Integrity Analysis of the Camisea Transportation System

Failure Analysis AssociatesIntegrity Analysis of the Camisea Transportation System, Peru, S.A., June 2007 Integrity Analysis of the Camisea Transportation System, Peru, S.A., June 2007 Prepared for Inter-American Development Bank 1300 New York Avenue N.W. Washington, DC 20577 Prepared by Exponent 320 Goddard, Suite 200 Irvine, CA 92618 June 8, 2007 Doc. No. SF36292.003 A0F0 0607 0806 June 8, 2007 Contents Page List of Figures List of Tables Acronyms and Abbreviations Limitations Executive Summary Background and Scope of Work Spill Incidents Risk Identification Risk Evaluation Design-Related Risks Construction-Related Risks Geotechnical and Geology-Related Risks Pipe Integrity–Related Risks Seismic-Related Risks Scour-Related Risks Future Activities 1 Introduction 1.1 1.2 1.3 2 Description of the System Operational History Report Organization vi ix x xi xii xii xv xvi xvii xvii xviii xx xxiii xxv xxvi xxvi 1 1 3 3 5 5 5 6 8 8 ii Exponent’s Investigation 2.1 2.2 2.3 Objective Phases of Work Scope 3 Review of NGL Pipeline Incidents 3.1 Background SF36292.003 A0F0 0607 0806 2 3.2 Hydraulic Design of NGL Pipeline 4.4 3.5 5.2.3 Hydrogen-Induced Crack–Related Risks 5.6 5.1 5. 2007 3.1 Geotechnical and Geologic Conditions iii SF36292.3 3.8 Hydrostatic Testing–Related Risks 5.5 3.9 6 Conclusions Geotechnical and Geology-Related Risks 6.2 Hydraulic Design Risks 4.1 Design Background 4.3 5.7 3.7 Pipeline Construction Characteristics Geotechnical Construction Characteristics Clearing Related Risks Trenching-Related Risks Pipe Material–Related Risks Pipeline Field Welding–Related Risks Pipeline X-ray–Related Risks 5.3 Hydraulic Design of NG Pipeline 4.8.June 8.6 3.2.2 5.1 General Review 4.3 4.8.8.2.4 5.003 A0F0 0607 0806 .1 Background 5.4 5 Geotechnical Design Risks Conclusions Construction-Related Risks 5.8 4 First Incident Second Incident Third Incident Fourth Incident Fifth Incident Sixth Incident Summary and Conclusions 8 13 17 21 25 29 30 32 32 33 33 34 35 37 38 40 40 45 46 47 48 50 51 51 51 52 53 54 56 56 Design-Related Risks 4.2 Hydrostatic Testing Results for the Camisea System 5. 2 Permanent Ground Deformation (PGD) Hazards 8.003 A0F0 0607 0806 iv .1 8.3.3.1 Background 7.3.3.June 8.1 10.1 Risk Assessment Methodology 6.3 Seismic Risk Evaluation 8.2 10.3.4 8 Conclusions Seismic-Related Risks 8.5 7 Ongoing Geotechnical Risk Mitigation Conclusions Pipeline Integrity–Related Risks 7.3 Geotechnical Risk Assessment 6.3 Inline Pipe Inspection 7.4 9 Conclusions Scour-Related Risks 9.3 Circumferential Crack Detection 7.3 Wave Propagation Hazards 8.2 Inline Pipe Inspection Results 7.2 9.3 River Crossings and Scour Risks at Buried River Crossings Conclusions 10 Summary and Conclusions 10.2 Application of the Risk Assessment Method 6. 2007 6.3.2 Tectonic Overview Seismic Hazards to Buried Pipelines 8.1 Characterization of Seismic Demand 8.1 7.3.2 Description of Potential Risks and Controls Pipe Material and Damage Tolerance–Related Risks 7.3 Pipeline Design–Related Risks Pipeline Construction–Related Risks Geotechnical and Geology-Related Risks SF36292.2 General Findings 57 60 60 62 69 70 73 73 74 75 75 76 77 78 80 80 82 84 84 85 86 87 88 88 89 93 94 94 94 95 6.4 6.3.1 9. 2 11.6 10.1 11.June 8.5 10. 2007 10.3 11.4 10.7 11 Pipeline Integrity–Related Risks Seismic-Related Risks Scour-Related Risks Summary 96 96 97 97 98 98 101 101 101 Recommendations 11.4 Geotechnical and Geologic Seismic Scour Pipe SF36292.003 A0F0 0607 0806 v . during permanent pipeline repair work. 2006. 23 SF36292. Location of second spill incident. 2 Figure 2. 11 Figure 3. at KP 50+900 showing river crossing and new steel truss bridge carrying the NGL bypass pipeline. red arrows indicate the inner surface of the pipe where the hydrogen-induced crack began. MCI photograph of pipe from the third spill incident. looking downstream. MCI photograph showing frontal view of fracture surface of the pipe from the second spill incident of the NGL pipeline at KP 222+500.003 A0F0 0607 0806 vi . Top: View upstream (downslope) along excavated trench along NGL pipeline. during ROW stabilization work. Photographs taken on June 13. during stabilization work. Photographs taken on June 14. Photographs taken on June 14. 15 Figure 6. Top: View downstream (looking downslope). at KP 200+700. Site of fourth spill incident. White arrows indicate the weld’s root pass in the background to the fracture surface. Top: View upstream showing large landslide above and below ROW. General area of first spill incident. 19 20 Figure 8. 2006. Bottom: View downstream along ROW showing alignment of temporary bypass pipeline (beneath stacked sacks) and new retaining wall at base of cut slope. and yellow arrows indicate the narrow remaining ligament at the outer surface of the pipe. Bottom: View downstream (upslope) across trenches opened for repairs. Figure 5. after stabilization work conducted in 2006. and September 19. at KP 200+700. at KP 8+850. Photographs taken on June 12. 12 13 Figure 4. Photograph taken on September 11. 2006. Figure 9. with the extraction and production (E&P) centered in Malvinas. 2006. a NGL fractionation plant in Pisco. General area of site of first spill incident. 2007 List of Figures Page Figure 1. at KP 8+850. and a NG distribution point in Lurin. Plastic sheeting covers 14-inch NGL pipeline. Bottom: View upstream (looking upslope). General area of the third spill incident. 16 Figure 7. Bottom: View looking upstream. 2006. Right-of-way of the Camisea Transportation System in Peru.June 8. Top: View looking downstream (uphill). MCI photograph showing frontal view of fracture surface of the first rupture at KP 8+850. 2006. at KP 222+500. Excavated NGL pipe section from the sixth spill incident. 2006. White arrows identify the narrow. Observed groove (white arrows) and rupture (red arrows) on the outer surface of the pipe. Risk by sectors for October 2006. Figure 16. Black material is the damaged protective polyethylene cover. Figure 21. Risk by sectors for May 2006. Figure 14. with the outer surface of the pipe being the top portion of the photograph. Trenching and stockpiling of cuttings at KP 391. Figure 26. with the pipe being horizontally aligned and NGL product flow being from the right to the left. Standard installation of NGL pipeline at KP 107. Top: View upstream (downslope) along the ROW. slanted fracture associated with crack nucleation. Figure 20. Figure 23. Bottom: View downstream (upslope) across excavation made to remove unstable soil. Figure 22. Laying of pipe over the Manugali River at KP 92. Change in risk from May to October 2006. Figure 18.June 8. Comparison of the pipeline elevation profile along the ROW. Placement of selected fill as bedding at KP 358 using a machine that separates larger stones from the remaining fill. Figure 24. Figure 17. Photographs taken on June 13. Washington State University website). MCI photograph showing fracture surface of NGL pipeline at the fifth spill incident. General area of the fifth spill incident. Ratio of the maximum operating pressure to the MAOP along the ROW of the NGL pipeline. 24 26 28 29 33 34 36 42 42 43 44 64 65 66 67 68 69 81 SF36292. Figure 25. 2007 Figure 10. Risk assessment results for October 2006. at an amplification of 14×. with protected wrinkle from which NGL was reported to have been leaking. at KP 125+950. Risk assessment results for May 2006. Figure 19. with the graph origin being in Malvinas. Figure 27. Figure 11. Blue arrows demarcate three distinct fracture zones. Figure 12. which includes the monitoring program for the September 2006 results. Ratio of the maximum operating pressure divided by the design pressure along the ROW of the NG pipeline. Figure 13. Figure 15. Cross-sectional view of the Peru-Chile Trench (after Worthey. during stabilization work. Each zone is numbered.003 A0F0 0607 0806 vii . Risk assessment results for September 2006. West coast of Peru showing source regions of great events of 1868 and 1877 and epicenters of notable 20th century earthquakes (after Dewey. Silva. Methodology utilized by Golder Associates for the scour analysis of the Camisea Pipeline (taken from “EVALUACIÓN DE CRUCES Y QUEBRADAS PROYECTO CAMISEA ‘RIVER CROSSING’” – presentation by Golder Associates January 24 and 25.June 8. 82 90 92 SF36292. Figure 30. Peru. Lima. 2007 Figure 28.003 A0F0 0607 0806 viii . Figure 29. 2007. Flow chart for conducting scour analysis (from FHWA HEC-18). and Tavera 2003). June 8.003 A0F0 0607 0806 ix . Leaks identified during hydrostatic testing of the pipeline Risk category assessment chart 49 62 SF36292. Table 2. 2007 List of Tables Page Table 1. 2007 Acronyms and Abbreviations ABSC API ASME BPD CFR COGA DOT E&P Exponent FCAW FHWA HEC-18 Golder HAZ HDPE HIC IDB IGL LL MAOP MCI MFL MMSCFD MOP MRA NG NGL PCS PGD PRS PS QWP RMP ROW SCADA SEM SL SMAW SR TgP the system TPS Vector ABS Consulting American Petroleum Institute American Society of Mechanical Engineers barrels per day Code of Federal Regulations Compania Operadora de Gas del Amazonas U. Magnetic Flux Leakage million standard cubic feet per day maximum operating pressure MR Associates natural gas natural gas liquid pressure control station permanent ground deformation pressure reduction station pump station Qualified Welding Procedures Risk Management Plan right-of-way supervisory control and data acquisition scanning electron microscopy Severity Levels Shielded Metal Arc Welding Safety Ratio Transportadora de Gas del Peru S.June 8. Camisea Transportation System Tuboscope Pipeline Services Vector Peru S. SF36292.C.S.A.003 A0F0 0607 0806 x . Department of Transportation extraction and production Exponent® Failure Analysis Associates Flux Arc Welding Federal Highway Administration Hydraulic Engineering Circular No.A. 18 Golder Associates heat-affected zone high-density polyethylene hydrogen-induced cracking Inter-American Development Bank Ingenieria y Geotecnia LTDA Likelihood Levels maximum allowable operating pressure Metallurgical Consultants Inc. Accordingly. 2007 Limitations At the request of the Inter-American Development Bank. In addition. based on engineering and geological experience and judgment. by changes that are beyond our control. beyond what was specifically revealed during the site visits and our document review. Accordingly.June 8. document review. and offers no warranty regarding subsurface conditions. ground stability. Exponent has used and relied upon certain information provided by sources that it believes to be reliable for the purpose of this report. wholly or in part. such as rains and landslides or human activities. limited visual inspection of some failed pipe sections. and engineering analysis. The scope of services performed during this investigation may not adequately address the needs of other interested parties. Our investigation included visual inspection of the pipeline right-of-way and adjacent areas. or the condition of concealed construction. SF36292. interviews of key personnel involved in the design and construction. This report also provides a site-specific technical evaluation of the geotechnical and mechanical aspects of each incident. Comments regarding concealed construction or subsurface conditions are our professional opinion. Changes in the conditions of the right-of-way may occur with time due to natural processes or events. Exponent prepared this report to summarize our evaluation of the integrity of the pipeline components in the Camisea Transportation System. the findings of this report may be invalidated.003 A0F0 0607 0806 xi . which experienced five spill incidents between December 2004 and March of 2006. Exponent has no direct knowledge of. and any reuse of this report or the findings or conclusions presented herein is at the sole risk of the user. and a sixth spill incident in April 2007. and are derived in accordance with current standards of professional practice. using the currently available information to identify the most probable contributing factors. 1 Along this route.003 A0F0 0607 0806 xii . 1 True length of pipeline. and the NG pipeline is approximately 734 km long. Exponent made recommendations to Transportadora de Gas del Peru S. on the coast of Peru south of Lima. SF36292. 2007 Executive Summary Background and Scope of Work Exponent® Failure Analysis Associates (Exponent) was retained by the Inter-American Development Bank (IDB) to perform a pipeline integrity analysis of the Camisea Transportation System (the system). The system consists of two buried pipelines: 1) a natural gas (NG) pipeline. This report summarizes these efforts and provides a risk-based evaluation of the system that incorporates extensive sources of information and field investigations by Exponent. the NGL pipeline telescopes from a nominal pipe diameter of 14 to 10¾ inches. TgP has implemented many of these interim recommendations and has undertaken other additional activities based on its experience and knowledge. commencing in April 2006. During our investigation of causal factors in the five incidents and assessment of pipeline integrity. Exponent’s retention followed the occurrence of five spill incidents. which runs from the upstream facilities at Malvinas to a terminal station at Lurin. climbs over the Andes Mountains at an elevation of approximately 4. The two pipelines share a common right-of-way (ROW) that traverses the Peruvian jungle. TgP contracted with Compania Operadora de Gas del Amazonas (COGA) for the operation and maintenance of the pipeline. during the first 19 months of operation. The Camisea Transportation System is owned and operated by TgP. and 2) a natural gas liquid (NGL) pipeline. The alignment of the ROW is shown on Figure 1. which transports the liquid condensates from Malvinas to a fractionation plant near Pisco. The NGL pipeline is approximately 561 km long. at the southern edge of Lima. The intent of our investigation was to develop a risk profile for the two component pipelines and identify the factors that contributed to the incidents. (TgP) in order to improve future pipeline integrity by mitigating and controlling identified risks to the system. and descends steeply toward the coast along the Pacific Ocean.A.800 m. each of which resulted in the release of hydrocarbons.June 8. 2) evaluating the SF36292. The locations and dates of the first five spill incidents are shown on Figure 1. Specifically. Exponent prioritized the identified hazards and evaluated the efficacy of currently used mitigation and control measures. which was compared to the baseline risk established during the first phase of our investigation. the mechanical design. and ongoing operation. 2007 and the larger NG pipeline telescopes from a nominal pipe diameter of 32 to 24 to 18 inches. one in the transition zone between the selva and the sierra sectors. we established a baseline risk level for the system and performed a technical review of the five spill incidents that occurred in the system between December 2004 and March 2006. geologic and geotechnical hazard mitigation. overall assessment of the integrity of the pipelines. The objectives of the second phase were to further evaluate key risks and to evaluate the progress made by TgP and COGA in reducing risks to the pipeline.June 8. TgP subsequently repaired the NGL pipeline and is currently investigating the root cause of this incident. no leaks have occurred on the larger diameter NG pipeline or on either pipeline in the costa sector. where a small amount of NGL was reported to have been released. The first phase included an evaluation of the suitability of the seismic design. In contrast. Recently. and the design of river crossings (scour analysis). Specifics of the first five individual spill incidents are presented later in this summary. and one in the sierra sector. Construction of the pipelines started in 2002. The following components were included in our evaluation of risk in the first phase: pipe material. pipeline construction.003 A0F0 0607 0806 xiii . 2007. pipeline design. TgP identified2 a sixth incident on April 2. pipeline maintenance. The objective of the first phase was to provide a forward-looking. Exponent’s pipeline integrity analysis was conducted in two integrated phases. The location of this spill incident is also shown on Figure 1. and commercial operation began in August 2004. All of the spill incidents occurred in the first 222 km of the NGL pipeline—four of the spills occurred in the selva sector. The risk was evaluated following the implementation of various mitigation measures constructed in 2006. the second phase included: 1) developing and assisting in the implementation of a hybrid risk-based system to evaluate potential geotechnical and geologic hazards to the pipeline system. As part of that study. primarily the NGL. and maintenance of the Camisea Transportation System. 2 Exponent was informed that TgP detected this minor leak during planned activities of its pipeline integrity program. or had been completed. and reviewed the metallurgical examination reports and evidence from the five spill incidents that we investigated. These inspections occurred at more than 50 sites along the ROW where geotechnical stabilization measures were proposed.June 8. These interviews were supplemented with numerous teleconference calls that included the designers. SF36292. 2007 effectiveness of the geotechnical stabilization measures constructed in 2006 to mitigate external soil pressures acting on the pipelines. Exponent performed its own engineering analysis to quantify certain risks to the integrity of the pipeline. river-crossing studies. operations. various internal and external pipeline inspection reports. under construction. and independent consultants hired during the construction and maintenance of the pipeline by TgP. service providers.003 A0F0 0607 0806 xiv . In addition to the document review and engineering analysis activities. construction specifications. Exponent reviewed more than 400 sets of documents related to the design. These documents included engineering specifications. In order to accomplish the pipeline integrity analysis. operators. Finally. pipe material data. hydrological studies. Exponent participated in the metallurgical investigation of samples of pipe that were involved in two of the incidents. seismic studies. construction. In some cases. construction. Exponent personnel also interviewed key personnel involved with design. and maintenance of the system. operation. geotechnical and geological studies. pipeline design drawings and calculations. and operational data. and 3) evaluating the efficacy of the current pipe integrity program. a multi-disciplinary team of Exponent engineers and scientists performed inspections along the pipeline ROW in June and September 2006. construction progress surveys. located at KP 222+500. both undermining and overtopping the ROW and the road next to the ROW. Exponent was not retained to perform a root-cause analysis of any of the spill incidents. The NG pipeline was not damaged at either location. to uniquely identify the cause or causes of failure. Exponent identified unstable geotechnical conditions as a significant contributor to the rupture of the pipe. hydrogen-induced crack in the weld. progressive soil loading likely propagated an initial crack and induced the rupture of the NGL pipeline. respectively. SF36292. Hence. The second incident. The hydrogen crack escaped detection by the post-welding radiography because of the inherent incubation time associated with hydrogeninduced crack initiation. ultimately rupturing the pipe and releasing the NGL at a very slow rate. a sizable landslide ultimately overwhelmed these measures. and to consider the potential for systemic problems. In both cases. the crack resulted in a throughwall leak of about 10 inches in extent. It is currently Exponent’s opinion that the high toughness of the pipe material allowed the pipe to pass subsequent hydrostatic testing (performed five months after the welding). appears to have been primarily the result of a timedelayed.3 Our evaluation identified similarities in fracture surfaces in the NGL pipe from the first and fifth incidents. While some measures were taken during construction to mitigate this geologic risk. Our current understanding is that the combination of hydrostatic load cycles and subsequent operational pressure fluctuations caused the hydrogen crack to be further destabilized. which occurred at KP 8+850 and KP 125+950. even though the crack had extended to approximately 90% of the wall thickness4 by the time the hydrostatic test was performed. the crack resulted in complete severance of the NGL pipe. In the incident at KP 125+950. In the incident at KP 8+850. At both of these locations. The third incident occurred in an area that was well studied from a geologic perspective and was known to be an area of very high risk of ground failure.June 8. and subsequent crack growth due to normal operational pressure fluctuations need be only minimal to reach a critical crack depth that causes the remaining ligament ahead of the crack to fail. This is a rather deep crack.003 A0F0 0607 0806 xv . 2007 Spill Incidents Exponent reviewed information related to the first five NGL pipeline spill incidents as a means of evaluating risk. 3 4 A root cause analysis is the integrated evaluation of all facts pertaining to the investigated failure. This triggering loading event could have been associated with riverbed scouring caused by the flash flooding. and then prioritize the remaining sources of risk so they can be mitigated. it is important to note that the metallurgical testing confirmed that none of the five spill incidents were related to pipe material quality.June 8. For the fourth incident. In this context. current information suggests that the rupture of the NGL pipe was induced by mechanical damage to the exterior concrete coating and a dent in the exterior wall of the NGL pipeline. The objective of risk management as part of a pipeline integrity management program is to identify. 2007 the rupture of the NGL pipe at this location is attributed to overload caused by a substantial landslide. For purposes of this report. we define risk as the likelihood that a given chain of events will occur and result in a consequence that has a defined severity. we identified four SF36292. located at KP 50+900. controlled. and/or monitored. Again. risk was ranked to be minimal if the risk is currently not a concern and effectively consistent with other pipelines. Analysis performed to date indicates that the dent was not made by a boulder washed downstream during the flash flooding that immediately preceded the spill. the pipe wall at this location was apparently capable of containing the NGL fluid until some unknown external loading event caused the already weakened pipe wall to fail in ductile overload at the damaged area. In this report.003 A0F0 0607 0806 xvi . the NG pipe at this location was not damaged. Finally. Indeed. The aggregate of the likelihood of failure and the severity of failure is risk. Risk Identification The pipeline integrity analysis evaluated the risk categories that influence the likelihood and severity of potential pipeline failures. during our study. The NG pipe at this location was not damaged. eliminate if appropriate. we first provide a brief summary of our investigation into potential systemic risks resulting from the design and construction of the system. Furthermore. Foreseeable load conditions apply to internal pressures and to external loads imposed by soil pressures or ground movement. geotechnical and geological hazards are defined as external pressures resulting from ground movement. Due to their importance. although pipe integrity–related risks typically increase with the age of the pipeline. Risk Evaluation The four primary categories of risk identified above are discussed in more detail in the paragraphs that follow.5 mechanical pipe integrity. 5 For the purposes of this report. Exponent’s review determined that TgP implemented various actions in 2006 to substantially reduce the risk of future incidents to the pipeline. SF36292. on decisions made during the design and construction of the pipeline. However. we also recognize that the four risk categories identified above depend. seismic events. to varying degrees.003 A0F0 0607 0806 xvii . and river scouring. seismic events. Design-Related Risks The system was designed to comply with the engineering code requirements of the American Society of Mechanical Engineers (ASME). whereas geological hazards are defined as movement in rock. we found that the risk associated with geotechnical and geological conditions is currently more significant than risks associated with pipe integrity. 2007 primary categories of risk affecting the integrity of the pipeline: geotechnical and geological.June 8. Each of these areas of integrity risk is discussed separately below. our communication with TgP to date indicates that they are committed to continue identifying and reducing the geotechnical risks to the pipeline.6 Code compliance is established if the designer demonstrates that all specific code requirements and all reasonably foreseeable load conditions are addressed by the design. In summary. poor foundation (ground) conditions. The higher risk level associated with geotechnical hazards is a direct consequence of the steep topography. Geotechnical hazards are defined as movement in soil. and abundance of water along the pipeline ROW in the selva sector. and scour. typically when saturated. These electric-resistance-welded tubular pipes are manufactured per the American Petroleum Institute’s API 5L standard. where the ROW itself was commonly the only available route for transportation. Argentina. This ROW had to be contained in a 3-km-wide. A review of the pipe book7 and the pipe manufacturing and coating records indicates that the pipe material used was purpose built for the system at two pipe mills during 2002 and 2003. Construction-Related Risks The system was constructed simultaneously at several so-called “mini-spreads” along the ROW. Given the demanding route of these pipelines through the jungle and up the mountains. and deviations from this pre-approved corridor had 6 7 ASME B31. The pipe manufacturer’s records indicate that these mills are located in Pindamonhangaba. each of which is up to 12 meters long. using more than 100.. Therefore. any risks associated with the internal pressure aspects of the design are minimal and consistent with other pipelines. hydraulic risk).June 8. The pipes were transported to the individual construction sites. such that steel plates are rolled and longitudinally welded at the mill. and Buenos Aires. external loads were an important element for the design and construction of the system. Subsequently. all pipes were coated with an outer high-density polyethylene (HDPE) layer to protect them from external corrosion.000 individual pipes.e. We have independently verified that the computed design pressures are code compliant and in good agreement with the measured operational pressures along the whole length of both pipelines. government mandated corridor. Brazil. The pipe book lists relevant pipe data.003 A0F0 0607 0806 xviii .8 [Gas Transmission and Distribution Piping Systems] is the applicable code for the larger NG pipeline. 2007 Our review indicates that the pipe wall thickness is sufficient to contain the internal pressures of the transported hydrocarbon products along the entire length of the pipeline (i. and ASME B31. SP.4 [Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids] is the applicable Code for the NGL pipeline. SF36292. Our design review revealed that the pipeline designers assumed that external soil loading would be entirely mitigated by geotechnical mitigation measures implemented during construction at sites deemed to pose a geotechnical or geological hazard. and potential damage to the pipe exterior.June 8. the constructor decided to preferentially build the pipeline along mountain ridges. and girth welds were used to join individual pipes. The ground conditions encountered during installation of the pipe were reportedly assessed by geotechnical engineers. A completed pipe section that may be several hundred meters long was then lowered into the trench and welded together to form an even longer pipe section. To minimize environmental impact. This standard construction methodology was replaced by special construction methods in very steep terrain. Geotechnical engineers also supervised the geotechnical mitigation measures to control surface water runoff and stabilize the ROW following installation of the pipelines. where potential risks to pipeline integrity arise primarily from the girth welds. and the work was inspected by outside consultants. and some mitigation measures were constructed at that time. 2007 to be granted by the Peruvian government.000 girth welds of both pipelines were to be welded per approved procedures and to be x-rayed 24 hours later. Due to limitations imposed by the narrow lane of clearing. at river crossings. the cleared section of the ROW was typically restricted to 25 meters. the pipe was strung out. and along rivers and drainages.003 A0F0 0607 0806 xix . The more then 100. SF36292. Within the 3-km-wide corridor. they ultimately became a source of concern related to the potential to exert external soil pressures on the pipes. Next. in that placing the ROW near the base of the mountains. the construction methods are consistent with general pipeline construction practice. it is our understanding the government of Peru– commissioned pipeline audit is performing this task. The ROW was cleared and cut. and at locations where the pipeline was laid along an existing road. grading along the ROW consisted of cutting into the hillside and placing the excavated material as “side-cast” or “spill” fill on the downhill side of the clearing.8 This process was generally effective at minimizing and 8 Exponent’s scope of work did not include reviewing these x-rays. Exponent’s review indicates that this approach was appropriate and preferred. would have likely resulted in substantially more construction-related damage to the environment. trench conditions. Overall. Although these side-cast fills were generally placed outside the limits of the pipe trenches. in which a hydrogeninduced crack survived the hydrostatic test. In this program. This situation arose with the second spill incident. external damage during construction in two cases. where weld quality was to be evaluated per the American Petroleum Institute’s API 1104 standard. a faulty longitudinal weld in two other cases. eight leaks were identified. All these failures were subsequently repaired. Geotechnical instability caused or substantially contributed to two of the five spill incidents (#1 and #5). which may be similar to other pipelines in the world. This hydrostatic test was performed for both pipelines along the entire length of the system. long individual sections of the pipeline were hydrostatically tested.June 8. the water-tightness of the pipeline was verified by maintaining a constant water pressure for at least 24 hours. of which seven occurred in the NGL pipeline and one in the NG pipeline. more than 100 sites along the ROW were evaluated and mitigated in 2006 by implementing SF36292.000 girth welds. Eight failures in more than 1. and geologic instability caused one of the five spill incidents (#3). and the pipeline section was successfully re-tested.250 km of pipeline is a low number. This incident is currently not considered to be indicative of any systemic problems for the more than 100.003 A0F0 0607 0806 xx . Next. To further reduce the likelihood of failure. Despite the above-described actions. During the hydrostatic testing. initiating the subsequent spill incident. especially considering the challenging terrain. The test results are more an indication of the test’s ability to detect preexisting faults. 2007 detecting weld defects that needed to be repaired. the radiography of all girth welds and hydrostatic testing of the Camisea Transportation System reduced the level of risk. The causes of the leaks were determined to be a faulty girth weld in three cases. Geotechnical and Geology-Related Risks The spill incidents and observed performance of the system as of early 2006 caused TgP to set into motion an aggressive geotechnical remediation program that began in earnest in April 2006. and a foreign object being introduced during rolling of the steel plate used to manufacture a pipe in one case. some minimal risk exists because defects may be aligned or sized such that the hydrostatic test would not rupture the pipe and the defect could go undetected. Overall. Hydrostatic testing involves filling each pipe section with water and pressurizing the water to a predefined level that exceeds the maximum operating pressure. Construction of geotechnical mitigation measures in 2006 significantly reduced this risk by improving the geotechnical and geological stability at specific sites of greatest hazard. During the second phase of our project. At the end of 2006. As early as April 2006. and data on movement characteristics. TgP and COGA had also contracted additional external geotechnical and geological specialists to help assess the hazards and evaluate the likelihood of failure. we determined that these measures were being applied in a consistent and effective manner. following extraordinary efforts to stabilize geotechnical and geologic conditions along the ROW.g. the sites identified are listed in the hybrid risk matrix. strain gauge. Based on our review. reliable repairs. to permit more expeditious. survey control. Further. This system was validated using information from our field inspections. Exponent worked collaboratively with TgP to develop a hybrid risk matrix to adequately assess the likelihood of future failure resulting from geotechnical and geologic conditions. representing SF36292. observations. As a result of these efforts.003 A0F0 0607 0806 xxi . To date. TgP and COGA had begun to implement a system of identifying those sites with the highest priority for mitigation based on the perceived likelihood of failure and the potential consequence of failure. addressed. TgP believed that geotechnical hazards due to soil movement were more effectively documented. slope inclinometer. piezometer. instrumentation (e. we concluded that geotechnical and geologic conditions initially posed a substantial risk to the pipeline.. Exponent concluded that geotechnical stabilization measures constructed during 2006 are generally reliable and robust. some on both occasions. In more critical areas. Based on our second round of inspections in September 2006 and subsequent documentation review. and rainfall monitoring) is being used or is recommended to provide additional interpretation and warning of ground instability. 2007 geotechnical mitigation measures using more robust construction techniques. Exponent observed over 50 sites. during our field inspections in June and September 2006.June 8. the risk of future failure of the system from external geotechnical forces has been substantially reduced. and controlled in this ongoing process. While the route of the system traverses a challenging and dynamic area. our initial inspection in June 2006 indicated that some of the original stabilization measures implemented during construction were not completely effective. and engineering experience. The risk at each station was then evaluated at three different points in time. The addition of monitoring provided a further reduction to 5 sites having a “high” to “very high” risk. 2007 locations that have exhibited manifestations of ground instability. We expect that the continuous. Therefore. In this regard. adjacent to the second pump station. we recommended that TgP adopt a proactive approach of continually assessing geotechnical hazards along the ROW. Thus. The results of the geotechnical risk assessment are consistent with our field observations that TgP and COGA have made substantial progress in reducing the overall risk. The core of this program involves regular visual inspections. between KP 0 and KP 220. the construction of the geotechnical mitigation measures in 2006 reduced this number to 12 sites. and after implementation of the additional monitoring programs discussed below. Exponent also reviewed a monitoring program initiated by TgP and COGA to help reduce the risk of future failure resulting from external geotechnical forces by detecting and quantifying early signs of slope instability. reflecting the risk prior to and after construction of the new geotechnical mitigation measures.” TgP has stated that construction of new geotechnical stabilization measures is ongoing or completed at these sites. Some of these sites may even be ranked with a high to very high risk and will need to be mitigated quickly. being now ranked as “very high. ongoing implementation of the risk matrix process will identify additional sites that are not included in the current hybrid risk matrix due to the absence of surface manifestations of ground movement. SF36292.June 8. It is our understanding that TgP is updating the hybrid risk matrix and is committed to implementing additional geotechnical measures in 2007. and the vast majority of these stations are located in the selva sector.003 A0F0 0607 0806 xxii . including during the rainy season. The multi-disciplinary team of inspectors is trained by COGA’s technical consultants and is intimately familiar with the project and conditions along the alignment. This program allows for the early detection and correction of potential problem areas. TgP has committed to implementing the recommended Risk Management Plan (RMP) that should govern the use of all risk assessment methods and guide TgP’s actions. This program appears to be comprehensive and is integral to reducing the risk of future failure resulting from geotechnical conditions. while we initially ranked 45 of 94 sites as having “high” to “very high” risk (along the initial 455 km of the ROW). with solely the site at KP 108. June 8. it is susceptible to this external failure mode. weld quality. TgP has reported that the inspection of the NGL pipeline identified 30 reportable defects. will identify additional sites and reduce the geotechnical-related risks further. the residual risk is now mostly confined to areas that may become geologically unstable and that may contain potential weld anomalies. while sufficient for internal pressures.003 A0F0 0607 0806 . At this time. To mitigate the residual risk. and the construction of additional geotechnical mitigation measures in 2007. Load capacity estimates for the NGL pipeline show that. the most significant risks to the system arise from external loading caused by soil movement. and the entire pipeline was hydrostatically tested. which is consistent with four of the first five spill incidents. 2007 decision process. Exponent’s analysis of this loading condition has shown that the as-designed NG pipeline has a significantly larger external load capacity and flaw tolerance than the NGL pipeline. As discussed above. These axial stresses are known to affect the girth welds in the pipe. per requirements by API 1160 xxiii SF36292. and TgP’s ongoing and prior geotechnical construction program reduces the likelihood of soil movement. and the quality of protection the pipe is afforded against environmental conditions. any growth of such defects that would lead to the rupture of the pipe requires the presence of external loading. TgP performed an inline inspection of the NGL pipeline in 2006 using the Magnetic Flux Leakage (MFL) inspection tool and a geometric inline inspection tool. Removal of the loading is a good way to further mitigate the risk. The MFL inspection tool has the capability to detect metal loss and other potential anomalies. Exponent believes that a successful implementation of the above. during construction. Soil movement imposes lateral loading upon the pipe. First. Second. such that the NG pipeline generally has a low risk of failure from external loads. Thus. reducing the potential number of potential weld-related and pipeline material defects. all the welds were x-rayed. and the geometric tool measures the pipe’s geometry along its length. and manner of execution. Several approaches have been adopted by TgP to reduce this risk. Pipe Integrity–Related Risks Pipe integrity–related hazards are associated with pipe material. which can induce axial pipe stresses in addition to those induced by the internal pressure of the transported hydrocarbons. have shown that. In an effort to quantify the MFL tool’s ability to detect crack-like features. no severe external or internal corrosion damage exists along the NGL pipeline. Exponent performed a pipeline integrity study to determine the MFL inspection tool’s utility in detecting circumferential cracks. In this regard. no pipeline inspection company is readily able to provide a commercially available inspection tool to detect potential circumferential cracks. The MFL inspection tool has proven to be an excellent tool to detect internal and external corrosion damage to the pipe in this project.June 8. In addition. TgP has voluntarily identified additional sites to further quantify the accuracy of the inline inspection tools. currently. SF36292. even though the technology to do so appears to be available. At present.003 A0F0 0607 0806 xxiv . Results of the MFL inspection tool. Despite the fact that the use of in-line inspection tools to detect small circumferential cracks is currently not a common practice among pipeline operators due to the 9 Department of Transportation of the United States of America. 2007 and DOT9 195.10 Our analysis indicates that a potential circumferential crack would need to be subjected to a significant external load to be detectable with high certainty by the currently employed MFL inspection tool. it is Exponent’s opinion that some sections of the NGL pipeline may be subject to a potential longterm risk that will need to be addressed in the long-term planning stages of TgP’s pipeline integrity program. However. TgP is currently excavating these sites to perform a more detailed evaluation and initiate the appropriate repair measures. Overall in 2006. TgP significantly reduced pipe integrity–related risks and is currently engaged in additional efforts to reduce the risk profile under technically and logistically difficult conditions. TgP and its contractors conducted a research program to quantify the crack detection limit of the MFL tool. Specific resources have been committed in 2007 to further improve TgP’s ability to detect potential circumferential cracks. A root cause analysis of spill incidents 1 and 5 and the origin and nucleation of the potential circumferential cracks will be performed by TgP. and evaluation of metal loss per ASME B31G. if required. which will assist in assessing the implications of this concern related to pipeline integrity. Recognizing the potential seismic hazard. and pressure reducing stations. the pipeline fabricator commissioned several seismic hazard studies during the design process. Exponent currently understands that TgP is engaged in a review. Although several seismic hazard studies were performed as part of the design of the system. SF36292. the probability of detection decreases rapidly. seismic risk management would benefit from an update of the design ground motions with up-to-date scientific information. 2007 relatively low risk to pipeline integrity posed by circumferential cracks under normal operating loads. landslides. and costa) and provided more specific evaluations of ground motions for the pump stations. as part of the pipeline integrity management plan of seismic risks. liquefaction. Another investigation identified active fault crossings along the pipeline and evaluated the pipeline’s capacity for predicted fault displacements. For cracks with a smaller crack opening. TgP will evaluate potential options. sierra. slope instability.June 8. The first study characterized the regional seismic hazard for each of the three sectors (selva. our review suggests that the potential for permanent ground displacements (e.g. Additionally. to determine whether these potential seismic risks are acceptable for this system or whether mitigation measures should be considered.1 mm can be detected with a probability of better than 90%. 10 The service provider of the currently used MFL inspection tool has determined that only circumferential cracks with a crack mouth opening of more than 0. Seismic-Related Risks The system lies within regions that have the potential for very large and frequent earthquakes.. and lateral spread) should be evaluated more comprehensively to reduce uncertainty.003 A0F0 0607 0806 xxv . Additional studies consisted of evaluating the potential for wave propagation damage for straight sections of buried pipe and 12 surface facilities. The earthquake hazard appears to be the greatest in the costa sector and least near the selva sector. pressure control stations. in the opinion of SF36292. TgP has implemented various actions to help reduce these risks. as described in the Federal Highway Administration’s Hydraulic Engineering Circular 18 (HEC-18). Given the potential uncertainty and the objective to minimize this risk. In addition. additional scour studies and investigation of potential scour mitigation measures are warranted and are currently being evaluated by TgP. Exponent recommends evaluation of additional potential scour processes. 2007 Scour-Related Risks Scour is defined as the erosion of streambed or bank material due to flowing water. However. HEC18 is not a design standard required under Peruvian law. and river scouring as secondary risks. Exponent’s review of the scour analyses performed during the design of the project indicates that some assessments were performed to determine the minimal depth at which to bury the pipeline. The analysis identified four primary categories of risk to the integrity of the pipeline: geotechnical. The higher risk level associated with geotechnical hazards is a direct consequence of the steep topography. considered to be the most significant.June 8. These design studies included field investigations of stream crossings. poor foundation (soil) conditions. Despite not being required. Future Activities Exponent performed a pipeline integrity analysis of the pipeline components of the Camisea Transportation System. However. In addition to the mentioned studies. which is considered the industry standard to evaluate stream scour. including various interim recommendations made by Exponent during our investigation. Therefore. pipeline crossings should be designed and constructed to withstand floods of relatively extreme magnitude. naturally occurring lateral migration of the mainstream channel within its floodplain may affect the stability of the buried pipeline crossings. with little warning and serious consequences. Flood-induced scour can occur over short periods of time. the HEC-18 scour design approach was partially utilized. and mechanical pipe integrity. seismic events. along with other procedures that were deemed to be appropriate by the designer. and the abundance of water along the pipeline ROW in the selva sector.003 A0F0 0607 0806 xxvi . Based on available information obtained during Exponent’s investigation and the proposed actions. future information and risks need to be continually and properly evaluated. 3) reconsideration of seismic risk. and that these actions have significantly reduced the risk to the system. 4) experimental evaluation of potential circumferential cracks and their impact on pipe integrity. In this context. and #5. If and when ongoing pipeline integrity management efforts identify additional issues. it appears to Exponent at this time that TgP is performing adequate pipeline integrity actions. implementation of actions to reduce such risks. which includes review of these actions and additional site visits in 2007. This plan includes: 1) implementation of geotechnical mitigation and monitoring actions in 2007. risk management actions above and beyond those currently being taken may be required. #4.June 8. SF36292. and thus. However. 2007 Exponent. based on the results. a technical action plan has been established with TgP and the IDB. permanent ground deformations. Exponent has been retained to provide continued technical assistance to the IDB related to the Camisea Transportation System. along with continued geotechnical risk assessment. resulting from strong ground shaking. 2) re-evaluation of potential scour risk at river crossings and. Exponent also notes that pipeline integrity management is a continuous process. additional actions are still recommended to continue the minimization of any existing pipeline integrity risks. 5) spill root cause analysis of spill incidents #1. excluding fault rupture.003 A0F0 0607 0806 xxvii . in particular wave propagation. government-mandated corridor. Deviations from this pre-approved corridor had to be granted by the Peruvian government. and the larger NG pipeline telescopes from a nominal pipe diameter of 32 to 24 to 18 inches.406 and 1 inch. follows a 3-km–wide. on the coast of Peru south of Lima.. and descends steeply toward the Pacific coast. and the wall thickness of the larger NG pipelines ranges between 0. with heavier wall thickness typically used for sections with larger diameter. which is shown on Figure 1.800 m. The NGL pipeline is approximately 561 km long. (TgP). Construction of the system was performed by Techint beginning in 2002.A.1 Description of the System The Camisea Transportation System (the system) is owned by Transportadora de Gas del Peru S. The wall thickness of the NGL pipeline ranges between 0. Commercial operation of the system began in August 2004. which transports the liquid condensates from Malvinas to a fractionation plant near Pisco. at the southern edge of Lima. The two pipelines share a common right-of-way (ROW) that traverses the Peruvian jungle. which runs from the upstream facilities at Malvinas to a terminal station at Lurin.11 Along this route. The system consists of two buried pipelines: 1) a natural gas (NG) pipeline.June 8.003 A0F0 0607 0806 1 .219 and 0. SF36292. traversing the roughly 200-km-long selva sector. 11 True length of pipeline.469 inch. TgP contracted with Compania Operadora de Gas del Amazonas (COGA) for the operation and maintenance of the pipeline. The alignment of the ROW. climbs over the Andes Mountains at a peak elevation of approximately 4. 2007 1 Introduction 1. Both pipelines are constructed of tubular high-strength steel in conformance with the American Petroleum Institute (API) 5L standard and sleeved in a protective plastic layer. the ~300-km-long sierra sector. the NGL pipeline telescopes from a nominal pipe diameter of 14 to 10¾ inches. and the NG pipeline is approximately 734 km long. Within this 3-km-wide corridor. the cleared section of the ROW was typically restricted to a width of 25 meters. and the 200-km-long costa sector. and 2) a natural gas liquid (NGL) pipeline. with the extraction and production (E&P) centered in Malvinas. a NGL fractionation plant in Pisco. and a NG distribution point in Lurin. The NGL pipeline is also equipped with nineteen block valves and ten check valves. On the west side of the Andes Mountains. The NG pipeline receives the processed gas products from Pluspetrol’s exploration and processing facility in Malvinas at a sufficiently high pressure such that no further compression is currently required. The PCS is equipped with several redundant safety features and a venting capability to protect the pipeline from over-pressurization events. and the pressure reduction stations reduce the pressure as the liquid hydrocarbons flow downhill to the fractionation plant located along the Peruvian coast. mostly at major river crossings.June 8. 2007 The NGL pipeline is equipped with four pump stations (PS) on the east side of the Andes Mountains and three pressure reduction stations (PRS) on the west side of the Andes Mountains. The pump stations propel the liquid hydrocarbons up the Andes Mountains. to minimize the amount of potential spillage. Figure 1. SF36292. a pressure control station (PCS) reduces the pressure of the natural gas. Right-of-way of the Camisea Transportation System in Peru.003 A0F0 0607 0806 2 . All block valves are connected to an automatic leak detection system to quickly shut down the NGL pipeline in case of a pipe rupture. A more detailed description of each incident is given in Section 3 of this report. the NGL pipeline has experienced six incidents involving a release of NGL (see Figure 1). 1. appears to have been primarily the result of a time-delayed. our work focused on the NGL pipeline. 1. The NG pipeline has not experienced a known gas release. and pipe-related risks of this system. SF36292. The sixth incident occurred upstream of the fifth incident in April 2007 and is currently under investigation by TgP.003 A0F0 0607 0806 3 . The fourth incident. hydrogen-induced crack in a girth weld. and 3) the identification and evaluation of the geotechnical and geologic risk. 2007 The system is centrally operated from Lurin using a state-of-the-art supervisory control and data acquisition (SCADA) system. seismic risk.3 Report Organization This report is structured in three main parts: 1) the review of the six spill incidents of the NGL pipeline. The second incident. appears to have been induced by mechanical damage to the exterior concrete coating and a dent in the exterior wall of the NGL pipeline and been triggered by riverbed scouring caused by a flash flood. The system communicates primarily via its own fiber optic cable that is installed along the pipelines and has two technologically different and independent backup systems: a satellite and a radio frequency–based system. in that external soil loading is currently considered to have been a significant contributor to the subcritical crack growth in the pipe. located at KP 222+500. In this regard. The third incident occurred in an area that was well studied from a geologic perspective and known to be an area of high risk of landsliding. The first (KP 8+850) and fifth (KP 125+950) incidents were similar.2 Operational History Since the Camisea Transportation System was placed into service in August 2004. The SCADA system gathers all operational data and allows direct remote control of all components. The rupture of the pipe at this location is attributed to overload caused by a landslide.June 8. An explosion occurred as a consequence of the fifth incident. 2) our review of the design and construction methods and their risk assessment. scour risk. located at a river crossing at KP 50+900. and pipeline fabrication are also discussed in Section 5. Sections 6 through 9 describe both the hazards and means that were and will be used to mitigate pipelinerelated risks in the following four areas: geotechnical and geological risks.June 8. seismic risks. Section 10 presents our overall conclusions and recommendations for future activities. pipe integrity risks. 2007 The spill incidents and their probable cause are reviewed in Section 3. Section 4 describes the system’s mechanical and geotechnical design and evaluates whether any systematic risks were introduced during the design process. Section 5 addresses construction and issues related to the geotechnical mitigation measures that were constructed during this period. SF36292. and scour risks at river crossings.003 A0F0 0607 0806 4 . pipe manufacture. Issues related to pipe material. This report also summarizes these efforts and provides a risk-based evaluation of the system that incorporates extensive sources of information and field investigations by Exponent. The following components were included in our evaluation of risk in the first phase: pipe material. Exponent’s retention in April 2006 followed the occurrence of five spill incidents during the first 19 months of operation. 2. During this investigation. 7) identify and evaluate seismic hazards. The primary objectives of our investigation were to: 1) develop a risk profile for the two component pipelines and identify the factors that contributed to the spill incidents. pipeline construction. 2) investigate the causal factors of the first five spill incidents. 3) review key information on the design and construction of the system. 2007 2 Exponent’s Investigation 2. The objective of the first phase was to provide a forward-looking. Although TgP had undertaken a substantial program to provide stabilization measures along the ROW beginning in April 2006. primarily the NGL. commencing in April 2006. 5) evaluate the effectiveness of the geotechnical measures constructed in 2006 to stabilize the ROW. 4) develop and assist TgP in implementing a qualitative risk assessment method to evaluate geotechnical and geological hazards. 6) evaluate the pipe inspection program. each of which resulted in the release of hydrocarbons. Exponent made recommendations to TgP intended to improve future pipeline integrity by mitigating and controlling identified risks to the system.June 8.2 Phases of Work Exponent’s pipeline integrity analysis was conducted in two integrated phases. pipeline design. TgP also implemented our interim recommendations. overall assessment of the integrity of the pipelines. geologic and SF36292.003 A0F0 0607 0806 5 .1 Objective Exponent® Failure Analysis Associates (Exponent) was retained by the Inter-American Development Bank (IDB) to perform a pipeline integrity study of the Camisea Transportation System. and 8) explore possible contributions of scour to the risk of future pipeline failure at stream and river crossings. pipeline design drawings and calculations. operation. a multi-disciplinary team of Exponent engineers and scientists performed inspections along the pipeline ROW in June and September 2006. In some cases.000 girth weld radiographs. geotechnical and geological studies. hydrological studies. The risk was evaluated following the implementation of various mitigation measures constructed in 2006.June 8. and operational data. Specifically. mechanical design. As part of that study. Exponent did examine the radiographs of the spill incidents and some additional of the more than 100. river-crossing studies. the second phase included: 1) developing and assisting in the implementation of a qualitative risk assessment method to evaluate potential geotechnical and geologic hazards to the pipeline system. we established a baseline risk level for the system and performed a technical review of the five spill incidents that occurred in the system between December 2004 and March 2006. These documents included engineering specifications.. 2. and maintenance of the Camisea Transportation System. construction. The objectives of the second phase were to further evaluate key risks and to evaluate the progress made by TgP and COGA in reducing risks to the pipeline. which was compared to the baseline risk established during the first phase of our investigation. The first phase included an evaluation of the suitability of the seismic design. various internal and external pipeline inspection reports. Exponent prioritized the identified hazards and evaluated the efficacy of currently used mitigation and control measures. seismic studies. and design of river crossings (scour analysis). In addition to these activities. 2007 geotechnical hazard mitigation. pipeline maintenance. and 3) evaluating the efficacy of the current pipe integrity program. These inspections SF36292. Exponent reviewed more than 400 sets of documents related to the design. construction progress surveys.003 A0F0 0607 0806 6 .3 Scope In order to accomplish the pipeline integrity analysis. pipe material data. and ongoing operation. Exponent performed its own engineering analysis to quantify certain risks to the integrity of the pipeline. 2) evaluating the effectiveness of the geotechnical stabilization measures constructed in 2006 to mitigate external soil pressures acting on the pipelines. construction specifications. 003 A0F0 0607 0806 7 . SF36292. or had been completed. 2007 occurred at more than 50 sites along the first 450 km of the ROW where geotechnical stabilization measures were proposed. Finally. service providers. where all spill incidents have occurred and geotechnical as well as geologic risks are considered to be highest. were under construction.June 8. and maintenance of the system. operators. These interviews were supplemented with numerous teleconference calls that included the designers. Special attention was given to the first 220 km of the ROW. Exponent participated in the metallurgical investigation of samples of pipe that were involved in two of the incidents. and reviewed the metallurgical examination reports and evidence from the first five spill incidents. Exponent personnel also interviewed key personnel involved with design. operation. construction. and independent consultants hired during the construction and maintenance of the pipeline by TgP. SF36292.2 First Incident The first incident occurred on December 22.003 A0F0 0607 0806 8 .1 Background Since the Camisea Transportation System was placed into commercial service in August 2004.12 All of the spill incidents occurred in the first 222 km of the NGL pipeline— four of the spills occurred in the selva sector. 3.25 inch along this section of the system. 2004. the pipe was on an intermediate bench14 and near a small stream. and to consider the potential for systemic problems. Exponent was not retained to perform a root-cause analysis of any of the spill incidents. one in the transition zone between the selva and the sierra sectors. a total of six spill incidents have occurred along the NGL pipeline. At the point of rupture. The topography at this site is characterized by undulating hills at a low elevation (~400 m). This location had been inspected by GEOTEC15 in September 2004. in the jungle sector near KP 8+850. A relatively level strip of land bounded by steeper slopes above and below. and 12 13 14 15 Root cause analysis is the integrated evaluation of all facts pertaining to the investigated failure to uniquely identify the cause or causes of failure. with a slope profile of approximately 15%. GEOTEC was the geotechnical engineering firm that supervised the implementation of geotechnical stabilization measures during construction of the pipeline system. In-place geotechnical mitigation measures consisted of surface drainage channels constructed of soil-cement bags. 13 The NGL pipe has a diameter of 14 inches and a nominal wall thickness of 0. Distance along the pipeline as measured from Malvinas and marked along the ROW at every kilometer point (KP). The locations and dates of these six spill incidents are shown on Figure 1. The hills contain gentle to moderately steep slopes bisected by short ravines that rise above the Urubamba River. In contrast. no leaks have occurred on the larger diameter NG pipeline.June 8. Exponent reviewed information related to the first five NGL pipeline spill incidents as a means of evaluating risk. and one in the sierra sector. 2007 3 Review of NGL Pipeline Incidents 3. 2007 revegetation with grass. A substantial amount of overburden soil had been 16 17 Circumferential weld joining two pipe sections. the 14-inch NGL line was exposed. Remediation and geotechnical stabilization work completed before our visit included repair of the pipeline. TgP stopped pumping hydrocarbons at PS #1. and interviewed TgP personnel who were knowledgeable about the history of construction. The hydrodynamic forces of the escaping NGL had formed a sinkhole above the pipeline. addition of ditch breakers to control subsurface seepage along the pipeline.” SF36292. 2006. and stabilization measures. repairs. Both pipelines were originally buried at a depth of up to 7 m. Exponent visited this site again on September 11. The pipeline rupture was detected in TgP’s control room in Lurin as an anomaly in the pressure characteristics of the pipeline between PS #1 and PS #2. the rupture site was isolated between the block valve at the outlet of PS #1 and the block valve on the east bank of the Urubamba River at KP 12. cleanup of hydrocarbon-containing soil. when additional geotechnical stabilization measures were nearly complete. 2006. TgP discovered that the pipe was circumferentially cracked in the vicinity of a girth weld16 but was not completely severed. they believed that there was no need for significant remedial geotechnical stabilization work. They recommended sealing of cracks and repairing channels and current breakers. “Analysis of Incident Report: Camisea Pipeline Project. and construction of retaining walls to mitigate lateral earth movement in the ROW. visit. Cracks in the soil and displacement of some of the drainage channels were interpreted as evidence of soil settlement. Stone and Webster Management Consultants (April 2006). At the time of our June 12.June 8. and additional stabilization measures were being constructed to stabilize a shallow landslide that had occurred in the vicinity of the rupture. TgP estimated that 260 m3 of hydrocarbons were released. Exponent inspected this site on June 12. but based on available information. Seven minutes after noting the anomaly. 2006. During their site investigation. and by the ninth minute.003 A0F0 0607 0806 9 . Selected photographs of the area from that visit are shown in Figure 2. GEOTEC recognized that the cracks provided a route for rainfall runoff to infiltrate the soil.17 No fires or explosions occurred as a consequence of the spillage. looking downstream. The extensive monitoring program being implemented for the site consists of strain gauges to detect pipe movement. 2007 removed from the ROW to improve the stability of the slope. Stabilization measures included the construction of surface and subsurface drainage features.5 m. and piezometers to monitor the groundwater level. 18 Current breakers and surface channels were installed to control surface runoff.18 as well as retaining walls and piles to stabilize the slope and prevent lateral earth movement along the ROW. and the depth of the NGL pipeline at that time was reported to be about 1. inclinometers to detect soil movement.0 to 1. Figure 3 provides an overview of the newly constructed geotechnical stabilization measures at the site on September 11. SF36292.003 A0F0 0607 0806 10 . 2006. whereas ditchbreakers were constructed to control subsurface water flow along the pipeline.June 8. 2007 Figure 2.June 8. Plastic sheeting covers 14-inch NGL pipeline.003 A0F0 0607 0806 11 . during ROW stabilization work. 2006. at KP 8+850. Bottom: View upstream (looking upslope). Photographs taken on June 12. SF36292. Top: View downstream (looking downslope). General area of site of first spill incident. General area of first spill incident. 19 20 Metallurgical Consultants. 2007 Figure 3. Photograph taken on September 11. is a Houston-based metallurgical laboratory. MCI stated that this initial crack formed when offset fatigue cracks coalesced. with the 12 o’clock position being straight up and the viewer looking downstream at the clock. after stabilization work conducted in 2006. At the request of TgP. 2006.June 8.19 (MCI) performed a metallurgical investigation of the ruptured pipe section. Inc. Metallurgical Consultants Inc. MCI concluded that the fracture occurred between the 4 and 7 o’clock positions20 (about 10 inches long). as shown in Figure 4. The circumferential position on a pipe is referenced to a clock. Subsequent loading propagated this crack subcritically. looking downstream.003 A0F0 0607 0806 12 . as evidenced by the presence of ratchet marks on the fracture surfaces. with the crack beginning at the pipe’s outer surface. SF36292. until the crack became critical. and the wall of the pipe was breached (see Figure 4). with rapid incremental tearing in a few load steps. at KP 8+850. and MCI.950 m on a fairly broad topographic ridge crest at the head of a long valley. MCI’s metallurgical investigation of the failed pipe confirmed that the pipe material and weld were in compliance with applicable codes but minor allowable anomalies per API 1104 were identified. Our current understanding is that the circumferential crack grew subcritically as soil loading bent the pipe until it ruptured.June 8. This spill incident occurred at an elevation of approximately 3. IGL (Ingenieria y Geotecnia LTDA). Analyses done by GIE (GIE S. MCI photograph showing frontal view of fracture surface of the first rupture at KP 8+850.003 A0F0 0607 0806 13 . the pipeline ascends an east-facing slope and is approximately 30 m away from the unimproved San 21 Soil placed beneath the pipe in the trench. As shown in Figure 5. identified soil movement and the possible loss of pipe bedding21 due to water infiltration as a significant contributor to the rupture of the NGL pipeline.).A. as well as our own investigation. The incident. 2007 Figure 4.3 Second Incident The second incident was discovered on August 29. occurred in the mountain sector near KP 222+500. referred to as the Pacobamba failure. 2005. SF36292. 3. approximately nine months after the first incident. Twenty minutes later. TgP’s control room received this information at 19:34 hours and commenced a leak investigation of the NGL pipeline. the block valves upstream and downstream were closed to isolate the rupture site.3 m long that connected two much longer sections of piping. just upstream of PS #4. the 14-inch NGL pipeline has a nominal wall thickness of 0. which verified the existence of a small (approximately 2. NGL pipeline excavation. a slope profile of approximately 15%. On September 1.5-inch-long) circumferential crack along a girth weld of the NGL pipeline. at 15:00. Exponent staff inspected this site and interviewed TgP personnel familiar with the rupture. A local resident discovered a small hydrocarbon surface stain caused by a minor leak in the NGL pipeline. the removed fractured pipe section. and a burial depth of 1 to 1½ m. and at 20:04.003 A0F0 0607 0806 14 . MCI identified the leaking weld as being part of a tie-in section approximately 1. MCI also performed a detailed investigation of the fracture surface of the NGL pipeline. 2005. the field investigation. Remediation and stabilization work completed before the inspection included temporary repair of the pipeline and cleanup of hydrocarbon-containing soil and rock.June 8.219 inch. the pipeline was shut down. 2006. On June 14. with initial participation of Exponent. Selected photographs of the area from that visit are shown in Figure 5. It is noteworthy that the normal operating pressure is very low at this elevated location. MCI analyzed. At this location. At the time of our visit. 2007 Antonio-Pacobamba Road. and temporary repair of the NGL pipeline using a slip-on sleeve were completed. which contributed to the low leakage rate (significantly less than a fraction of 1% of the NGL pipeline’s product flow rate). the NGL line was exposed in a series of three trenches. and a bypass pipe was being installed to enable removal of the fractured pipe section with the slip-on sleeve and installation of a permanent repair. SF36292.to 2. 2007 Road Ridge Figure 5.003 A0F0 0607 0806 15 . Photographs taken on June 14. Location of second spill incident. Bottom: View downstream (upslope) across trenches opened for repairs. SF36292. 2006.June 8. during permanent pipeline repair work. at KP 222+500. Top: View upstream (downslope) along excavated trench along NGL pipeline. June 8, 2007 MCI’s investigation indicates that the leakage began as a time-delayed, hydrogen-induced crack on the inside surface of the pipe and extended radially to a crack depth of more than 90% of the wall thickness (see Figure 6). Mild steels used in pipeline construction are known to be susceptible to hydrogen-induced cracking (HIC). Because hydrogen can be introduced temporarily during welding, welded regions of the pipe are particularly susceptible. Typically, these cracks can take between several hours and several days to develop after welding. While the hydrogen-induced crack was evident in the post-failure radiograph, it was not visible in the post-weld radiograph that was performed according to TgP one day after welding. This 90% deep hydrogen-induced crack, though close to critical, was able to pass the subsequent hydrostatic test, performed approximately 5 months after welding. Pressure cycling during hydrostatic testing and the subsequent pressure fluctuations during operation of the pipeline further destabilized the crack, which ultimately caused—at a much later time during normal operation of the NGL pipeline—the formation of a tight through-wall crack from which the NGL escaped very slowly. Exponent’s current understanding is that the hydrogen-induced crack originated in the weld, and that the low normal operating pressure at this location likely delayed the rupture of the weakened NGL pipeline. Figure 6. MCI photograph showing frontal view of fracture surface of the pipe from the second spill incident of the NGL pipeline at KP 222+500. White arrows indicate the weld’s root pass in the background to the fracture surface; red arrows indicate the inner surface of the pipe where the hydrogen-induced crack began; and yellow arrows indicate the narrow remaining ligament at the outer surface of the pipe. SF36292.003 A0F0 0607 0806 16 June 8, 2007 3.4 Third Incident The third incident, referred to as the Toccate failure, occurred on September 16, 2005. This failure occurred in the upper jungle sector near KP 200+700 on the Pacobamba variant, a portion of the ROW that was rerouted before construction, primarily for environmental reasons. This rupture was caused by a fairly substantial landslide that extended across the ROW and severed a girth weld that joined a bend (wall thickness of 0.344 inch) to a straight pipe (wall thickness of 0.219 inch). This section of the ROW is on a tall, steep, west-facing valley wall and follows a long, unimproved road between San Antonio and Toccate. The third incident occurred approximately 1 km northeast of the town of Toccate at an elevation of approximately 2,350 m. Various studies conducted prior to construction had identified this area as having many unstable geologic zones that would require special engineering and construction methods. The location was described as having a very high physical risk due to the potential for shallow landslides,22 rockslides,23 and debris flows.24 Based on these findings, some geotechnical mitigation measures were installed to stabilize the slope and protect the pipeline. Mitigation measures implemented during construction included the establishment of a narrower ROW to minimize the heights of cut slopes, and carefully controlled blasting to minimize vibrations that could loosen rock masses above and below the roadway. GEOTEC’s October 2004 report, two months after the system was placed into operation, describes the area as the most unstable site that they evaluated along the ROW, and the area of greatest risk for the stability of the pipelines in case of ground movement. Evidence of ground movement in the form of cracks and distorted retaining walls was noted in two zones, one above the pipelines and one below. The upper zone of movement was adjacent to a slope failure that occurred after the installation of the pipelines and forced their relocation. GEOTEC recommended long-term monitoring and geotechnical stabilization measures. Exponent’s site visits along this section of 22 23 24 A mass of soil and/or detached bedrock that slides downslope. The moving mass is generally thinner than about 3 to 6 m. Movement can be slow or rapid – measured in meters per month to meters per second. A mass of detached bedrock that slides downslope. The mass can be less than a meter to many tens of meters thick. Movement is generally rapid – measured in meters per day to meters per second. A mass of mud and rocks that flows downslope, generally during or shortly after heavy rainfall. The mass is usually no more than a few meters thick. Movement is rapid – measured in meters per second. SF36292.003 A0F0 0607 0806 17 June 8, 2007 the ROW slopes showed evidence of incoherent, highly fractured rock and locally thick soil along very steep slopes that extend a long distance above and below the road. The rupture was detected in the control room due to a pressure drop at PS #3 on September 16, 2005. At 00:15 hours, the operating system reported normal operating conditions. A drop in pressure and flow rate was registered at 00:16, which automatically activated the upstream and downstream block valves to isolate the rupture site. One minute later, the pipe operator stopped pumping NGL. The total amount of released NGL was estimated to be approximately 1,102 m3, of which approximately 410 m3 remained after evaporation.25 No fires or explosions occurred as a consequence of the rupture. TgP’s technical report on this rupture identifies several measures that were deployed to capture the NGL liquid downslope of the rupture site, as well as along the possible flow path of the Chunchubamba River, a tributary to the larger Apurimac River. Exponent inspected this site on June 14 and September 19, 2006. Selected photographs of the area from the first visit are shown in Figure 7. Remediation and stabilization work completed before our June 2006 visit included construction of a bypass pipeline beneath the roadway, and completion of various interim geotechnical works along approximately 500 m of the ROW. As a result of ongoing stability problems at the site, a bypass tunnel, approximately 730 m long, was under construction from Rio Corimayo northeast of the site to the next ravine southwest of the site. Remediation works completed by September 19, 2006, just prior to completion of the tunnel, included widening the road by cutting back the base of the upper slope, removing about 60,000 m3 of unstable material above the road, benching the slope above the road, building a new retaining wall and subdrain at the base of the road cut, improving surface drainage, and planting trees. Although the pipeline was to be rerouted through the tunnel, away from the unstable area, stabilization work was performed to allow continued use of the San Antonio– Toccate Road through the failure area. 25 Inter-American Development Bank (2006), “Camisea Project: Incident Report”. SF36292.003 A0F0 0607 0806 18 June 8.003 A0F0 0607 0806 19 . SF36292. 2006. during stabilization work. Top: View upstream showing large landslide above and below ROW. General area of the third spill incident. Bottom: View downstream along ROW showing alignment of temporary bypass pipeline (beneath stacked sacks) and new retaining wall at base of cut slope. 2007 Landslide Walls Figure 7. 2006. and September 19. Photographs taken on June 14. at KP 200+700. 003 A0F0 0607 0806 20 . MCI conducted various tests to quantify the material’s strength.June 8. Exponent concludes that the most significant contributing factor to the failure of the pipe was external geotechnical forces induced by a large landslide that extended across the ROW. Figure 8 shows the ruptured NGL pipe section that was completely severed by the landslide in a ductile overload tension failure. MCI determined that the fracture had no distinct fracture origin and occurred in the base metal and heat-affected zone next to the circumferential weld. SF36292. Figure 8. 2007 MCI performed the metallurgical investigation of the pipe from this incident. at KP 200+700. Exponent reviewed MCI’s investigation and visually inspected the failed pipe section. MCI confirmed that the weld was in compliance with the applicable codes. In summary. MCI photograph of pipe from the third spill incident. and ductility and determined that it showed satisfactory properties and compliance with the applicable codes. hardness. the NGL pipeline has a diameter of 14 inches and a nominal wall thickness of 0.1 m for the NGL pipeline.0 to 3. a cleaning pig with plates was passed through the entire pipeline. 2005. After installation of the pipelines. operations personnel closed the block valves 55 minutes after pumping stopped and the leak analysis was completed.0 to 2. pumping was stopped by TgP. At 05:00. at the crossing of the Paratori River (KP 50+900).0 m in diameter had been installed along the river banks to protect the pipeline from lateral erosion. 26 27 28 The “as-built” drawing at this specific location identifies a minimum burring depth of 2. Both pipelines were originally buried about 2. the operational flow rate decreased by approximately 20% over a period of 5 minutes.26 At this location. which is standard construction practice.0 m during the rainy season. Consequently.June 8. In addition to the protective polyethylene cover that sheaths each pipeline. which can rise 1. The river is less than 10 m wide. and ascend a steep slope on the opposite side of the river. both the NGL and NG pipelines were covered with a reinforced concrete layer at the river crossing.1 m below the stream bottom.219 inch. 2007 3.27 TgP has indicated to Exponent that the sizing plates did not identify any significant deformation to the pipe. The pressure reduction was not sufficiently large to activate the automatic rupture detection mechanism of the block valves upstream and downstream of the rupture. SF36292. but the fast flow and the presence of large boulders (approaching 3 m in maximum dimension) suggest a steep gradient. According to TGP procedures. The pipelines approach the river on relatively flat terrain. At approximately 04:55 in the morning of November 24. including this river crossing section. Furthermore. the first action to perform after indication of a leak is to stop the pumping and start an operating analysis to identify the segment of pipe involved in the leak. 2005. TgP operations personnel in Lurin identified this rupture by detecting a reduction in flow downstream at PS #2 (KP 108).5 Fourth Incident The fourth incident was detected on November 24. The October 2004 GEOTEC report describes the river as carrying a high flow of water. the hydrostatic test of this section was performed and did not indicate any leakage.28 Estimates29 of total NGL volume leaked indicate a loss of approximately 736 m3. A protective rockfill layer of boulders 1. No fires or explosions occurred as a consequence of the rupture. An inline pipe tool to clean the pipeline.003 A0F0 0607 0806 21 . Subsequent to the failure of the NGL pipeline. and is nearly vertical above the groove. 2006. Excavation revealed that the concrete coating of the NGL pipeline was missing over a length of a few meters and that the slightly-higher-positioned NG pipeline’s concrete coating showed some signs of erosion. Testing of the pipe material from this location revealed satisfactory material characteristics. 29 Inter-American Development Bank (2006). The groove itself is inclined at an angle of 55 degrees with respect to the pipe axis. MCI’s external examination of this pipe section revealed a deep dent and an external groove that bisected the approximately 7. Figure 10 shows that the rupture is inclined 50 degrees to the pipe axis below the groove. The groove was more likely caused by a gradual application of pressure due to construction equipment than by the scraping movement of rocks carried by streamflow. Exponent participated in the initial metallurgical laboratory investigation of this rupture in July 2006.June 8. A flash flood reportedly preceded the rupture. a steel truss bridge was installed to support an aerial bypass pipeline.5-inch-long rupture. TgP removed the section of the NGL pipeline containing the rupture and sent it to MCI for metallurgical evaluation. 2007 On June 13. The maximum water level was reported to be on the order of 2 to 3 m above the stream level observed during our site visit (see Figure 9). No girth welds were present in the vicinity of the rupture. Selected photographs of the area from this site visit are shown in Figure 9. The original NGL pipeline section that crossed the river was excavated in late May 2006. Exponent made observations and interviewed TgP personnel who were familiar with the construction and stabilization measures at this site. “Camisea Project: Incident Report”.003 A0F0 0607 0806 22 . SF36292. Photographs taken on June 13. SF36292.003 A0F0 0607 0806 23 .June 8. at KP 50+900 showing river crossing and new steel truss bridge carrying the NGL bypass pipeline. Top: View looking downstream (uphill). Bottom: View looking upstream. 2007 Approximate Location of Rupture Approximate High Water Mark at Rupture Figure 9. Site of fourth spill incident. 2006. it was not sufficient to breach the wall of the pipe. Indeed. In summary. Black material is the damaged protective polyethylene cover. with the pipe being horizontally aligned and NGL product flow being from the right to the left. although the initial mechanical damage that caused the dent and groove initiated the subsequent rupture.003 A0F0 0607 0806 24 . 2007 Figure 10. SF36292. the pipe wall at this location apparently was capable of containing the NGL fluid until some unknown external loading event caused the already weakened pipe wall to fail in ductile overload at the damaged area. It is currently believed that the damage sustained to both the NGL pipeline’s concrete coating and to the pipe itself was most likely associated with external mechanical damage caused by human activity. Observed groove (white arrows) and rupture (red arrows) on the outer surface of the pipe. This triggering loading event could have been associated with the flash floods that immediately preceded detection of the leak.June 8. and an elevation of approximately 1. which was apparently ignited by a source in a farm dwelling located downhill from the rupture. the NGL pipeline has a diameter of 14 inches and a nominal wall thickness of 0.30 below a saddle.” with medium potential for mudflows. The NG pipeline was buried at a slope and depth similar to the NGL pipeline.32 30 31 32 A swale is a small valley. 2007 3. The geological and geotechnical reports of this sector indicate the potential for slope instability to be “high” to “very high. A saddle is a low point on a ridgeline. The rupture of the NGL pipeline resulted in an explosion. in the jungle sector at KP 125+950.June 8. The resulting hydrodynamic force of the escaping NGL formed a sinkhole. This section of the pipeline is in a broad topographic swale. The NGL pipeline at the rupture location has a slope of about 15% to 20%. TgP’s control-room personnel in Lurin detected this rupture following a pressure-drop warning from an upstream block valve at 15:27:00 in the afternoon. Site soils are described as wet. The downstream block valve was closed at 15:32:12. SF36292. At the point of rupture. Pumping at the upstream pump station (PS #2) was reported to have ceased 20 seconds after the pressure drop was detected. At this location. this block valve automatically started to close and was verified to be closed at 15:28:12. No fatalities. The slopes at the site are gentle to moderate and are bisected in some places by shallow ravines. generally on a hillside. 2006.000 m. approximately 5 minutes after the pressure drop was detected. Subsequent site inspection revealed that the NGL pipeline was completely severed at the rupture point. a burial depth of approximately 1 to 2 m.6 Fifth Incident The fifth incident occurred on March 4. but with good surface drainage and moderately good subsurface drainage. Inter-American Development Bank (2006).375 inch.31 on a ridge about 2 km southwest of Rio Cumpirusiato. the pipe was near the base of a slope above an intermediate bench. as shown in Figure 11.003 A0F0 0607 0806 25 . A few seconds later. “Camisea Project: Incident Report”. were reported. but two injuries. Osinerg filings indicate that 661 m3 of NGL was released during this rupture. SF36292. General area of the fifth spill incident.003 A0F0 0607 0806 26 . during stabilization work. 2006.June 8. Top: View upstream (downslope) along the ROW. Photographs taken on June 13. Bottom: View downstream (upslope) across excavation made to remove unstable soil. 2007 New Stabilization Measures Figure 11. at KP 125+950. with rapid incremental tearing. MCI concluded that crack nucleation occurred at the bottom portion of the pipe in the heat-affected zone of the weld.01 inch per load step. cleanup of hydrocarbon-containing soil. was upslope along the ROW. and the third. 2007 On June 13 and September 20. uppermost. MCI determined that the ductility. after which its rate of growth increased to approximately 0. excavation of unstable soil to the left of the point of rupture and extending left of the ROW. lowest. The rupture was believed to have been caused by a shallow landslide that was part of a complex.055 inch (see Figure 12). The first. Using scanning electron microscopy (SEM). As with the preceding four failures. installation of subdrains along and across the ROW.003 A0F0 0607 0806 27 . construction of the foundation and first above-ground layer of a retaining wall in the excavated area. Subsequent loading propagated this crack. This nucleation zone was characterized by mostly ductile narrow slant fractures that joined to form a single large crack with a depth of approximately 0. The crack then became critical. hardness.June 8. 2006. Selected photographs of the area from that visit are shown in Figure 11.5-inch-long arc. landslide was located in the area that has since been excavated. and construction of most of the length of a concrete-lined channel along the right edge of the ROW to replace the original berm-type drainage channel lined with sacks of soil cement. and the pipe wall was breached and severed around its complete circumference. to form a flat fracture that followed a 10. strength of the pipe materials and weld materials were in compliance with the required codes. the second was at the point of failure. it was determined that the nucleated crack grew through about half the thickness of the pipe wall. interconnected soil movement of at least three landslides that occurred at about the same time. Remediation and stabilization work completed before our visit included repair of the pipeline. MCI performed a detailed investigation of both the fracture surface of the NGL pipeline and the material properties of the pipe. MCI was retained to perform the metallurgical investigation of this rupture at KP 125+950. SF36292. Exponent inspected this site and interviewed TgP personnel who are familiar with the construction and stabilization measures. construction of a buried retaining wall parallel to and to the left of the NGL pipeline with stabilizing ties to the pipeline. 003 A0F0 0607 0806 28 . were likely a substantial factor in the rupture of the NGL pipeline at this location. The cause of movement of the shallow landslide was likely the infiltration of surface water into the ground due. indicate that both pipelines pass through a shallow active landslide at this location. We therefore conclude that external forces produced by ground movement. slanted fracture associated with crack nucleation. SF36292. We also believe that the geotechnical stabilization measures implemented after the rupture have significantly reduced the future risk of landslides at this location. We also understand that a local inhabitant had altered some of the surface drainage in this area prior to the rupture. to the truncation of a natural drainage crossing the ROW and direct precipitation and surface runoff.33 as well as Exponent’s field inspection of the rupture site. at an amplification of 14×. in part. Each zone is numbered. MCI photograph showing fracture surface of NGL pipeline at the fifth spill incident. White arrows identify the narrow. with the outer surface of the pipe being the top portion of the photograph. Recent geotechnical studies by IGL.June 8. 2007 Figure 12. and this shallow slide overlies an older. 33 Ingeneria y Geotecnia LTDA is a geotechnical firm in Columbia that has extensive experience in jungle areas. likely preceded or accompanied by washout of the pipeline’s bedding. Blue arrows demarcate three distinct fracture zones. larger landslide. Typically. SF36292.” April 16th. including the reports TgP submitted to OSINERG. TgP is currently investigating the root cause of this incident. TgP identified as part of its pipeline integrity analysis a sixth incident of the 14-inchdiameter NGL pipeline on April 2.7 Sixth Incident Recently. TgP informed us that the NGL pipeline was repaired by mid-April 2007. Figure 13 depicts the excavated pipe section with the localized wrinkle away from the girth welds.June 8. Exponent has not conducted a complete investigation. To date. with protected wrinkle from which NGL was reported to have been leaking. however. and this analysis is based on the material submitted by TgP to Exponent. 2007. 2007 3.003 A0F0 0607 0806 29 . “Estamacion Del Volumen De Perdida De NGL En KP 125+500. Figure 13. external loading is responsible for the formation of such wrinkles if no thermal stresses are induced. TgP reported that only a small amount (approximately 0. 2007. and this leak was discovered during planned activities of TgP’s pipeline integrity management program. Excavated NGL pipe section from the sixth spill incident. 34 Coga.3 m3)34 of NGL was released. The location of this spill incident is shown on Figure 1. at KP 125+500. at KP 125+950. are relatively small. respectively. SF36292. and subsequent crack growth due to normal operational pressure fluctuations need be only minimal to reach a critical crack depth that causes the remaining ligament ahead of the crack to fail. progressive soil loading is the likely driver that propagated an initial crack and induced the rupture of the NGL pipeline.June 8. In the case of the first incident. appears to have been primarily the result of a time-delayed.35 Our current understanding is that the combination of hydrostatic load cycles and subsequent operational pressure fluctuations caused the initial hydrogen-induced crack to be further destabilized. For the fourth incident. the rupture of the pipe at this location is attributed to overload caused by a substantial landslide. ultimately perforating the pipe wall and releasing the NGL at a very slow rate. 2007 3. Analysis performed to date indicates that this dent was not 35 This is a rather deep crack.8 Summary and Conclusions Exponent’s review of the first five NGL pipeline spill incidents identified similarities in the fracture surfaces of the first and fifth incidents. current information suggests that the rupture of the NGL pipe was induced by mechanical damage to the exterior concrete coating and a dent in the exterior wall of the NGL pipeline. the crack resulted in complete severance of the pipe. The toughness of the pipe material allowed the pipe to pass subsequent hydrostatic testing. though frequent. at KP 8+850. which occurred at KP 8+850 and KP 125+950. The pressure fluctuations at this location. hydrogen-induced crack in the weld. While some measures to mitigate this geologic risk were taken during construction. a sizable landslide ultimately overcame these measures and both undermined and overtopped the road and ROW. The second incident. which helped delay the propagation of the crack through the remaining wall thickness. The hydrogen crack escaped detection by the post-welding radiography because of the inherent time delay of hydrogen cracking. the crack resulted in a through-wall leak of about 10 inches in extent. The third incident occurred in an area that was well studied from a geologic perspective and was known to be an area of very high risk of ground failure. In both cases. In both cases. in the fifth incident.003 A0F0 0607 0806 30 . even though the crack extended to approximately 90% of the wall thickness. Exponent’s investigation identified unstable geologic conditions as a significant contributor to the ruptures. Hence. at KP 222+500. at KP 50+900. The sixth incident is still under investigation. SF36292. This triggering loading event could have been associated with the flash floods that immediately preceded detection of the leak. Indeed. and no final conclusions concerning its origin and relation to the other incidents have been reached to date.June 8. 2007 caused by contact with a boulder being washed downstream.003 A0F0 0607 0806 31 . the pipe wall at this location was apparently capable of containing the NGL fluid until some unknown external loading event caused the already-weakened pipe wall to fail in ductile overload in the damaged area. Part 192. but are fundamentally intended to ensure pipeline integrity and safe operation.June 8. These design load requirements vary slightly from code to code. we review the hydraulic analysis and the geotechnical design considerations for the system during the design phase. operation and maintenance of pipeline systems. respectively. The mechanical engineer is ultimately responsible for the overall pipeline design.4 (Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids). Seismic hazards and scour at river crossings are evaluated in Sections 8 and 9. the first step in the mechanical design process is the hydraulic analysis.003 A0F0 0607 0806 32 . Rather.8 (Gas Transmission and Distribution Piping Systems) as well as the Code of Federal Regulations (CFR). SF36292. the designer needs to exercise due care and consideration for all reasonable and expected load cases. 2007 4 Design-Related Risks 4. and the NG pipeline was required to conform to ASME B31. construction. with guidance from the geotechnical engineer or geologist. these codes do not provide requirements for all conditions. and pipes is performed. inspection. whether usual or unusual.1 Design Background Several different engineering disciplines are involved in designing pipelines. In this section. where the sizing of pumps. Transportation of Natural and Other Gas by Pipeline. that the designer may encounter. wherein the designer considers load cases other than the internal design pressure in the pipe. This typically leads to an iterative design process between the engineers performing the hydraulic and the pipe stress analyses. Specifically. testing. This information is carried over to the next step. The Camisea Transportation System was designed to the requirements of standards issued by the American Society of Mechanical Engineers (ASME) that are national standards of the United States. Title 49. the NGL pipeline was required to conform to ASME B31. but reliable input is sought from geotechnical engineers and geologists to evaluate the manner in which the pipe will interact with soils and other environmental components. However. The primary purpose of these codes is to establish requirements for design. Commonly. a pipe stress analysis. valves. The profiles show good agreement. 2007 4. the hydraulic analysis determines the internal pressures along the pipeline route. indicating that only minor deviations should be expected between the design calculations and the as-built alignment.2. Using this information.2 Hydraulic Design Risks 4. Comparison of the pipeline elevation profile along the ROW. Figure 14.003 A0F0 0607 0806 33 .June 8.1 General Review Exponent reviewed the design hydraulic analysis and operational data from TgP’s SCADA system. The hydraulic modeling of the system requires as input a well-defined pipeline profile and the hydraulic performance requirements of the pipeline. Figure 14 provides a comparison of the elevation profile of the pipeline for the first 550 km between the initial design and the as-built condition. SF36292. with the graph origin being in Malvinas. This internal pressure is then used to compute a minimum allowable pipe wall thickness that adheres to the code design requirements for the internal pressure. For the NGL pipeline.June 8.003 A0F0 0607 0806 34 .7 0. with the smallest margins typically existing downstream of the four pump stations.4 0. and 226.2 Hydraulic Design of NGL Pipeline The hydraulic analysis can be divided into two parts: the steady-state analysis and the transient analysis. where this ratio is to be smaller than 1 at all times.000 BPD (barrels per day). Based on this internal pressure. 108.9 0. 2007 4.1 #1 PS PS #2 PS #3 PS #4 Maximum Operating Pressure/MAOP 1 0.2.5 0.1 0 0 100 200 300 400 500 600 Distance (Km) Figure 15.000 to 70.2 1. a minimum allowable wall thickness was determined. Ratio of the maximum operating pressure to the MAOP along the ROW of the NGL pipeline. Our review indicates that the hydraulic analysis relied on typical modeling techniques to compute the internal pressures along the NGL pipeline.8 0.2 0. Figure 15 provides a graphical depiction of the ratio of the maximum internal operating pressure to the maximum allowable operating pressure (MAOP) per ASME B31.6 0. at KP 0.4. the steady-state analysis was carried out for flow rates of 10. SF36292. 1. 209.3 0. The requirements of ASME B31. The steady-state analysis was carried out for flow rates ranging from 205 to 215 MMSCFD (million standard cubic feet per day). Our review indicates that the considered transient events are at all times smaller than 1.3 Hydraulic Design of NG Pipeline Techint’s hydraulic analysis of the NG pipeline included a steady-state analysis and a blocked-in load condition providing the largest pressures. In summary. Based on this internal pressure. Accordingly. and the minimum specified delivery pressure at Lurin is 40 barg. Furthermore. and pipeline control in the operating pipeline appear to be consistent with the hydraulic analysis.June 8.1 times the allowable MAOP.003 A0F0 0607 0806 35 . because the hydraulic analysis shows that the Camisea NGL pipeline does not exceed either the static or transient MAOP. a minimum allowable wall 36 Stoner Pipeline Simulator (SPS) is widely used for the transient flow simulation of natural gas and liquid transmission systems. pumping capacity. pump shutdown and pump startup. our review indicates that the hydraulic analysis of the NGL pipeline has been properly executed in conformance with code requirements. the mechanical design was carried out in compliance with applicable codes and engineering practice.4. a transient study was performed using the Stoner36 pipe simulation software. SF36292. The hydraulic analysis relied on typical modeling techniques to compute the pipe friction coefficient and associated pressure drops. The maximum operating pressure is the blocked-in pressure if the block valve at the end of the pipeline were to be closed. or any combination of these events. and no undue hydraulic risks were introduced. flow rates. 4. the actual internal pressure. 2007 In addition to this static analysis. The maximum delivery pressure of the NG pipeline at Malvinas is approximately 147 barg. This static analysis determines the internal operating pressures along the ROW. The largest transient operating pressures are found along the first 50 km of the NGL pipeline and downstream of PS #2 at KP 108. This analysis determined transient pressures along the NGL pipeline due to valve closure.4 concerning the internal pressure design have been met.2. and are in compliance with ASME B31. an analysis was performed that included a compressor station at KP 208 to increase the flow rate. In addition. The largest margins are typically found at river crossings where the pipe has been thickened.8.June 8.8 0. at all times. The requirements of ASME B31. 2007 thickness was determined per ASME B31.8 concerning the internal pressure design appear to have been met. Ratio of the maximum operating pressure divided by the design pressure along the ROW of the NG pipeline.7 0. the hydraulic analysis of the NG pipeline is adequate. The mechanical design was carried out in compliance with codes and general engineering practice. and no undue hydraulic risks were introduced. 1. SF36292.6 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 Distance (km) Figure 16. since the ratio of them is at all times smaller than 1.1 1 Max. larger than the largest expected operating pressure. In summary. Operating Pressure/Design Pressure 0. The operational internal pressure and flow rates appear to be consistent with the results of the hydraulic analysis. Figure 16 clearly illustrates that the design pressure is.9 0.003 A0F0 0607 0806 36 . MRA reviewed aerial photographs. 2007 4. to identify additional unstable zones and recommend stabilization measures. particularly in the selva sector. Orlando Felix38 and Dario Verastegui39 performed more detailed geologic and geotechnical evaluation at thirteen critical sites in the selva sector and made preliminary recommendations to mitigate hazards. In addition. Prior to construction. or adequately mitigating the geotechnical hazards. debris flows.” March 21. External soil loads can be addressed by either designing the pipeline to withstand external soil loads. Golder Associates (Golder) conducted a preliminary geologic and geotechnical investigation in the selva sector.3 Geotechnical Design Risks ASME codes require the designer to demonstrate that all reasonable foreseeable load conditions. be considered during the design process. 2003. Route in Sector Selva – Project Camisea. topographic information. Sierra and Costa Sections. and conducted field inspections along the proposed 37 38 39 40 Golder Associates. with the stated objective of determining the geologic and geotechnical feasibility of the proposed alignment. Orlando Felix Salvador.003 A0F0 0607 0806 37 .June 8. which include external loads. hillside erosion.” February 2002. rock falls. MR Associates. “Final Report – Geologic and Geotechncial Reconnaissance. and geologic maps.” December 2001. imposed by soil pressures or ground movements. the system designers opted to construct geotechnical stabilization measures to mitigate potential external soil loads. SF36292. The Golder study identified the five main geotechnical and geologic hazards in the selva sector as being landslides. “Final Report – Geologic and Geotechnical Reconnaissance. Given the challenging geotechnical conditions and diverse terrain present along the pipeline. and flooding/river erosion. MR Associates40 (MRA) conducted a preliminary geologic and geotechnical investigation in the sierra and costa sectors. Natural Gas and Liquid Natural Gas Pipelines. “Pipeline –Sector Selva – Geologic Inspection of the Route – Critical Zones and Pumping Stations 2 and 3. with the stated objective of determining the geologic and geotechnical feasibility of the proposed alignment. Route of Camisea Pipeline. “Geotechnical Inspection of Route – Camisea Pipeline – Sector Selva. Both the Felix and Verastegui reports recommended further geological and geotechnical studies during construction. satellite images. Golder developed an algorithm to evaluate the risk at sites along the route and identify zones of concern. and conducted field inspections along the proposed pipe route.” March 2002. 37 Golder reviewed aerial photographs and satellite images. Dario Verastegui. 41 Code compliance is established if the designer demonstrates that all specific code requirements and all reasonably foreseeable load conditions are addressed by the design. MRA recommended implementing surface and subsurface drainage facilities to prevent erosion and soil creep. We have independently verified that the computed design pressures are code compliant and in good agreement with the measured operational pressures along the whole length of both pipelines.e. external loads were expected to be an important consideration in designing and constructing the system.June 8. identifying locations where excavation cuts would reduce the stability of the slopes near the pipes. 4.. any risks associated with the internal pressure aspects of the design are minimal and consistent with other pipelines. increasing the depth of pipe embedment at sites susceptible to erosion. debris flows. Our review revealed that the pipeline was designed such that external soil loads would be mitigated by geotechnical SF36292. and recommending corrosion prevention near the costa sections. as evidenced by the geotechnical and geologic studies. 2007 pipe route. hydraulic risk). Given the demanding route of these pipelines through the jungle and over the mountains. or scour.4 Conclusions The system was designed to comply with ASME engineering code requirements. and evaluation of alternative route alignments where active slides or marshy lands were identified. Foreseeable load conditions apply to internal pressures and to external loads imposed by soil pressures or ground movement.003 A0F0 0607 0806 38 . The preliminary geotechnical and geologic reports and more specific geotechnical studies performed during the design phase indicated that the geotechnical and geologic conditions would be complex and challenging along the alignment. Our review indicates that the pipe wall thickness is sufficient to contain the internal pressures of the transported hydrocarbon products along the entire length of the pipeline (i. Therefore. 4 [Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids] is the applicable Code for the NGL pipeline.June 8.003 A0F0 0607 0806 39 . and ASME B31. SF36292. 2007 stabilization measures to be constructed at sites deemed to pose a geotechnical or geological hazard. 41 ASME B31.8 [Gas Transmission and Distribution Piping Systems] is the applicable code for the larger NG pipeline. In order to minimize the impact on the environment. the cleared section of the ROW was typically restricted to 25 meters or less.. access roads. Each sector was supervised by a Project Manager and a Construction Manager.e. 42 The rainy season is a time period of elevated precipitation from late October until April. sierra.42 Techint finalized the pipeline alignment.000 people on 12 spreads. At the end of the 2001–2002 rainy season. The pipe route had to be contained within the 3-kmwide. The first step was to clear and grade the ROW. TgP decided to preferentially build the pipeline along or near topographic ridges of the government-mandated 3-km-wide corridor. Exponent interviewed key individuals involved in the construction. both of whom were ultimately responsible for construction of the pipeline in their respective sectors. Due to limitations imposed by the topography of the ridges and the narrow lane of clearing (25 meters). government-mandated corridor. and mitigation measures were constructed at that time. and costa sectors. camps. SF36292. with each spread constructing an assigned section of both pipelines. pipe staging sites.June 8. fuel depots. Responsibility for constructing the system was divided into the selva.1 Pipeline Construction Characteristics Techint commenced construction of support infrastructure (i. Within this 3-km-wide corridor. grading along the ROW typically consisted of cutting into the ridge or hillside and placing the excavated material as “side-cast” or “spill” fill on the downhill side(s) of the clearing. and deviations from this pre-approved corridor had to be granted by the Peruvian government. and loading docks) in 2001. Techint employed up to 10. The pipeline was constructed simultaneously along the ROW between 2002 and early 2004. During construction. 2007 5 Construction-Related Risks 5.003 A0F0 0607 0806 40 . who informed us that the ground conditions encountered during grading and installation of the pipe were assessed by geotechnical engineers. SF36292. trenching may have occurred first. Each weld was x-rayed 24 hours after completion of the weld. The engineer responsible for laying the pipe determined the spacing and number of side-booms and other auxiliary equipment to be used. Techint’s standard installation method appears to have been flexible and adaptable to specific site conditions. Another “special installation” method was also employed at river crossings. The excavated material was placed next to the trench.June 8. the side-booms moved continuously forward with roller-equipped slings. In some instances. the pipes were welded together into a continuous section measuring several hundred meters in length. Figure 17 shows an example of the standard construction method in hilly terrain. or socalled pillows. depending on the terrain: “standard” and “special. every 3 to 5 meters on the trench bottom.003 A0F0 0607 0806 41 . if the ROW was sufficiently wide. resting each pipe on two blocks. upon which the pipeline would initially rest. and later joined to the already-laid pipeline.” The “standard installation” method was used in flat to hilly terrain along the majority of the pipeline ROW. The pipe trench was then dug and prepared for the pipeline by placing several sand bags. Techint used two general types of construction methods to install the pipes. The “special installation” method was reserved for very steep terrain with a grade more than 35%. and protective measures were reportedly taken to prevent the soaking of the excavated material. 2007 The pipes typically were transported to the individual construction sites along the ROW itself. Afterward. because it was the only available route for transportation. If the terrain was flat. The welded pipe sections were lowered into the trench. and sites located along roads and narrow mountain ridges. Techint preferred to string out the pipe prior to welding. as depicted in Figure 18. 2007 Figure 17.June 8. Standard installation of NGL pipeline at KP 107. SF36292. Trenching and stockpiling of cuttings at KP 391. Figure 18.003 A0F0 0607 0806 42 . When possible. The pipe was clamped and welded to the pipeline. rather than in long strings as was done in more gently sloping terrain. the machine depicted in Figure 19 was used to backfill a portion of the trench. Another specialized construction variation arose at ridges and roads. Placement of selected fill as bedding at KP 358 using a machine that separates larger stones from the remaining fill. Backfilling was finalized by forming a crown on top of the filled trench and driving an approximately 4-ton vehicle over the trench to achieve some degree of compaction. SF36292. 2007 Techint’s special installation procedure for steep hills started with trenching. Backfilling of the trench had to satisfy Techint’s construction specification 2794-L-SP-0045. thereby constructing the pipeline segment by segment. concrete plates were placed on top of the backfill to minimize vehicle loads acting on the pipes.003 A0F0 0607 0806 43 . a backhoe carrying the pipe was winched from the top of the hill to the end of the pipeline to place the pipe in position. This construction method allowed advancement of only approximately two pipe segments per day. Once the trench was dug. In locations where the pipeline followed a road.June 8. where the NG and NGL pipeline share a single narrow trench that may be stepped to further reduce the trench width. Figure 19. which provided for the use of selected backfill to contain stones of sizes up to 1½ by 1½ inches. Micro-tunneling was used solely at the Urubamba River crossing. blasting was required to trench. Laying of pipe over the Manugali River at KP 92. 2007 Techint used two types of techniques to construct river crossings: micro-tunneling and trenching.003 A0F0 0607 0806 44 . In some cases. As discussed below. Typically. SF36292. The most commonly used technique relied on trenching the riverbed and laying the pipe into the trench. the pipe was coated with a thick concrete layer to provide ballast and protection (Construction Specification 2794-L-SP-0043: Concrete Casing of Pipes).June 8. Figure 20. the construction methods employed standard engineering procedures. Figure 20 shows the laying of the pipe over the Manugali River at KP 92. reduce. people. GEOTEC was also responsible for evaluating the geotechnical and geologic risks after installation of the system and commencement of system operation in August 2004. whereas cut-slope failures were judged to pose the greatest threat when the cut is in colluvium because of its origin as a landslide deposit that could reactivate.June 8. GEOTEC concluded that geotechnical stabilization works had improved some of the sites during construction. Sections of the pipelines constructed along roadways were identified as being at higher risk of failure. GEOTEC believed that the landslide risk was highest between about KP 50 and KP 90. and to a lesser extent in the sierra sector. two months after the system was put into operation. and control potential damages from natural phenomena to the system. and the environment. 2007 5. Additionally. Supervision of construction required an evaluation of future risks of erosion. and between about KP 175 and KP 197.2 Geotechnical Construction Characteristics During construction of the pipelines. a consortium of geotechnical consultants named GEOTEC was retained by TgP to develop and supervise the implementation of the geotechnical protection work from KP 0 to KP 520. They pointed out that other sites not described in the report could also have stability problems in the future due to the dynamic nature of the terrain and significant precipitation. but other sites already showed signs of increased deterioration. GEOTEC cautioned that maintenance in the selva sector would be required for at least the first 5 years of operation. The report pointed out that the results were intended to prioritize areas for SF36292. and river erosion. GEOTEC concluded that most of the slope failures evaluated in the sierra sector had occurred during construction and were believed to have reached equilibrium but to be at risk of reactivation if subjected to an earthquake or a harsh winter. In October 2004. detailing examples of areas of erosion and ground movement. rockfalls. TgP requested that GEOTEC complete an extensive risk study to characterize the postconstruction stability conditions of the ROW.43 The report concentrated on critical areas of the selva sector and included descriptions of specific stations along the ROW. The report also noted the potential long-term risk to the pipelines arising from failures in side-cast fill downslope of the ROW.003 A0F0 0607 0806 45 . GEOTEC documented numerous manifestations of instability in the selva sector. as well as areas of successful geotechnical stabilization efforts. and recommend measures to prevent. landslides. cracking. Field Reconnaissance on July 17. necessitated the creation of side-cast fills in some particular areas where there was a limitation of the cleared ROW section. conservative values were assumed. no date. they ultimately became a source of concern related to the potential to exert external soil pressures on the pipes. SF36292. During our site inspections. 45 “Camisea Project.003 A0F0 0607 0806 46 .1.” memo to Lucio Costarrosa from Milos Stepanek. excavated soil and rock materials had washed or slid down the steep ridge flanks. 2002. necessitating geotechnical mitigation measures.3 Clearing Related Risks As mentioned previously in Section 5.44. At some narrow ridges. Detailed stability analyses were performed for critical areas. The October 2004 GEOTEC report describes numerous sites at which thick fill stockpiles had experienced ground movement in the form of settlement. Lineas de Conduccion de GN y LGN. Exponent generally concludes that this approach was appropriate for pipeline integrity purposes and helped reduce environmental impacts. soil saturation is mentioned as a key factor in the instability of stockpiles.” memo to Lucio Costarrosa from Milos Stepanek. Although these side-cast fills were generally placed outside the limits of the pipe trenches. Exponent 43 Estudio de Riesgos por Fenomenos Naturales. Variant Pisco. and discussions with Techint employees who were directly involved in the construction of the pipeline.June 8. During our inspections. Based on our field inspections. Proyecto Camisea. where possible. but TgP is currently addressing this issue through the stabilization measures discussed in Section 6. no date. October 2004. TgP decided to preferentially build the pipeline along or near topographic ridges. not all of these side-cast fills were adequately stabilized during construction. In many of these locations. coupled with the government mandate to limit the cleared section of the ROW to 25 meters. 5. 2007 maintenance. Pacobamba Route Sector. 45 In our opinion. The route selection along mountain ridges. 44 Camisea Project. and shallow landsliding. When only limited detailed data were available. Exponent noted sites being stabilized where the geotechnical stabilization measures originally installed during or immediately after pipeline construction were not adequate to stabilize the ROW. g. we noted that TgP constructed many geotechnical stabilization measures in 2006 to address the issues described above.June 8. The ability of material dumped into the trench to flow around and beneath the pipe is dependent on the size of the gap on the sides and beneath the pipe. A detailed description of the stabilization measures undertaken by TgP in 2006 is given in Section 6. would likely flow freely around and beneath the pipe.003 A0F0 0607 0806 47 . soil conditions in the trench are expected to have varied significantly along the alignment. This is generally not a recommended practice. Clods of clay. Exponent reviewed representative photographs taken during construction of the project in the three sectors and at river crossings (e. the material surrounding the pipe was dumped via a mechanized conveyor. primarily because of the wet ground conditions and heavy precipitation that wets the stockpiles. which were known to vary substantially along the alignment. but rather will fall and stack on the sides of the pipe. The moisture conditions in the ground varied from dry (in the coastal sector) to wet (in the jungle sector) to saturated (at river crossings). specifically in natural drainages. potentially creating a large. for example. The conditions in the selva sector. During our field inspection. the trench was backfilled using material processed from excavated material stockpiled along the ROW. likely represent some of the worst conditions for producing material in a suitable form for backfilling the pipe.. Figures 17 to 20). 2007 observed a few instances where this excessive material was apparently used to widen the ROW. 5. Therefore. SF36292. continuous void beneath the pipe and interspersed voids among the clods. The materials used for the pipe bedding and embedment were derived from excavated native materials. Dry sand. unless the slope is sufficiently stabilized. on the other hand. which provide a glimpse of the range of ground conditions that existed during construction of the pipe zones and possible current conditions. The backfill around the pipe reportedly was lightly to moderately compacted. Except in special circumstances. using the tracks and/or wheels of the construction vehicles. will not flow.4 Trenching-Related Risks Based on our discussions with Techint construction personnel. and the material type and wetness of the backfill. One of these three defects was related to the rolled plate material. Brazil. is intended to ensure the integrity of the outer HDPE coating. each approximately 12 m in length.906 installed pipes of the NG pipeline and only three of the 49.June 8. API 5L provides provisions to minimize potential risks to pipe integrity that can arise from the fabrication of the steel plate and the longitudinal electric-resistance weld by requiring minimum material performance. Additionally.e. and two were defective longitudinal welds. flat steel plates were rolled into a tubular cross-section and longitudinally welded into a pipe segment. The pipe manufacturers’ records indicate that these two pipe manufacturers are located in Pindamonhangaba. the hydrostatic testing and the metallurgical analysis of the five spill incidents) indicate that the pipe material was in compliance with the required codes.000 individual pipe segments. Documents and evidence reviewed showed that the pipe was specifically built for this system and consistent with API 5L requirements. and Buenos Aires. Specifically. We understand that TgP is in the process of installing piezometers in the ROW and inspecting the performance of the subterranean drainage systems as a means to assess the potential for internal soil erosion. 2007 Potential geotechnical risks from trench conditions relate primarily to internal soil erosion (“piping”). These electric-resistance welded tubular products were manufactured per API 5L standard. as well as material sampling and quality assurance procedures. 5.003 A0F0 0607 0806 48 . Each segment was then coated with an outer highdensity polyethylene (HDPE) layer to protect the pipe’s exterior from the environment. as described in Specification 2794-P-SP-00005.5 Pipe Material–Related Risks The system was constructed using more than 100. the loss of backfill from erosion could result in external soil pressures acting on the pipe. Available data (i.. SP. A review of the pipe book46 and the pipe manufacturing and coating records indicates that the entire stock of pipe segments used for this system was fabricated at one of two pipe mills during 2002 and 2003. Without proper use of flow barriers to reduce the flow of water traveling through the backfill (“ditch breakers”). Adherence to DIN 30670. All three pipes SF36292. Argentina. hydrostatic testing revealed that none of the 59.193 installed pipes of the NGL pipelines had pipe material defects. SF36292. overlapping the adjacent pipe to provide continuous surface protection. 2003 July 27. 2003 February 16. they demonstrate that the hydrostatic testing was successful in removing these defects before the pipeline was placed into operation. 2004 September 16. Table 1. because hydrostatic testing provided an effective means of identifying longitudinal welding defects. A failure of this protective coating system is significant to the pipeline’s 46 The pipe book lists relevant pipe data. The HDPE coating system is designed to mitigate external pipe corrosion.003 A0F0 0607 0806 49 . risks to the integrity of the HDPE coating arise during the various stages of moving and handling the coated pipes. as can be seen from the more comprehensive discussion of the hydrostatic testing given in Section 5. 2004 March 23. 4. ID 1 2 Leaks identified during hydrostatic testing of the pipeline Location KP 9+906 KP 1+726 Date August 8. at each circumferential pipe joint. 2004 October 4. Pipeline integrity– related risks associated with the manufacture of the coating are typically low. a sleeve is placed.8. This level of defect removal is not atypical. and 5 in Table 1. however. It needs to be recognized that. The three pipe material–related failures do not indicate that the manufacturing process was inadequate. For details on these three leaks. 2003 External damage Partial circumferential rupture of girth weld Exponent currently considers the residual risk of future pipeline failures caused by pipe manufacturing-related risks to be negligible. 2003 Failure Type Partial circumferential rupture of girth weld Longitudinal fracture Partial circumferential rupture Short longitudinal fracture along the longitudinal weld Short longitudinal fracture along the longitudinal weld Partial circumferential rupture of girth weld Failure Cause Description Incorrect assembly of weld joint during construction External mechanical deformation and gauges Localized material defect of manufactured steel plate used for pipe manufacture Localized defect along the factory manufactured longitudinal weld Localized defect along the factory manufactured longitudinal weld Failure of a repair girth weld External damage of pipe due to unauthorized use of construction equipment near pipeline Failure of a repair girth weld Pipeline NGL NGL 3 4 5 6 NGL NGL NGL NGL KP 171 KP 31+494 KP 48+830 KP 170 October 4. rather. The prevention of surface damage to the protective outer layer is an important step in enhancing the protection against external corrosion. 2007 were replaced and successfully passed a subsequent hydrostatic test. see leaks 3. 2003 7 8 NGL NG KP 210 KP 388 January 9.June 8. The crack missed detection by both of these weld quality tests because the crack appears to have developed after the weld was x-rayed. A more detailed description of the inline inspection’s results and a discussion of our observations can be found in Section 7. were the significant contributing factors in three of these four incidents. a review of the welding records indicates that the issued welder certificates were consistent with the requirements of API 1104 and ASME Sec. automated methods were used. 5. The NGL pipeline was fabricated using the manual SMAW method. Qualified Welding Procedures (QWP) for girth welds and their field repair are given in Construction Specifications 2794-L-SP-00012. and because the pipe material toughness exceeded the minimum required so that the crack was just below the failure threshold. These standards are used throughout the world for the construction of pipelines. performed an inline pipe inspection of the NGL pipeline to detect any external as well as internal material loss. geotechnical loading conditions.6 Pipeline Field Welding–Related Risks The individual pipes are circumferentially joined in the field using the Shielded Metal Arc Welding (SMAW) and Flux Arc Welding (FCAW) method in compliance with API 1104.003 A0F0 0607 0806 50 . 2794-L-SP-00017. Although four of the six incidents occurred at girth welds. It is not unusual for a small number of preexisting line defects to cause small leaks that are detectible and SF36292. In addition. API 1104 and ASME B31.4 (liquid) and ASME B31. IX. and 2794-L-SP-00031.3. and not weld quality. whereas for the NG pipeline. Exponent reviewed these welding specifications and found them to be acceptable and in conformance with API 1104.June 8.8 (gas) standards establish the framework for the many girth welds that join the individual pipes. In this regard. 2794-L-SP00016. in 2006. TgP operates a cathodic protection system and. This hydrogen crack does not necessarily represent an unacceptable level of risk. 2007 long-term integrity and mitigated by operation of a cathodic protection system and detection of material loss by inline inspection tools. The other incident was caused by a hydrogen-induced crack in the girth weld that both escaped radiographic detection and passed hydrostatic testing. and the radiograph evaluated per API 1104 for any potential welding-induced defects. Hydrostatic testing of the system is mandated by the ASME codes.003 A0F0 0607 0806 51 .1 Background Hydrostatic testing of pipelines is an important tool to verify integrity and identify any leaks.47 It only becomes a significant risk if such cracking is pervasive throughout the system. that a tight hydrogen crack could escape detection by the radiograph. Exponent reviewed a limited number of radiographs and associated reports that did not show any API 1104 code deviations. Hydrostatic testing involves filling each pipe section with water and pressurizing the water to a predefined proof pressure that 47 G. page 10. 5. 5.June 8. there is a very small possibility. 2007 easily repaired for a line that has been hydrostatically tested. “The Development and Results of High Stress Hydrostatic Testing of Gas Transmission Lines in the United States”. Because defects such as an undercut are more easily identified than a very tight hydrogen crack. it was to be radiographed. as with all pipelines.3. A review of the certification records confirmed that the contracted inspection personnel were certified to the required level. 1973.8. Ewing.7 Pipeline X-ray–Related Risks Techint specified that 24 hours after a weld was made. Likewise. Any defects determined not to be acceptable per API 1104 were to be removed and the weld repaired. Radiography is particularly effective in finding weld defects such as undercuts in the weld.8. SF36292. there is also a finite risk that a hydrogen crack could develop just after the radiograph is taken. 12th World Gas Conference. The inspectors who conducted and interpreted these radiographs were to be certified to Level II per API 1104.H. due to the time-delayed nature of a hydrogen crack. A more detailed discussion of the risks associated with hydrogen-induced cracking of girth welds can be found in Section 5.8 Hydrostatic Testing–Related Risks 5. Three leaks were caused by faulty girth welds. eight leaks were identified. such that the effectiveness to detect defects varied along the length of the pipelines. Table 1 lists the specific information for each leak. and the pipeline section was successfully re-tested.June 8. of which seven occurred in the NGL pipeline. The test results are more an indication of the test’s ability to detect preexisting faults. two by faulty longitudinal welds. induced stresses were not uniform. A similar criterion applies to the NG pipeline and is defined per ASME B31. our review indicates that the hydrostatic tests were executed in conformance with the ASME Codes. during hydrostatic testing. These welds are then radiographed 24 hours after the welding. 5. two by external damage that had occurred during construction. All of these failures were subsequently repaired. In the case of the NGL pipeline.25 times the internal design pressure. the individual tested sections of the pipeline are welded back together using either pipe tie-in pieces or welding the adjoining pipe sections together. Eight failures during hydrostatic testing in more than 1. Hydrostatic testing removed 129 defects over a span of 48 TgP’s water tightness test was conservatively extended to be 24 hours long.003 A0F0 0607 0806 52 .2 Hydrostatic Testing Results for the Camisea System During the hydrostatic testing of the Camisea system.000 miles of transmission pipelines that have been hydrostatically tested. For example. If a leak is detected during hydrostatic testing. However.250 km of pipeline is a low number.8. the Texas Eastern Transmission Corporation has in service over 5.48 This hydrostatic test was performed for both pipelines along the entire length of the system. especially considering the challenging terrain. Next. Per this criterion. the water-tightness of the pipeline is verified by maintaining a slightly smaller constant water pressure for at least 4 hours. the specific code requirements are that the hydrostatic test’s proof pressure is 1. which is the expected maximum operating pressure (MOP).8. the pipe is repaired and hydrostatic testing is performed again to verify the pipe’s water tightness and strength. After the test. 2007 exceeds the maximum operating pressure. and one by a foreign object being introduced during rolling of the steel plate. SF36292. SF36292. because defects may be aligned or sized such that the hydrostatic test would not rupture the pipe and the defect could go undetected. and the remainder were defects at the longitudinal welds. Despite these actions.8. The multiple hydrostatic test cycles and subsequent operational pressure cycles of the transported hydrocarbons further 49 G. In the absence of significant external pipe loading. despite the precautions taken by hydrostatic testing. As in any pipeline. but will not leave any trace of its presence after it diffuses out of the weld. where a hydrogen-induced crack was not detected by the radiograph. During the time the hydrogen is present. In the Camisea system and consistent with general pipeline engineering practice throughout the world.June 8. 10 were plate defects. it needs to be recognized that these risks cannot be fully eliminated but need to be managed by the pipeline operator.” 1973. 5. 16 were defects in the girth welds. Ewing. the weld material and HAZ is susceptible to hydrogen-induced cracking. this type of potential defect.H. if it results in a leak. would typically release only small amounts of gas or liquid hydrocarbons.003 A0F0 0607 0806 53 . however.3 Hydrogen-Induced Crack–Related Risks Hydrogen-induced cracking (HIC) is a well-known phenomenon that affects welds in which hydrogen can be temporarily introduced during welding of mild steels. some minimal risk may exist. This temporarily trapped hydrogen embrittles the weld material and heat-affected zone (HAZ).49 Of these 129 defects. This situation arose with the second spill incident of the NGL pipeline. 2007 3. page 10. This situation arose with the second spill incident at KP 222+500. Hydrostatic testing plays an important role in detecting flaws and cracks in pipelines in order to reduce operational risks and the likelihood of subsequent pipeline incidents. 12th World Gas Conference. this hazard was mitigated during construction by radiographic inspection of all girth welds and hydrostatic testing. “The Development and Results of High Stress Hydrostatic Testing of Gas Transmission Lines in the United States. and the subsequent hydrostatic test and initiated the subsequent spill incident. these cracks are formed several hours to several days after welding.424 miles of pipe. Typically. in which the tough pipe material of the system did not rupture during hydrostatic testing. a potential residual risk is that partial penetration cracks can survive the hydrostatic test. ultimately breaching the wall and causing a slow leak in the NGL line at KP 222+500. the radiography of all girth welds and hydrostatic testing of the system provides a level of risk mitigation consistent with general pipeline engineering practice. but the post-failure radiograph clearly showed a hydrogen-induced crack. risks are not as high as for a rupture situation. However. which are discussed in more detail in Section 6. because absent soil movement. the review showed that (1) the pipe was specifically built for this system and consistent with API 5L requirements. GEOTEC recognized this risk and recommended additional geotechnical stabilization measures. The incident at KP 222+500 is currently not considered to be indicative of any systemic problems for the more than 100. We currently believe that hydrogen-induced cracking is not a systemic issue. The five repetitions of this hydrostatic test were necessitated by the pipe’s inability to hold pressure in the initial test. the constructed geotechnical stabilization measures proved to be insufficiently robust that soil stability was initially problematic along the ROW. The occurrence of this type of failure should be very low. 2007 propagated this initial hydrogen-induced crack. and when it does occur. Overall. Exponent’s investigation currently indicates that the post-weld radiograph at KP 222+500 showed no signs of a hydrogen-induced crack. a failure with a slow leak rate should be the more likely outcome.000 girth welds. The severity and challenges of the dynamic terrain led to the construction of geotechnical remedial measures at more than 100 locations in 2006.003 A0F0 0607 0806 54 . (2) the issued welder certificates and qualifications of the inspectors SF36292. The hydrostatic test of this section was performed five months after the fabrication of this joint and lasted for approximately a month. Exponent’s review and analysis currently indicates that the most likely cause for the failure of the initial hydrostatic tests was entrapped air. our inspections in 2006 showed that a significant portion of these measures were not sufficiently effective and robust to stabilize the ROW.9 Conclusions Construction of the pipeline used methods that employed standard engineering procedures. 5. Overall. The reviewed test results showed no indication of a leak for the final hydrostatic test.June 8. On the other hand. 2007 were in compliance with API 1104.June 8. and (3) hydrostatic testing of the system was in compliance with the required ASME codes.003 A0F0 0607 0806 55 . SF36292. low resistance to weathering. the conditions include very steep and high slopes. narrow ridges. but the water table can rise during periods of intense rainfall that occur 50 For purposes of this report. particularly when devoid of vegetation. The mountain (sierra) sector is characterized by natural conditions that are somewhat better than those in the selva sector. 2007 6 Geotechnical and Geology-Related Risks 6. amounts of precipitation. deep rotational landslides in colluvial deposits. and other conditions that pose a myriad of geotechnical and geologic hazards50 and challenge the integrity and reliable operation of the pipeline. whereas geologic hazards are defined as movement in rock. hard rock. and high-gradient streams. The jungle (selva) sector is characterized as having geotechnical and geologic conditions that pose the highest risk to the integrity of the pipelines. geotechnical and geologic hazards are external ground pressures resulting from ground instability or movement. freezing temperatures.1 Geotechnical and Geologic Conditions The Camisea Transportation System carries natural gas products through the jungle. wedge landslides.003 A0F0 0607 0806 56 . and ridge instability. isolated areas of flatter slopes with high-plasticity weathered soils. Geotechnical hazards are defined as movement in soil. and along the Pacific coast. relatively thick deposits of moderate to high-plasticity residual soils. Groundwater typically does not exist within the pipe zone. typically when saturated. low strength. Specifically. Each of these geographic regions possesses distinctive terrain. SF36292. but still pose significant risk to the pipelines. all of which are a direct consequence of the steep topography and heavy precipitation. rock slides. The salient geotechnical and geologic hazards for the selva sector include debris flows. The rocks and soils in the selva sector are generally characterized as materials with low durability. The conditions include very steep and high slopes. and moderate to high susceptibility to erosion. rockfalls. and heavy precipitation leading to underground seepage and numerous water crossings. high groundwater levels.June 8. isolated regions with infrequent occurrence of high intensity rainfall. geology. over the Andes Mountains. this design approach requires the construction of effective stabilization measures.003 A0F0 0607 0806 57 . SF36292. very little rainfall. In January 2005. The primary non-seismic geotechnical hazards are mudflows and flash floods in ravines during infrequent downpours. particularly reconstruction of surface drainage works. and broad river crossings. metal or concrete piles. and reinforced shotcrete. wedge landslides. rockslides. surface surveying. and lateral erosion of river terraces in the Pisco River Valley. and gravity walls. slope armoring. the pipeline was designed such that external soil loading would be mitigated by stabilization measures constructed at sites deemed to pose a geotechnical or geologic hazard.June 8. GEOTEC presented a plan of action. and rockfalls. The costa sector is characterized by regions with low topographic relief. gabion walls. These geotechnical and geologic conditions were known and evaluated by several geotechnical and geologic consultants. including GEOTEC. five months after the system was placed into operation. and also a hydro-meteorological (rainfall and river-stage) alert network.2 General Findings As described previously in Chapter 4. The coastal (costa) sector generally has the most favorable natural conditions with respect to the static stability of soil and rock along the ROW. These recommended measures were to be used in conjunction with regular maintenance activities. For a challenging alignment such as this system. reinforced concrete walls. 2007 intermittently. This report also recommended the following types of instrumentation: observation wells or piezometers. rock bolts. and stabilization systems such as buttress fills. The principal geotechnical and geologic hazards in the sierra sector include debris flows. the consortium hired to provide engineering services during and immediately after construction of the system. crib walls. with recommendations for remedial actions that included surface and subsurface drainage systems. predominantly granular soils and gravel. and slope inclinometers. 6. More than 100 sites along the ROW were evaluated and remediated by implementing geotechnical stabilization measures using designs and construction techniques that were more robust than those used previously. As described in Chapter 4. which indicated that the stabilization measures were not adequately mitigating geotechnical or geologic hazards at the time of our inspections. construction were not completely effective in mitigating external soil loads acting on the pipes. we observed gabion walls that had displaced laterally with significant tilting. and made preliminary recommendations. and displaced or disrupted drainage facilities. The most comprehensive study of geotechnical risks was performed by GEOTEC after installation of the pipeline was complete. Based on this study. or immediately following. 2007 Also described in Chapter 4 are the preliminary geologic and geotechnical investigations that were conducted by Golder and MRA for design of the system with the stated objective of determining the geologic and geotechnical feasibility of the proposed alignment. Verastegui. In addition. GEOTEC made several other recommendations. The spill incidents and the observed performance of the system as of early 2006 caused TgP to set into motion an aggressive geotechnical stabilization program that began in earnest in April 2006.003 A0F0 0607 0806 58 . In some instances. topographic surveys. Exponent concluded that some of the stabilization measures implemented during. some site-specific evaluations of geotechnical and geologic hazards were performed prior to or during construction by various consultants (Felix. Following our June 2006 inspections. The geotechnical risk assessment requested by TgP from GEOTEC identified areas (slopes and ravine/river crossings) that required additional geotechnical stabilization. TgP developed a master plan to address geotechnical and geologic recommendations. For example. These preliminary studies recommended further geologic and geotechnical studies during construction to identify additional unstable zones and recommend stabilization measures.June 8. These preliminary studies evaluated the geologic (and geotechnical) risk along the proposed route. and Stepanek). and routine annual geotechnical maintenance. we observed evidence of substantial ground movement. including implementation of subsurface exploration. The primary components of the 2006 geotechnical stabilization measures included: (1) gabion walls that were typically founded in weathered rock SF36292. identified critical zones in the selva sector. Based on our second set of site inspections.003 A0F0 0607 0806 59 . Further. Exponent also noted that effective and continuous monitoring of the performance of surface and subsurface drainage systems is necessary. rows of small-diameter pipe or timber “pin” piles that were placed parallel to the ROW. 2007 below the landslide plane. where evidence of soil movement was observed above the gabion wall installed at the toe of the landslide. (3) reduction in thickness of soil overburden above the unstable ground or landslide. and subsequent review of documentation of individual site stabilization design approaches.June 8. with the exception of one site at PS #2. (2) in some limited cases. rain gauges..g. lined ditch to a main surface collector system. slope inclinometers. (4) subsurface drains (“filters”) consisting of perforated PVC pipe wrapped in geo-fabric and connected to solid pipe discharging into a lined drainage channel. We understand that TgP has followed our recommendations. including soil sampling in borings and test pits. Exponent recommended the deployment of instrumentation and monitoring equipment (e. in September 2006. SF36292. Exponent recommended that a detailed geotechnical investigation. Based on our observations at PS #2. and survey control) at sites with the greatest residual risk to assess surface and subsurface conditions. we determined that these measures were being applied in a consistent and effective manner. we believe that the risk of future failure of the system resulting from external geotechnical forces has been substantially reduced at locations where stabilization measures were implemented in 2006. and a significant portion of the stabilization measures have been completed at PS #2. and (7) lined drainage channels to collect water from current breakers and ditch breaker drains. be performed at PS #2 and that appropriate geotechnical stabilization measures be implemented as soon as possible. Hence. This instrumentation will provide earlier warnings of ground instability and additional data on ground movement locations. strain gauges. because high groundwater conditions have been a major factor in the initiation of slope movements. As a result of these efforts. (6) surface “current breakers” to collect runoff water and convey it in a controlled. (5) subsurface “ditch breakers” to collect water flowing through trench backfill in steep terrain and route it to underground drain pipes. Exponent concluded that the remedial geotechnical stabilization measures at most sites are sufficiently robust and appear to represent a reasonable and practical approach to reduce the risk of failure to the pipeline. in September 2006. depths. piezometers. and rates of movement will be available to permit more expeditious and reliable repairs.1 Risk Assessment Methodology Exponent and TgP collaboratively developed a qualitative method to assess the likelihood and severity of future failure resulting from geotechnical and geologic conditions at a given site along the ROW. 2007 directions. and (4) qualitative evaluation of the overall risk of failure.3. In late 2006. with a separate evaluation of the likelihood of failure versus the severity of failure. Exponent also reviewed a proposed inspection program (marcha vigilante) initiated by TgP and COGA to help reduce the risk of future failure resulting from external geotechnical forces by detecting and quantifying early signs of slope instability. (3) characterization of the severity of failure should one occur.3 Geotechnical Risk Assessment 6. dynamic. In our opinion. (2) evaluation of the likelihood of failure using a screening analysis and the geo-integrity parameters. The marcha vigilante inspection teams document relevant geotechnical conditions at each site on a weekly basis. The core of this program involves regular ROW visual inspections within the selva and sierra sectors by multi-disciplinary teams trained by COGA’s technical consultants.003 A0F0 0607 0806 60 . and remediation) causes. In this method.g. SF36292.. this approach enhances the characterization of overall risk.June 8. 6. complex. deforestation. This method was developed to assess geotechnical and geologic risk in a project setting that is diverse. providing a stronger basis to make fundamental decisions on acceptable and unacceptable levels of risk. and develops the most effective means to reduce risk and to prioritize remedial and monitoring efforts. and this information is used to update the geotechnical risk assessment method described below. risk is assessed using traditional geotechnical failure modes. The geotechnical risk assessment method formulated by Exponent and TgP consists of the following four major steps: (1) evaluation of geo-integrity parameters. and sensitive as a result of both natural and man-made (e. development. The Safety Ratio relationships developed for this method are intended to be an interim surrogate measure of safety factors51 in the absence of more rigorous engineering analysis. health. The Risk Categories are: Risk Category 1 – Low risk Risk Category 2 – Moderately low risk that is acceptable Risk Category 3 – Medium risk that should be evaluated for mitigation measures 51 The ratio between the forces resisting ground movement and the forces driving ground movement. Likelihood Levels consist of four numerical categories that correspond to our interpretation of the probability of occurrence of the failure mode at that site. Severity Levels (SL) are characterized using four rating levels. and safety. more severe. These parameters were chosen based on our experience and knowledge of the conditions along the ROW. SF36292. (b) wedge landslide.. consequences.June 8. The following geotechnical failure modes are currently considered in this risk method and capture most of the observed landslides for the system: (a) deep rotational landslide. including geologic and geotechnical conditions that likely led to three of the first five pipeline ruptures. and a slope is at the point of marginal stability or imminent failure. The final step in the risk assessment method involves assigning the final Risk Category for each site by combining the computed Likelihood and Severity Levels as shown in Table 2. the greater the susceptibility. 2007 Geo-integrity parameters are typically evaluated during the inspection program (e. and (d) ridge instability. with higher numerical levels also corresponding to greater. The initial step in the likelihood evaluation involves computing a Safety Ratio (SR) for the site using geo-integrity parameters for each failure mode.g. property.003 A0F0 0607 0806 61 . (c) translational landslide. The computed Safety Ratios are then used to assign Likelihood Levels (LL) for each failure mode. A safety factor of 1 indicates that the forces are equal. The Severity Level considers the following four different consequence categories: environmental. The higher the Likelihood Level. marcha vigilante) to characterize the likelihood of a potential pipeline failure using readily available or measurable information from a given site. Exponent has recommended to TgP that all sites in Risk Categories 3. 52 Although more than 100 sites were mitigated as part of the 2006 geotechnical stabilization program conducted by TgP and COGA. considering all four failure modes. Of the 95 sites in the risk matrix.3. 28 are in the sierra sector. 67 are in the selva sector. and Severity Level as shown in Table 2.003 A0F0 0607 0806 62 . The final Risk Category is evaluated using the most critical combination of the Likelihood Level. Table 2. SF36292.2 Application of the Risk Assessment Method The geotechnical risk assessment method was applied to 95 different sites52 along the system to create a risk matrix. and 5 be subjected to a formal engineering stability analysis to determine whether mitigation measures are necessary. the geo-integrity parameters necessary to apply the geotechnical risk assessment method were characterized for only 95 sites as of October 2006. Risk category assessment chart Likelihood 1 1 2 Severity 3 4 1 1 2 2 2 1 2 2 3 3 2 2 3 4 4 2 3 4 5 6. The sites were selected by COGA based on their interpretation of the geotechnical and geologic hazards present along the ROW. and none are in the costa sector. 2007 Risk Category 4 – High risk that should be evaluated for mitigation measures with high priority Risk Category 5 – Very high risk that requires immediate evaluation of the need for mitigation measures.June 8. 4. The risk matrix initially ranked 48% of the sites (45 sites. Exponent did not independently evaluate the geo-integrity parameters for the remaining 61 sites but did collaborate with COGA in their evaluation. Exponent inspected more than 50 sites. it is our understanding that TgP will transition in 2007 toward a proactive implementation to address this potential geotechnical risk. respectively. The risk at each site was then re-evaluated following the completion of the stabilization measures (September 2006). surface depression.June 8. The risk matrix is based on the geotechnical expert evaluation of the first 450 km of the ROW. soil movement. For each time period. the risk was re-evaluated to incorporate the implementation of the marcha vigilante inspection program (October 2006). in order to provide a baseline assessment of risk. Finally. Thirty-five of these sites were in the COGA risk matrix. slope bulging. and ridge instability is included in the risk matrix.003 A0F0 0607 0806 63 . along the initial 455 km of the ROW) as having “high” to “very high” risk (Risk Categories 4 and 5) in May SF36292. The overall risk at each site was first evaluated assuming conditions that existed prior to the construction of the new geotechnical stabilization measures (May 2006). there currently are no sites in the matrix involving this potential hazard. For example. and October 2006 are presented in Figures 21 to 23. pipe movement. The results of the geotechnical risk assessment and our field observations indicate that TgP made substantial progress in 2006 to diminish the overall risk of future failure resulting from external soil or rock pressures. September. because there were no known manifestations of ground movement in these same sections as of 2006. The 35 sites in the risk matrix that were inspected by Exponent are shown in blue. In this regard. In addition. and subsequently by Exponent for the sites that we visited. 2007 In general. the maximum combination of likelihoodseverity pairings of each individual site is presented. However. the results were compiled in pie charts to summarize the overall risk level of the 95 sites in the COGA risk matrix (Figures 21 to 23). The results of the geotechnical risk assessment for May. excessive fiber optic attenuation) are observed. during our field inspections in June and September 2006. tension cracks. the risk matrix does not necessarily include all potential risk sites along the entire pipeline alignment.g.. sites are entered into the risk matrix if manifestations of earth instability (e. some on both occasions. even though narrow ridge instability is a substantial hazard on some sections of the ROW in the selva sector. The geointegrity parameters for these 35 sites were evaluated initially by COGA. and 74% of sites were ranked as having “moderately low” risk (Risk Category 2) by October 2006. SF36292. the percentage of sites ranked “high” to “very high” risk was 13% (12 sites) in September 2006.June 8. Further reductions to the risk level were observed in the October 2006 risk matrix results wherein only 5% of the sites (5 sites) were characterized as having a “high” to “very high” risk. TgP has recently been implementing stabilization works at this location to reduce the geotechnical risk.003 A0F0 0607 0806 64 .” As mentioned before. only one site adjacent to the second pump station was ranked as “very high. 94 Likelihood 1 1 2 3 4 0 0 3 2 0 4 17 2 0 1 13 9 0 7 24 12 Severity 2 3 4 DISTRIBUTION for MAY 2006 1 2 3 4 5 35% 23% 0% 29% 13% Figure 21. 2007 2006. By October 2006. Risk assessment results for May 2006. By comparison. June 8. Risk assessment results for September 2006. 2007 95 Likelihood 1 1 2 3 4 0 0 9 3 0 5 22 16 0 6 20 4 0 2 6 2 Severity 2 3 4 DISTRIBUTION for SEPTEMBER 2006 1 2 3 4 5 40% 47% 0% 11% 2% Figure 22.003 A0F0 0607 0806 65 . SF36292. 003 A0F0 0607 0806 66 . which includes the monitoring program for the September 2006 results. Risk assessment results for October 2006. SF36292.June 8. 2007 95 Likelihood 1 1 2 3 4 0 0 16 9 0 8 33 14 0 4 6 1 0 0 3 1 Severity 2 3 4 DISTRIBUTION for OCTOBER 2006 1 2 3 4 5 74% 21% 0% 4% 1% Figure 23. June 8. which began in earnest in April 2006. Figure 24 shows that the most significant reductions in risk were achieved at sites possessing “high” to “very high” risk (Risk Category ≥ 4). slope inclination. 3 1 Reduction in Risk 2 21 9 1 21 9 1 0 27 1 3 1 2 3 4 5 May 2006 Risk Category Figure 24. SF36292. Figure 24 summarizes the computed reduction in Risk Category versus the baseline risk (i.. The rankings in the May and October risk matrices were compared to evaluate the total progress made as of October 2006 in mitigating geotechnical and geologic hazards along the ROW through geotechnical stabilization.. and presence of gabion walls). because Severity Levels were likely unchanged.e. the Risk Category as of May 2006). The change in Likelihood Levels from May to September coincides with COGA’s progress in completing robust geotechnical stabilization measures.e. inspections. Change in risk from May to October 2006. The construction of geotechnical stabilization measures is reflected in the risk matrix through re-evaluation of geointegrity parameters used to characterize various site conditions (i. The further reduction of Likelihood Levels in the October risk matrix corresponds to TgP’s commencement of its comprehensive inspection program. whereas marginal effects were observed at “moderately low” to “medium” risk sites. surface drainage control. groundwater depth. and monitoring.003 A0F0 0607 0806 67 . 2007 The substantial reduction in overall risk from May to October 2006 is directly attributable to changes in Likelihood Levels. the October 2006 results show a substantial reduction in the risk for the selva sector. In contrast. whereas the majority of the sierra sector sites fall into Risk Category 2. the current geotechnical risk assessment method was developed in 2006. However. 2007 The results of the risk assessment for the 95 sites were separated by sector. However. to geographically delineate variations in the potential for geotechnical risk along the system. because 67 of the 95 sites are located in the selva sector—the location of the vast majority of sites that have exhibited manifestations of ground instability—and the remaining sites are in the sierra sector. wherein most of the selva sites fall into Risk Categories 2 and 3. Results of this method appear to work reasonably well in providing a qualitative assessment of the geotechnical and geologic hazards present along the ROW. representation across the three sectors was not possible. Risk by sectors for May 2006. Selva (May 2006) Sierra (May 2006) 4 5 SF36292. 50 45 40 Frequency 35 30 25 20 15 10 5 0 1 2 3 Risk Category Figure 25. recognizing the qualitative nature of the approach. Hence. The May 2006 rankings show that the majority of the selva sector sites evaluated fall into Risk Categories 4 and 5. comparison of Figures 25 and 26 suggests that the majority of the geotechnical stabilization works and monitoring programs are appropriately focused on the selva sector. Figures 25 and 26 show the risk by sectors for the May and October risk matrix rankings. While TgP had been using a risk assessment method for some time.June 8.003 A0F0 0607 0806 68 . respectively. engineering judgment should be exercised at all times when applying the risk assessment method. . 2007 50 45 40 35 30 25 20 15 10 5 0 1 2 3 Selva (October 2006) Sierra (October 2006) Frequency 4 5 Risk Category Figure 26. strain gauges and inclinometers). Initially. 6. decision processes and means of execution. This RMP should state at least the following: SF36292.g.003 A0F0 0607 0806 69 . Exponent recommends that TgP develop a Risk Management Plan (RMP) that governs the use of all geotechnical risk assessment methods and guide TgP’s actions. Risk by sectors for October 2006. Therefore. we recommend that TgP adopt a proactive approach of continually assessing geotechnical and geologic hazards along the ROW where manifestations of instability are not present. Some of these potential new sites may even be ranked with a high to very high risk. In addition. requiring immediate measures to sufficiently mitigate the hazard.June 8. ongoing implementation of the risk matrix process will identify additional sites that are not included in the current risk matrix as new manifestations of ground movement are observed or detected using the installed instrumentation (e.4 Ongoing Geotechnical Risk Mitigation We expect that the continuous. this approach will likely require an assessment of geologic and topographic maps to identify the most susceptible sites. • Mandated actions ranging from authorizing investigations to shutting down the pipeline need to be provided. 2007 • • • All sites with a risk ranking 4 and 5 should be mitigated immediately. and concluded that the geotechnical risk has been reduced substantially at the remediated sites. Exponent recommended that a detailed geotechnical investigation. Exponent visited more than 50 sites during our September 2006 inspection. and engineering experience. caused TgP to implement aggressive geotechnical stabilization measures.June 8. be performed at PS #2 as soon as possible. During our inspections in 2006. we conclude that geotechnical and geologic conditions posed the most significant risk to the integrity and reliable operation of the system.003 A0F0 0607 0806 70 . we observed evidence that some geotechnical stabilization measures implemented during or immediately following construction proved insufficient to mitigate external soil pressures acting on the pipes. This remedial program began in earnest in April 2006 and employed robust construction techniques that were applied in a consistent and effective manner. and sensitive. when stabilization measures were completed or significantly underway. Furthermore. The observed performance of the pipeline system. Based on Exponent’s review. Clear organizational structures and the level of responsibility and authority need to be assigned. All sites with a likelihood ranking of 4 should be mitigated immediately. with the exception of a site adjacent to the second pump station.5 Conclusions The geotechnical and geologic conditions along the pipe alignment are diverse. Exponent recommended the deployment of instrumentation and monitoring equipment at critical SF36292. including soil sampling in borings and test pits. wherein three of the spill incidents were attributed to geotechnical and geologic instabilities. observations. Extraordinary efforts were made to complete the geotechnical stabilization measures along the ROW before the start of the 2006–2007 rainy season. and TgP has communicated that such efforts have been substantially completed. 6. complex. dynamic. June 8, 2007 sites to provide earlier warnings of ground instability, and to provide additional data on ground movement locations, depths, directions, and rates to permit more expeditious and reliable repairs. Exponent also reviewed the inspection program initiated by TgP to help reduce the risk of future failure from external geotechnical forces by detecting and quantifying early signs of slope instability. This program, which involves weekly visual inspections of critical sections of the system during the rainy season, appears to be comprehensive and aggressive. During the second phase of our project, Exponent worked collaboratively with TgP to develop a geotechnical risk assessment method to evaluate the occurrence of geotechnical hazards along the ROW that could ultimately affect the stability of the system. This risk assessment method was validated using information from our field inspections and applied to 95 sites along the system to create a risk matrix. The risk at each site was evaluated at three different points in time, reflecting the risk prior to construction of the new geotechnical remedial measures (May 2006), after the construction of those measures (September 2006), and after implementation of the additional monitoring programs (October 2006). In general, the results of the geotechnical risk assessment are consistent with our field observations that TgP has made substantial progress in diminishing the overall risk. The reduction in risk in 2006 was achieved primarily through the construction of geotechnical stabilization measures and implementation of monitoring programs to decrease the likelihood of future failures. Furthermore, the results suggest that the geotechnical stabilization measures and monitoring programs have appropriately targeted sites that formerly had high to very high risk, which are located primarily in the selva sector. We expect that the continuous, ongoing implementation of the risk matrix process will identify additional sites that are not included in the current risk matrix as new manifestations of ground movement are observed or detected using the installed instrumentation (e.g., strain gauges and inclinometers). Some of these sites may even be ranked with a high to very high risk and will need to be mitigated quickly. Therefore, we recommended that TgP adopt a proactive approach of continually assessing geotechnical hazards along the ROW, such that sites possessing higher risk profiles that have not exhibited instability manifestations will be included in the risk matrix. In SF36292.003 A0F0 0607 0806 71 June 8, 2007 this regard, TgP has committed to implementing a RMP, recommended by Exponent, that will govern the use of all risk assessment methods and guide TgP’s actions, decision process, and manner of execution. At this time, Exponent believes that a successful implementation of the above, and the construction of additional geotechnical mitigation measures in 2007, will further reduce the geotechnical-related risks to the pipeline system. SF36292.003 A0F0 0607 0806 72 June 8, 2007 7 Pipeline Integrity–Related Risks 7.1 Description of Potential Risks and Controls In any operating pipeline, pipe integrity–related risks are associated with pipe loading conditions, pipe material, weld quality, and the quality of protection the pipeline is afforded against environmental conditions. Pipe material and pipe manufacture–related risks have been discussed in prior sections and been deemed to be at a typical and acceptable level for pipelines. Risk mitigation during the construction of the pipeline relied foremost on hydrostatic testing and radiography of girth welds, which is in compliance with the requirements of the applicable codes. During operation, inline inspections and external pipe inspections are the most effective means of controlling long-term hazards to pipeline integrity, most commonly manifested as internal and external corrosion. As with the Camisea system, cathodic protection and the exterior HDPE coating are common methods of protecting the pipeline from external environmental attack. Inline inspection tools, particularly the Magnetic Flux Leakage (MFL) tool, in conjunction with pipe excavation at areas identified as problematic, are common means of identifying internal metal loss and other potential anomalies. These inspections are typically conducted in compliance with API 1160 and federal regulations by the U.S. Department of Transportation (DOT) 49 CFR 195.452. In this regard, TgP has implemented an inline inspection program in compliance with these requirements. This section summarizes the results of these pipe inspections performed by TgP in 2006 on the NGL pipeline and discusses the key findings and future needs to mitigate potential residual risks. In the dynamic landscape of the Camisea selva sector, soil movement has been identified to be the most significant hazard to the system, because soil movement imposes a lateral loading upon the pipe. Lateral loading from external soil pressures can induce axial stresses in the pipe, in addition to the stresses induced by the internal pressure of the transported hydrocarbons. These axial stresses affect the girth welds in the pipe, by growing circumferential defects if they exist, SF36292.003 A0F0 0607 0806 73 We refer to fast crack growth in the context of geologic time scales and not dynamic fast fracture due to impact loading. SF36292. where soil movement was identified to be a significant contributor in three of the five spill incidents. MCI. The results of Exponent’s analysis are consistent with the operational experience. TgP’s outside consultant. 7. because the NGL pipeline only requires a smaller diameter and thus thinner walls than the NG pipeline per the hydraulic design considerations of the ASME codes. Therefore. an increased residual risk due to subcritical crack propagation may exist at sites where geotechnical mitigation measures have not been constructed. while sufficient for internal pressures. Thus.000 psi and a minimum ultimate strength of 82. These tests independently substantiated the adequacy of pipe strength. the pipeline is less able to resist external soil loads. tested samples of pipe from the first five spill incidents. axial loading due to internal pressure alone cannot account for the observed fast54 crack growth rates and final overload failure. Identification of these sites and construction of effective geotechnical measures mitigates this risk most effectively. for the first and fifth spill incidents. Significant progressive lateral soil loading is the likely force that propagated these cracks and induced the 53 54 The sixth spill incident is currently being investigated and is not included in this comparison. 2007 and this could also significantly affect the integrity of a pipeline. This standard requires minimum yield strength of 70. In addition to the material testing required by API 5L during pipe manufacturing. Load capacity estimates for the NGL pipeline show that.53 In particular. Exponent’s analysis of the system’s ability to withstand lateral soil movement has shown that the as-designed NG pipeline has a significantly larger external load capacity and flaw tolerance than the NGL pipeline.June 8.000 psi for an X70 grade pipe.003 A0F0 0607 0806 74 . such that the NG pipeline generally has a low risk of failure from external loads. This basic residual strength advantage of the NG pipeline versus the NGL pipeline is approximately a factor of two in tension and a factor of six in bending.2 Pipe Material and Damage Tolerance–Related Risks The tubular pipe material used for the system was required to conform to API 5L. Elimination of potential defects in the pipe or weld reduces the potential risk even further. these external soil loads should be mitigated by geotechnical stabilization measures. metal loss.3 7. The goal of the pipe inspections is to identify pipe wall anomalies. ANSI B31G is a manual that is used and referenced in DOT 49 CFR 195. Our review indicates that this set of 55 The hydrogen-induced crack that imitated the second spill incident was significantly deeper but relatively short. and dents. The geometric tool continuously measures the pipe’s geometry along its length. This failure evolution occurred with very few load cycles until the crack reached critical length.452. geologic hazards pose a risk to the NGL pipeline. 2007 overload failure of the NGL pipeline. to determine the remaining strength of corroded pipes.June 8. 7. providing guidance to the pipeline industry in maintaining the integrity of pipelines that transport hazardous liquids.452. Under normal operating pressures. pipe gauge. The MFL inspection tool has the capability to detect metal loss and other potential pipe wall anomalies. since the NG pipeline has a larger diameter such that smaller stresses are induced by the same soil load. Our analysis indicates that this crack was at the limit of detection for the hydrostatic test performed at this location. SF36292. because the pipe material is sufficiently tough to pass the hydrostatic test. DOT regulates inspections per 49 CFR 195. any potential defects that may have survived the hydrostatic test are unlikely to cause rupture. which lays out the classification and reporting of these conditions. potentially leading to pipe failure.3. repeated hydrostatic testing will not reduce this risk.003 A0F0 0607 0806 75 .55 because soil movement can induce the growth of such cracks. These tools are inserted at a launch point at each pump station and record data from their sensors for later analysis. Furthermore. However. However. using the MFL inspection tool and a geometric inline inspection tool. especially if circumferential cracks are deeper than 40% of the wall thickness.1 Inline Pipe Inspection Background TgP contracted Tuboscope Pipeline Services (TPS) in 2006 to perform an inline inspection of the entire NGL pipeline. this soil loading is mostly load controlled and therefore is more detrimental to the NGL pipeline than the NG pipeline. API 1160 is a standard that is used to implement these rules. First. TGP is also investigating additional locations where the internal inspection tool reported some indications (e. in terms of required follow-up action/investigation).June 8. Beyond what is required by applicable norms (i. the existing pipe was in sufficient condition to reinforce. etc. micro hardness measurement). 2007 regulations and standards are being used by TgP to conduct their pipeline integrity review of the recently performed inline pipe inspection. numerous sites have SF36292. ultrasound wall thickness measurement. The approach for each of these sites is to do a field investigation at each site. In this regard. 13 to dents.e. external ultrasound inspection of girth weld...2 Inline Pipe Inspection Results TgP used the combined data from the MFL inspection and geometric inspection. and it was not necessary to replace the pipe or repair a girth weld. Then we discuss the MFL inspection tool’s ability to detect potential circumferential cracks and its impact on the NGL pipeline’s risk. to determine which conditions were reportable per DOT 49 CFR 195. external magnetic particle inspection of girth weld. By the end of March.. 12 sites have been investigated and necessary repair actions completed. Our discussion of the results of the inline inspection is divided into two parts.g. In all cases. visual inspection. and based on the results. measure of pipe diameter and axial pipe misalignment. The investigation of the remaining 18 anomalies is ongoing. radiographic examination of girth weld. Good correlation was found between the inline inspection results and the field verifications. a series of detailed non-destructive testing (i.188 pipes) only identified 30 locations with reportable conditions per the requirement.452. as well as external excavations. and the more sophisticated MFL inspection tool is used to identify other reportable wall thinning conditions encountered in the pipeline industry. As of March 2007. 2 to girth welds and 1 to dent and metal loss. 14 were related to metal loss. re-weld.e. the geometric inspection tool is typically used to identify dents. The inline inspection results of the entire NGL pipeline (48.452.3. patching.).g. implementation of any necessary remedial actions (e.003 A0F0 0607 0806 76 .. potential anomalies). which includes excavation. 7. we discuss the results of the inline inspection with regard to the requirements of 49 CFR 195. Among the 30 locations. 7. currently. Based on these findings.e. Exponent performed a pipeline integrity study to determine the MFL inspection tool’s utility in detecting circumferential cracks. the burst pressure of the pipeline is at all times larger than the maximum operating pressure). more than 95% of these were deviations in diameter of less than 6%. the data showed that the vast majority of metal loss occurrences had depths of less than 15% with respect to the pipe’s wall thickness. SF36292. and nearly 80% of the detected damage is less than 10% deep. TgP employed the geometric inspection tool to identify dents with a depth of more than 2%.452.3 Circumferential Crack Detection In an effort to quantify the MFL tool’s ability to detect circumferential cracks. TgP requested that TPS use a more stringent criterion of identifying any diametrical change larger than 2%.003 A0F0 0607 0806 77 . Overall.3. A verification of other sites is ongoing. This inspection identified a total of 90 locations along the first 452 km of inspected NGL pipeline with deviations. the probability of detection decreases rapidly. this portion of the NGL pipeline may be subject to this potential risk over the long term. no severe external and internal corrosion damage exists along the NGL pipeline (i. The deepest metal loss was reported to have occurred in the selva sector. For cracks with a smaller opening. Specifically. However.452. it also appears that there is a relatively elevated frequency of metal loss occurrences within the first 50 km of the NGL pipeline. which is still less than the mitigation threshold of 80% as required per DOT 49 CFR 195. In addition. results of the MFL inspection tool and evaluation of metal loss per ASME B31G has shown that. Specifically.56 Our analysis indicates that a potential circumferential crack would need to be subjected to a significant external load to be detectable 56 The service provider of the currently used MFL inspection tool has determined that only circumferential cracks with a crack mouth opening of more than 0. per DOT 49 CFR 195. with a depth of 49%.. TgP and its contractors conducted a research program to quantify the crack detection limit of the MFL tool. All other metal loss reported in the selva sector is less than 25% deep. 2007 been verified in the field without having encountered any significant defect. Therefore.June 8. and we recommend that this should be evaluated as part of TgP’s ongoing pipeline integrity program.1 mm can be detected with a probability of better than 90%. June 8. the NG pipeline’s strength advantage is even larger. 7. Unfortunately. Clearly. Therefore. whereas. TgP has committed to evaluating potential options. 2007 with a high degree of certainty using the currently employed MFL inspection tool. Specifically. because the NGL pipeline only requires a smaller diameter and thus thinner wall than the NG pipeline. In this regard. the most effective means at this time to contain this potential risk is to identify sites with geologic and geotechnical instability and construct the geotechnical mitigation measures needed to eliminate any potential external soil loadings that could cause these circumferential cracks to grow. but it was caused by a specific site condition. the loading condition that commonly results from external soil loads. no pipeline inspection company is able to provide a commercially viable inspection tool that can detect potential circumferential cracks. Exponent expects that the most commonly encountered geologic and geotechnical hazards will induce bending moments that may be accompanied by tension loading. the third failure where tension loads were larger was an exception to this loading assumption. This is especially true if the pipe is loaded in bending. at present. in bending. Despite the fact that the use of inline inspection tools to detect small circumferential cracks is currently not a common practice among pipeline operators due to the relatively low risk to pipeline integrity posed by circumferential cracks under normal operating loads. TgP has also committed resources in 2007 to further assess the ability to detect potential circumferential cracks. only a 40% deep circumferential crack will typically have a residual strength greater than the NGL pipeline with no flaws. even though the technology appears to be readily available. Under bending loads that are typically induced by external soil loads.4 Conclusions The NG pipeline is at least twice as strong as the NGL pipeline under a variety of loading conditions. Our fracture mechanics study showed that the flaw tolerance of the NG pipeline is significantly better than that of the NGL pipeline. in pure axial loading. per the hydraulic design considerations of the ASME code. the NG pipeline with a nearly 60% deep circumferential crack will typically have a residual strength that will surpass that of a perfectly good NGL pipeline. based on this study. the NG pipeline is deemed to be of SF36292.003 A0F0 0607 0806 78 . June 8, 2007 significantly lower risk than the NGL pipeline. Geological and geotechnical hazards are the most significant hazards for the NGL pipeline, and are even more of a concern when circumferential cracks deeper than 40% preexist. Specific data from the fifth failure suggest that rapid crack growth due to soil movement is possible, and only a few cycles were required to propagate the crack to a critical length. TgP used the combined data from the MFL inspection and geometric inspection, as well as external excavations, to determine which conditions were reportable per DOT 49 CFR 195.452. This review only identified 30 reportable locations in the entire NGL pipeline per this requirement. These 30 locations are being investigated and repaired as needed. Overall, results of the MFL inspection tool and evaluation of metal loss per ASME B31G has shown that, currently, no severe external and internal corrosion damage exists along the NGL pipeline. However, it appears that there is a relatively elevated frequency of metal loss occurrences within the first 50 km of the NGL pipeline. Therefore, this portion of the NGL pipeline may be subject to this potential risk over the long term, and we recommend that this be evaluated as part of TgP’s ongoing pipeline integrity program. The in-line inspections and external excavations performed at many sites have shown that the MFL inspection tool is an excellent tool to detect internal and external metal loss in this system. However, its ability to identify circumferential cracks is dependent on external loading conditions, which reduces the probability of detecting potential circumferential cracks within an actionable time frame. In addition, hydrostatic testing will also not likely identify potential circumferential cracks, because identifiable critical crack sizes need to be at least 60% deep and very long, given that the pipe material has such good toughness properties. We understand that TgP has committed specific resources in 2007 to further assess the ability to detect potential circumferential cracks. A root-cause analysis of the first and fifth spill incidents and the origin and nucleation of the potential circumferential cracks, to be performed by TgP in 2007, will assist in assessing the implications of this concern related to pipeline integrity. Overall, in 2006, TgP significantly reduced pipe integrity–related risks and is currently engaged in additional efforts to further reduce the risk profile. SF36292.003 A0F0 0607 0806 79 June 8, 2007 8 Seismic-Related Risks 8.1 Tectonic Overview Peru represents one of the most seismically active regions in the world. This distinction is the consequence of its location along a segment of the circum-Pacific seismic belt where the continental block of South America is drifting westward, overriding and forcing down the denser Pacific Ocean (Nazca) plate along a major offshore fault zone known as a subduction zone. This deformation of the earth’s crust causes elastic strain energy57 to accumulate until a breaking point is reached—an earthquake. At least nine large-magnitude earthquakes58 have been recorded in or near Peru during the last 60 years. The intensity of ground shaking and significant effects of a particular earthquake depend largely on the magnitude, faulting mechanism, distance to the origin of rupture, and local site and subsoil conditions. The Nazca and South American plates are “slipping” at a rate of 78 to 84 mm per year.59 By comparison, the famous San Andreas fault between the Pacific and North American plates is slipping at a rate of approximately 50 mm per year. Because of the position and orientation of the subduction zone, earthquakes in Peru generally occur at increasingly greater depths toward the east, as illustrated in Figure 27. Earthquakes affecting Peru have three distinct mechanisms:60 • Shallow, offshore inter-slab thrust events wherein failure occurs at the boundary of the subducting Nazca and overriding South American plates. 57 58 59 60 Elastic strain energy is potential energy stored in a volume of the earth’s crust that has been deformed but not yet ruptured. A large-magnitude earthquake is defined as having a magnitude of 7 or greater. DeMets, C., Gordon, R.G., Stein, S. and Argus, D.F. (1990). “Current plate motions,” Geophysical Journal International, 101, pp. 425-478. Yeats, R.S., Sieh, K. and Allen, C.R. (1997). “The Geology of Earthquakes,” Oxford University Press, New York. SF36292.003 A0F0 0607 0806 80 June 8, 2007 • Shallow continental in-slab events where some of the relative motion of the Nazca and South American plates is accompanied by deformation within the overriding South American plate. • Finally, deep onshore in-slab events caused by internal deformation of the subducting Nazca slab at depths of 40 to 700 km. As shown in Figure 28, the Peru-Chile segment of the circum-Pacific-seismic belt has experienced two great61 earthquake events in historical time. Recent notable earthquakes (e.g., the 2001 southern Peru event) have significantly reduced the elastic strain energy along a 300-km-long segment of the circum-Pacific seismic belt. However, the approximately 700-kmlong plate interface between Chala and Limahas has been quiescent since the great earthquakes of 1868 and 1877, and thus has been accumulating elastic strain energy since the late 19th century.62 Consequently, elastic strain energy with the potential to produce large-magnitude earthquakes in the upcoming decades exists along the part of the plate boundary closest to the Camisea ROW. Figure 27. Cross-sectional view of the Peru-Chile Trench (after Worthey, Washington State University website). 61 62 A “great” earthquake has an approximate Richter magnitude of at least 8.0. Dewey, Silva, and Tavera (2003). “Seismicity and Tectonics” in Southern Peru Earthquake 23 June 2001 Reconnaissance Report, EERI Supplement A to Volume 19. SF36292.003 A0F0 0607 0806 81 SF36292. and this mechanism is considered an indirect consequence of earthquake ground shaking. West coast of Peru showing source regions of great events of 1868 and 1877 and epicenters of notable 20th century earthquakes (after Dewey. Excessive movement associated with ground failure can. 2007 Figure 28. and Tavera 2003). lead to pipeline damage. 8.June 8. in turn.2 Seismic Hazards to Buried Pipelines Incidents of seismically induced pipeline damage are typically characterized as arising from one of two earthquake effects: 1. Permanent ground deformation: Strong ground shaking during earthquakes can induce permanent ground deformations (PGD) in regions where underlying soil materials or bedrock are susceptible to ground failure mechanisms. Silva.003 A0F0 0607 0806 82 . Vol.67 lateral spread. “Seismic damage to segmented buried pipe. typically with little to no perceptible slope.g. 2007 2.. or poorly compacted fills). Ground failure mechanisms capable of inducing PGD damage to pipelines include surface faulting.e. “An overview of geotechnical and lifeline earthquake engineering.70 63 64 65 66 67 68 69 70 Transient strain is short-term deformation. Wave propagation–induced damage can be thought of as a direct consequence of earthquake ground shaking. Seismic compression refers to the settlement of unsaturated soils due to strong earthquake shaking. Wave propagation damage can occur due to the propagation of body waves (i. 20(4).66 slope instability liquefaction. SF36292. cohesionless soils subjected to rapid loadings (i. VA. Recent studies have shown that pipes are typically more susceptible to wave propagation damage when subjected to surface waves. 75. 2. it follows that wave propagation tends to affect weaker pipeline components.g. PGDinduced damage is typically confined to a local geographic area susceptible to ground failure (e.68 and seismic compression.64 However. O’Rourke and Deyoe (2004). Rayleigh or Love). damage to buried pipelines may result. Wave propagation: Seismic waves traveling through the earth (i. Liquefaction refers to a phenomenon wherein saturated soils temporarily lose their strength and behave like a viscous fluid.e. Vol.” Earthquake Spectra.003 A0F0 0607 0806 83 . 1167-1183. ground shaking) induce transient strains63 in buried pipelines and the surrounding soil.e.” ASCE Geotechnical Special Publication No.69 Wave propagation typically induces smaller strains in the pipe than PGD but covers a much longer extent of the pipeline. which cause the development of excess pore-water pressures. This phenomenon generally occurs in loose. O’Rourke (1998). The mechanism of lateral spread requires the occurrence of soil liquefaction.. Lateral movement of ground. When these transient strains become sufficiently large. Earthquakes generate different types of seismic waves. 1392-1426. compression or shear) or surface waves (e. resulting in breaks throughout the entire portion or large portions of the pipeline system within the PGD zone.June 8. Therefore.. earthquakes). for similar levels of earthquake motion. unstable slopes. Surface faulting is the rupture and displacement of the ground where the earthquake fault intersects the ground surface. Reston. as opposed to body waves. Landsliding occurs during earthquakes when inertial forces introduced during strong shaking cause shear stresses to exceed the shear strength of the slope materials. liquefiable soils.. Studies of the performance of pipelines during past earthquakes clearly indicate that the most serious pipeline damage during earthquakes is caused by PGD. faults. toward an open face such as a stream channel. EERI..65 landslides. and (ii) a “design” event based on a probabilistic assessment assuming an event with a 475-year recurrence interval. Specifically.C. SF36292. and pressure reducing stations. and costa) and provided more specific evaluations of ground motions for the pump stations. 2007 8. For a subduction-zone earthquake.7g73 for the extreme event and 0. additional studies may be warranted to re-evaluate the seismic demand. 71 72 73 Vector Peru S. These findings may have important implications as to which earthquake scenarios may affect the hazard along various segments of the Camisea ROW.5g represents half the acceleration of gravity. inter-slab versus in-slab events).June 8.C. Several studies have significantly advanced the scientific understanding of ground motions generated by subductionzone earthquakes. pressure control stations. Therefore. Ground acceleration is measured as a percent of the acceleration of gravity. Vector evaluated the earthquake loading for two different scenario earthquake events: (i) an “extreme” event based on a deterministic assessment corresponding to the greatest earthquake that a seismogenic zone can produce under well-defined tectonic conditions. there are substantial differences in the ground motion characteristics between the various faulting mechanisms (i.e. “Estudio de Peligro Sismico Traza de los Ductors de Gas Y Condensados Proyecto Camisea.0g.3.003 A0F0 0607 0806 84 .5g for the design event.A. Vector concluded that the costa sector would experience the strongest shaking.A.” Seismic demand is the earthquake loading imposed on the system as a result of strong ground shaking.3 Seismic Risk Evaluation 8. Consequently. with estimated peak ground accelerations of 0. Exponent reviewed the Vector study and concluded that engineering models used to evaluate the seismic demand may under-predict the actual ground-shaking hazard.1 Characterization of Seismic Demand Vector Peru S. (2001). 0. sierra. (Vector)71 characterized the regional seismic demand72 for each of the three sectors (selva.. They also identified the potential for continental seismic activity occurring along the Razuwilcas fault system near Ayacucho in the sierra sector. and is typically expressed in acceleration and/or velocity. which is 1. referred to as the Los Libertadores fault. For the sierra and selva sectors. However. Based on our understanding of the regional geology and descriptions of ground failures during the 2001 Southern Peru Earthquake. particularly for slopes in the selva and sierra sectors that are marginally stable under non-seismic conditions. sands. Based on our review of documents provided to Exponent. rapid uplift and erosion) creates poorly sorted gravels. ABSC identified only one active fault crossing. and silts with high fines and clay content.g. at the intended alignment. sand dunes). we conclude that PGD hazards arising from fault rupture pose a low risk to the pipeline.52 m. Empirical correlations were used to develop design displacements for the fault. 2007 8. “Seismic hazard investigations of active faults for the Camisea Pipeline.2 Permanent Ground Deformation (PGD) Hazards ABS Consulting74 (ABSC) was retained by Techint to investigate surface fault rupture hazards posed by active faults along the system. and seismic compression) should be evaluated on a site-specific basis outside limited areas that have been improved with geotechnical stabilization measures. and did not observe surface evidence of any past liquefaction episodes. liquefaction.June 8. which could mask any evidence of past liquefaction episodes. APA Consulting was subsequently subcontracted by ABSC to evaluate the pipe performance for such fault displacements and concluded that both the NG and NGL pipes are expected to withstand the design displacements at the Los Libertadores fault.003 A0F0 0607 0806 85 . Peru. Their investigation consisted of identifying active faults that cross the pipelines.3. ABSC postulated that soil deposits are less susceptible to liquefaction. lateral spread. and mountainous areas exhibiting recent or ancient deep-seated landslides. and evaluating the pipeline’s capacity for such displacements... The Los Libertadores fault was characterized as a predominately left-lateral strike-slip fault. They also concluded that large sections of the costa sector are covered by windblown deposits (e.e. ABSC also reviewed aerial photographs to identify regions susceptible to liquefaction.. seismically induced landslides pose a substantial risk to the pipeline.” SF36292. it appears that other modes of PGD (i. slope instability. with expected mean horizontal displacements of 0. landsliding. Seismically induced slope instability poses a 74 ABS Consulting (2002). because the depositional environment in the Andes (i. characterizing potential fault displacements.e. The seismic stress analysis performed by Techint assumed that all supports move in unison with the defined ground motion.June 8. Techint found that the surface facilities were code compliant per ASME B31. or with major curves or bends. Techint evaluated the effects of ground shaking on 12 surface facilities using CAESAR II. 8. However.” SF36292.3. “Seismic Verification of Camisea Pipelines. may be vulnerable to wave propagation damage. However. an analysis should be performed to evaluate the performance of above-ground pipe sections with rigid 75 ABS Consulting (2002). They performed the analysis for a straight section of buried pipe using the earthquake loadings for the 475-year return period design event developed by Vector. Consequently. Based on the results of the seismic stress analysis using earthquake loadings per Vector’s recommendations. and hence does not capture the wave-propagation effect. 2007 substantial risk in the costa sector. Furthermore.3 Wave Propagation Hazards ABSC75 evaluated the potential for wave propagation damage to occur along the system. a numerical pipe stress analysis software program.4. ABSC evaluated the strain levels associated with these ground motions using conservative soil properties. Based on Exponent’s review of wave propagation studies. we conclude that straight sections of buried pipe are unlikely to be damaged by seismic wave passage during a major earthquake. segments of above-ground pipe with rigid connections to surface facilities. and concluded that both the NG and NGL pipes can adequately resist the passage of seismic waves during the design earthquake. the directional dependency of the seismic loading should be investigated in more detail. sections of the pipeline near river deposits and in low coastal regions may be susceptible to liquefaction and lateral spread.003 A0F0 0607 0806 86 . Each pipeline model encompassed the respective surface facility and several hundred meters of buried pipeline upstream and downstream of the facility. seismic risk management would benefit from an update of the design ground motions with up-to-date scientific information. 8. Although seismic hazard studies were performed as part of the system design.4 Conclusions The Camisea system lies within regions that are prone to very large and frequent earthquakes. to determine whether these potential seismic risks are acceptable for this system or whether mitigation measures should be considered. our review suggests that the potential for permanent ground displacements should be evaluated more comprehensively at the most susceptible sites to reduce the uncertainty in the risk. which are most susceptible to wave propagation damage due to the high impedance76 contrast. as part of their pipeline integrity management plan. SF36292. Additionally. Consequently. 2007 connections. Exponent currently understands that TgP is engaged in a review of seismic risks. strong ground shaking generated by large earthquakes poses a substantial risk of damaging the pipeline and disrupting operations. However.003 A0F0 0607 0806 87 . 76 Impedance contrast provides a measure of the stiffness of one material relative to another. The seismic hazards arising from fault rupture and wave propagation along straight sections of the buried pipeline are considered to pose a low risk to the pipeline.June 8. the effects of wave propagation on the pipeline at rigid connections and major curves and bends should be evaluated further. Local scour is the removal of material due to acceleration of flow around submerged obstructions. intermittent (flowing reaches interspersed with dry reaches). 2007 9 Scour-Related Risks 9. Pipelines buried in streams that are perennial (year-round). and ephemeral (flowing only after rainfall) can become exposed or undermined as a result of scour. SF36292. pipelines can fail or be damaged due to debris impact or from the spanned weight of the pipe. and (3) local scour. Long-term scour refers to aggradation and degradation of the streambed due to natural or anthropogenic causes. naturally occurring lateral migration of the mainstream channel within its flood plain may affect the stability of buried crossings. Once a pipeline is exposed or undermined. To prevent breakage and subsequent accidental contamination of runoff during the lifetime of the pipeline. (2) general scour. Factors that affect lateral stream migration are the geomorphology of the stream.003 A0F0 0607 0806 88 . In addition to the types of scour mentioned above. it can potentially become a source of further erosion as water accelerates around the pipe. General scour is the lowering of a streambed due to the passing of a flood.1 River Crossings and Scour Scour is defined as the erosion of streambed or bank material due to flowing water. location of the pipe crossing. Once exposed or undermined. Erosion of the streambed is considered to have three principal components: (1) long-term scour.June 8. and characteristics of the bed and bank materials. all stream crossings should have burial depths designed and constructed according to site-specific conditions. characteristics of the flood. Lateral migration of a streambed can occur gradually over decadal time periods or episodically during very large flood events. ” 78 GMI S.3 and 479. they are widely used for various types of scour studies internationally. Techint then used Golder’s studies and design recommendations to construct each river crossing. is symbiotic with FHWA HEC-20 and -23. “Estudio Hidrologico General Gasoducto Camisea. and HEC-23 provides guidance on the design and construction of scour countermeasures.” 81 Golder Associates (2003).” 80 Golder Associates (2002).2 Risks at Buried River Crossings A rigorous and robust scour analysis of buried river crossings is outlined in Figure 29. Techint retained Hydroconsult and GMI Consulting Engineers to complete hydrology and hydraulic studies on separate areas of the pipeline ROW. However. “Cruce De Ríos Sector Costa Poliducto de Gas y Condensados Proyecto Camisea. Ingenieros Consultores. in determining the pipelines’ design burial depth at each river crossing. and -23 considers the factors likely to play a role in the scour behavior during the lifetime of a pipeline. Furthermore. “Camisea Project Peru Rio Pisco Preliminary Report on Instream Allignments at Prog 477. 18 (FHWA HEC-18). Although these documents were developed in the United States to estimate bridge scour depths. HEC-20 provides guidance on the evaluation of the long-term stability and geomorphology of the stream. to our knowledge.003 A0F0 0607 0806 89 . which is taken from the Federal Highway Administration Hydraulic Engineering Circular No. 80.79. Sierra Y Selva Poliducto De Gas y Condensados Proyecto Camisea. This methodology outlined in FHWA HEC-18.” – date unknown. “Cruce De Ríos Sectores Selva y Sierra Poliducto de Gas y Condensados Proyecto Camisea. 78 This hydrologic information was used by Golder to aid in their calculations of the burial depth of the NG and NGL pipeline at each river crossing. the FHWA documents are guidance documents and. Exponent reviewed documentation and interviewed the parties involved in the design of the 62 identified river crossings along the ROW. which provides guidance on the hydrologic and hydraulic aspects of a scour analysis.A. 2007 9. Techint.77. 79 Golder Associates (2002). Exponent’s review indicates that specialist firms were retained to support the general contractor. -20. “Cruce De Ríos Sectores Costa. FHWA HEC-18. do not constitute design standards required by Peruvian law. 81 77 Hydroconsult (2003).” SF36292.June 8. aspects of the FHWA approach were utilized in the original design of the Camisea system. The design return period was 200 years (0.003 A0F0 0607 0806 90 . As seen in Figure 30. Exponent’s review of the scour studies indicates that a portion of the guidance in the FHWA publications was used by Techint to establish the design burial depth.5% chance of occurrence SF36292. Flow chart for conducting scour analysis (from FHWA HEC-18). 2007 Figure 29.June 8. including: • Hydroconsult and GMI Consulting Engineers completed hydrology and hydraulic studies for the river crossings. the design team incorporated the following elements of the FHWA methodology in their recommended burial depth. The main objective of these studies was to quantify the magnitude of the floods in the rivers crossed by the pipeline. 2% chance of occurrence during any year) for crossings deemed critical. and energy dissipators. If the calculated scour depth for unconsolidated alluvium was less than 2 meters. The clear-water contraction scour equation (FHWA HEC-18 equation 5. • At each river crossing. such as reinforcement of the riverbed. a stochastic stream flow generation program. stabilization of embankment with gabion walls.S. • If the calculated scour depth for rock material was less than 1 meter.4) was deemed the most conservative and was used for many of the crossings. it was increased to 1 meter. the data were incomplete or had been recorded only for short periods of time. • The river crossing locations were surveyed. • Scour countermeasures. SF36292. • Data from 19 rain gauges and 5 stream gauges were relied upon for the GMI hydrologic study. the system is reinforced with a concrete cover. Army Corps of Engineers’ HEC-4 model.003 A0F0 0607 0806 91 . The details of the other evaluated methodologies were not given in the Scour Analysis Summary Reports published by Golder in 2002 and 2003. were designed and built in selected locations. 2007 during any year) for most crossings and was 500 years (0. Different methodologies for calculating the potential scour depth were evaluated. Incomplete or short records were supplemented using the U. providing a certain amount of protection against abrasion and impact from small boulders. it was increased to 2 meters at each crossing. but in some cases. This provides an additional safety factor above the adopted equations.June 8. and site-specific conditions were documented during field investigations. • Data from the hydrology and hydraulic study and the field investigations were used to calculate the potential scour depth at each river crossing. 2007. our general practice and experience in scour prediction.003 A0F0 0607 0806 92 . Lima. SF36292. All of the above-listed factors. and our review of the design process shown in Figure 30 and the documentation provided to us. However. 2007 Figure 30. These include: • • • • Stream classification and evaluation of long-term stream stability Evaluation of stream bank migration Identification of possible headcutting or knickpoint migration Evaluation of the potential effects of debris flows. Peru.June 8. result in a reasonable overall design basis for pipeline burial depth. indicate that certain phenomena could play an important role in the prediction of scour risk for the Camisea system. when combined. Methodology utilized by Golder Associates for the scour analysis of the Camisea Pipeline (taken from “EVALUACIÓN DE CRUCES Y QUEBRADAS PROYECTO CAMISEA ‘RIVER CROSSING’” – presentation by Golder Associates January 24 and 25. The more comprehensive identification of potential scour risks in 2007 will be helpful to better identify potential hazards and reduce the current uncertainty. These measures would help to mitigate potential risks from large-scale flood events. to identify which crossings may require further risk mitigation measures.June 8.003 A0F0 0607 0806 93 . To mitigate this potential residual risk. primarily due to the limitations of the available hydrologic data and the use of the clear-water contraction scour equation. TgP has committed resources in 2007 to investigate the risk of scour damage at each river crossing. SF36292. These methodologies are incorporated into the design procedure set forth in FHWA HEC-18. TgP fortified several river crossings and smaller streams to mitigate scour risk. During our field inspections in 2006. -20. 2007 Our review of the overall scour design concludes that there is some uncertainty as to whether each stream crossing is protected from scour over the long term and during extreme flood events. Our review of the overall scour design concludes that there is some uncertainty as to whether each stream crossing is protected from scour over the long term and during extreme flood events. 9. TgP has committed to study all river crossings in 2007. such as the construction of additional fortifications and flow control measures. and to design and construct additional mitigation measures where necessary. which are widely used in the design of scour protection for key infrastructure. Given the uncertainty and recognizing that the objective of all parties involved is to minimize risk. The primary sources of uncertainty arise from sparse hydrologic data and the additional phenomena mentioned above.3 Conclusions The design team’s approach of utilizing their local knowledge and site-specific investigations in their scour analysis appears to be sound. and -23. Furthermore. such that hydraulic risks of the design are minimal and consistent with other pipelines. risk management actions above and beyond those underway and completed to date may be necessary. (5) hydrostatic testing of the system was in compliance with the required ASME SF36292. (3) the issued welder certificates and qualifications of the inspectors were in compliance with API 1104. 10. (4) radiography of all girth welds was performed per API 1104. Second.000 individual pipe segments were specifically built for this system and consistent with API 5L requirements. First. the pipe wall thickness is sufficient to contain the internal pressures of the transported hydrocarbon products along the entire length of the pipeline. TgP continues to address pipeline integrity and risk issues on an ongoing basis. the review showed that (1) the more than 100. (2) all pipe segments were subsequently coated with an outer high-density polyethylene (HDPE) layer to protect the exterior from the environment. and that TgP has taken actions in 2006 to significantly reduce these risks to the system.June 8. the system was designed such that external soil loads would be mitigated by geotechnical stabilization measures to be constructed at sites deemed to pose a geotechnical or geological hazard.1 Pipeline Design–Related Risks Our review indicates that the system was designed to comply with the engineering code requirements of the American Society of Mechanical Engineers (ASME)82.003 A0F0 0607 0806 94 . related to the Camisea Transportation System.2 Pipeline Construction–Related Risks Overall. Overall. 2007 10 Summary and Conclusions Exponent was retained to provide continued technical assistance to the IDB. 10. our investigation indicates that the primary risks to the pipeline are geological and geotechnical. As these efforts identify risks to the integrity of the pipeline. we observed evidence that some geotechnical stabilization measures implemented during or immediately following construction proved to be insufficient to adequately mitigate external soil pressures acting on portions of the NGL pipeline. This program allows for the early detection and subsequent correction of potential problem areas. The spill incidents and observed performance of the system as of early 2006 caused TgP to set into motion an aggressive geotechnical remediation program that began in earnest in April 2006. Exponent believes that the successful implementation of the above. and sensitive. 10. and (6) construction of the pipeline used methods that employed standard engineering procedures. We expect that the continuous. will further reduce the geotechnical-related risks to the pipeline system. and engineering experience. and ASME B31. and the construction of additional geotechnical mitigation measures in 2007. However. observations. Exponent also reviewed a monitoring program initiated by TgP and COGA to help reduce the risk of future failure resulting from external geotechnical forces.4 [Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids] is the applicable Code for the NGL pipeline. Ultimately. we conclude that geotechnical and geologic conditions posed the most significant risk to the integrity and reliable operation of the system.003 A0F0 0607 0806 95 . 82 ASME B31. complex. the severity and challenges of the dynamic terrain led to the construction of additional robust geotechnical remedial measures at more than 100 sites in 2006. Geotechnical instability caused or substantially contributed to two of the five spill incidents (#1 and #5).June 8. Based on Exponent’s review. SF36292.8 [Gas Transmission and Distribution Piping Systems] is the applicable code for the larger NG pipeline. ongoing implementation of the risk matrix process and monitoring program may identify additional sites that are not included in the current risk matrix as new manifestations of ground movement are observed or detected. and geologic instability caused one of the five spill incidents (#3).3 Geotechnical and Geology-Related Risks The geotechnical and geologic conditions along the pipe alignment are diverse. During our inspections in 2006. 2007 codes and performed along the entire length of both pipelines. dynamic. TgP is currently excavating these sites to perform a more detailed evaluation and initiate the appropriate repair measures if required. and (3) the effects of wave propagation on the pipeline at rigid connections and major curves and bends should be re-evaluated further. TgP has reported that the inspection of the NGL pipeline identified 30 reportable defects per requirements of DOT 49 CFR 195.003 A0F0 0607 0806 96 . no severe external and internal corrosion damage exists along the NGL pipeline.June 8. TgP performed an inline inspection of the NGL pipeline in 2006 using the Magnetic Flux Leakage (MFL) inspection tool and a geometric inline inspection tool.5 Seismic-Related Risks The Camisea system lies within regions that are prone to very large and frequent earthquakes. However. It is our understanding that TgP is currently engaged in a review of seismic risks. any growth of such defects that would lead to the rupture of the pipe requires the presence of external loading. Therefore.4 Pipeline Integrity–Related Risks Several approaches have been adopted by TgP to reduce pipeline integrity-related risks. Consequently. results of the MFL inspection tool and evaluation of metal loss per ASME B31G have shown that. and TgP’s ongoing and prior geotechnical construction program reduces the likelihood of soil movement. as part of their pipeline integrity management plan. Overall. and the entire pipeline was hydrostatically tested. during construction. all the welds were x-rayed. Although seismic hazard studies were performed as part of the system design. and we recommend that this should be evaluated as part of TgP’s ongoing pipeline integrity program (see Section 11). (2) seismic risk management would benefit from an update of the design ground motions. 2007 10. reducing the potential number of weld-related and pipeline material defects. our review suggests that (1) the potential for permanent ground displacements should be re-evaluated more comprehensively at the most susceptible sites. to determine whether SF36292. currently. First. Removal of the loading is a good way to further mitigate the risk. this portion of the NGL pipeline may be subject to this potential risk over the long term. it appears that there is a relatively elevated frequency of metal loss occurrences within the first 50 km of the NGL pipeline. 10. strong ground shaking generated by large earthquakes poses a substantial risk of damaging the pipeline and disrupting operations. Second.452. To mitigate this potential residual risk. future information and risks need to be continually and properly evaluated. and Exponent has been retained to provide continued technical assistance to the IDB on this matter. primarily due to the limitations of the available hydrologic data. which includes review of these actions and additional site visits in 2007.June 8. and that these actions have significantly reduced the risk to the system. our review of the overall scour design concludes that there is some uncertainty as to whether each stream crossing is fully protected from scour over the long term during extreme flood events.6 Scour-Related Risks The design team’s approach of utilizing their local knowledge and site-specific investigations in their scour analysis appears to be sound. Based on available information obtained during Exponent’s investigation and the proposed actions.7 Summary TgP has agreed with the IDB to implement the recommendations listed in Section 11. SF36292. to identify which crossings may require further risk mitigation measures. 10.003 A0F0 0607 0806 97 . However. we recommended and TgP has committed to study all river crossings in 2007. such as the construction of additional fortifications and flow control measures. and thus. If and when ongoing pipeline integrity management efforts identify additional issues. Exponent also notes that pipeline integrity management is a continuous process. it appears to Exponent at this time that TgP is performing adequate pipeline integrity management actions. 10. risk management actions above and beyond those currently being taken may be required. 2007 these potential seismic risks are acceptable for this system or whether mitigation measures should be considered. However. which TgP has committed to implement. These recommendations. including various interim recommendations made by Exponent during our investigation. seismic events. performance of rigorous site-specific stability analysis. our investigation indicates that the primary risks to the pipeline are geological and geotechnical. are described in the following sections. Exponent has recently made several recommendations to further reduce the risk. 2007 11 Recommendations Exponent performed a pipeline integrity analysis of the pipeline components of the Camisea Transportation System.003 A0F0 0607 0806 98 . TgP has implemented various actions to help reduce these risks. Exponent recommends that TgP develop a comprehensive risk management plan (RMP) that establishes a framework for pipeline integrity risk management.June 8. and river scouring as secondary risks. such as the excavation of specific sites to verify data from the inline MFL inspection. from which TgP and the IDB have developed a technical action plan for 2007. TgP should continue to apply the risk assessment method as described herein in a proactive manner to other sections of the pipeline. construction of additional geotechnical stabilization measures in 2006. At a minimum. 11. with mechanical pipe integrity. Overall. the plan should clearly define the framework and approach for making management decisions in terms of what geotechnical remedial measures should be implemented. and will identify means and responsibilities for execution of such remedial measures. and installation of monitoring equipment at specific sites. 2. SF36292.1 Geotechnical and Geologic The following are geotechnical and geological recommendations that apply to the pipeline alignment: 1. based on the results and conclusions of this investigation. The reduction of potential ground cracks will simplify the geotechnical investigation at these locations.5-cm-diameter perforated metal pipe into the ground using SF36292. Exponent recommends that attention and care be given to proper soil conditioning and compaction of backfill behind and in front of retaining walls and other remedial structures. We understand that some equipment has been purchased since then and is being used at the COGA office at Kiteni.003 A0F0 0607 0806 99 . Proper compaction will reduce forces acting on the walls and reduce potential ground cracks that could form in poorly compacted fill behind walls. At most of the locations. Piezometers to monitor water levels at nearly all sites of geotechnical stabilization. In addition to the above general recommendations. During the past site inspections. 2007 3. We recommend that the results and findings from this analysis be transmitted from engineers at Lurin to the COGA field personnel on a regular and frequent basis. should the data indicate that stabilization is either necessary or desirable. 4. TgP should continue the implementation of the ROW inspection program as described in Section 6. 5. Prior to our site inspections. The strain gauge program should provide the type of data that will allow TgP to evaluate movement in the pipelines and should allow a preemptive remedial program to be implemented at a specific location. 7. Exponent recommended some basic geotechnical testing equipment to perform index property testing of soil samples taken from the borings made on the project. TgP installed strain gauges on the pipelines at seven locations.June 8. piezometers can be constructed by hand by driving 2. Exponent recommends that the project purchase a small drilling and sampling rig that is portable using helicopters. 6. Exponent recommends that the following geotechnical technologies be employed at specific sites as appropriate: 8. Exponent recommends that a detailed geotechnical analysis be performed to identify subsurface conditions and construct cross sections for this site. presence of discoloration.June 8. Installation of these will require the use of portable drilling equipment. 11. Alignment of concrete-lined surface water channels and soil-cement bag current breakers and lined channels. This work will require the use of the portable drilling and sampling equipment. and to perform conventional stability analyses of existing slopes at the site. Nature and amount of the occurrence of surface water flows. c.003 A0F0 0607 0806 100 . b. as necessary. Pipe should be relatively heavy (schedule 80) pipe with threaded couplings. It is our understanding that TgP has performed this geotechnical study. Detailed geotechnical investigations. and qualified personnel to install. as discussed with TgP. SF36292. and interpret results. Following completion of this work. to be performed at PS #2 as soon as possible. Examples of observations and measurements are as follows: a. and other such observations. as discussed with TgP. This may involve placement of simple staking to assist in making precise quantitative measurements of movement. and construction of remedial measures is currently underway. monitor. Nature and size of ground cracking or other indications of displacement in the slopes. analyze. including soil sampling in borings and test pits. to evaluate soil strength and groundwater levels. Slope inclinometers to monitor subsurface movements in soil and rock. 2007 simple hand drive hammers. 9. Specific observations and physical measurements to be made at individual sites. increases or decreases in the rate of flow. 10. especially noting new occurrences. 2007 d. Later. 11. This information shall be used to update. damage to check dams. design ground motions. the seismic risk management plan and perform any required upgrades.2 Seismic TgP should perform a complete and comprehensive upgrade to the seismic hazard assessment for the system.4 Pipe To reduce pipe integrity–related risks. Alignment of the gabion walls at each location. if necessary. 11. lateral shifting of the stream banks.e. TgP will investigate the feasibility of identifying circumferential cracks along the system and will continue with its external excavation program to make further advances in the interpretation of the recently performed MFL inline inspection. and possible floods of relatively extreme magnitude. including an experimental evaluation of the nucleation of circumferential cracks at pipe girth welds that are loaded externally (i. or shifting of rock protection on the floors of streambeds. such as long-term degradation. e. retreat of stream banks.June 8. Formation of erosion gullies. and fifth spill incidents. Based on the analysis. SF36292. if necessary. TgP should implement. and effects of wave propagation on the pipeline at rigid connections and major curves and bends. specifically related to the potential for permanent ground displacements. fourth.003 A0F0 0607 0806 101 .. TgP has committed to perform a root-cause analysis of the first. 11. This study shall consider factors that are very likely to play a part in some of the stream crossings where more complex processes are active. appropriate remedial measures. soil movement).3 Scour TgP should evaluate the scour potential and existing countermeasures at each river crossing and should perform a scour risk analysis that classifies the scour risk at each river crossing.