ecda implementation on eden yuturi 18 inch gathering pipelines

ECDA IMPLEMENTATION ON EDEN YUTURI 18” GATHERING PIPELINES Carlos A. Melo G. Petroamazonas EP Quito, Ecuador

ABSTRACT In 2010, mechanical integrity personnel assessed five 18” diameter gathering pipelines in the Eden Yuturi field (Ecuador’s Amazon basin, South America), as part of the Pipeline Integrity Management Plan. The assessment of what amounted to 23.5 km of pipelines was carried out using an External Corrosion Direct Assessment Methodology (ECDA) developed and implemented following NACE-SP0502-2008 standard. This document presents a summary of the results of the ECDA implementation in the Eden Yuturi Field. During the pre-assessment stage, we found four preconditions that justified the development and implementation of the ECDA project:

• Following the CFR Title 49, Part-195.6, the Eden Yuturi field is an Unusually Sensitive Area.

• More than 50% of the total production of the company is transported by the five gathering pipelines included in the study.

• The oldest pipeline was constructed in 2002 and the newest in 2008.

• On July of 2008 a leak was detected in one of these gathering pipelines. With these antecedents, in 2008 CIS and DCVG indirect inspections were carried on the five gathering pipelines. We proceeded with three dig inspections. After the inspection, external pitting was discovered on one pipeline. The discovery of pitting, in addition to the previously found and corrected leakage, reinforced the need for developing a complete ECDA analysis. In 2010, we carried CIS and DCVG Indirect Inspection Techniques on the pipelines. Within the framework of NACE Conference Papers 05184 and 08143, we defined eight dig sites. After digging we found coating damage at all the dig sites. As part of post-assessment, we conclude that there was a need to develop separate ECDA projects for all the river crossings, as well as Internal Corrosion Direct Assessment (ICDA) for the Eden Yuturi Gathering pipelines. Keywords: ECDA assessment, CIS, DCVG, indirect inspection, multiphase pipelines.

INTRODUCTION Catastrophic failures in pipeline systems can generate significant economic losses, environmental havoc, and sometimes lead to human casualties. In response to these incidents, there has been a push to develop standards and regulations to insure pipeline integrity. Although the implementation of most of these standards has been done in developed countries—such as the U.S.—the use of pipelines is widespread. Thus, there is a need to adopt and implement Pipeline Integrity Management Systems in other areas and conditions. This document presents a summary of the results of the ECDA implementation in the Eden Yuturi Field [Eastern Ecuador]. According to NACE training Manual for Pipeline Corrosion Integrity Management there are three possible methodologies of evaluating the pipeline integrity. These methods are:

• Hydrostatic Test

• In line inspection

• Direct Assessment: o External Corrosion Direct Assessment o Internal Corrosion Direct Assessment o Stress Corrosion Cracking Direct Assessment

Additionally, the ASME B31.8 S standard recommends an evaluation of the pipeline integrity every five years. In the case of the Eden Yuturi 18’’ Gathering Pipelines (hereafter identified as EY18GP), a hydrostatic test was performed as a part of the commissioning process. No further testing (including inline inspection) was performed on the EY18GP due to many operational difficulties. In 2010, the pipeline integrity personnel decided to implement External Corrosion Direct Assessment as a part of the Pipeline Integrity Program. The process was developed and implemented following NACE-SP0502-2008 standard (Pipeline Integrity Management Programs in pipelines located in high consequence areas). We adopted this protocol for three reasons: first, the Eden Yuturi field qualifies as an unusually sensitive area (CFR Title 49, Part-195.6) given its location upstream of Ecuador’s Yasuni National Park; second, more than 50% of the total production of the company is transported by the five gathering pipelines we studied; and third, in July of 2008 a leak was detected on one these pipelines.

BACKGROUND Petroamazonas EP (PAM) is one of Ecuador’s two public State-owned companies. It operates Block 15 in the Amazon Basin (among others). In 2010, PAM’s Block 15 average production was 96,000 oil barrels per day; approximately 57% of this production was transported in the EY18GP. The EY18GP includes three above ground pipelines (that transport approximately 2% of the field production) and six below ground pipelines (that transport 98% of the field production).The oldest of the 18’’ gathering pipelines were constructed in the year 2002 and the newest pipeline started its operation in 2008. Five of the six below ground gathering pipelines were included on the ECDA analysis.

Additional to the ECDA program for the EY18GP, PAM mechanical integrity personnel together with the Mechanical Engineering Department of Ecuador’s National Polytechnic School (MED) developed a Pipeline Integrity Plan under the API-1106 standard, and Muhlbauer’s Pipeline Management Manual, Third Edition, 2004. The main objective of this project was to identify the risk level of the EY18GP and to recommend actions for its reduction to acceptable levels. This project was developed between January and July of 2010. This project identified the threats of external corrosion to the EY18GP; further analysis demonstrated that the implementation of the ECDA process reduced considerably the threat of external corrosion in this pipeline system. Figure 1 shows the distribution of EY18GP in the Eden Yuturi Field.

Figure 1. EY18GP Diagram

ECDA PRE-ASSESMENT Details about nomenclature, pipeline length, year of installation, and operating data (temperature and pressure) are included in Table 1.

Table 1 Eden Yuturi 18” Gathering Pipelines Properties

Eden-Yuturi 18”gathering pipelines Operating Operating Length Year Temperature Pressure Region Pipeline (m) installed (°F) (°C) (psi) (kPa)

1 Pad G – Y 7150 2004 185 85.00 294 2027.13 2 Pad J – Pad C 1210 2007 200 93.00 245 1689.28 3 Pad F – Pad A 7140 2004 200 93.00 299 2061.61 4 Pad A – EPF Line 1 4200 2002 200 93.33 193 1330.74 5 Pad A – EPF Line 2 3780 2008 200 93.00 193 1330.74 Note: All pipelines: Ø 18”, wall thickness 7.92 mm, pipe material API 5LX42 and FBE external coating; all pipelines transport a multiphasic fluid (oil, gas and water) and have internal coating. To check pipeline integrity, we perform two types of surveys:

• Every three-months-monitoring in EY18GP test stations. These surveys are performed using cathodic protection current interruption in order to get ON and OFF potentials of pipeline versus the copper – copper sulfate reference electrode (CSE). During this survey the integrity personnel also measure soil resistivity at several depths in order to measure this parameter in the layer where the pipeline is operating.

• CIS and DCVG surveys were performed in the EY18GP in the years 2007, 2008 and 2010. The data obtained in the surveys from the years 2008 and 2010 was stored in the company’s Pipeline Integrity Software to facilitate the analysis. The full data from the 2007 surveys was not available. After analysis of the data from the 2008 CIS and DCVG surveys three direct examination sites were evaluated.

Data collection Pipeline PAD A – EPF line 1 (Region 4). We conducted CIS and DCVG surveys in 2008. The DCVG survey detected eight anomalies in this pipeline. Two direct examinations were performed. After digging on the sites of direct examinations, all coating defects where repaired using Polyken tape. This kind of coating can produce cathodic protection current shielding when disbonded due its dielectrical properties. The station numbers of these two interventions are 5+44 and 31+36 (Figure 2 and 3).

Additionally, a leak was detected in this pipeline on July 13, 2008. The station number of this leak is 30+00 (approximately). According to the failure report the damage was caused by a dent in the pipe (probably during construction) and external corrosion (Figure 4).

Data collection Pipeline PAD G-Y (Region 1). The 2008 DCVG survey detected three anomalies in this pipeline. One of these three anomalies was analyzed using direct examination. This defect is located in station number 58+06. External localized corrosion was detected in this site. Therefore, a clamp was installed over the defect and the coating was repaired using Polyken tape (Figures 5 and 6). Data collection Pipeline PAD F-PAD A (Region 3), PAD J-PAD C (Region 2), and PAD A-EPF Line 2 (Region 5). One coating defect was detected in the 2008 DCVG survey. This defect was not analyzed using direct examination. No anomalies were detected in the 2008

DCVG survey of the pipeline Pad J – Pad C. The pipeline from Pad A – EPF Line 2 was not surveyed in the year 2008 because it was completed after the indirect inspections were performed.

Figure 2. Direct Examination 5+44 2008 Figure 3. Direct Examination 31+36 2008

Figure 4. Leak, External Corrosion 3+000 Figure 5. Direct Examination 58+06 2008

Figure 6. Clamp located in 58+06, 2008

ECDA Feasibility, Indirect Inspection Tools selection, and ECDA Regions. The main reason to support the feasibility of the 2010 ECDA was that external corrosion had been detected in 2008. Additionally, due to the previous external corrosion presence in two of the five ECDA regions, the parameters to determine the necessity of direct examination in these regions were made stricter. We selected CIS and DCVG indirect inspection tools for the 2010 ECDA after consulting Table 2 of NACE ECDA SP0502-2008. Given that the EY18GP are externally coated with FBE, installed in a non-rocky soil (clay), and in some places are covered with coatings that can produce impress cathodic protection current shielding (such as Polyken tape or concrete sleeves). The primary objective of the pre-assessment in an ECDA analysis is the determination of the ECDA regions, therefore according to section 3.5 of NACE SP-0502-2008 the following ECDA regions were established for the EY18GP:

Table 2. ECDA Regions

Wall Previous

External Thickness Corrosion

Region Pipeline Coating (mm) Detected

1 Pad G - Y FBE 7.92 Yes

2 Pad J - Pad C FBE 7.92 No

3 Pad F - Pad A FBE 7.92 No

4 Pad A - EPF Line 1 FBE 7.92 No

5 Pad A - EPF Line 2 FBE 7.92 Yes ECDA indirect inspection. According to section 3.4 of NACE SP-0502-2008, we used CIS and DCVG as indirect inspection techniques for the 2010 surveys of the EY18GP.

• Region 1, Pipeline Pad G – Y: 14 DCVG anomalies were detected in this region all of them with a cathodic/cathodic status. Detailed information of these anomalies is shown in Table 5. Additionally, in Figure 7 there is a detail of the alignment of CIS and DCVG surveys.

• Region 2, Pipeline Pad J – C: 3 DCVG anomalies were detected in this region all of cathodic status. Detailed information of these anomalies is shown in Table 7. Additionally, in Figure 9 there is a detail of the alignment of CIS and DCVG surveys.

• Region 4, Pipeline Pad A – EPF Line 1: 18 DCVG anomalies were detected in this region all of them with a cathodic/cathodic status. Detailed information of these anomalies is shown in Tathem with a cathodic/cathodic status. Detailed information of these anomalies is shown in Table 6. Additionally, in Figure 8 there is a detail of the alignment of CIS and DCVG surveys.

• Region 3, Pipeline Pad F – A: 4 DCVG anomalies were detected in this region all of them with a cathodic/ ble 8. Additionally, in Figure 10 there is a detail of the alignment of CIS and DCVG surveys.

• Region 5, Pipeline Pad A – EPF Line 2: No DCVG anomalies were detected in this region.

ECDA indirect inspection Indications classification. In order to set the results of the 2010 surveys within the framework of NACE Conference Papers 05184 and 08143, we developed a classification scheme detailed in Tables 3 and 4. In Tables 5 to 8, we show the results of applying the Criteria for Prioritization of Intervention to the results of the 2010 (CIS and DCVG) indirect inspections.

Table 3. Criteria for classification of indications

Survey Type

Indication

Minor Moderate Severe

CIS mVcse OFF More Positive than -950 and More Negative than -900

mVcse OFF More Positive than -900 and More Negative than -850.

mVcse OFF More Positive than -850

DCVG % IR from 2.5% to 15% and C/C behavior.

% IR from 15% to 35% and C/C behavior

%IR greater than 35% and C/A or A/A behavior

Table 4. Criteria for prioritization of intervention

DCVG

PRIORIZATION

CIS ECDA WITH Previous Corrosion Detected

CIS ECDA WITHOUT Previous Corrosion Detected

SV MD MN NI SV MD MN NI

1 2 3 4 1 2 3 4

DCVG, SV 1 I I S S I S S S

DCVG, MD 2 I S S M S S M M

DCVG, MN 3 S S M M S M M M

DCVG, BT 4 S M M N S M M N

DCVG, NI 5 N N N N N N N N

Legend: SV: Severe Indication I: Immediate Action Required MD: Moderate Indication S: Scheduled Action Required MN: Minor Indication M: Suitable for Monitoring BT: Below threshold N: No Action Required NI: No Indication N/A: Not Applicable

Alignment of indication for ECDA region 1

Table 5. Prioritization of intervention Pipeline PAD G - Y

ECDA ON OFF ECDA

Defect Station IR DCVG Potential Potential CIS

Nº Number % Status Criteria [-mVcse] [-mVcse] Criteria Intervention

1 0+012 22.11 C/C MD 1333 1216 NI M

2 0+846 1.48 C/C BT 1381 1236 NI N

3 2+188 6.38 C/C MN 1340 1218 NI M

4 2+226 4.68 C/C MN 1338 1210 NI M

5 2+748 2.56 C/C MN 1325 1190 NI M

6 0+010 7.72 C/C MN 1249 1100 NI M

7 0+020 4.41 C/C MN 1280 1134 NI M

8 0+122 5.04 C/C MN 1296 1121 NI M

9 0+140 15.33 C/C MD 1297 1172 NI M

10 2+122 2.96 C/C MN 1226 1102 NI M

11 2+388 3.12 C/C MN 1349 1162 NI M

12 3+254 5.98 C/C MN 1328 1159 NI M

13 4+018 45.09 C/C SV 1339 1156 NI S

14 4+270 3.27 C/C MN 1339 1156 NI M

Facilities

PAD G

PAD G

PAD G

PAD G

PAD G

PT-01G

PT-01G

PT-01G

PT-01G

PT-01G

PAD D

PAD D

PAD D

PAD D

PAD D

PAD J

PAD J

PAD J

PAD J

PAD J

PT-01J

PT-01J

PT-01J

PT-01J

PT-01J

PAD C

PAD C

PAD C

PAD C

PAD C

PT-04A

PT-04A

PT-04A

PT-04A

PT-04A

Y-EPF

Y-EPF

Y-EPF

Y-EPF

Y-EPF

DCVG 2010 G-YDCVG MNDCVG MDDCVG SV

% IR

45

40

35

30

25

20

15

10

5

0

DCVG 2010

CIS 2010 G-Y OnCIS 2010 G-Y OffCIS MNCIS MDCIS SV

-mVcse

-0.8

-0.9

-1

-1.1

-1.2

-1.3

-1.4

-1.5

-1.6

CIS 2010

0+00 10+00 20+00 30+00 40+00 50+00 60+00 70+00

Figure 7. Indications Alignment Indirect Inspection 2010, Pad G - Y


Table 6. Prioritization of intervention Pipeline PAD J – C

ECDA ON OFF ECDA



1 0+012 6.41 C/C MN 1275 1122 NI M

2 0+096 48.08 C/C SV 1207 1149 NI S

3 1+145 45.38 C/C SV 1179 1094 NI S

Facilities

PAD J

PAD J

PAD J

PAD J

PAD J

PT-01J

PT-01J

PT-01J

PT-01J

PT-01J

PAD C

PAD C

PAD C

PAD C

PAD C

DCVG 2010 J-CDCVG MNDCVG MDDCVG SV

%IR

50

45

40

35

30

25

20

15

10

5

0

DCVG 2010

CIS 2010 J-C OnCIS 2010 J-C OffCIS MNCIS MDCIS SV

-mVcse

-0.9

-1

-1.1

-1.2

-1.3

-1.4

CIS 2010

0+00 2+50 5+00 7+50 10+00

Figure 8. Indications Alignment Indirect Inspection 2010, Pad J – C


Table 7. Prioritization of intervention Pipeline PAD F – A

ECDA ON OFF ECDA



1 0+012 4.53 C/C MN 1330 1195 NI M

2 0+166 18.64 C/C MD 1295 1197 NI M

3 0+172 40.57 C/C SV 1297 1210 NI S

4 1+488 8.09 C/C MN 1311 1192 NI M

Facilities

PAD F

PAD F

PAD F

PAD F

PAD F

PT-02F

PT-02F

PT-02F

PT-02F

PT-02F

PT-01F

PT-01F

PT-01F

PT-01F

PT-01F

PAD A

PAD A

PAD A

PAD A

PAD A

DCVG 2010 F-ADCVG MNDCVG MDDCVG SV

% IR

45

40

35

30

25

20

15

10

5

0

DCVG 2010

CIS 2010 F-A OnCIS 2010 F-A OffCIS MNCIS MDCIS SV

- mVcse

-0.9

-1

-1.1

-1.2

-1.3

-1.4

CIS 2010

0+00 10+00 20+00 30+00 40+00 50+00 60+00 70+00

Figure 9. Indications Alignment Indirect Inspection 2010, Pad F - A

Alignment of indication for ECDA region 4 Table 8. Prioritization of intervention Pipeline PAD A – EPF LINE 1

ECDA ON OFF ECDA Defect Station IR DCVG Potential Potential CIS Nº Number % Status Criteria [-mVcse] [-mVcse] Criteria Intervention

1 0+010 45.90 C/C SV 1128 1027 NI S 2 0+050 8.67 C/C MN 1182 1056 NI M 3 0+546 18.21 C/C MD 1122 1053 NI M 4 0+558 37.19 C/C SV 1111 1046 NI S 5 1+670 6.98 C/C MN 1252 1140 NI M 6 1+845 6.17 C/C MN 1265 1135 NI M 7 1+938 4.96 C/C MN 1294 1117 NI M 8 2+048 2.54 C/C MN 1319 1125 NI M 9 2+544 4.50 C/C MN 1329 1148 NI M 10 3+228 27.48 C/C MD 1221 1096 NI M 11 3+250 16.32 C/C MD 1194 1101 NI M 12 3+508 22.14 C/C MD 1216 1086 NI M 13 3+764 9.96 C/C MN 1246 1016 NI M 14 3+774 33.36 C/C MD 1268 1058 NI M 15 3+806 20.28 C/C MD 1252 1066 NI M 16 3+852 5.95 C/C MN 1212 995 NI M 17 3+892 23.79 C/C MD 1083 924 MN S 18 3+976 10.01 C/C MN 962 823 SV S

Facilities

PAD A

PAD A

PAD A

PAD A

PAD A

PT-03A

PT-03A

PT-03A

PT-03A

PT-03A

PT-02A

PT-02A

PT-02A

PT-02A

PT-02A

EPF

EPF

EPF

EPF

EPF

DCVG A-EPF 2010DCVG MNDCVG MDDCVG SV

% IR

50

45

40

35

30

25

20

15

10

5

0

DCVG 2010

CIS 2010 A-EPF OnCIS 2010 A-EPF OffCIS MNCIS MDCIS SV

-mVcse

-0.8

-0.9

-1

-1.1

-1.2

-1.3

-1.4

CIS 2010

0+00 10+00 20+00 30+00

Figure 10. Indications Alignment Indirect Inspection 2010, Pad A – EPF Line 1

Alignment of indication for ECDA region 5 We found no Indications with the indirect inspection techniques (CIS and DCVG) in this region.

DIRECT EXAMINATION Prioritization of interventions. According to the data analysis detailed in tables 5 to 8, eight direct examination sites were established (Scheduled) as it is detailed in table 9.

Table 8. Prioritization of intervention EY18GP

ECDA ECDA

ECDA OFF WITH WITHOUT

ECDA Station Defect IR DCVG Potential Previous Previous

Region Number Nº % Criteria [-mVcse] Corrosion Corrosion Intervention Priority

4 0+010 1 45.90 SV 1027 NI S 1

1 4+018 13 45.09 SV 1156 NI S 2

2 0+096 2 48.08 SV 1149 NI S 3

2 1+145 3 45.38 SV 1094 NI S 4

4 0+558 4 37.19 SV 1046 NI S 5

3 0+172 3 40.57 SV 1210 NI S 6

4 3+892 17 23.79 MD 924 MN S 7

4 3+976 18 10.01 MN 823 SV S 8

Direct examination ECDA Region 1. One direct examination site was performed on pipeline form Pad G – Y- The station number of this site is 4+018 (Figure 11). Despite the fact that general coating damage was found in this site no external corrosion was detected. The possible cause of coating failure is the elevated temperature of operation of the pipeline (85°C). Direct examination ECDA Region 2. Two direct examination sites were performed on pipeline form Pad J – C- The station number for these sites are 00+96 and 11+45 respectively. No coating defects were found on these sites because the pipe was covered by concrete sleeves (therefore the indirect inspection tools are not applicable for these sites). Direct examination ECDA Region 3. One direct examination site was performed on pipeline form Pad F – A- The station number of this site is 01+72 (Figure 12). No external corrosion was detected although a damaged heat shrinkable sleeve was found at this site. We believe that this coating failure was caused by improper installation procedure and lack of surface profile preparation before the installation of the sleeve. Direct examination ECDA Region 3. Four direct examination sites were performed on pipeline form Pad A – EPF Line 1- The station number for these sites are 00+10 (Figure 13), 05+58 (Figure 14), 38+92 (Figure 15) and 39+76 (Figure 16) respectively. At these sites, we found damaged coating, but no signs of external corrosion.

• In 00+10 the main cause of the DCVG anomaly was the contact between the pipeline and a below ground support.

• In 05+58 severe coating damage was found at 6 pm in the pipeline. The possible cause of coating failure is the elevated operation temperature (greater than 90°C).

• In 38+92 minor coating damage was found; we also found a concrete sleeve, therefore indirect inspection tool (CIS and DCVG) are not suitable.

• In 39+76 minor coating damages were detected. The DCVG survey found a defect in this site because the contact between the pipeline and the below ground support produced a fake indication.

Coating Repairs. Coating repair was performed in six of the eight intervention sites (Figures 17 to 22), because two sites from Region 3, pipeline F-A were covered by concrete sleeves. The pipelines were sand blasted up to SSPC SP 10 and coated with a 100% solid two- components coating. Parameters such as temperature and environmental humidity were controlled before and during cutting application. After an adequate cure-time, Dry Film Thickness (DFT) was controlled according to SSPC SP PA-2 1996. Finally a ‘high voltage holiday test’ was performed in all the coating repairs with a voltage according to the coating manufacturer specifications. Calculation of remaining life. Calculation of remaining life is not applicable because we did not find external corrosion. Additionally wall thickness measurements using Ultrasonic Test Scan A was performed in all the dig sites. We did not found evidence of internal corrosion. Post Assessment. As part of the ECDA process, one sample CIS & DCVG null (in which no indications of corrosion were found by using the indirect inspection tools) dig site was selected and analyzed. No coating damage or external corrosion was detected at this site (Figure 23).




Figure 17. Pad G – Y , 04+18, 2010 Figure 18. Pad F – A , 01+72, 2010

Figure 19. Pad A– EPF , 00+10, 2010 Figure 20. Pad A – EPF , 05+58, 2010

Figure 21. Pad A – EPF , 38+92, 2010 Figure 22. Pad A – EPF , 39+72, 2010

Figure 23. ECDA validation site, no coating

defect detected 2010.

CONCLUSION

• Although we found coating damage in six of the eight direct examination sites, we found no signs of external corrosion. This shows that the EY18GP’s cathodic protection system is working adequately.

• The contact between below ground supports and the pipelines generate fake DCVG indications.

• ECDA methodology is not applicable for concrete coated pipelines due to the electrical shielding produced by the concrete.

• Suitable inspection techniques must be determined for the EY18GP in river crossings and road crossings due to the concrete coat used on these places.

• An Internal Corrosion Direct Assessment (ICDA) must be implemented for the EY18GP in order assess internal corrosion for this important pipeline system.

ACKNOWLEDGEMENTS

The author wishes to express his gratitude to all the Department of Maintenance at Petroamazonas EP for their constant support in order to develop this important project. Additionally, the author thanks NACE for the quality of the training programs, standards and technical information that were provided for the development of this study. Finally the author acknowledges Dr. Cristian Melo of Florida International University for his comments on an earlier draft.

REFERENCES

1. NACE Standard Practice SP0502-2008, “Pipeline External Corrosion Direct

Assessment Methodology”, Houston, 2008.

2. NACE 2008. Conference Paper No.08143, Evaluation of Classification and Prioritization

Criteria Based on the Results of Direct Examinations, S.M. Segall, P. Eng. R.A.

Gummow, P. Eng. Corrosion Service Company Limited.

3. NACE 2005. Conference Paper No.05184, Results from an ECDA Plan, S.M. Segall, P.

Eng. R.A. Gummow, P. Eng. Corrosion Service Company Limited.

4. NACE Pipeline Corrosion Integrity Management Training Manual, Houston, 2009.

5. Final Report CIS and DCVG Surveys in the EY18GP, Petroenergy, 2008.

6. Final Report CIS and DCVG Surveys in the EY18GP, Petroenergy, 2010.

ecda implementation on eden yuturi 18 inch gathering pipelines

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