ANALYSIS OF GEOTHERMAL CASING THINNING RATE OF LEYTE GEOTHERMAL PRODUCTION FIELD
Corrosion is one of the technological problems that geothermal management faces in the operation of geothermal wells. The primary cause of corrosion in geothermal wells is exposure to geothermal brine where conductive and convective heat transfer happens from the reservoir to the surface. The geothermal well supplies the motive two-phase steam fluid from the reservoir to the surface fluid collection facility, and then to the separator where steam is separate from brine. The casing of the well is the first equipment that encounters the field’s geothermal fluid. The flow of geothermal brine from the reservoir causes the casing to deteriorate by way of corrosion. The impact of turbulence, corrosion and erosion significantly reduce the integrity of the casing. Thus, monitoring these facilities is vitally important to minimize the risks to geothermal operations. Caliper measurements are taken to monitor the thickness of the casing for safety and environmental concerns. The effective management of a geothermal well necessitates a very thorough knowledge of the extent to which the aforementioned factors contribute to casing degradation. In this paper, the contribution of factors affecting the thinning rate of a geothermal casing, such as temperature, flow velocity, pH, well geometry and corrosion species, was studied. The effects of several corrosive species on casings were also studied. The corrosive species and the factors affecting the thinning rate of the production wells of the Leyte geothermal production field were analysed with multiple linear regression models in order to determine the dependency of the thinning rate on these parameters. Fluid discharge measurements and sampled chemistry concentrations at the surface were simulated at downhole conditions using software HOLA and WATCH. The results were analysed statistically using ANOVA, a P value test, and multiple regression coefficients. Adjusted R2 of the regression analysis and mean absolute percentage error (MAPE) aided in selecting a good regression model. The study showed that fluid discharge characteristics such as temperature, velocity, pH, steam fraction and geometry of the well contribute about 56.71% to the thinning rate of the casing. The predicted thinning rate model also shows similar trending of the average thinning rate compared to the measured thinning rate for the first and second surveys of repeatedly measured wells.
Corrosion is one of the technological problems that geothermal management faces
in the operation of geothermal wells. The primary cause of corrosion in geothermal
wells is exposure to geothermal brine where conductive and convective heat transfer
happens from the reservoir to the surface. The geothermal well supplies the motive
two-phase steam fluid from the reservoir to the surface fluid collection facility, and
then to the separator where steam is separate from brine. The casing of the well is
the first equipment that encounters the field’s geothermal fluid. The flow of
geothermal brine from the reservoir causes the casing to deteriorate by way of
corrosion. The impact of turbulence, corrosion and erosion significantly reduce the
integrity of the casing. Thus, monitoring these facilities is vitally important to
minimize the risks to geothermal operations. Caliper measurements are taken to
monitor the thickness of the casing for safety and environmental concerns. The
effective management of a geothermal well necessitates a very thorough knowledge
of the extent to which the aforementioned factors contribute to casing degradation.
In this paper, the contribution of factors affecting the thinning rate of a geothermal
casing, such as temperature, flow velocity, pH, well geometry and corrosion species,
was studied. The effects of several corrosive species on casings were also studied.
The corrosive species and the factors affecting the thinning rate of the production
wells of the Leyte geothermal production field were analysed with multiple linear
regression models in order to determine the dependency of the thinning rate on these
parameters. Fluid discharge measurements and sampled chemistry concentrations at
the surface were simulated at downhole conditions using software HOLA and
WATCH. The results were analysed statistically using ANOVA, a P value test, and
multiple regression coefficients. Adjusted R2 of the regression analysis and mean
absolute percentage error (MAPE) aided in selecting a good regression model. The
study showed that fluid discharge characteristics such as temperature, velocity, pH,
steam fraction and geometry of the well contribute about 56.71% to the thinning rate
of the casing. The predicted thinning rate model also shows similar trending of the
average thinning rate compared to the measured thinning rate for the first and second
surveys of repeatedly measured wells.
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Ponce 732 Report 30
TABLE 9: Summary of parameter estimates
Case model Variables Coefficients Standard error t Stat P-value
Intercept 29.4158 1.7118 17.1841 2.92 x 10 -59
1
-3.6181 0.2898 -12.4852 1.07 x 10 -33
-0.7349 0.0433 -16.9838 4.59 x 10 -58
-5.9338 0.1658 -35.7958 8.72 x 10 -191
Intercept 30.8487 1.6602 18.5816 7.98 x 10 -68
-4.1648 0.2859 -14.5655 2.50 x 10 -44
2 -0.5784 0.0450 -12.8427 1.95 x 10 -35
-5.1166 0.1826 -28.0276 5.59 x 10 -133
0.0720 0.0077 9.3109 5.97 x 10 -20
Intercept 23.4251 2.1111 11.0959 2.77 x 10 -27
-3.0741 0.3434 -8.9522 1.32 x 10 -18
3
-0.7261 0.0518 -14.0303 1.77 x 10 -41
-4.5885 0.2036 -22.5374 7.44 x 10 -94
0.3005 0.0538 5.5811 2.96 x 10 -08
0.0529 0.0084 6.3153 3.81 x 10 -10
Intercept 2.61 x 10 -02 0.0241 1.0815 2.80 x 10 -01
-1.09 x 10 -05 0.0000 -5.0462 5.22 x 10 -07
-3.18 x 10 -03 0.0019 -1.6717 9.49 x 10 -02
4
2.80 x 10 -04 0.0000 20.1761 5.22 x 10 -78
1.11 x 10 -05 0.0001 0.0951 9.24 x 10 -01
4.86 x 10 -02 0.0058 8.4308 9.89 x 10 -17
3.73 x 10 -04 0.0000 7.8152 1.21 x 10 -14
-4.94 x 10 -06 0.0000 -3.1630 1.60 x 10 -03
Intercept -4.4051 1.4990 -2.9387 3.36 x 10 -03
-0.7249 0.0555 -13.0570 1.71 x 10 -36
0.9019 0.2729 3.3046 9.80 x 10 -04
5
0.0653 0.0087 7.4773 1.48 x 10 -13
-1.3214 0.2644 -4.9968 6.71 x 10 -07
0.4364 0.0419 10.4157 2.30 x 10 -24
0.6935 0.2239 3.0976 2.00 x 10 -03
0.7771 0.2765 2.8102 5.03 x 10 -03
Intercept -19.8154 3.7784 -5.2444 2.08 x 10 -07
-0.2237 0.0884 -2.5311 1.16 x 10 -02
6 0.0718 0.0137 5.2574 1.95 x 10 -07
3.5387 0.7192 4.9203 1.08 x 10 -06
0.1368 0.0445 3.0745 2.19 x 10 -03
the stability of iron sulphide were observed. However, due to a continuing decrease in pH, the corrosion
reaction moved from the limits of FeS into Fe ++ , which is free of corrosion. This signifies that the pH of
the fluid predominantly controls the thinning rate of the casing and is in agreement with the experimental
results of Sanada et al. (1998); thus, the ph of the fluid predominantly controls the rate of corrosion.
The thinning rate of the casing is also higher in the low velocity range, as shown in Figure 7. The
velocity of the fluid at downhole increases as the fluid phase changes from single to two-phase, as
induced by boiling. The observed trend of a higher thinning rate at lower fluid velocity implies that
thinning of the casing occurs at the velocity where the fluid is in a liquid phase condition. Slow velocity
of the fluid results in longer residency time; this gives more time for thinning reactions at the surface of
the casing. Most of the wells with higher thinning rates were wells with low pH fluid (Wells 1, 2, 3, 19,
16 and 15).
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