Inspection Based Corrosion Rate Mapping for Remaining Strength and Remaining Life of Two-Phase Geothermal Steel Piping

Geothermal as green energy has many advantages for power generation due to cleanness, zero waste, and renewable. However, during the operational period, corrosion and scaling in two-phase geothermal steel piping are two main challenges that can cause leaks, reduce flow performance, and reduce safety. Therefore, the two-phase geothermal steel piping remaining strength and life analysis are conducted to manage its integrity. This paper presents a case study on the corrosion rate mapping, excessive corrosion, and scaling for a two-phase flow line in Well Pad B, one of the geothermal production facilities in Unit 1 Dieng, PT Geo Dipa Energi. The data used for this assessment refer to the results of the wall thickness inspection; meanwhile, the data used for scaling and corrosion analysis refer to field observation results. The results of the remaining strength calculation, using both ASME B31G Original and Modified methods, indicate that the remaining strength of all tested points was deemed acceptable in 2020. The remaining life calculation, based on API 579, reveals that the longest remaining life is 9.08 years and the shortest is 0.83 years in the long-term scenario. In the short-term scenario, the longest remaining life is 57.29 years and the shortest is 11.01 years. The corrosion rate is classified as Class I, based on the total key species, with a predictive corrosion rate value > 1.3 mm/year or 51.1 mpy (poor level). In the long-term scenario, the highest corrosion rate recorded is 258.7 mpy (unacceptable level), while the lowest is 39 mpy (fair level). In the short-term scenario, the highest corrosion rate observed is 23 mpy (fair level), and the lowest is 9 mpy (good level). Furthermore, based on the calculation of the Ryznar Stability Index, the fluid has the potential to generate heavy scale, with an RSI value of 4.1.


Introduction
Geothermal energy systems represent a viable choice for meeting our energy needs.With the increasing demand for energy and the promising potential of geothermal energy sources, it is crucial to ensure the efficient functioning of the entire geothermal system, including the well and surface equipment in the geothermal field to maximize the contribution of geothermal energy towards fulfilling the world's energy requirements.
In a geothermal system, the steel piping is a crucial part of equipment for transporting the working fluid.However, it is worth noting that high-pressure piping and pipelines, especially those with a long service history, may be susceptible to corrosion and scaling.Despite this, various studies, including theoretical analyses, scientific research, and industry operating experience, suggest that there is a range of acceptable metal loss caused by corrosion can be acceptable without compromising the safe operation of the steel piping.
Several studies have been carried out to analyze remaining strength, corrosion, and scaling phenomena.In 2006, the Remaining Strength analysis was conducted for Corroded Pipeline with Complex Shape Defects under Combined Loading [1].Additionally, several studies have been conducted to improve the integrity of pipes and other machine components [2][3][4] [5][6][7] [8].Regarding the scaling phenomena, an investigation for the mechanism of scale formation and corrosion based on the pH of geothermal fluids in 2020 using the Pourbaix-Lindal and Rayznar index diagram approach that correlated with the velocity profile of geothermal [9].In 2021, [10] investigated the phenomena of scaling and corrosion on crude oil pipelines.The studies could be used to determine the remaining strength, remaining life, corrosion, and scaling phenomena in geothermal steel piping.
In this study, an API 5L grade B line pipe in geothermal power plant piping system was evaluated using Ultrasonic Inspection (UT) to determine the remaining wall thickness.This assessment takes place in geothermal production facilities Unit 1 Dieng, Central Java, Indonesia owned by PT Geo Dipa Energi.The result of UT inspection is used as a database to determine the remaining strength and remaining life of geothermal steel piping.The evaluation of metal loss to determine the remaining strength in pressurized steel piping was conducted using ASME B31.G.Meanwhile, the evaluation for remaining life in geothermal piping was conducted using API 579.Moreover, fluid characteristic to predict the scale production was also determined using Ryznar Stability Index (RSI).

Assessment and Analysis Methodology
The assessment and analysis will be conducted in 2 phases geothermal flow line with NPS 12" and 16" which transporting fluid from Well Pad B to line B as shown in Figure 1.

Data Collection and Processing
To conduct the assessment and analysis of the remaining strength, remaining life, corrosion, and scaling of steel piping, several types of data are required such as field observation data, fluid data, design data, operational data, and wall thickness inspection data.The S F is calculated following the equation below [14]: The Safe Operating Pressure (P s ) is calculated following the equation below [14]: where   , d, t, M,   , D and SF are flow stress, depth of metal loss, pipe wall thickness, bulging stress magnification factor, failure pressure, pipe outside diameter, and safety factor, respectively.The pipe still meets the conditions to operate if   ≥  ×  or   ≥  ×   where  and   are Hoop Stress and Operating Pressure (May Equal Maximum Allowable Operating Pressure (MAOP) or Maximum Operating Pressure (MOP)) respectively.

Remaining Life Analysis
Based on API 579.As an initial stage, the data needed to determine the remaining life is collected, then in parallel, the corrosion rate and minimum thickness of the pipe are calculated in the longitudinal (tL) and circumferential (tC) directions based on the pipe thickness of the inspection results, and at the final stage, the remaining life is calculated based on the data obtained to determine the long-term remaining life and short-term remaining life.
The where   is minimum wall thickness which is the largest wall thickness value between tL and tC.

Corrosion and Scaling 2.3.1 Corrosion Analysis.
In conducting a corrosion analysis on steel piping, the corrosion classification approach uses the Geothermal Classification System, namely Key Corrosive Species or Total Key Species (TKS).
The level of corrosiveness in the geothermal environment is influenced by several chemical elements, some of these chemical elements are known as Key Corrosive Species.
Corrosive phenomena caused by some or all the Key Species and their relationship to physical factors such as fluid temperature, pressure and fluid flow velocity are uniform corrosion, pitting corrosion, crevice corrosion, stress corrosion cracking (SCC), sulfide stress cracking (SSC), intergranular corrosion, corrosion-fatigue, exfoliation, and erosion corrosion.

Scaling Analysis. The possibility of scaling formation increases along with the increasing of pH.
Various types of scale are formed such as: calcium, silica, and sulfide compounds.There are several metals that may dissolve along with the formed scaling such as: zinc, iron, lead, magnesium etc.
The properties of the flowing fluid are important to predict the potential of scaling formation or even corrosion.In this analysis, the Ryznar Stability Index (RSI) method is used as a quantitative approach.The formula used in the RSI is as follows.
= 2  −  (8) Where   , and  are saturated pH, and actual pH, respectively.The relation between RSI and its indication is shown in Table 1.[16].The geothermal steel piping design and operating data that used in this study is as shown in the Table 2.

RSI
Table 2. Geothermal pipe data [17].The ultrasonic inspection was conducted along the pipe, reducer, and elbow.The inspection test points are marked as illustrated in the Figure 2.  The minimum actual thickness at some test points is higher than the previous thickness due to the silica scaling phenomenon that occurs when geothermal fluids cool and silica precipitates out of the fluid, forming deposits on the inner surface of the piping and being detected by the UT Thickness Tool.During the site survey, it is confirmed that the scaling, leak, and corrosion have been observed and documented as shown in the Figure 3.  4 is important to determine the corrosion status and the scaling potential as per total key species.G.The calculation of the remaining strength in the steel piping refers to the data from the wall thickness inspection in 2020.The existing data is processed to determine the maximum corrosion depth that occurs.The corrosion length value is determined from the maximum corrosion length data in ASME B31.G.This value will be used to calculate the remaining strength of the pipe according to the ASME B 31.G standard.

Material Data Assumption
The remaining strength analysis criteria based on ASME B31.G is the inspection section with a ratio of d/t between 10% -80%.Therefore, elbow (E1, E2) and reducer (R1) segments are not eligible for remaining strength analysis because the d/t < 10%.The calculation result of remaining strength, with 1.25 of SF, is shown in Figure 4.The remaining strength calculation acceptance criteria is   ≥  ×  or   ≥  ×   .The  ×  is far below the original and modified   , therefore the pipe is still in a proper operating condition.If the  ×  is close below the   , there is a possibility that the pipe will be deformed.This condition serves as an initial warning sign of possible pipe failure, and its progression may accelerate due to other contributing factors.It can be seen also in Figure 4 that the  ×   is below the original and modified   (acceptable).This means that the pipe can still operate even though it has been corroded.
The calculation of Safe Operating Pressure (Ps) based on ASME B31.G Level 1 for each pipe segment in Figure 5 shows that several pipe segments are predicted to fail after reaching a certain time.The declining Ps value resulting from the operating conditions highlights the importance of monitoring the remaining lifespan of the pipe to its integrity is maintained.
With the constant operating pressure in 2 phase line with 12" NPS, then the Ps of P3 will be less than OP1 after 2 years while the Ps of P1 and P2 will be less than OP1 after 2.5 years.
In 2 phase line with 16" NPS or after Reducer and with constant operating pressure, the Ps of P12, P13 and E4 will be less than OP2 after 1.5 years.Another Ps in this line will be less than OP2 after 2 and 2.5 years, except the Ps of It can also be seen in the Figure 5 that the Ps of R1, E2 and E1 is still greater than OP1 and OP2 in the third year.
While the calculation of remaining strength using ASME B31.G standards is focused on corrosionrelated factors, it is also necessary to analyze other factors that can contribute to pipe failure.For this reason, the addition of a safety factor and the conducting of periodic inspections need to be considered properly.In addition, to determine how long the pipe can operate then it is necessary to refer to the Remaining Life analysis of the pipe based on API 579.

Remaining Life.
After the data is processed, the results of the calculation of the remaining life of the pipe at 18 points (13 Pipes, 4 Elbows and 1 Reducer) for the long-term corrosion rate scenario and 6 test points (4 Pipes, 1 Elbows and 1 Reducer) with a short-term corrosion rate scenario can be seen in Figure 6.Based on the long-term corrosion rate scenario graph in Figure 6 (a), the lowest remaining life is at the P12 test point or on the 16" sch 40 pipe with 0.83 years for its remaining life since this point has the lowest average thickness of inspection results, 0.45 in, with the highest corrosion rate.Meanwhile, the maximum remaining life is at the E2 test point or at the elbow 16" sch 40 with 9.08 years for its remaining life because this point has the highest average thickness of inspection results with the lowest corrosion rate.
Figure 6 (b) shows the short-term corrosion rate scenario graph with the maximum remaining life value is 57.29 years at the R1 test point, and the minimum remaining life is 11.01 years in the P8 test point.There are only 6 remaining life points that can be determined in short-term corrosion rate scenario, as the wall thickness values from the most recent inspection were greater than the previous inspection for other points.The increase in pipe wall thickness may be attributed to the presence of a ferrous oxide layer in the area, since UT thickness measurement provides a wall thickness value that includes the oxide layer as illustrated in Figure 7, resulting in a larger overall wall thickness value than the actual wall thickness of the pipe.This ferrous oxide layer is read by UT thickness because it has the same density as the pipe material.

Classification of Corrosion Based on Total Key Species.
In classifying corrosion based on the total key species, there are several parameters that must be considered.Table 5 shows the actual result based on field data for each parameter.After that, the corrosivity class is determined.Since each parameter has a different corrosivity class, then the corrosivity class I as the worst condition in this case is chosen to represent this entire geothermal pipe system.Table 6 shows the parameter determination of characteristics for corrosion class 1 in geothermal systems.In this Class I, there is a predictive corrosion rate of 1.3 mm/year or 51.1 mpy (poor level) and the type of corrosion is uniform and pitting corrosion on carbon steel.

-50 Fair
Based on the long-term corrosion rate scenario distribution graph of the steel piping in Figure 8 (a), there are 18 test points that are examined.There are 7 test points that are at the unacceptable level, 10 test points are at the poor level and 1 test point is at the fair level.This is directly proportional to the previously calculated remaining life value (high corrosion rate, low remaining life).Figure 8 (b) shows the corrosion rate with a short-term scenario with only 6 corrosion rate points.Corrosion rate value at other points is negative due to the addition of pipe thickness which is read when the UT thickness inspections is performed.This low corrosion rate is caused by the time span between the first inspection and the last inspection, and it does not start from the beginning of the installation to the last inspection, so it is relatively short.Another potential factor that affects the corrosion rate is erosion phenomenon in the pipe segments with the possibility 20.8 mpy to 27.5 mpy of corrosion rate [18].This erosion probably comes from the silica sand that flows along with the fluid as shown in Figure 9. Erosion particles come from silica sand which flows with the fluid, while corrosion that occurs comes from corrosive agent such as chloride ions.4.2.3Scaling Analysis.Scaling analysis is conducted by analyzing the results of field observations and estimating the properties of the flowing fluid using the RSI.According to the data gathered from the survey that showed in Figure 3 (a), the pipe is observed to have silica scale buildup.The thickness of the silica scale ranges from 2-4 mm and the hardness level of silica, based on the Mohs scale which corresponds to a value of 800 kg/mm 2 , is rated at 7.  The presence of silica on the pipe could be due to its flow along with the fluid from the well.Apart from forming scale on the pipe, the hardness level of silica, which is 7 according to the Mohs scale, can also potentially cause erosion on the inner surface.
The indication of scaling is calculated using the RSI.The calculation results with pHs value 5.4 indicate that the flowing fluid has a heavy scale potential with an RSI value of 4.1.

Conclusion
Based on the analysis results, it can be concluded as follows: • The remaining strength of all the Test Points is still acceptable in 2020 based on Original and Modified ASME B31.G calculations.• In long term scenario, the longest remaining life is 9.08 years at the 9th point (E2, elbow area 16" Sch 40), and the shortest is 0.83 years at the 17th point (P12, 16" Sch 40 pipe area).• In short term scenario, the longest remaining life is 57.29 years at the 4th point (R1, reducer area), and the shortest is 11.01 years at the 6th point (P8, pipe area 16" Sch 40).• The Corrosion is classified into Class I based on the total key species, with the types of corrosion in the form of uniform corrosion and pitting corrosion that have a predictive corrosion rate value is > 1.3 mm/year or > 51.1 mpy (poor level).• The highest corrosion rate in the long-term scenario is 258.7 mpy (unacceptable level) at the 16th point (E4, elbow area 16" sch 40), and the lowest is 39 mpy (fair level) at the 9th point (E2, elbow area 16" Sch 40).• The highest corrosion rate in the short-term scenario is 23 mpy (fair level) at the 6th point (P8, pipe area 16" sch 40), and the lowest is 9 mpy (good level) at the 1st, 2nd and 5th Point (P1, E1, and P4).• Erosion factor is another factor that gives the potential to trigger high corrosion rates in long term scenarios.
• The fluid gives the potential to produce heavy scale with an RSI value is 4.1 based on the calculation of the Ryznar Stability Index.

Figure 2 .
Figure 2. Inspection test point schematic ilustration [17].The thickness data of piping, elbow, and reducer in Table3is based on ultrasonic thickness inspection using PANAMETRIC-NDT 37 DL PLUS in 10 April 2020 and 30 May 2020 with 18 Test Point locations.The measurement was conducted at 12, 3, 6, and 9 o'clock position.

Figure 3 .
Figure 3. Site survey data, (a) Piping scale, (b) A leak at replaced reducer, and (c) Corrosion at a bypass line [18].The chemical composition of fluid and operating data in Table 4 is collected based on Certificate of Analysis (Fluid Data) PT Geo Dipa Energi unit Dieng.The chemical composition of fluid in the Table4is important to determine the corrosion status and the scaling potential as per total key species.

Figure 4 .
Figure 4. Graph of remaining strength calculation results.

Figure 5 .
Figure 5. Ps VS years curve at each test point.

Figure 6 .
Figure 6.Remaining life distribution graph based on API 579.(a) long-term corrosion rate and (b) short-term corrosion rate

Figure 8 .
Figure 8. Corrosion rate distribution graph.(a) long-term corrosion rate and (b) short-term corrosion rate.

Figure 9 .
Figure 9. Illustration of erosion on pipe segment, based on field condition root cause analysis.
2.2 Remaining Strength and Remaining Life of the Corroded Geothermal Steel Piping 2.2.1 Remaining Strength Analysis Based on ASME B31.G.The calculation of Failure Stress (S F ) based on ASME B31.G Level 1 shows the maximum value of the pipe that is predicted to fail due to corrosion.So that if the pipe operates under Failure Stress (S F ), the pipe still meets the conditions to operate.

Table 4 .
[19]ical composition of fluid and operating data that affect the potential for scaling[19].

Table 6 .
[21]s I corrosion characteristics in geothermal system[21].Calculation of Corrosion Rate.The long term corrosion rate and short term corrosion rate based on the actual wall thickness obtained from the wall thickness inspection are used to calculate the corrosion rate.The corrosivity level that will be used to determine the level of corrosion rate is shown in Table7below.