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On-line corrosion monitoring in geothermal steam pipelines
Geothermics Vol. 27. No. 2, pp. 167 182, 1998 1998 CNR Published by Elsevier Science Ltd Printed in Great Britain. All rights reserved 0 3 7 5 6505/98 $19.00 + 0.00
Pergamon PII: S0375-6505(97)00002-3
ON-LINE C O R R O S I O N M O N I T O R I N G IN G E O T H E R M A L S T E A M PIPELINES MARIA E. INMAN, 1. ROY M. SHARp,it PETER T. WILSON:I: and GRAHAM A. WRIGHT§ *Faraday Technology, Inc., 315 Huls Drive, Clayton, OH 45315, U.S.A. t Victoria University, Wellington, New Zealand ~New Zealand Institute fi~r Industrial Research and Development, Wellington, New Zealand §Department ~f Chemistry, University c?fAuckland, Auckland, New Zealand (Received October 1995; accepted May 1997)
Abstraet--A Fluid Flow Test Rig has been designed and commissioned to simulate corrosion occurring in geothermal steam pipelines. The test rig was used to evaluate the effectiveness of a variety of corrosion monitoring techniques for application to full-scale pipelines. Although unsuccessful, the thin layer activation method, which is based on the conversion of Fe to 56Co upon irradiation with high-energy protons, showed potential for application to geothermal systems. Corrosion rates measured in the test facility were similar to those estimated for the Ohaaki (New Zealand) steam pipelines after three years of service. © 1998 CNR. Published by Elsevier Science Ltd. Key words: corrosion, geothermal, pipelines, Ohaaki, New Zealand.
INTRODUCTION
Generation of electricity from geothermal steam requires the transmission of steam from wells dispersed throughout a geothermal steam field to the power station. The use of carbon steel for the steam pipelines, rather than more highly alloyed materials (e.g. 9 C r l M o or 13Cr alloys), is a significant factor allowing the economic generation of electricity from geothermal steam. However, the behaviour of carbon steel in geothermal steam derived from liquid-dominated sources, under flowing conditions, is inadequately documented. In particular, the threshold values of the controlling parameters, such as condensate velocity, chemical composition and pH, at which there is a transition from passive behaviour to active corrosion of the carbon steel, have not been established. This can be contrasted, for
Formerly at Department of Chemical and Materials Engineering, University of Auckland, Auckland, New Zealand. 167
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M.E. hmum et al.
example, with the extensive documentation of the behaviour of carbon steel exposed to CO2-containing fluids (Hausler and Godard, 1984). Accelerated material loss has been observed in Wairakei steam pipelines (Thain et al., 1981; Braithwaite, 1978), which have a morphology similar to "mesa" attack typical of CO~ corrosion. The objective of the work described in this paper was to develop a small-scale experimental and practical facility able to simulate the fluid flow regimes and chemical conditions encountered in steam pipelines. This test facility would allow measurement of the corrosivity of geothermal steam as a function of the key chemical and physical parameters controlling steam corrosivity, and provide a means for continuous monitoring of the corrosion rate of carbon steel steam pipelines.
S I M U L A T I O N OF THE C O N D E N S A T E FLOW REGIME OF S T E A M PIPELINES
The fluid flow regime, which influences the corrosion rate within steam pipelines, can be effectively characterized by the condensate velocity and the wall shear stress. The velocity of geothermal condensate on the inside wall of the steam pipelines was estimated at the Wairakei geothermal field to be approximately 1 m/s (Braithwaite, 1978). It was assumed for this work that the condensate velocity in the Ohaaki steam pipelines was similar, or at least of the same order of magnitude. Wall shear stress, z,,, is considered one of the best indicators of the ability of a flow loop to simulate the fluid flow regime at a corroding interface, and is a function of the dynamic viscosity of the fluid, It, and the velocity profile in the pipe, dr~dr (Holland, 1973) dl ~
r,, =/l'ru
(1)
For single-phase fluid flow in a pipe, eqn. (1) can be approximated by V
~,, = ll D
(2)
where V is the average fluid velocity, and D is the diameter of the pipe. For laminar flow of an annular film flowing horizontally along a pipe wall, the wall shear stress beneath the annular film is given by kl V
where kL is a correlation factor, relating the velocity gradient at the wall to the average fluid velocity and film thickness, and 6~ is the thickness of the annular film (Chen, 1979). Ideally the diameter of the corrosion monitoring test section in the Fluid Flow Test Rig would have been of such a size as to provide a steam and condensate flow regime similar to that encountered in full-scale pipelines. However, in any practical simulation, the diameter will be limited by the cost of the steam/condensate passing through the test rig and the subsequent disposal of the condensate. This cost limitation necessitated a final inside diameter of the test section, of the experimental facility described in this paper, of 7.55 ram, compared with the 750 mm diameter of a typical full-scale steam pipeline at Ohaaki. A conductive fluid path was required, to allow the use of electrochemical techniques for characterizing the corrosion activity through measurement of both corrosion potentials
On-line Corrosion Monitoriny & Geothermal Steam Pipelhtes
169
and corrosion rates. To avoid the technical difficulties associated with maintaining a conductive fluid path in a two-phase flow of steam and condensate in a 7.55mm diameter pipeline, steam condensate alone was used. The condensate velocity within the corrosion monitoring test section, around 1.5m/s, closely matched that estimated for the actual Ohaaki pipelines. The wall shear stress calculated for this system was approximately 18 Pa; see Table 1. By comparison, the wall shear stress beneath a film of condensate, calculated for the Ohaaki full-scale steam pipelines from eqn. (3), is between 16.5 and 49.5 Pa. The design requirements were met with a Fluid Flow Test Rig which was assembled at Well BR19 in the Ohaaki geothermal field. Steam, drawn from Well BR19, was condensed and passed through a corrosion monitoring section where corrosion rates and potentials of carbon steel test coupons were measured. Figure 1 shows a flow diagram of the Fluid Flow Test Rig. Steam from Well BR19 was separated using a cyclone separator at 170°C and 8 bar and condensed to 153°C at a pressure of 6 bar using an annular heat exchanger, 4 m in length and with an internal diameter of 50 mm, made from AISI type 316 stainless steel. Cooling water flowed counter-currently to the steam. Silica and chlorides present in liquid droplets in the steam were removed through a steam trap inserted prior to the heat exchanger. After passing through the heat exchanger, the two-phase fluid contained 4% by weight of non-condensable gases, mainly CO2. The gas/condensate mixture was separated prior to the test section using a vertical separator, eliminating the possibility of slug flow, which would have had a detrimental effect on the electrochemical measurements. The pipeline was lagged using fibreglass encased in aluminium foil cladding from the (LP) pressure gauge up to the test section, lowering the amount of heat loss prior to the test section. Thermocouples and pressure gauges were inserted into the line at various points to
Table I. Fluid flow parameters in the Fluid Flow Test Rig and Ohaaki intermediate-pressure steam pipelines (Holland, 1973; Chen, 1979)
Intrinsic parameters (measured) Temperature ('C) [H2S+ HS ] (mmol/kg) Flow parameters (calculated) Fluid velocity, V (m/s) Pipe diameter, D (ram) Fluid density, p (kg/m 3) Dynamic viscosity, p (kg/m s) Condensate film thickness, 6L (mm) Reynolds number equation Reynolds number, NR~ Wall shear stress calculation Correlation factor, k[ Wall shear stress, Zw(Pa)
Fluid Flow Test Rig
Ohaaki intermediatepressure steam pipelines
155 0.3
150 0.079
1.5" 7.55 914 0.011
1 3* 750 914 0.011 2*
VDp/I~ 940 8p V/D
4 V(~Lp/l,t 660-1990 ~kL V/fiE 3.0 16.5~49.5
-
-
18
*Calculated from measured mass flow rate, based on pipe diameter. +Assumed to be similar to that estimated in the Wairakei pipelines (Braithwaite, 1978). ~kL(Chen, 1979) is the correlation factor for laminar flow relating the velocity gradient at the wall to the average fluid velocity and condensate film thickness.
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Cyclone
Key
Line
~
.
-
t.ooJmg w~ outlet
I~ Ste~-n trap On/Off valve
valve
, Control valve
Building
pressure gauge
Annular heat exchanger
Control
-
temperaturegauge
Cooling
f~'~&
BII
Q
linepressure
Q
wellheadpressure
Not To Scale
y~
NaOH
Q
Control valve
bubbler
I relief valve
Water m~omct~
Vertical separator 254 mm carbon steel pipe flow
valve 9 4 mm SS pipe
Corrosionmonitoring test section (see Figure42) 254 mm carbon steel pipe
--@ Control valve
I Control ~ valve Vertical separator
TI0 Corrosometer probe
U
~t Throttlevalve
Calorimeter m Drain To drain
~
e
Fig. 1. Flow diagram of the Fluid Flow Test Rig at Well BR! 9 in the Ohaaki geothermal field.
On-line Corrosion Monitoring in Geothermal Steam Pipelines
171
monitor system conditions. The mass flow rate of the steam was measured using a calorimeter, and controlled at around 240 kg/h, which resulted in a condensate velocity in the corrosion monitoring section of around 1.5 m/s. CONDENSATE CHEMISTRY The purpose of this work was to develop a facility that could evaluate the effect of chemistry on the corrosivity of the steam condensate. The Fluid Flow Test Rig was commissioned to operate at conditions simulating those existing in the pipelines at the Ohaaki Power Station (New Zealand). These included a steam/condensate temperature of approximately 160°C, a pressure of approximately 6.5bar and a condensate chemistry similar to that given in Table 2 for the Ohaaki steam pipelines. Although the temperature, pressure, and condensate pH requirements were satisfied, the concentrations of CO2, H2S, and N O 3 species in the condensate were two to six times higher than those measured for Ohaaki condensate. Unfortunately, these discrepancies in the condensate chemistry could not be rectified during the timeframe of this project. For the eventual use of this test facility, the chemistry of the condensate would likely have to more closely match that inside the actual pipeline under investigation. However, although some comparison with the corrosion activity inside the Ohaaki pipelines, documented after three years of service, was attempted, this period of initial testing was aimed primarily at developing the test facility and the techniques being used. As such, the two to six times difference in chemistry between Ohaaki steam condensate and the condensate running through the test facility was considered acceptable for the purpose of this test. The effect of the two to six times variation in steam condensate chemistry upon the corrosivity of the steam condensate, and subsequently the corrosion activity inside a pipeline, is unknown at this stage. The pH of the condensate was controlled by additions of H2SO 4 and NaOH. Na2SO4 was added to the condensate at a concentration of 0.2mmol/kg to improve the solution conductivity, and so allow the use of electrochemical methods for measuring corrosion rates. NaCI was added to the condensate at a concentration of 4.2 mmol/kg to maintain the Ag/AgC1 reference electrode used for monitoring corrosion potentials. Bore fluid from Well BR 19 was injected separately to give SiO2 concentrations of up to 4 mg/kg to simulate the effect of separated water carryover on the corrosion. These adjustments to the condensate chemistry were made by the injection of additive solutions, which were stored in three plastic tanks and bubbled with nitrogen for oxygen removal. Tanks 1 and 2 (Fig. 1)
Table 2. Calculated chemistry of condensate in contact with steam in high-pressure steam pipelines and that used in the Fluid Flow Test Rig (160°C and 6.5 bar)
Species CO2 + HCO- 3 H2S + HSNH3 + NH +4 Condensate pH
Ohaaki (mmol/kg)
Fluid Flow Test Rig (mmol/kg)
0.65 0.05 0.45 6.60
1.34 0.30 1.78 6.60
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M.E. lnman el al.
contained mixtures of NaeSO4, NaCI, and either H 2 S O 4 o r N a O H , the choice and concentration dependent upon the desired condensate pH. Two tanks were used as this allowed rapid switching between condensate pHs. Bore fluid was pumped separately from the bore fluid tank. The solutions were pumped from the tanks into the pipeline using Magdos" MD4 dosing pumps. The final injection point was a 6 . 4 m m pipe inserted midway into a mixing pipe of 25.4 mm carbon steel. The concentration of species in the additive solution varied with the injection rate, which was either 0.24 or 0.Skg/h, A non-return valve prevented condensate from flowing into the injection line and flashing. The above solutions were injected into the mixing pipe prior to the transition to the 7.55 mm inside diameter pipe, both for convenience and to allow for additional mixing of the solution into the condensate prior to the corrosion monitoring section. C O R R O S I O N M O N I T O R I N G TEST S E C T I O N The Reynolds number for the flow of condensate within the test section was calculated from eqn. (4) NR~. =
VDp
(4)
tl for a condensate velocity (V) of 1.5 m/s, a pipe diameter (D) of 7.55 ram, a fluid density (p) of 914 kg/m ~ and a dynamic viscosity (p) of 0.011 kg/m s. A Reynolds number of 940 was obtained, which suggested that the flow within the corrosion monitoring test section was laminar. In order to characterize the corrosion activity of the carbon steel within the test section, the ability to monitor both the instantaneous corrosion rate and the cumulative material loss was of particular importance. The corrosion monitoring techniques incorporated into the design of the Fluid Flow Test Rig were as follows: • • • • • •
weight loss coupons electrical resistance linear polarization resistance corrosion potential measurements hydrogen probe thin layer activation.
Experiments were conducted to evaluate the suitability of the Fluid Flow Test Rig for monitoring corrosion activity, and to test the available techniques for monitoring corrosion performance of the steel test specimens. Surface analysis of the corrosion product formed on the steel test sections was performed to evaluate the composition and morphology of these products. Figure 2 shows a detailed cross-section to illustrate the design of the corrosion monitoring test section. The test samples used in the corrosion monitoring test section were fabricated from AISI 1012 carbon steel, which was similar to the requirement for ASTM A53 Grade A steel used in the Ohaaki steam pipelines. The steel electrodes were push-fitted into P T F E rings, which were pressed into a steel holder. Twenty-five percent glass-fibre-filled P T F E was used between the electrodes as this provided the required electrical insulation and mechanical stability. Pressure was applied to the electrode set using AISI type 316 stainless steel plugs to prevent the condensate leaking between the electrodes, and maintained by
On-line Corrosion Monitoring in Geothermal Steam Pipelines
173
Note: All dimensions in mm ,~
195
T l
6.35
6.35 8.93
D ir ~t.i 0.D.o_f_C gp.dgJl.~.t ~._F Low . . . . . .
T
=__ . _
C
7.55 50,8
ground to enable spanners to be applied
section to be attached to the Fluid Flow Test Rig
Key R - LPR reference electrode A - LPR auxiliary electrode W - LPR working electrode
[]
AISI type 1012 carbon steel
[]
AISI type 316 stainless steel
S - Spare electrodes Wgt Loss - Weight loss coupon
B
Low carbon steel
•
25% glass fibre filled PTFE
T - ER test element C - ER control element
~ N~:le Reference
m Bleed [ valve
Asbestos
~ 0
plug I i Cooling N I-~ water
II li
Cooling II •
i
II
PTFE
water . J J
II
_ ,ned
inlet 7
~
tube
I
'-,J Corrosion Monitoring Test Section
H,0ro0enProbe
Reference Electrode Holder
Fig. 2. Design of the corrosion monitoring test section, part of the Fluid Flow Test Rig at Well BR 19 in the Ohaaki geothermal field.
174
M.E. hlman et al.
locking the plugs at either end. Electrical access to the electrodes was made through insulated fittings set in holes drilled through the holder. The advantages of this design are that the holder can be reused, that the type and arrangement of monitoring techniques can be easily modified, and that the effect of solution resistance on the electrochemical results is minimized by standardizing the distance between electrodes.
CONDENSATE DISPOSAL Following passage through the corrosion monitoring test section, the condensate was remixed with the non-condensable gas to balance the flow rig pressures (see Fig. 1). This arrangement prevented a pressure drop in the test line which would have caused flashing of the condensate. A control valve, located just after the second separator, controlled the pressure inside the test rig to 6.5 bar. The condensate and steam mixture was then flashed to atmospheric pressure in a steam pipe of approximately 7m length, to drain into a stream outside the building. At the drainage point the temperature of the condensate was approximately 95 C.
CORROSION MONITORING TECHNIQUES Weiqhl loss coupons for the test rig were prepared and cleaned using ASTM Standard GI-88 (ASTM, 1988) as a guideline. The coupons were used to obtain an average corrosion rate measurement throughout the experiments carried out in the Fluid Flow Test Rig. In experiments where the condensate pH was changed over the course of the experiment, the weight loss coupons provided an overall material loss and corrosion rate, rather than a distinct measure of corrosion rate at each pH value tested. Results obtained for the weight loss coupons provided a standard against which other techniques could be compared. An electrical resistance lesl element (Bovankovich, 1973: ASM, 1987) was incorporated in the corrosion monitoring test section (Fig. 2). The test element thickness was approximately I m m . A control element was also incorporated in the test section to compensate for the effect of temperature on the measured test element resistance. In addition, a T10 Corrosometer" probe was inserted in the Fluid Flow Test Rig, parallel to the flow of condensate, at the base of the second vertical separator. This was used to calibrate the electrical resistance test element contained within the corrosion monitoring test section. A Rohrback Corrosometer" CK-3 instrument was used to measure the resistance across the electrical resistance test element and to monitor the material loss from the T I 0 Corrosometer" probe. The linear polarization resistance method for measuring corrosion rates is based on the mverse relationship between the corrosion rate of the metal and the polarization resistance (Rp), which is the resistance of the corroding metal/solution interface to the flow of electrochemical current. If Npdecreases, the electrochemical current due to corrosion increases, and therefore the corrosion rate increases. Conversely, the corrosion rate drops with an increase in Rp. Rp is measured by the application of a small potential perturbation potential, AE, to the freely corroding interlace and measurement of the resulting current, AI. A plot of AE vs AI yields a slope equal to Rp, which is converted to a corrosion rate using the Stern Geary equation i..... = B/Rp
(5)
On-line Corrosion Monitorin 9 in Geothermal Steam Pipelines
175 (6)
r = 3.29icorrM/nD
where icorris the corrosion current density (pA/cmZ), B is a function of the Tafel slope (V), r is the corrosion rate (#m/yr), M is the molecular weight (g/mol), n is the number of electrons involved in the anodic reaction, and D is the density (g/cm3). A more detailed discussion of this technique can be found in the corrosion literature (Mansfeld, 1970; Fontana, 1986). The instrument used to measure corrosion rates in the project experiments was a Model M-103 Petrolite Corrosion Rate meter. The M-103 polarizes the test electrode away from its equilibrium potential by 10 mV, and measures the polarization resistance. The corrosion current is calculated and the corrosion rate obtained based on a known electrode surface area and composition. As the probes used in these experiments were not of standard dimensions, the LPR readings were adjusted using the weight loss data. Hydroyen probes provide a means of collecting hydrogen liberated when steel corrodes. In H2S-containing, non-aerated environments, some of this hydrogen enters the steel substrate as H atoms, which diffuse through the steel. A hydrogen probe was constructed from a 21.9 mm outside diameter low carbon steel sheath welded around a section of 7.55mm inside diameter AIS! 1012 low carbon steel pipe (Fig. 3). The volume of hydrogen diffusing through the pipe wall into the sheath space was measured using a mercury manometer linked to the probe via a stainless steel capillary. McAdam et al. (1981) found a linear relationship between the amount of hydrogen generated by the corrosion process and the corrosion rate of the steel. The amount of hydrogen produced during the corrosion process can also be measured on a regular basis to provide a semi-continuous measure of the ongoing corrosion rate. The hydrogen probe results can be corrected using coupon weight loss results of cumulative corrosion over a fixed period of time. Thin layer activation is a method of measuring wear, corrosion and erosion of materials (Boulton et al., 1989; Williams and Asher, 1984; Finnigan et al., 1982). The surface to be exposed is irradiated using a nuclear accelerator with a beam of high-energy protons. Some of the protons initiate a nuclear reaction causing the conversion of Fe atoms to 56Co. The distribution with depth of 56Co into the surface is well defined. Natural decay of the 56Co has a half life of 78.8 days and is accompanied by the emission of 7-rays. As material is lost from the surface, the intensity of y-radiation emitted from the test piece decreases, so the rate of corrosion can be measured on a semi-cumulative basis, provided the lost iron does
Note: all dimensions in mm
AISI 1012 carbon steel
Stainless steel capillary brazed into place Sheath space
7.55 Direction of condensate flow M L.
w
150
.d
-,
Fig. 3. Design of the hydrogen probe used for measuring the amount of hydrogen generated by the corrosion of low carbon steel exposed to hot geothermal condensate.
176
M.E./nman et al.
not reprecipitate as a corrosion product scale. One advantage of this technique is that the test coupons may be mounted flush with the pipe wall, and thus experience the same hydrodynamic flow conditions as the pipe wall. A I mm diameter spot on the surface of the electrical resistance test piece was activated to a depth of approximately 30 #m by irradiation with high-energy protons to produce the 56Co isotope (Wallace, pers. comm., 1992). The intensity of ~'-radiation emitted from the test specimen within the Fluid Flow Test Rig was measured on a daily basis using a Ludlum Model 200 g a m m a ray scintillation detector. A calibration coupon was made of the same material as the test piece, and irradiated in the same way but not exposed to the corrosive environment. Results from the calibration coupon tests were used to compensate for natural decay of the S6Co in the material loss calculations. The background radiation was also measured and accounted for in the calculations. O P E R A T I O N OF THE FLUID FLOW TEST RIG
Three experiments were carried out at the Ohaaki geothermal field using the Fluid Flow Test Rig to measure the corrosion rate of low carbon steel, exposed to hot geothermal condensate, as a function of condensate pH. The tests ranged in duration from 285 (experiment 2) to 2298 hours (experiment 3), allowing the type of corrosion products formed and the average corrosion rate to be evaluated as a function of time. The measured chemistry of the condensate available from Well BR19 is given in Table 2; the high-temperature pH of the condensate which was in equilibrium with steam was 6.6. During experiment 2, the condensate pH was controlled at values ranging from pH 4 to pH 7.8, using additions of H2SO4 and N a O H . The conditions and results of each experiment are given in Table 3, which also includes observations made during an inspection of steam pipelines at the Ohaaki geothermal field (lnman and Wilson, 1992), after three years of service. Table 3 details the coupon weight loss results for each experiment, including material loss, average corrosion weight and film thickness. The average corrosion rate and material loss of the Ohaaki intermediate pressure steam pipeline, estimated from measured scale thicknesses, are also listed. Figure 4 shows typical linear polarization resistance data obtained, in this case, from experiment 2. The corrosion rate at pH 6.6 is in good agreement with the long-term experiment (2300hours at pH6.6), which gave an average corrosion rate of 50/tin/yr. Corrosion rates measured at pH 5 are higher than those at pH 6,6 and 7.8, as expected. The results at pH 4, however, show considerable scatter and are lower than would be expected, given the greater corrosiveness of the system at the more acidic pH. The reasons for these low corrosion rates at p H 4 are unclear. The results in Fig. 4 suggest that the linear polarization resistance method could provide a means of detecting the influence of condensate pH on corrosion activity within a pipeline, although some refinement is obviously required to reduce scatter. Thin layer activation data from experiment 1 are presented in Fig. 5. Although somewhat scattered, the data indicate a material loss in the range of 1.5 2/~m, which was three times less than that given by the coupon weight loss data (Table 3). Thin layer activation data from experiments 2 and 3 also indicate material losses two to three times lower than coupon material losses. The use of thin layer activation to measure material loss depends upon the removal of the radioactive 5~'Co ions from the test area. If the ~6Co ions are incorporated into a film of corrosion product, such as that formed here, the apparent material loss will
On-line Corrosion Monitorin9 in Geothermal Steam Pipelines
177
Table 3. Results of experiments carried out using the Fluid Flow Test Rig at well BR19 in the Ohaaki geothermal field Experiment l
Experiment 2
331 6.6
285 4, 5, 6.6, 7.8 (for 3 days at each pH)
2298 6.6
approx. 3 years 6.6
not measured pyrrhotite or pyrite pyrrhotite magnetite
variable pyrrhotite or pyrite pyrrhotite magnetite
- 0.50 pyrite magnetite pyrite magnetite
unknown pyrite
5.1 135 12.0 15.6
3.7 113 8.7 17.0
13.0 49 30.7 25.6
Duration (h) Condensate pH
Final corrosion potential (V/SHE at 155~C) Predicted corrosion products Actual corrosion products major (minor) Weight loss coupon results (averaged) Material loss (/~m) Corrosion rate (/~m/yr) Calculated film thickness (/~m) Measured film thickness (/~m)
Experiment 3 0 h a a k i inspection*
pyrite (magnetite pyrrhotite) 60-185' 20-60* 135-310
*Inman and Wilson (1992). *Estimated from measured film thickness. Standard experimental conditions: • condensate flowrate = 240 kg/h; condensate velocity = 1.5 m/s; injection rate of H2SO4 and NaOH solutions = 0.24 or 0.5 kg/h; T = 155°C; p = 6.5 bar; • [NaCl]co,d...... = 4.2 x 10 3mol/kg; [Na2SO4]co.~....... = 0.2 x 10 3mol/kg. SHE: Standard Hydrogen Electrode.
200
pH-~,
pH=5
pH=6.6
pH=7.8
150
.-t
~
100-
@
"N
r..)
•
50-
•
I
I
I
I
50
100
200
250
•
300
Time / h Fig. 4. Corrosion rate vs time, linear polarization resistance, experiment 2.
178
M . E . lnman et al. 2.5
E =k
15-
¢0 0 J
¢0
0.5
I 50
r 100
I 150
I 200
I 250
I 300
350
Time / h Fig. 5. Material loss vs time, thin layer activation, experiment I.
be smaller than the actual material loss. However, if a steady-state corrosion rate and a constant film thickness are reached, the rate of removal of 56Co ions from the test area should equal the rate of loss of ~6Co atoms from the steel substrate. The accuracy of the thin layer activation method will therefore depend on the properties of the films formed. It is possible that in these short-term experiments a steady-state film thickness and composition were not reached, leading to an underestimation of corrosion rates. The scatter in the thin layer activation results was likely due to the effect of ambient temperature upon the instrumentation. The instrument did not have a means of compensating for changes in ambient temperature, which ranged from 4 to 24'C during these experiments (Wallace, 1992, private comm.). Reliability was also possibly influenced by exposure of the electronics used within the instrument to the corrosive atmosphere that existed at the Ohaaki geothermal field, eventually causing malfunction after experiment 3. In spite of these problems, the mass loss results obtained from thin layer activation are similar in magnitude to the weight loss coupon data, which indicates that this method, with some refinement to the instrumentation to ensure reliability and reproducibility, may be useful for on-line corrosion monitoring in geothermal applications. The electrical resistance T I0 C o r r o s o m e t e r " probe, located at the bottom of the second separator, typically gave material loss data up to three times higher than coupon material losses. Figure 6 shows data from experiment 2, which yielded a total material loss of around 11 Fm, three times larger than the coupon material loss, 3,7/Lm. The T I 0 Corrosometer" probe intruded into the fluid stream at the bottom of the second separator where it would have experienced a different and possibly more turbulent flow regime than the electrodes and weight loss coupon within the test section, which were flush with the pipe wall. Corrosion rates in the Ohaaki intermediate-pressure steam pipelines, after approximately three years of service, were estimated, from the thickness of scale removed from the pipelines, to be in the range 20 601lm/yr (Inman and Wilson, 1992). These rates can be
179
On-line Corrosion Monitorin9 in Geothermal Steam Pipelines
8
6-
4
pH=4 0
0
pH=7.8
pH=6.6
pH=5 I
t
I
t
t
50
lO0
150
200
250
300
Time / h
Fig. 6. Material loss vs time, Tl0 Corrosometer~' Rprobe, experiment 2.
compared with the results of the long-term experiment 3 which, at a condensate pH close to that within the Ohaaki steam pipelines, gave an average corrosion rate of around 50 #m/yr. The corrosion rates measured in experiments 1 and 2 were two to three times higher, as expected for short-term experiments in which the corrosion interface had probably not reached steady state. These results indicate that the Fluid Flow Test Rig has the potential to be a viable tool for determining the corrosivity of steam condensate and estimating corrosion rates of the steam pipelines, although further development is required. Measurement of corrosion potentials required development of procedures. Initially, the reference electrode was in direct contact with the condensate, and contamination by HzS in the condensate took place. This was confirmed by visual examination of the reference electrode upon removal. To avoid contamination, an asbestos plug soaked in 0.01 M KCI was inserted between the reference electrode and the condensate (Fig. 2). The potential drop across this barrier was considered negligible. The reference electrode was maintained in a solution of 0.01 M KC1. The measured corrosion potentials shown in Table 3 were used in conjunction with the Pourbaix diagram (Fig. 7) to predict the corrosion products that would be thermodynamically stable in the test environment. The Pourbaix diagram (Fig. 7) for Ohaaki steam condensate was prepared for a total sulphur concentration of 0.30 mmol/kg at 155°C using thermodynamic data collected from the literature (Johnson, 1994). X-ray diffraction of the corrosion products formed on the test specimens showed that a duplex film of iron sulphide and magnetite was formed. The iron sulphide and magnetite were formed in roughly equal quantities, as determined visually with optical microscopy from cross-sections of the test coupons after they were removed from the test rig. In the short-term experiments the iron sulphide formed was pyrrhotite. However, in the long-term experiment 3, pyrite was the stable iron sulphide. Pyrite was also the dominant corrosion product removed from the Ohaaki steam pipelines, with minor amounts of magnetite, pyrrhotite and marcasite also present (Inman and Wilson, 1992). This result shows that the
180
M. E. lnman ctal. HSO4[
$042-
Fe203
&
>
Fe 2
Fe
0
2
4
6
8
10
12
14
pH
Fig. 7. Potential pH diagram lbr the Fe S HxO system in the Fluid Flow Test Rig at Well BRI9 at the Ohaaki geothermal field, tk~r a temperature of 155 C. SHE: Standard Hydrogen Electrode.
Pourbaix diagram can accurately predict the nature of the corrosion products that would be thermodynamically stable on the steel surface, provided enough time is allowed for the system to reach an equilibrium state. The hydrogen collection probe and the electrical resistance test element did not function correctly. The hydrogen probe was not hermetically sealed and, as a result, changes in pressure due to the generation of hydrogen from corrosion processes could not be observed. The electrical resistance test element was too thick (1 ram), lacked sensitivity, and did not exhibit a measurable change in resistance in response to a decrease in thickness due to corrosion. CONCLUSIONS The objective of this work was to design and commission a t:acility that could determine the corrosivity of geothermal steam condensate towards carbon steel, by monitoring and characterizing the corrosion activity experienced within steam pipelines. Visual inspection of a pipeline requires an interruption to electricity generation, is manpower-intensive and provides only qualitative material-loss information. The Fluid Flow Test Rig would allow the study of chemical and physical parameters that influence corrosion in a controlled manner, without the need to interrupt the steam supply. Care must be taken, however, to
On-line Corrosion Monitorin9 in Geothermal Steam Pipelines
181
match the fluid flow regime and the steam condensate chemistry in the test facility to that of the full-scale pipeline. Weight loss measurements showed that similar corrosion rates were obtained in the Fluid Flow Test Rig to those measured in full-scale pipelines after three years of service. Linear polarization resistance measurements showed the influence of steam condensate pH on the corrosion rate over the pH range 5-7.8, although the results were scattered, and possibly misleading, at pH 4. Thin layer activation is potentially capable of providing a high equivalent quality estimate of corrosion rates but requires development to improve reproducibility and instrument reliability. As thin layer activation coupons can be placed flush with the pipe wall, this method provides an advantage over the more traditional corrosion monitoring techniques, such as linear polarization resistance, in which probes are typically placed perpendicular to the fluid stream and as such experience a different, and possibly more turbulent, flow regime, resulting in an overestimation of corrosion rates. Measurement of corrosion potentials requires attention to isolation of the reference electrode to avoid contamination. However, it is feasible to use corrosion potential measurements together with Pourbaix diagrams to predict corrosion product stability. Acknowledgements--This project was funded by Electricity Corporation of New Zealand and the New Zealand Foundation for Research, Science and Technology, FRST Contract C08216. The technical assistance of Mr Tom Gould, Mr Keith Lichti, Mr Lew Bacon and Mr Joe Jordan is gratefully acknowledged. REFERENCES
ASM (1987) Corrosion. In Metals Handbook, 9th edn, ed. ASM International Handbook Committee, Volume 13, pp. 19%200. ASM International, Ohio. ASTM (1988) Standard practice for preparing, cleaning and evaluating corrosion test specimens. In Annual Book of A S T M Standards, Vol. 03.02: Wear and Erosion; Metal Corrosion, ASTM Standard G1-88. American Society for Testing and Materials. Boulton, L. H., Wallace, (3. and Barry, B. J. (1989) Thin layer activation: new method for monitoring corrosion. Materials Forum 13, 261-265. Bovankovich, J. C. (1973) On-line monitoring. Materials Performance 12, 20-23. Braithwaite, W. R. (1978) Corrosion in the 30 inch main steam lines--Wairakei geothermal field--progress report on corrosion investigation. DSIR Report IPD 30/555/I-WRB, 18 August 1978. Chen, J. J. J. (1979) Two-phase gas liquid flow--with particular emphasis on holdup measurements and predictions. Ph.D. thesis, University of Auckland, Auckland. Finnigan, D. J., (3arbett, K. and Woolsey, I. S. (1982) The application of thin layer surface activation to the study of erosion-corrosion behaviour. Corrosion Science 22, 359 372. Fontana, M. G. (1986) Corrosion En#ineering, 3rd edn, pp. 192 194. Mc(3raw-Hill, New York. Hausler, R. H. and Godard, H. P. (eds) (1984) Advances in C02 Corrosion. Volume l: Proceedings of the CORROSION/83 Symposium on C02 Corrosion in the Oil and Gas Industry. NACE, Houston, TX. Holland, F. A. (1973) Fluid Flow for Chemical Engineers. Edward Arnold, London. Inman, M. E. and Wilson, P. T. (1992) Report on the inspection of the Ohaaki HP and IP steamlines. Report No. RI 18531.01, Industrial Research Ltd, Wellington, New Zealand. Johnson, C. (1994) User guide to program "Pourbaix" for calculating and plotting Pourbaix diagrams. Report No. 18013.31, Industrial Research Limited, Lower Hutt, New Zealand. Mansfeld, F. (1970) The polarization resistance technique for measuring corrosion currents.
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In Advances in Corrosion Science and I'echnolog)', eds M. G. Fontana and R. W. Staehle, Volume 6, pp. 163 262. Plenum Press, New York. McAdam, G. D., Lichti, K. A. and Soylemezoglu, S. (1981) Hydrogen in steel exposed to geothermal fluids. Geothermics 10, 115 131. Thain, I. A., Stacey, R. E. and Nicholson, D. J. (1981) Zero solids condensate corrosion in steam pipes at Wairakei. Geothermal Resources Council, Transactions. Williams, D. E. and Asher, J. (1984) Measurement of low corrosion rates: comparison of AC impedance techniques and thin layer activation methods. Corrosion Science 24, 185196.
Pergamon PII: S0375-6505(97)00002-3
ON-LINE C O R R O S I O N M O N I T O R I N G IN G E O T H E R M A L S T E A M PIPELINES MARIA E. INMAN, 1. ROY M. SHARp,it PETER T. WILSON:I: and GRAHAM A. WRIGHT§ *Faraday Technology, Inc., 315 Huls Drive, Clayton, OH 45315, U.S.A. t Victoria University, Wellington, New Zealand ~New Zealand Institute fi~r Industrial Research and Development, Wellington, New Zealand §Department ~f Chemistry, University c?fAuckland, Auckland, New Zealand (Received October 1995; accepted May 1997)
Abstraet--A Fluid Flow Test Rig has been designed and commissioned to simulate corrosion occurring in geothermal steam pipelines. The test rig was used to evaluate the effectiveness of a variety of corrosion monitoring techniques for application to full-scale pipelines. Although unsuccessful, the thin layer activation method, which is based on the conversion of Fe to 56Co upon irradiation with high-energy protons, showed potential for application to geothermal systems. Corrosion rates measured in the test facility were similar to those estimated for the Ohaaki (New Zealand) steam pipelines after three years of service. © 1998 CNR. Published by Elsevier Science Ltd. Key words: corrosion, geothermal, pipelines, Ohaaki, New Zealand.
INTRODUCTION
Generation of electricity from geothermal steam requires the transmission of steam from wells dispersed throughout a geothermal steam field to the power station. The use of carbon steel for the steam pipelines, rather than more highly alloyed materials (e.g. 9 C r l M o or 13Cr alloys), is a significant factor allowing the economic generation of electricity from geothermal steam. However, the behaviour of carbon steel in geothermal steam derived from liquid-dominated sources, under flowing conditions, is inadequately documented. In particular, the threshold values of the controlling parameters, such as condensate velocity, chemical composition and pH, at which there is a transition from passive behaviour to active corrosion of the carbon steel, have not been established. This can be contrasted, for
Formerly at Department of Chemical and Materials Engineering, University of Auckland, Auckland, New Zealand. 167
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M.E. hmum et al.
example, with the extensive documentation of the behaviour of carbon steel exposed to CO2-containing fluids (Hausler and Godard, 1984). Accelerated material loss has been observed in Wairakei steam pipelines (Thain et al., 1981; Braithwaite, 1978), which have a morphology similar to "mesa" attack typical of CO~ corrosion. The objective of the work described in this paper was to develop a small-scale experimental and practical facility able to simulate the fluid flow regimes and chemical conditions encountered in steam pipelines. This test facility would allow measurement of the corrosivity of geothermal steam as a function of the key chemical and physical parameters controlling steam corrosivity, and provide a means for continuous monitoring of the corrosion rate of carbon steel steam pipelines.
S I M U L A T I O N OF THE C O N D E N S A T E FLOW REGIME OF S T E A M PIPELINES
The fluid flow regime, which influences the corrosion rate within steam pipelines, can be effectively characterized by the condensate velocity and the wall shear stress. The velocity of geothermal condensate on the inside wall of the steam pipelines was estimated at the Wairakei geothermal field to be approximately 1 m/s (Braithwaite, 1978). It was assumed for this work that the condensate velocity in the Ohaaki steam pipelines was similar, or at least of the same order of magnitude. Wall shear stress, z,,, is considered one of the best indicators of the ability of a flow loop to simulate the fluid flow regime at a corroding interface, and is a function of the dynamic viscosity of the fluid, It, and the velocity profile in the pipe, dr~dr (Holland, 1973) dl ~
r,, =/l'ru
(1)
For single-phase fluid flow in a pipe, eqn. (1) can be approximated by V
~,, = ll D
(2)
where V is the average fluid velocity, and D is the diameter of the pipe. For laminar flow of an annular film flowing horizontally along a pipe wall, the wall shear stress beneath the annular film is given by kl V
where kL is a correlation factor, relating the velocity gradient at the wall to the average fluid velocity and film thickness, and 6~ is the thickness of the annular film (Chen, 1979). Ideally the diameter of the corrosion monitoring test section in the Fluid Flow Test Rig would have been of such a size as to provide a steam and condensate flow regime similar to that encountered in full-scale pipelines. However, in any practical simulation, the diameter will be limited by the cost of the steam/condensate passing through the test rig and the subsequent disposal of the condensate. This cost limitation necessitated a final inside diameter of the test section, of the experimental facility described in this paper, of 7.55 ram, compared with the 750 mm diameter of a typical full-scale steam pipeline at Ohaaki. A conductive fluid path was required, to allow the use of electrochemical techniques for characterizing the corrosion activity through measurement of both corrosion potentials
On-line Corrosion Monitoriny & Geothermal Steam Pipelhtes
169
and corrosion rates. To avoid the technical difficulties associated with maintaining a conductive fluid path in a two-phase flow of steam and condensate in a 7.55mm diameter pipeline, steam condensate alone was used. The condensate velocity within the corrosion monitoring test section, around 1.5m/s, closely matched that estimated for the actual Ohaaki pipelines. The wall shear stress calculated for this system was approximately 18 Pa; see Table 1. By comparison, the wall shear stress beneath a film of condensate, calculated for the Ohaaki full-scale steam pipelines from eqn. (3), is between 16.5 and 49.5 Pa. The design requirements were met with a Fluid Flow Test Rig which was assembled at Well BR19 in the Ohaaki geothermal field. Steam, drawn from Well BR19, was condensed and passed through a corrosion monitoring section where corrosion rates and potentials of carbon steel test coupons were measured. Figure 1 shows a flow diagram of the Fluid Flow Test Rig. Steam from Well BR19 was separated using a cyclone separator at 170°C and 8 bar and condensed to 153°C at a pressure of 6 bar using an annular heat exchanger, 4 m in length and with an internal diameter of 50 mm, made from AISI type 316 stainless steel. Cooling water flowed counter-currently to the steam. Silica and chlorides present in liquid droplets in the steam were removed through a steam trap inserted prior to the heat exchanger. After passing through the heat exchanger, the two-phase fluid contained 4% by weight of non-condensable gases, mainly CO2. The gas/condensate mixture was separated prior to the test section using a vertical separator, eliminating the possibility of slug flow, which would have had a detrimental effect on the electrochemical measurements. The pipeline was lagged using fibreglass encased in aluminium foil cladding from the (LP) pressure gauge up to the test section, lowering the amount of heat loss prior to the test section. Thermocouples and pressure gauges were inserted into the line at various points to
Table I. Fluid flow parameters in the Fluid Flow Test Rig and Ohaaki intermediate-pressure steam pipelines (Holland, 1973; Chen, 1979)
Intrinsic parameters (measured) Temperature ('C) [H2S+ HS ] (mmol/kg) Flow parameters (calculated) Fluid velocity, V (m/s) Pipe diameter, D (ram) Fluid density, p (kg/m 3) Dynamic viscosity, p (kg/m s) Condensate film thickness, 6L (mm) Reynolds number equation Reynolds number, NR~ Wall shear stress calculation Correlation factor, k[ Wall shear stress, Zw(Pa)
Fluid Flow Test Rig
Ohaaki intermediatepressure steam pipelines
155 0.3
150 0.079
1.5" 7.55 914 0.011
1 3* 750 914 0.011 2*
VDp/I~ 940 8p V/D
4 V(~Lp/l,t 660-1990 ~kL V/fiE 3.0 16.5~49.5
-
-
18
*Calculated from measured mass flow rate, based on pipe diameter. +Assumed to be similar to that estimated in the Wairakei pipelines (Braithwaite, 1978). ~kL(Chen, 1979) is the correlation factor for laminar flow relating the velocity gradient at the wall to the average fluid velocity and condensate film thickness.
170
M . E . lnman et al.
Cyclone
Key
Line
~
.
-
t.ooJmg w~ outlet
I~ Ste~-n trap On/Off valve
valve
, Control valve
Building
pressure gauge
Annular heat exchanger
Control
-
temperaturegauge
Cooling
f~'~&
BII
Q
linepressure
Q
wellheadpressure
Not To Scale
y~
NaOH
Q
Control valve
bubbler
I relief valve
Water m~omct~
Vertical separator 254 mm carbon steel pipe flow
valve 9 4 mm SS pipe
Corrosionmonitoring test section (see Figure42) 254 mm carbon steel pipe
--@ Control valve
I Control ~ valve Vertical separator
TI0 Corrosometer probe
U
~t Throttlevalve
Calorimeter m Drain To drain
~
e
Fig. 1. Flow diagram of the Fluid Flow Test Rig at Well BR! 9 in the Ohaaki geothermal field.
On-line Corrosion Monitoring in Geothermal Steam Pipelines
171
monitor system conditions. The mass flow rate of the steam was measured using a calorimeter, and controlled at around 240 kg/h, which resulted in a condensate velocity in the corrosion monitoring section of around 1.5 m/s. CONDENSATE CHEMISTRY The purpose of this work was to develop a facility that could evaluate the effect of chemistry on the corrosivity of the steam condensate. The Fluid Flow Test Rig was commissioned to operate at conditions simulating those existing in the pipelines at the Ohaaki Power Station (New Zealand). These included a steam/condensate temperature of approximately 160°C, a pressure of approximately 6.5bar and a condensate chemistry similar to that given in Table 2 for the Ohaaki steam pipelines. Although the temperature, pressure, and condensate pH requirements were satisfied, the concentrations of CO2, H2S, and N O 3 species in the condensate were two to six times higher than those measured for Ohaaki condensate. Unfortunately, these discrepancies in the condensate chemistry could not be rectified during the timeframe of this project. For the eventual use of this test facility, the chemistry of the condensate would likely have to more closely match that inside the actual pipeline under investigation. However, although some comparison with the corrosion activity inside the Ohaaki pipelines, documented after three years of service, was attempted, this period of initial testing was aimed primarily at developing the test facility and the techniques being used. As such, the two to six times difference in chemistry between Ohaaki steam condensate and the condensate running through the test facility was considered acceptable for the purpose of this test. The effect of the two to six times variation in steam condensate chemistry upon the corrosivity of the steam condensate, and subsequently the corrosion activity inside a pipeline, is unknown at this stage. The pH of the condensate was controlled by additions of H2SO 4 and NaOH. Na2SO4 was added to the condensate at a concentration of 0.2mmol/kg to improve the solution conductivity, and so allow the use of electrochemical methods for measuring corrosion rates. NaCI was added to the condensate at a concentration of 4.2 mmol/kg to maintain the Ag/AgC1 reference electrode used for monitoring corrosion potentials. Bore fluid from Well BR 19 was injected separately to give SiO2 concentrations of up to 4 mg/kg to simulate the effect of separated water carryover on the corrosion. These adjustments to the condensate chemistry were made by the injection of additive solutions, which were stored in three plastic tanks and bubbled with nitrogen for oxygen removal. Tanks 1 and 2 (Fig. 1)
Table 2. Calculated chemistry of condensate in contact with steam in high-pressure steam pipelines and that used in the Fluid Flow Test Rig (160°C and 6.5 bar)
Species CO2 + HCO- 3 H2S + HSNH3 + NH +4 Condensate pH
Ohaaki (mmol/kg)
Fluid Flow Test Rig (mmol/kg)
0.65 0.05 0.45 6.60
1.34 0.30 1.78 6.60
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M.E. lnman el al.
contained mixtures of NaeSO4, NaCI, and either H 2 S O 4 o r N a O H , the choice and concentration dependent upon the desired condensate pH. Two tanks were used as this allowed rapid switching between condensate pHs. Bore fluid was pumped separately from the bore fluid tank. The solutions were pumped from the tanks into the pipeline using Magdos" MD4 dosing pumps. The final injection point was a 6 . 4 m m pipe inserted midway into a mixing pipe of 25.4 mm carbon steel. The concentration of species in the additive solution varied with the injection rate, which was either 0.24 or 0.Skg/h, A non-return valve prevented condensate from flowing into the injection line and flashing. The above solutions were injected into the mixing pipe prior to the transition to the 7.55 mm inside diameter pipe, both for convenience and to allow for additional mixing of the solution into the condensate prior to the corrosion monitoring section. C O R R O S I O N M O N I T O R I N G TEST S E C T I O N The Reynolds number for the flow of condensate within the test section was calculated from eqn. (4) NR~. =
VDp
(4)
tl for a condensate velocity (V) of 1.5 m/s, a pipe diameter (D) of 7.55 ram, a fluid density (p) of 914 kg/m ~ and a dynamic viscosity (p) of 0.011 kg/m s. A Reynolds number of 940 was obtained, which suggested that the flow within the corrosion monitoring test section was laminar. In order to characterize the corrosion activity of the carbon steel within the test section, the ability to monitor both the instantaneous corrosion rate and the cumulative material loss was of particular importance. The corrosion monitoring techniques incorporated into the design of the Fluid Flow Test Rig were as follows: • • • • • •
weight loss coupons electrical resistance linear polarization resistance corrosion potential measurements hydrogen probe thin layer activation.
Experiments were conducted to evaluate the suitability of the Fluid Flow Test Rig for monitoring corrosion activity, and to test the available techniques for monitoring corrosion performance of the steel test specimens. Surface analysis of the corrosion product formed on the steel test sections was performed to evaluate the composition and morphology of these products. Figure 2 shows a detailed cross-section to illustrate the design of the corrosion monitoring test section. The test samples used in the corrosion monitoring test section were fabricated from AISI 1012 carbon steel, which was similar to the requirement for ASTM A53 Grade A steel used in the Ohaaki steam pipelines. The steel electrodes were push-fitted into P T F E rings, which were pressed into a steel holder. Twenty-five percent glass-fibre-filled P T F E was used between the electrodes as this provided the required electrical insulation and mechanical stability. Pressure was applied to the electrode set using AISI type 316 stainless steel plugs to prevent the condensate leaking between the electrodes, and maintained by
On-line Corrosion Monitoring in Geothermal Steam Pipelines
173
Note: All dimensions in mm ,~
195
T l
6.35
6.35 8.93
D ir ~t.i 0.D.o_f_C gp.dgJl.~.t ~._F Low . . . . . .
T
=__ . _
C
7.55 50,8
ground to enable spanners to be applied
section to be attached to the Fluid Flow Test Rig
Key R - LPR reference electrode A - LPR auxiliary electrode W - LPR working electrode
[]
AISI type 1012 carbon steel
[]
AISI type 316 stainless steel
S - Spare electrodes Wgt Loss - Weight loss coupon
B
Low carbon steel
•
25% glass fibre filled PTFE
T - ER test element C - ER control element
~ N~:le Reference
m Bleed [ valve
Asbestos
~ 0
plug I i Cooling N I-~ water
II li
Cooling II •
i
II
PTFE
water . J J
II
_ ,ned
inlet 7
~
tube
I
'-,J Corrosion Monitoring Test Section
H,0ro0enProbe
Reference Electrode Holder
Fig. 2. Design of the corrosion monitoring test section, part of the Fluid Flow Test Rig at Well BR 19 in the Ohaaki geothermal field.
174
M.E. hlman et al.
locking the plugs at either end. Electrical access to the electrodes was made through insulated fittings set in holes drilled through the holder. The advantages of this design are that the holder can be reused, that the type and arrangement of monitoring techniques can be easily modified, and that the effect of solution resistance on the electrochemical results is minimized by standardizing the distance between electrodes.
CONDENSATE DISPOSAL Following passage through the corrosion monitoring test section, the condensate was remixed with the non-condensable gas to balance the flow rig pressures (see Fig. 1). This arrangement prevented a pressure drop in the test line which would have caused flashing of the condensate. A control valve, located just after the second separator, controlled the pressure inside the test rig to 6.5 bar. The condensate and steam mixture was then flashed to atmospheric pressure in a steam pipe of approximately 7m length, to drain into a stream outside the building. At the drainage point the temperature of the condensate was approximately 95 C.
CORROSION MONITORING TECHNIQUES Weiqhl loss coupons for the test rig were prepared and cleaned using ASTM Standard GI-88 (ASTM, 1988) as a guideline. The coupons were used to obtain an average corrosion rate measurement throughout the experiments carried out in the Fluid Flow Test Rig. In experiments where the condensate pH was changed over the course of the experiment, the weight loss coupons provided an overall material loss and corrosion rate, rather than a distinct measure of corrosion rate at each pH value tested. Results obtained for the weight loss coupons provided a standard against which other techniques could be compared. An electrical resistance lesl element (Bovankovich, 1973: ASM, 1987) was incorporated in the corrosion monitoring test section (Fig. 2). The test element thickness was approximately I m m . A control element was also incorporated in the test section to compensate for the effect of temperature on the measured test element resistance. In addition, a T10 Corrosometer" probe was inserted in the Fluid Flow Test Rig, parallel to the flow of condensate, at the base of the second vertical separator. This was used to calibrate the electrical resistance test element contained within the corrosion monitoring test section. A Rohrback Corrosometer" CK-3 instrument was used to measure the resistance across the electrical resistance test element and to monitor the material loss from the T I 0 Corrosometer" probe. The linear polarization resistance method for measuring corrosion rates is based on the mverse relationship between the corrosion rate of the metal and the polarization resistance (Rp), which is the resistance of the corroding metal/solution interface to the flow of electrochemical current. If Npdecreases, the electrochemical current due to corrosion increases, and therefore the corrosion rate increases. Conversely, the corrosion rate drops with an increase in Rp. Rp is measured by the application of a small potential perturbation potential, AE, to the freely corroding interlace and measurement of the resulting current, AI. A plot of AE vs AI yields a slope equal to Rp, which is converted to a corrosion rate using the Stern Geary equation i..... = B/Rp
(5)
On-line Corrosion Monitorin 9 in Geothermal Steam Pipelines
175 (6)
r = 3.29icorrM/nD
where icorris the corrosion current density (pA/cmZ), B is a function of the Tafel slope (V), r is the corrosion rate (#m/yr), M is the molecular weight (g/mol), n is the number of electrons involved in the anodic reaction, and D is the density (g/cm3). A more detailed discussion of this technique can be found in the corrosion literature (Mansfeld, 1970; Fontana, 1986). The instrument used to measure corrosion rates in the project experiments was a Model M-103 Petrolite Corrosion Rate meter. The M-103 polarizes the test electrode away from its equilibrium potential by 10 mV, and measures the polarization resistance. The corrosion current is calculated and the corrosion rate obtained based on a known electrode surface area and composition. As the probes used in these experiments were not of standard dimensions, the LPR readings were adjusted using the weight loss data. Hydroyen probes provide a means of collecting hydrogen liberated when steel corrodes. In H2S-containing, non-aerated environments, some of this hydrogen enters the steel substrate as H atoms, which diffuse through the steel. A hydrogen probe was constructed from a 21.9 mm outside diameter low carbon steel sheath welded around a section of 7.55mm inside diameter AIS! 1012 low carbon steel pipe (Fig. 3). The volume of hydrogen diffusing through the pipe wall into the sheath space was measured using a mercury manometer linked to the probe via a stainless steel capillary. McAdam et al. (1981) found a linear relationship between the amount of hydrogen generated by the corrosion process and the corrosion rate of the steel. The amount of hydrogen produced during the corrosion process can also be measured on a regular basis to provide a semi-continuous measure of the ongoing corrosion rate. The hydrogen probe results can be corrected using coupon weight loss results of cumulative corrosion over a fixed period of time. Thin layer activation is a method of measuring wear, corrosion and erosion of materials (Boulton et al., 1989; Williams and Asher, 1984; Finnigan et al., 1982). The surface to be exposed is irradiated using a nuclear accelerator with a beam of high-energy protons. Some of the protons initiate a nuclear reaction causing the conversion of Fe atoms to 56Co. The distribution with depth of 56Co into the surface is well defined. Natural decay of the 56Co has a half life of 78.8 days and is accompanied by the emission of 7-rays. As material is lost from the surface, the intensity of y-radiation emitted from the test piece decreases, so the rate of corrosion can be measured on a semi-cumulative basis, provided the lost iron does
Note: all dimensions in mm
AISI 1012 carbon steel
Stainless steel capillary brazed into place Sheath space
7.55 Direction of condensate flow M L.
w
150
.d
-,
Fig. 3. Design of the hydrogen probe used for measuring the amount of hydrogen generated by the corrosion of low carbon steel exposed to hot geothermal condensate.
176
M.E./nman et al.
not reprecipitate as a corrosion product scale. One advantage of this technique is that the test coupons may be mounted flush with the pipe wall, and thus experience the same hydrodynamic flow conditions as the pipe wall. A I mm diameter spot on the surface of the electrical resistance test piece was activated to a depth of approximately 30 #m by irradiation with high-energy protons to produce the 56Co isotope (Wallace, pers. comm., 1992). The intensity of ~'-radiation emitted from the test specimen within the Fluid Flow Test Rig was measured on a daily basis using a Ludlum Model 200 g a m m a ray scintillation detector. A calibration coupon was made of the same material as the test piece, and irradiated in the same way but not exposed to the corrosive environment. Results from the calibration coupon tests were used to compensate for natural decay of the S6Co in the material loss calculations. The background radiation was also measured and accounted for in the calculations. O P E R A T I O N OF THE FLUID FLOW TEST RIG
Three experiments were carried out at the Ohaaki geothermal field using the Fluid Flow Test Rig to measure the corrosion rate of low carbon steel, exposed to hot geothermal condensate, as a function of condensate pH. The tests ranged in duration from 285 (experiment 2) to 2298 hours (experiment 3), allowing the type of corrosion products formed and the average corrosion rate to be evaluated as a function of time. The measured chemistry of the condensate available from Well BR19 is given in Table 2; the high-temperature pH of the condensate which was in equilibrium with steam was 6.6. During experiment 2, the condensate pH was controlled at values ranging from pH 4 to pH 7.8, using additions of H2SO4 and N a O H . The conditions and results of each experiment are given in Table 3, which also includes observations made during an inspection of steam pipelines at the Ohaaki geothermal field (lnman and Wilson, 1992), after three years of service. Table 3 details the coupon weight loss results for each experiment, including material loss, average corrosion weight and film thickness. The average corrosion rate and material loss of the Ohaaki intermediate pressure steam pipeline, estimated from measured scale thicknesses, are also listed. Figure 4 shows typical linear polarization resistance data obtained, in this case, from experiment 2. The corrosion rate at pH 6.6 is in good agreement with the long-term experiment (2300hours at pH6.6), which gave an average corrosion rate of 50/tin/yr. Corrosion rates measured at pH 5 are higher than those at pH 6,6 and 7.8, as expected. The results at pH 4, however, show considerable scatter and are lower than would be expected, given the greater corrosiveness of the system at the more acidic pH. The reasons for these low corrosion rates at p H 4 are unclear. The results in Fig. 4 suggest that the linear polarization resistance method could provide a means of detecting the influence of condensate pH on corrosion activity within a pipeline, although some refinement is obviously required to reduce scatter. Thin layer activation data from experiment 1 are presented in Fig. 5. Although somewhat scattered, the data indicate a material loss in the range of 1.5 2/~m, which was three times less than that given by the coupon weight loss data (Table 3). Thin layer activation data from experiments 2 and 3 also indicate material losses two to three times lower than coupon material losses. The use of thin layer activation to measure material loss depends upon the removal of the radioactive 5~'Co ions from the test area. If the ~6Co ions are incorporated into a film of corrosion product, such as that formed here, the apparent material loss will
On-line Corrosion Monitorin9 in Geothermal Steam Pipelines
177
Table 3. Results of experiments carried out using the Fluid Flow Test Rig at well BR19 in the Ohaaki geothermal field Experiment l
Experiment 2
331 6.6
285 4, 5, 6.6, 7.8 (for 3 days at each pH)
2298 6.6
approx. 3 years 6.6
not measured pyrrhotite or pyrite pyrrhotite magnetite
variable pyrrhotite or pyrite pyrrhotite magnetite
- 0.50 pyrite magnetite pyrite magnetite
unknown pyrite
5.1 135 12.0 15.6
3.7 113 8.7 17.0
13.0 49 30.7 25.6
Duration (h) Condensate pH
Final corrosion potential (V/SHE at 155~C) Predicted corrosion products Actual corrosion products major (minor) Weight loss coupon results (averaged) Material loss (/~m) Corrosion rate (/~m/yr) Calculated film thickness (/~m) Measured film thickness (/~m)
Experiment 3 0 h a a k i inspection*
pyrite (magnetite pyrrhotite) 60-185' 20-60* 135-310
*Inman and Wilson (1992). *Estimated from measured film thickness. Standard experimental conditions: • condensate flowrate = 240 kg/h; condensate velocity = 1.5 m/s; injection rate of H2SO4 and NaOH solutions = 0.24 or 0.5 kg/h; T = 155°C; p = 6.5 bar; • [NaCl]co,d...... = 4.2 x 10 3mol/kg; [Na2SO4]co.~....... = 0.2 x 10 3mol/kg. SHE: Standard Hydrogen Electrode.
200
pH-~,
pH=5
pH=6.6
pH=7.8
150
.-t
~
100-
@
"N
r..)
•
50-
•
I
I
I
I
50
100
200
250
•
300
Time / h Fig. 4. Corrosion rate vs time, linear polarization resistance, experiment 2.
178
M . E . lnman et al. 2.5
E =k
15-
¢0 0 J
¢0
0.5
I 50
r 100
I 150
I 200
I 250
I 300
350
Time / h Fig. 5. Material loss vs time, thin layer activation, experiment I.
be smaller than the actual material loss. However, if a steady-state corrosion rate and a constant film thickness are reached, the rate of removal of 56Co ions from the test area should equal the rate of loss of ~6Co atoms from the steel substrate. The accuracy of the thin layer activation method will therefore depend on the properties of the films formed. It is possible that in these short-term experiments a steady-state film thickness and composition were not reached, leading to an underestimation of corrosion rates. The scatter in the thin layer activation results was likely due to the effect of ambient temperature upon the instrumentation. The instrument did not have a means of compensating for changes in ambient temperature, which ranged from 4 to 24'C during these experiments (Wallace, 1992, private comm.). Reliability was also possibly influenced by exposure of the electronics used within the instrument to the corrosive atmosphere that existed at the Ohaaki geothermal field, eventually causing malfunction after experiment 3. In spite of these problems, the mass loss results obtained from thin layer activation are similar in magnitude to the weight loss coupon data, which indicates that this method, with some refinement to the instrumentation to ensure reliability and reproducibility, may be useful for on-line corrosion monitoring in geothermal applications. The electrical resistance T I0 C o r r o s o m e t e r " probe, located at the bottom of the second separator, typically gave material loss data up to three times higher than coupon material losses. Figure 6 shows data from experiment 2, which yielded a total material loss of around 11 Fm, three times larger than the coupon material loss, 3,7/Lm. The T I 0 Corrosometer" probe intruded into the fluid stream at the bottom of the second separator where it would have experienced a different and possibly more turbulent flow regime than the electrodes and weight loss coupon within the test section, which were flush with the pipe wall. Corrosion rates in the Ohaaki intermediate-pressure steam pipelines, after approximately three years of service, were estimated, from the thickness of scale removed from the pipelines, to be in the range 20 601lm/yr (Inman and Wilson, 1992). These rates can be
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On-line Corrosion Monitorin9 in Geothermal Steam Pipelines
8
6-
4
pH=4 0
0
pH=7.8
pH=6.6
pH=5 I
t
I
t
t
50
lO0
150
200
250
300
Time / h
Fig. 6. Material loss vs time, Tl0 Corrosometer~' Rprobe, experiment 2.
compared with the results of the long-term experiment 3 which, at a condensate pH close to that within the Ohaaki steam pipelines, gave an average corrosion rate of around 50 #m/yr. The corrosion rates measured in experiments 1 and 2 were two to three times higher, as expected for short-term experiments in which the corrosion interface had probably not reached steady state. These results indicate that the Fluid Flow Test Rig has the potential to be a viable tool for determining the corrosivity of steam condensate and estimating corrosion rates of the steam pipelines, although further development is required. Measurement of corrosion potentials required development of procedures. Initially, the reference electrode was in direct contact with the condensate, and contamination by HzS in the condensate took place. This was confirmed by visual examination of the reference electrode upon removal. To avoid contamination, an asbestos plug soaked in 0.01 M KCI was inserted between the reference electrode and the condensate (Fig. 2). The potential drop across this barrier was considered negligible. The reference electrode was maintained in a solution of 0.01 M KC1. The measured corrosion potentials shown in Table 3 were used in conjunction with the Pourbaix diagram (Fig. 7) to predict the corrosion products that would be thermodynamically stable in the test environment. The Pourbaix diagram (Fig. 7) for Ohaaki steam condensate was prepared for a total sulphur concentration of 0.30 mmol/kg at 155°C using thermodynamic data collected from the literature (Johnson, 1994). X-ray diffraction of the corrosion products formed on the test specimens showed that a duplex film of iron sulphide and magnetite was formed. The iron sulphide and magnetite were formed in roughly equal quantities, as determined visually with optical microscopy from cross-sections of the test coupons after they were removed from the test rig. In the short-term experiments the iron sulphide formed was pyrrhotite. However, in the long-term experiment 3, pyrite was the stable iron sulphide. Pyrite was also the dominant corrosion product removed from the Ohaaki steam pipelines, with minor amounts of magnetite, pyrrhotite and marcasite also present (Inman and Wilson, 1992). This result shows that the
180
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>
Fe 2
Fe
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2
4
6
8
10
12
14
pH
Fig. 7. Potential pH diagram lbr the Fe S HxO system in the Fluid Flow Test Rig at Well BRI9 at the Ohaaki geothermal field, tk~r a temperature of 155 C. SHE: Standard Hydrogen Electrode.
Pourbaix diagram can accurately predict the nature of the corrosion products that would be thermodynamically stable on the steel surface, provided enough time is allowed for the system to reach an equilibrium state. The hydrogen collection probe and the electrical resistance test element did not function correctly. The hydrogen probe was not hermetically sealed and, as a result, changes in pressure due to the generation of hydrogen from corrosion processes could not be observed. The electrical resistance test element was too thick (1 ram), lacked sensitivity, and did not exhibit a measurable change in resistance in response to a decrease in thickness due to corrosion. CONCLUSIONS The objective of this work was to design and commission a t:acility that could determine the corrosivity of geothermal steam condensate towards carbon steel, by monitoring and characterizing the corrosion activity experienced within steam pipelines. Visual inspection of a pipeline requires an interruption to electricity generation, is manpower-intensive and provides only qualitative material-loss information. The Fluid Flow Test Rig would allow the study of chemical and physical parameters that influence corrosion in a controlled manner, without the need to interrupt the steam supply. Care must be taken, however, to
On-line Corrosion Monitorin9 in Geothermal Steam Pipelines
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match the fluid flow regime and the steam condensate chemistry in the test facility to that of the full-scale pipeline. Weight loss measurements showed that similar corrosion rates were obtained in the Fluid Flow Test Rig to those measured in full-scale pipelines after three years of service. Linear polarization resistance measurements showed the influence of steam condensate pH on the corrosion rate over the pH range 5-7.8, although the results were scattered, and possibly misleading, at pH 4. Thin layer activation is potentially capable of providing a high equivalent quality estimate of corrosion rates but requires development to improve reproducibility and instrument reliability. As thin layer activation coupons can be placed flush with the pipe wall, this method provides an advantage over the more traditional corrosion monitoring techniques, such as linear polarization resistance, in which probes are typically placed perpendicular to the fluid stream and as such experience a different, and possibly more turbulent, flow regime, resulting in an overestimation of corrosion rates. Measurement of corrosion potentials requires attention to isolation of the reference electrode to avoid contamination. However, it is feasible to use corrosion potential measurements together with Pourbaix diagrams to predict corrosion product stability. Acknowledgements--This project was funded by Electricity Corporation of New Zealand and the New Zealand Foundation for Research, Science and Technology, FRST Contract C08216. The technical assistance of Mr Tom Gould, Mr Keith Lichti, Mr Lew Bacon and Mr Joe Jordan is gratefully acknowledged. REFERENCES
ASM (1987) Corrosion. In Metals Handbook, 9th edn, ed. ASM International Handbook Committee, Volume 13, pp. 19%200. ASM International, Ohio. ASTM (1988) Standard practice for preparing, cleaning and evaluating corrosion test specimens. In Annual Book of A S T M Standards, Vol. 03.02: Wear and Erosion; Metal Corrosion, ASTM Standard G1-88. American Society for Testing and Materials. Boulton, L. H., Wallace, (3. and Barry, B. J. (1989) Thin layer activation: new method for monitoring corrosion. Materials Forum 13, 261-265. Bovankovich, J. C. (1973) On-line monitoring. Materials Performance 12, 20-23. Braithwaite, W. R. (1978) Corrosion in the 30 inch main steam lines--Wairakei geothermal field--progress report on corrosion investigation. DSIR Report IPD 30/555/I-WRB, 18 August 1978. Chen, J. J. J. (1979) Two-phase gas liquid flow--with particular emphasis on holdup measurements and predictions. Ph.D. thesis, University of Auckland, Auckland. Finnigan, D. J., (3arbett, K. and Woolsey, I. S. (1982) The application of thin layer surface activation to the study of erosion-corrosion behaviour. Corrosion Science 22, 359 372. Fontana, M. G. (1986) Corrosion En#ineering, 3rd edn, pp. 192 194. Mc(3raw-Hill, New York. Hausler, R. H. and Godard, H. P. (eds) (1984) Advances in C02 Corrosion. Volume l: Proceedings of the CORROSION/83 Symposium on C02 Corrosion in the Oil and Gas Industry. NACE, Houston, TX. Holland, F. A. (1973) Fluid Flow for Chemical Engineers. Edward Arnold, London. Inman, M. E. and Wilson, P. T. (1992) Report on the inspection of the Ohaaki HP and IP steamlines. Report No. RI 18531.01, Industrial Research Ltd, Wellington, New Zealand. Johnson, C. (1994) User guide to program "Pourbaix" for calculating and plotting Pourbaix diagrams. Report No. 18013.31, Industrial Research Limited, Lower Hutt, New Zealand. Mansfeld, F. (1970) The polarization resistance technique for measuring corrosion currents.
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In Advances in Corrosion Science and I'echnolog)', eds M. G. Fontana and R. W. Staehle, Volume 6, pp. 163 262. Plenum Press, New York. McAdam, G. D., Lichti, K. A. and Soylemezoglu, S. (1981) Hydrogen in steel exposed to geothermal fluids. Geothermics 10, 115 131. Thain, I. A., Stacey, R. E. and Nicholson, D. J. (1981) Zero solids condensate corrosion in steam pipes at Wairakei. Geothermal Resources Council, Transactions. Williams, D. E. and Asher, J. (1984) Measurement of low corrosion rates: comparison of AC impedance techniques and thin layer activation methods. Corrosion Science 24, 185196.