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Developments in geothermal energy in Mexico—part six. Evaluation of a process to remove non-condensable gases from flashed geothermal steam upstream of a power plant
Heat Recovery Systems Vol. 6, No. 4, pp. 295-303, 1986
0198-7593/86 $3.00 + .00 Pergamon Journals Lid
Printed in Great Britain.
DEVELOPMENTS IN GEOTHERMAL ENERGY IN MEXICO PART SIX. EVALUATION OF A PROCESS TO REMOVE NON-CONDENSABLE GASES FROM FLASHED GEOTHERMAL STEAM UPSTREAM OF A POWER PLANT R.
ANGULO,L. LAM,H. GAMII~IO,H. JIMI~NEZ
Departmento de Geotermia, Instituto de Investigaciones Electricas, Cerro Prieto, Mexico
and
E. E. HUGHES Electrical Power Research Institute, California, U.S.A. (Received 2 January 1986)
Abstract--A process to remove non-condensable gases from flashed geothermal steam, by condensation and reevaporation of the steam in a heat exchanger, upstream of a power plant, was tested at the Cerro Prieto Geothermal Field in Mexico. The nominal capacity of the equipment was 0.4 tonne h - ' of steam and after more than 200 test runs and 3000 operating hours, a mean value of 94% of gas removal efficiency and an overall heat transfer coefficient average value of 3 . 8 2 0 k W m - 2 K -~ was obtained. Noncondensable gas removal efficiency was found to depend on the fraction of steam vented with non-condensable gases. The heat transfer coefficient was not affected by changes in vent rate, pressure, gas content or any of the other parameters varied during the test.
NOMENCLATURE A H OHB OMB P
Q
total surface area of the heat exchanger's tubes [m2] enthalpy per unit mass [kJ kg -t] overall heat balance [kW] overall mass balance [kg s-i] total pressure of _ g ~ u s phase [bar] total heat transfer rate across tubes [kW] shell side material balance [kg s -I] temperature [°C or K] temperature difference driving force [°C or K] tube side material balance [kgs -I] overall heat transfer coefficient [kW m - : K - ' ] total flow rate [kgs -t] weight fraction [dimensionless] mole fraction in liquid phase [dimensionless] mole fraction in gas phase [dimensionless] solubility constant [bar mole fraction-'] fluid viscosity [Pa s]
SSMB T AT TSMB U W X x Y 3ff # Subscripts C chemical component
CO, H20 I L LM MIX S V W 1 2 3 4 5 6
carbon dioxide water process stream liquid phase logarithmic mean mixture steam vapour phase water steam supply vent steam product steam recirculated condensate blowdown transferred condensate 295
296
R, ANGULO et al.
INTRODUCTION One of the main characteristics of geothermal steam is the presence of non-condensable gases. Among the most common gases found in the geothermal fields of the world are: carbon dioxide (CO2), hydrogen sulphide (H2 S), ammonia (NH3) and methane (CH4). Of these chemical species. carbon dioxide (CO2) is the most abundant and hydrogen sulphide (H2S) is the worst pollutant. The presence of these gases in the steam fed into power plants causes a decrease in net power recovery [1] plus contamination of the enwronment and materials. The development of processes to eliminate gases from geothermal steam, has focused on the removal of hydrogen sulphide (H2S) through oxidation, downstream of the power plant. However because the contamination problem is considered serious, m 1979 and 1980 the Electrical Power Research Institute (EPRI) tested a new process to remove total non-condensable gases from geothermal steam, upstream of the turbine at the Geysers geothermal field. These tests were conducted for EPRI by Coury & Associates with support from Pacific Gas & Electric Co. [2]. The process consisted in condensing and reboiling steam in a shell-and-tube vertical heat exchanger while non-condensable gases were purged with a small amount of incoming steam. Several parameters were measured to determine the process efficiency and economics. These were; the H2S removal percentage, the total non-condensable gas removal percentage, the heat transfer coefficient of the condenser and the net power loss. After 1000 h of accumulated test time. the average values obtained from the measured variables were: H2S removal non-condensable gas removal heat transfer coefficient
94% 98% 3.3 kW m -2 k -~.
Once the technical feasibility of the process was proven, to remove more than 90°/, of the H2 S and other gases present in the geothermal steam, it was decided to continue with the gases removal tests, using the same heat exchanger but operating with steam produced m a water-dominated geothermal field, and under a greater range of operating conditions (pressure, temperature, gas content, steam flow). The Cerro Prieto field in Mexico. was chosen for these tests. The Comisi6n Federal de Electricidad (CFE), owner and operator of the Cerro Prieto geothermal field, with the collaboration of the Instituto de Investigaciones El~ctricas (liE) has been working on the assessment of the environmental effects of the H2 S discharges, as well as on the study of processes to dispose of it. Due to CFE's continuous efforts to optimize the use of geothermal energy, the desire of EPRI to test the reboiling process in a water-dominant field and the interest of liE in developing new technologies to eliminate geothermal gases, liE decided to participate in the experimental assessment of the reboiling process. CFE provided the test site and geothermal fluid and l i e and EPRI developed a cost shared project. This paper presents the methodology used in the process evaluation, the preliminary results and the conclusions, placing special emphasis on the overall heat transfer coefficient. PROCESS The gas removal system and the process steams are shown in Fig. 1. The main component was a shell-and'tube vertical heat exchanger with 50 titanium tubes with a dia. of 50mm (2 in,). These were 0.76 mm (0.03 in.) thick and 1.8 m (6 It) long, with 3 baffles attached to the tubebundle. Steam was fed into the shell side of the heat exchanger. This flowed upwards while most of it condensed on the walls of the tubes. The non-condensable gases, together with a small amount of steam were vented through a purge line located at the upper part of the shell. The condensate flowed into a transfer tank, that acted as a steam seat and finally, into a storage tank, operated at a pressure of 0.7 bar (10psi) lower than the shell s i d e . In this way, a temperature difference: was created between the incoming steam and the stored condensate. From the bottom of the storage tank, a pump transferred condensate to the flood box, from which it flowed inside the tubes, The latent heat of the incoming steam was transferred, causing a portion of the condensate to be evaporated, thus producing steam with a low gas content that was discharged at the upper part of the storage
291
Developments in geothermal energy in Mexico-VI
Flood box
Vent
-
A FCV-3
_ _Geothermol
In
*
yy
steam
(I
I
-1
I’1 ‘4 ‘4
“roduct
Condensate
o
PC
0 0 0
q-----~~’ - Pressure
controtler
DP
- DIfferentgal
FC
- Flow controller
LC
- Level controller
FCV
- Flow control
LCV - Level control
pressure
controller
valve valve
Fig. 1. Flow diagram of the gas removal equipment.
The gases carried by this steam were those dissolved in the condensate in the shell side of the heat exchanger. Due to heat losses, a small portion of condensate accumulated in the storage tank, which needed to be blown down periodically. This process produced a concentrated purge of gases (15% by weight) which can be treated separately to control the emission of H,S. No chemical treatment of the main steam or condensate flow is required. tank.
EQUIPMENT
The M-42 well was chosen as the steam source [3]. The following equipment was installed next to the wellhead: (a) a fully instrumented shell-and-tube vertical heat exchanger, with transfer tank, recirculation pump, storage tank, steam lines and control panel, (b) a two stage Webre-type steam separator, (c) gas dosifying equipment, (d) CO,, NH, and Hr S storage tanks, (e) a water cooling tower, (f) an air compressor.
298
R. ANGULO et at.
Table I. Operat!on variables range of test runs
Runs
Vented steam (%)
AT (K)
Reeireulation flow rate (l/min-tube)
35 90 45
2-19 2-21 2-22
3-9 2-11 2-7
2.3-10.2 2.3-10.2 2.6-10.6
Pressure (bar) 4.137 7.929 9.653
....
H2S (mgkg-')
Gas content NH 3 (mg k g - ' )
CO~ (%)
Blowdown (%)
130-550 420-1230 490-870
50-790 80-690 60-1500
0,2-2,0 " 3 1..~-5,. 1.3-4.2
2-7.5 2--16 3-18
EXPERIMENTAL For the evaluation of the test equipment, a test plan was prepared specifying the operating range of each process variable [4]. The plan covered a steam supply flow requirement from 0.455 to 0.910tonneh -1, operating pressures of 4.137, 7.929 and 9.653 bar and a wide range of gas concentrations. From March to November of 1984, more than 200 gas removal test runs were performed, with more than 3000h of accumulated equipment operation time. The longest continuous operating period was 237 h. Table 1 shows the ranges of the variables investigated during the experimentation.
CALCULATIONS Raw data
During each test run, temperature, pressure and flow readings for each stream of the process, were collected and recorded for further heat and mass balance calculations. In addition, steam and condensate samples were collected and analyzed to determine CO2, H2S and NH~. Flow rate calculations
Based on the raw data obtained from each process stream, the flow rate of the steam supply, the product stream, the vent stream, the condensate produced and the reeireulation condensate, were calculated. The inputs required for each flow rate calculation were; pressure, temperature, meter differential (at the orifice plate), fluid density, fluid viscosity, specific heat ratio, inside pipe diameter, orifice bore, drain hole, plate expansion coefficient and chemical analysis. The fluid density, specific heat ratio and mole fraction of the CO2 were calculated using the temperature, pressure and weight fractions of CO,. The fluid viscosity was calculated from the pure component properties for steam and carbon dioxide. Heat balance calculations
The first step in performing the heat balance calculations was to determine the heat content of each stream. Steam supply (Stream 1) H, = Hs,(l - Xco..,) + Hco:(Xco2.,) Qvl = H, W,.
(1) (2)
Vent stream (Stream 2) H: = Hs2 (1 - Xco2:) + Hco2(Xco2.:) Q.__ =
H2 W2.
(3) (4)
Product stream (Stream 3) Hs = Hss(l - Xco,.3) + Hco2(Xc%,s) Qv3 = H3 Ws.
(5)
(6)
Recirculated condensate (Stream 4) Hw4 = Hw4 Q,, =
Hw, w4.
(7)
(8)
Developments in geothermal energy in Mexicty--VI
299
Blowdown (Stream 5)
Hws = Hw5
(9)
QL5 = Hw5 Ws.
(1O)
Transferred condensate (Stream 6) (11)
HIe6 = Hw6
QL6 = Hw6 W6.
(12)
The next step was to calculate the overall heat balance (OHB) based on: heat in = heat out
av~ = Qr3 + Qr2 + QL5 OHB =
(13)
heat in - heat out 100% heat in
(14)
OHB = Qv, - (Qv3 + Qr2 + QL5) 100%. Qvt
(15)
Temperature difference The calculation of the heat transfer coefficients were based on the logarithmic mean of the feed-product stream and the vent-product stream temperature difference.
Removal efficiencies The removal efficiency o f a given component was defined as the reduction in concentration of that component divided by the concentration o f that component in the feed stream. For H2 S, the removal efficiency was calculated as follows: Removal efficiency =
[ H 2 S ] , - [H2S]3
[HzS],
100%.
(16)
The CO2, NH3 and total non-condensable gases (NCG) removal efficiencies were calculated in the same manner.
Material balance calculation Overall material balance (OMB) calculation: mass in = mass out
w , = w3+ w2+ w~ OMB =
mass i n - mass out 100% mass in
OMB = W1 - ( W 3 + W2+ Ws) 100%. W,
(17)
(18) (19)
Shell side material balance (SSMB) calculation:
SSMB =
mass in s h e l l - mass out of shell 100% mass in shell
SSMB = WI - ( W 2 + I416) 100%.
W~
(20)
(21)
R. ANGULO el al.
300
Tube side material balance (TSMB) calculation:
TSMB =
mass in tube - mass out o f tube 100% mass in tube
(22)
TSMB = W6 - (W~ + W, ) Wi
(23)
Heat transfer coefficient The heat transfer coefficient of the condenser was one of the main evaluation parameters for the process equipment; this coefficient was calculated by using the following equations:
Q = UA ATLM
(24)
where: Q = total heat transfer rate across the tubes
Qv,
=
Qv2
-
QL6
-
(25)
so the overall heat transfer coefficient was: U=
Q ,4 A TLM
(26)
The heat transfer area A is the total surface of the heat exchanger's 50 tubes; Tj is the equilibrium temperature of the feed steam at the corresponding working pressure; /'2 is the vent stream temperature and corresponds to the equilibrium temperature o f the vented steam a t the respective working pressure, corrected by the partial pressure of vented gases; /'3 is the equilibrium temperature o f the clean steam at the corresponding pressure; Qe~ is the heat content in the feed steam; Qv2 is the heat content of the vented gases; and QL6 is the heat content in the produced condensate. The equation for the solubility of gases in water, mentioned previously, establishes that the gases solubility is a function of the system's total pressure. Therefore, a decrease in the gas removal efficiency was expected, as the operation pressure was raised on the shell side o f the heat exchanger. Figure 3 shows the gas removal efficiency for base cases at 4.137, 7.929 and 9.653 bar.
Heat transfer performance One o f the main parameters to evaluate in this gas removal process, was the overall heat transfer coefficient value U, since this information will be very useful in the design of commercial size Z9 bar
I00 98
0
0
0
O0 0
96--
° ° °g 0% o
Oo
94-o
o
G
92--
,8°
o
°
~o°
o oo
0
0
0
00
o
o
o
o
o
o
oo
°°
coo
o
90-0
E
8B--
(13
8 6 --
"r 8(-8;=-8C 0
1
2
1
4
I
6
I
8
I
I0
I
12
I
14
I
16
t
lib
vented steorn (%)
Fig. 2. Vented steam effect on hydrogen sulfide removal efficiency.
I
2O
22
Developments in geothermal energy in Mexico--VI
301
Base case I00 989694O
u
92-
O
90-
3
8
88-
CO
86-
E
Note : Bose coses. -
84-
Vented steom : 6 to 8 % -Ternp. cliff.(T-T ):4t05
K
82-
I
8C
I
4
)
5
I
6
I
7
I
8
10
9
Pressure (bar)
Fig. 3. Pressure effect on hydrogen sulfide removal efficiency.
equipment. Therefore, for each test run U was calculated, with the proper mass and energy balances, following the procedure already described. The temperature difference (T, - T3) varied from 2 to l l °C, but the calculated logarithmic mean temperature difference was used to obtain the U value. Figure 4 shows the corresponding relationship. The average U value found was 3820 Wm -2 k -I, with a standard deviation of 15%. Theoretical studies and experimental results, indicated that the gas removal efficiency should improve, as the amount of vented steam increases. Therefore it was decided to observe any possible effect of the gas removal efficiency on the U values obtained. Figure 5 shows these results. At the end of the test period, the equipment interior was inspected. No signs of corrosion, scaling or tube fouling were found. RESULTS
Gas removal efficiency During the steam condensation in the shell side of the heat exchanger, there were in close contact, a gaseous phase and a liquid phase and part of the separated gases dissolved in the produced liquid. Pressure : 4.137 'to 9 . 6 5 3 bar
iooo(2 i 3E
,~ E
eooc
g ._u 6000 u
g ~
o
40o0
0
°°oO
0 q5 0 O0
. ~ 0 0 ~ 0 ~ 0 ~0
0 0
0
°o
0
°
0
0
0
0
0 0
20o0
o
I
I
I
2
I
5
I
4
1
5
I
6
I
7
I
8
Logarithmic-mean temperature difference (K)
Fig. 4. Temperature difference effect on the overall heat transfer coefficient. H.R.S. 6/4--C
I
9
I0
302
R. ANGULO et al. Pressure : 4.137 to 9.653
bor
I0000 v
E
8000
u 6000
8
o o o
e4000
"6 .=
0 00 O0o
~ o
0
°O°o ~ ~ , ~
%
o 0 o
0
0
0
° °°~o%o ° oo~o
o~Oo o
0
~° %
oo o
o °° o o
o~
°°°
%
o
o
2000
0
1
• I
t
I
I
I
t
1
t
Z
4
6
8
I0
12
14
16
18
Vented
steam
I 20
22
(%)
Fig. 5. Vented steam effect on the overall heat transfer coefficient. These gases went out together with the clean steam produced during the evaporation of condensate in the tube side of the heat exchanger. The quantity of gases dissolved depended on their solubility at the operating conditions as expressed by the following equation:
PYc = ~cXc.
(27)
The quantity of component C in the liquid phase (xl) is proportional to the quantity of component C in the gaseous phase (yl). The main components of the gaseous phase were CO2. H2S, NH3 and HzO; H 2 0 was the most abundant. Considering that the shell and transfer tank condensates were in contact with a gaseous mixture particularly of the same composition as the vented gases, then the mole fraction of each gas in the gaseous phase was a function of its concentration in that stream. When the vent rate increased. the amount of steam in the gaseous phase, which was in contact with the condensate, also increased, lowering the separated gases concentration. Therefore, the mole fraction and the gas partial pressure, also decreased. To measure this effect, the vent rate was varied during experimentation, from 2 to 20%, and the results for H2 S removal efficiency are shown in Fig. 2; the average value for all the tests was 94%.
CONCLUSIONS
Gas removal efficiency The controlling factor in the gas removal efficiency was the solubility in the produced condensate on the shell side of the condenser. The gases carried by the product steam were those dissolved in the condensate and later evaporated during the reboiling process, The gas solubility i s a direct function of the gases" partial pressure, as established by Henry's Law. Therefore, when the vented steam increased, the efficiency improved because the ~ s partial pressure decreased, However, Henry's Law also predicts that as total pressure increases, the gas removal efficiency will be lowered. Heat transfer performance After correlating the overall heat transfer coefficient with the AT log mean, the vented steam percentage and the vented gases percentage, n0 relationship or tendency was observed; the U average value remained constant during the test period.
Developments in geothermal energy in Mexico--VI
303
REFERENCES 1. E. E. Michaelides, The influence of non-condensable gases on the net work produced by the geothermal steam power plants. Geothermics 11, 163-174 (1982). 2. Coury and Associates Inc., Upstream H2S removal from geothermal steam. Final report EPRI AP-2100, Palo Alto, California (I 981). 3. R. Angulo, L. Lain, J. Gon~les and P. Mul~.s. Cerro Prieto field test of H2S removal by reboiling. Proc. Eighth Annual Geothermal Conf. and Workshop, EPRI AP-3698, Santa Cruz, California (1984). 4. Bectel Group Inc., EPRI test of H2S removal by upstream reboiler at the Cerro Prieto geothermal field test plan, Research Project 1197-5, Palo Alto, California (1984). 5. R. Angulo, L. Lam, J. Gonz~les, P. Mulfis and E. E. Hughes, Results of field testing of process for removing H2S by condensing and re-evaporating geothermal steam at Cerro Prieto, 1985 EPRI/IIE Geothermal Conference and Workshop, San Diego, California (1985).
0198-7593/86 $3.00 + .00 Pergamon Journals Lid
Printed in Great Britain.
DEVELOPMENTS IN GEOTHERMAL ENERGY IN MEXICO PART SIX. EVALUATION OF A PROCESS TO REMOVE NON-CONDENSABLE GASES FROM FLASHED GEOTHERMAL STEAM UPSTREAM OF A POWER PLANT R.
ANGULO,L. LAM,H. GAMII~IO,H. JIMI~NEZ
Departmento de Geotermia, Instituto de Investigaciones Electricas, Cerro Prieto, Mexico
and
E. E. HUGHES Electrical Power Research Institute, California, U.S.A. (Received 2 January 1986)
Abstract--A process to remove non-condensable gases from flashed geothermal steam, by condensation and reevaporation of the steam in a heat exchanger, upstream of a power plant, was tested at the Cerro Prieto Geothermal Field in Mexico. The nominal capacity of the equipment was 0.4 tonne h - ' of steam and after more than 200 test runs and 3000 operating hours, a mean value of 94% of gas removal efficiency and an overall heat transfer coefficient average value of 3 . 8 2 0 k W m - 2 K -~ was obtained. Noncondensable gas removal efficiency was found to depend on the fraction of steam vented with non-condensable gases. The heat transfer coefficient was not affected by changes in vent rate, pressure, gas content or any of the other parameters varied during the test.
NOMENCLATURE A H OHB OMB P
Q
total surface area of the heat exchanger's tubes [m2] enthalpy per unit mass [kJ kg -t] overall heat balance [kW] overall mass balance [kg s-i] total pressure of _ g ~ u s phase [bar] total heat transfer rate across tubes [kW] shell side material balance [kg s -I] temperature [°C or K] temperature difference driving force [°C or K] tube side material balance [kgs -I] overall heat transfer coefficient [kW m - : K - ' ] total flow rate [kgs -t] weight fraction [dimensionless] mole fraction in liquid phase [dimensionless] mole fraction in gas phase [dimensionless] solubility constant [bar mole fraction-'] fluid viscosity [Pa s]
SSMB T AT TSMB U W X x Y 3ff # Subscripts C chemical component
CO, H20 I L LM MIX S V W 1 2 3 4 5 6
carbon dioxide water process stream liquid phase logarithmic mean mixture steam vapour phase water steam supply vent steam product steam recirculated condensate blowdown transferred condensate 295
296
R, ANGULO et al.
INTRODUCTION One of the main characteristics of geothermal steam is the presence of non-condensable gases. Among the most common gases found in the geothermal fields of the world are: carbon dioxide (CO2), hydrogen sulphide (H2 S), ammonia (NH3) and methane (CH4). Of these chemical species. carbon dioxide (CO2) is the most abundant and hydrogen sulphide (H2S) is the worst pollutant. The presence of these gases in the steam fed into power plants causes a decrease in net power recovery [1] plus contamination of the enwronment and materials. The development of processes to eliminate gases from geothermal steam, has focused on the removal of hydrogen sulphide (H2S) through oxidation, downstream of the power plant. However because the contamination problem is considered serious, m 1979 and 1980 the Electrical Power Research Institute (EPRI) tested a new process to remove total non-condensable gases from geothermal steam, upstream of the turbine at the Geysers geothermal field. These tests were conducted for EPRI by Coury & Associates with support from Pacific Gas & Electric Co. [2]. The process consisted in condensing and reboiling steam in a shell-and-tube vertical heat exchanger while non-condensable gases were purged with a small amount of incoming steam. Several parameters were measured to determine the process efficiency and economics. These were; the H2S removal percentage, the total non-condensable gas removal percentage, the heat transfer coefficient of the condenser and the net power loss. After 1000 h of accumulated test time. the average values obtained from the measured variables were: H2S removal non-condensable gas removal heat transfer coefficient
94% 98% 3.3 kW m -2 k -~.
Once the technical feasibility of the process was proven, to remove more than 90°/, of the H2 S and other gases present in the geothermal steam, it was decided to continue with the gases removal tests, using the same heat exchanger but operating with steam produced m a water-dominated geothermal field, and under a greater range of operating conditions (pressure, temperature, gas content, steam flow). The Cerro Prieto field in Mexico. was chosen for these tests. The Comisi6n Federal de Electricidad (CFE), owner and operator of the Cerro Prieto geothermal field, with the collaboration of the Instituto de Investigaciones El~ctricas (liE) has been working on the assessment of the environmental effects of the H2 S discharges, as well as on the study of processes to dispose of it. Due to CFE's continuous efforts to optimize the use of geothermal energy, the desire of EPRI to test the reboiling process in a water-dominant field and the interest of liE in developing new technologies to eliminate geothermal gases, liE decided to participate in the experimental assessment of the reboiling process. CFE provided the test site and geothermal fluid and l i e and EPRI developed a cost shared project. This paper presents the methodology used in the process evaluation, the preliminary results and the conclusions, placing special emphasis on the overall heat transfer coefficient. PROCESS The gas removal system and the process steams are shown in Fig. 1. The main component was a shell-and'tube vertical heat exchanger with 50 titanium tubes with a dia. of 50mm (2 in,). These were 0.76 mm (0.03 in.) thick and 1.8 m (6 It) long, with 3 baffles attached to the tubebundle. Steam was fed into the shell side of the heat exchanger. This flowed upwards while most of it condensed on the walls of the tubes. The non-condensable gases, together with a small amount of steam were vented through a purge line located at the upper part of the shell. The condensate flowed into a transfer tank, that acted as a steam seat and finally, into a storage tank, operated at a pressure of 0.7 bar (10psi) lower than the shell s i d e . In this way, a temperature difference: was created between the incoming steam and the stored condensate. From the bottom of the storage tank, a pump transferred condensate to the flood box, from which it flowed inside the tubes, The latent heat of the incoming steam was transferred, causing a portion of the condensate to be evaporated, thus producing steam with a low gas content that was discharged at the upper part of the storage
291
Developments in geothermal energy in Mexico-VI
Flood box
Vent
-
A FCV-3
_ _Geothermol
In
*
yy
steam
(I
I
-1
I’1 ‘4 ‘4
“roduct
Condensate
o
PC
0 0 0
q-----~~’ - Pressure
controtler
DP
- DIfferentgal
FC
- Flow controller
LC
- Level controller
FCV
- Flow control
LCV - Level control
pressure
controller
valve valve
Fig. 1. Flow diagram of the gas removal equipment.
The gases carried by this steam were those dissolved in the condensate in the shell side of the heat exchanger. Due to heat losses, a small portion of condensate accumulated in the storage tank, which needed to be blown down periodically. This process produced a concentrated purge of gases (15% by weight) which can be treated separately to control the emission of H,S. No chemical treatment of the main steam or condensate flow is required. tank.
EQUIPMENT
The M-42 well was chosen as the steam source [3]. The following equipment was installed next to the wellhead: (a) a fully instrumented shell-and-tube vertical heat exchanger, with transfer tank, recirculation pump, storage tank, steam lines and control panel, (b) a two stage Webre-type steam separator, (c) gas dosifying equipment, (d) CO,, NH, and Hr S storage tanks, (e) a water cooling tower, (f) an air compressor.
298
R. ANGULO et at.
Table I. Operat!on variables range of test runs
Runs
Vented steam (%)
AT (K)
Reeireulation flow rate (l/min-tube)
35 90 45
2-19 2-21 2-22
3-9 2-11 2-7
2.3-10.2 2.3-10.2 2.6-10.6
Pressure (bar) 4.137 7.929 9.653
....
H2S (mgkg-')
Gas content NH 3 (mg k g - ' )
CO~ (%)
Blowdown (%)
130-550 420-1230 490-870
50-790 80-690 60-1500
0,2-2,0 " 3 1..~-5,. 1.3-4.2
2-7.5 2--16 3-18
EXPERIMENTAL For the evaluation of the test equipment, a test plan was prepared specifying the operating range of each process variable [4]. The plan covered a steam supply flow requirement from 0.455 to 0.910tonneh -1, operating pressures of 4.137, 7.929 and 9.653 bar and a wide range of gas concentrations. From March to November of 1984, more than 200 gas removal test runs were performed, with more than 3000h of accumulated equipment operation time. The longest continuous operating period was 237 h. Table 1 shows the ranges of the variables investigated during the experimentation.
CALCULATIONS Raw data
During each test run, temperature, pressure and flow readings for each stream of the process, were collected and recorded for further heat and mass balance calculations. In addition, steam and condensate samples were collected and analyzed to determine CO2, H2S and NH~. Flow rate calculations
Based on the raw data obtained from each process stream, the flow rate of the steam supply, the product stream, the vent stream, the condensate produced and the reeireulation condensate, were calculated. The inputs required for each flow rate calculation were; pressure, temperature, meter differential (at the orifice plate), fluid density, fluid viscosity, specific heat ratio, inside pipe diameter, orifice bore, drain hole, plate expansion coefficient and chemical analysis. The fluid density, specific heat ratio and mole fraction of the CO2 were calculated using the temperature, pressure and weight fractions of CO,. The fluid viscosity was calculated from the pure component properties for steam and carbon dioxide. Heat balance calculations
The first step in performing the heat balance calculations was to determine the heat content of each stream. Steam supply (Stream 1) H, = Hs,(l - Xco..,) + Hco:(Xco2.,) Qvl = H, W,.
(1) (2)
Vent stream (Stream 2) H: = Hs2 (1 - Xco2:) + Hco2(Xco2.:) Q.__ =
H2 W2.
(3) (4)
Product stream (Stream 3) Hs = Hss(l - Xco,.3) + Hco2(Xc%,s) Qv3 = H3 Ws.
(5)
(6)
Recirculated condensate (Stream 4) Hw4 = Hw4 Q,, =
Hw, w4.
(7)
(8)
Developments in geothermal energy in Mexicty--VI
299
Blowdown (Stream 5)
Hws = Hw5
(9)
QL5 = Hw5 Ws.
(1O)
Transferred condensate (Stream 6) (11)
HIe6 = Hw6
QL6 = Hw6 W6.
(12)
The next step was to calculate the overall heat balance (OHB) based on: heat in = heat out
av~ = Qr3 + Qr2 + QL5 OHB =
(13)
heat in - heat out 100% heat in
(14)
OHB = Qv, - (Qv3 + Qr2 + QL5) 100%. Qvt
(15)
Temperature difference The calculation of the heat transfer coefficients were based on the logarithmic mean of the feed-product stream and the vent-product stream temperature difference.
Removal efficiencies The removal efficiency o f a given component was defined as the reduction in concentration of that component divided by the concentration o f that component in the feed stream. For H2 S, the removal efficiency was calculated as follows: Removal efficiency =
[ H 2 S ] , - [H2S]3
[HzS],
100%.
(16)
The CO2, NH3 and total non-condensable gases (NCG) removal efficiencies were calculated in the same manner.
Material balance calculation Overall material balance (OMB) calculation: mass in = mass out
w , = w3+ w2+ w~ OMB =
mass i n - mass out 100% mass in
OMB = W1 - ( W 3 + W2+ Ws) 100%. W,
(17)
(18) (19)
Shell side material balance (SSMB) calculation:
SSMB =
mass in s h e l l - mass out of shell 100% mass in shell
SSMB = WI - ( W 2 + I416) 100%.
W~
(20)
(21)
R. ANGULO el al.
300
Tube side material balance (TSMB) calculation:
TSMB =
mass in tube - mass out o f tube 100% mass in tube
(22)
TSMB = W6 - (W~ + W, ) Wi
(23)
Heat transfer coefficient The heat transfer coefficient of the condenser was one of the main evaluation parameters for the process equipment; this coefficient was calculated by using the following equations:
Q = UA ATLM
(24)
where: Q = total heat transfer rate across the tubes
Qv,
=
Qv2
-
QL6
-
(25)
so the overall heat transfer coefficient was: U=
Q ,4 A TLM
(26)
The heat transfer area A is the total surface of the heat exchanger's 50 tubes; Tj is the equilibrium temperature of the feed steam at the corresponding working pressure; /'2 is the vent stream temperature and corresponds to the equilibrium temperature o f the vented steam a t the respective working pressure, corrected by the partial pressure of vented gases; /'3 is the equilibrium temperature o f the clean steam at the corresponding pressure; Qe~ is the heat content in the feed steam; Qv2 is the heat content of the vented gases; and QL6 is the heat content in the produced condensate. The equation for the solubility of gases in water, mentioned previously, establishes that the gases solubility is a function of the system's total pressure. Therefore, a decrease in the gas removal efficiency was expected, as the operation pressure was raised on the shell side o f the heat exchanger. Figure 3 shows the gas removal efficiency for base cases at 4.137, 7.929 and 9.653 bar.
Heat transfer performance One o f the main parameters to evaluate in this gas removal process, was the overall heat transfer coefficient value U, since this information will be very useful in the design of commercial size Z9 bar
I00 98
0
0
0
O0 0
96--
° ° °g 0% o
Oo
94-o
o
G
92--
,8°
o
°
~o°
o oo
0
0
0
00
o
o
o
o
o
o
oo
°°
coo
o
90-0
E
8B--
(13
8 6 --
"r 8(-8;=-8C 0
1
2
1
4
I
6
I
8
I
I0
I
12
I
14
I
16
t
lib
vented steorn (%)
Fig. 2. Vented steam effect on hydrogen sulfide removal efficiency.
I
2O
22
Developments in geothermal energy in Mexico--VI
301
Base case I00 989694O
u
92-
O
90-
3
8
88-
CO
86-
E
Note : Bose coses. -
84-
Vented steom : 6 to 8 % -Ternp. cliff.(T-T ):4t05
K
82-
I
8C
I
4
)
5
I
6
I
7
I
8
10
9
Pressure (bar)
Fig. 3. Pressure effect on hydrogen sulfide removal efficiency.
equipment. Therefore, for each test run U was calculated, with the proper mass and energy balances, following the procedure already described. The temperature difference (T, - T3) varied from 2 to l l °C, but the calculated logarithmic mean temperature difference was used to obtain the U value. Figure 4 shows the corresponding relationship. The average U value found was 3820 Wm -2 k -I, with a standard deviation of 15%. Theoretical studies and experimental results, indicated that the gas removal efficiency should improve, as the amount of vented steam increases. Therefore it was decided to observe any possible effect of the gas removal efficiency on the U values obtained. Figure 5 shows these results. At the end of the test period, the equipment interior was inspected. No signs of corrosion, scaling or tube fouling were found. RESULTS
Gas removal efficiency During the steam condensation in the shell side of the heat exchanger, there were in close contact, a gaseous phase and a liquid phase and part of the separated gases dissolved in the produced liquid. Pressure : 4.137 'to 9 . 6 5 3 bar
iooo(2 i 3E
,~ E
eooc
g ._u 6000 u
g ~
o
40o0
0
°°oO
0 q5 0 O0
. ~ 0 0 ~ 0 ~ 0 ~0
0 0
0
°o
0
°
0
0
0
0
0 0
20o0
o
I
I
I
2
I
5
I
4
1
5
I
6
I
7
I
8
Logarithmic-mean temperature difference (K)
Fig. 4. Temperature difference effect on the overall heat transfer coefficient. H.R.S. 6/4--C
I
9
I0
302
R. ANGULO et al. Pressure : 4.137 to 9.653
bor
I0000 v
E
8000
u 6000
8
o o o
e4000
"6 .=
0 00 O0o
~ o
0
°O°o ~ ~ , ~
%
o 0 o
0
0
0
° °°~o%o ° oo~o
o~Oo o
0
~° %
oo o
o °° o o
o~
°°°
%
o
o
2000
0
1
• I
t
I
I
I
t
1
t
Z
4
6
8
I0
12
14
16
18
Vented
steam
I 20
22
(%)
Fig. 5. Vented steam effect on the overall heat transfer coefficient. These gases went out together with the clean steam produced during the evaporation of condensate in the tube side of the heat exchanger. The quantity of gases dissolved depended on their solubility at the operating conditions as expressed by the following equation:
PYc = ~cXc.
(27)
The quantity of component C in the liquid phase (xl) is proportional to the quantity of component C in the gaseous phase (yl). The main components of the gaseous phase were CO2. H2S, NH3 and HzO; H 2 0 was the most abundant. Considering that the shell and transfer tank condensates were in contact with a gaseous mixture particularly of the same composition as the vented gases, then the mole fraction of each gas in the gaseous phase was a function of its concentration in that stream. When the vent rate increased. the amount of steam in the gaseous phase, which was in contact with the condensate, also increased, lowering the separated gases concentration. Therefore, the mole fraction and the gas partial pressure, also decreased. To measure this effect, the vent rate was varied during experimentation, from 2 to 20%, and the results for H2 S removal efficiency are shown in Fig. 2; the average value for all the tests was 94%.
CONCLUSIONS
Gas removal efficiency The controlling factor in the gas removal efficiency was the solubility in the produced condensate on the shell side of the condenser. The gases carried by the product steam were those dissolved in the condensate and later evaporated during the reboiling process, The gas solubility i s a direct function of the gases" partial pressure, as established by Henry's Law. Therefore, when the vented steam increased, the efficiency improved because the ~ s partial pressure decreased, However, Henry's Law also predicts that as total pressure increases, the gas removal efficiency will be lowered. Heat transfer performance After correlating the overall heat transfer coefficient with the AT log mean, the vented steam percentage and the vented gases percentage, n0 relationship or tendency was observed; the U average value remained constant during the test period.
Developments in geothermal energy in Mexico--VI
303
REFERENCES 1. E. E. Michaelides, The influence of non-condensable gases on the net work produced by the geothermal steam power plants. Geothermics 11, 163-174 (1982). 2. Coury and Associates Inc., Upstream H2S removal from geothermal steam. Final report EPRI AP-2100, Palo Alto, California (I 981). 3. R. Angulo, L. Lain, J. Gon~les and P. Mul~.s. Cerro Prieto field test of H2S removal by reboiling. Proc. Eighth Annual Geothermal Conf. and Workshop, EPRI AP-3698, Santa Cruz, California (1984). 4. Bectel Group Inc., EPRI test of H2S removal by upstream reboiler at the Cerro Prieto geothermal field test plan, Research Project 1197-5, Palo Alto, California (1984). 5. R. Angulo, L. Lam, J. Gonz~les, P. Mulfis and E. E. Hughes, Results of field testing of process for removing H2S by condensing and re-evaporating geothermal steam at Cerro Prieto, 1985 EPRI/IIE Geothermal Conference and Workshop, San Diego, California (1985).