowpaths of reinjected fluids based on tracer tests--Palinpinon I, Philippines. Proc. 8th New Zealand Geothermal Workshop, pp. 53~68.

APPENDIX DILUTION FROM INJECTED WATER, COOLING AND GAS REEQUILIBRATION This method evaluates 7~ and X based on the conceptual model outlined in Fig. 10 and chemical equilibria 2 and 3 (see text). During injection, a portion of the reservoir feeding the well is considered. With time, varying amounts of injected brine enter this portion of the reservoir through fractures. During mixing at any step 'T', when a portion of the total H 2 0 comes from the injected brine (X), the fluid sampled at the wellhead will have measured molar concentrations Cn2,d and CH:S,d. The thermal equilibration of the local reservoir, that is, the temperature in the producing fractures at step "i 1", is represented by ~ . At this step, we assume that the fluid is already mixed with some previously injected fluid and is chemically equilibrated with the local rocks. This original fluid at step "'i - 1" has a composition represented by the following parameters:

II

~JECTED BRINE IIDILOTED GAS-WATER

160-170=C MIXTUREIN THE WELL CI CONTENT ]AT Tg -
HIGH

NO GAS

TO SHALLOW ZONES

LOCAL VAPOR LOSS T= ---Tg (2 5 - 240=C)

OPEN FRACTURE LPEN FRACTURE RESERVOIRCELL k IN FRACTURED IHEAT LOSS I FORMATION DILUTION "] ATT*(240-300*C)

OPEN FRACTURE

IRREVERSIBLY LOST

HEAT FROM ROCKS BUFFERING T*

Fig. 10. Conceptual model outlining the main processes occurring in the portion of reservoir (e.g. for well PN-28) affected by injection returns.

552

F. D ' A m o r e

e t al.

F I " = 4 log (FG/HeO °) - log ((7'H~/CO~)

i I>)

H S H ' = 3 log (H2S°/H20°) - log (1-17/|t2 O°)

(l<~)

The ....... notation indicates quantities m thc cell before the step "T" (e.g. before mixing with u fraction A" ol micctcd brine). At any temperature, the theoretical values of FT:' and HSH ° are known for v 0. However. if tfic fluid at F' hw, already lost some vapour (at a t c m p e r a m r e "17,).there will be negative values ofy. We approximate the fraction of vapour Iossy and T, at the values given by the calculation of FI' and HSH at step "T" after mixing with the rejected brine (Fig. 10). The method consists of an itcrativc procedure to calculate 1~ when a givcn fraction X at step "T" of injected brmc i~ added to the initial fluid producing the observed concentrations CHe.d and Cu2s. d. The equations used arc dcrixed from consideration of FT and HSH equilibria as given below. In the following equations, for a given portion of the rcscrwfir, H,(Y' is the original water before injection, and H 2 0 i is the amount of injected brine. L,',se o / H 2 concentration Tfic computation of the recovered fraction of fluid coming from injected water may bc performed using the hydrogen concentration in the total discharge and Ihc FI" reaction (2 in the text). ( ' U , . d - H~/(H2 ( ) ° + H2()i)

17]

1/Ca ,d

18)

or

(H20°/H~) + (H2Oi/H)).

Considering chemical equilibrmm at T" using the FI" reaction we have: log (H2()°/H~) = - [ F T ° + Iog(('H~i/('O~)/4 ]

(Its)

H2Oi/H ~ = 1/C~l,d -- (H20°/H~)

t201

and

X, the fraction of the injected brine contribution, is defined as: X-

H 2 O i / ( H 2 0 ° + H20i)

(21)

X-

1/(1 + H20°/H2Oi)

(22)

or

Inserting H) m the H20°/H20i term we obtain: (H20°/H20i) - (H20°IH~)/(H20i/tt~)

(23)

Using the already defined expression,, for H~O°/lq~ and H 2 0 / H ° we obtain the following expressions: Xw =

I +

e x p m - {[FT°+ Iog(CHUCO~)]I~ _ ' I/CH:, d -- ]e--xpt~ ~ U ]FT o + 1,,g(CH~/CO3)l/4} ]

i24)

In the computation ol X H the fl~llowing approximation is used: (CH]/CO~) = (CH j('O2) d Use o f H2S concentration The computation of X can bc also madc by using hydrogen sulphide concentrations in the total discharge and both the FT and HSH reactions (2 and 3 in text). ('it S,d = H2S°/(H2 O° + H 2 0 i)

125)

I/Cu2s. a - ( H20°/HeS °) + (H2Oj/H2S')

(26)

Considering chemical equilibrium at F ° using the HSH reaction: log (HeO°/H2 S°) = - [ H S H ° + log (H~/H20°)]/3

(27)

Considering cquation ( 19): log (HeO°/HeS °) = - { H S H ° / 3 + [FT ° + log (CH~/CO~)]/12}

(28)

H2Oi/H2 S° = l/Ctt2S,d -- HeO°/H2 g°

(29)

and

where H20°/H2S ° has already been defined.

Applications of Gas Chemistry in Southern Negros, Philippines

553

Inserting H:S ° into H20°/H2Oj term we obtain: H20°/H2Oj = (H20°/H2S°)/(H2Oi/H2S °)

(30)

expm -- ((HSH°/3) + [ F T ° + Iog(CH~/CO~)]/12) .] 1 XHSH = 1 + (l/CH:-~-_--expm_ {(HSHO/3 ) + [FT~ + Iog(CHO4/CO3)]/12}J

(31)

thcn

The value of T ~ is obtained when XFT = XL~Sll, that is, when X assumes the same value when both are computed using Ci12, d and CH:S. d.