Updated December Pembina. Engin. Submitted to: Prepared by: Prepared: September Updated:

Transcription

1 Pembina Redwater Manifold Expansion at Edmonton Terminal Reactivation Engin eering Assessment Submitted to: National Energy Board of Canada ( NEB ) Prepared by: Prepared: September 2016 Updated: December 2016

2 Contents 1 Summary Introduction Background Objective of Assessment Scope of Assessment Team Methodology and Applicability Assessment Design Basis of the Pipeline System Design Conditions Operating Conditions Steady State Loading Conditions Transient Impact Assessment Material Specifications & Properties Manufacturing Process & Installation Method Construction and Testing Specifications Configuration of Pipeline System Threat Assessment Condition of Piping a. Internal Corrosion b. External Corrosion c. Mechanical Damage d. Coating Release History Risk Assessment Risk Assessment Results Assessment Recommendations Activities Prior to Startup Activities Post Startup Changes to Integrity Management Plan for Affected Asset Page 1 of 18

3 Tables Table 2.1 Team... 6 Table 3.1 Pipe Properties of Redwater Piping... 8 Table to 2015 Crude Characteristics... 9 Table 3.3 Properties of Future Commodities Table 3.4 Impact to Threats Figures Figure 2.1 Existing Redwater connection between TP 19 and TP 1 deactivated January Figure 2.2 Existing pipe rack section between TP 5 and TP 10 deactivated January Figure 2.3 Proposed reactivation of Redwater connection between TP 19 and TP Figure 2.4 Proposed reactivation of pipe rack between TP 5 and TP Figure 2.5 Piping within manifold 106 to remain deactivated and to be removed Figure 3.1 Isometric of Redwater piping between TP 19 and TP Figure 3.2 Isometric of pipe rack between TP 5 and TP Figure 3.3 Acuren NDE inspection location, February Page 2 of 18

4 1 Summary ( Enbridge ) and Fluor Canada Ltd. ( Fluor ) completed this ( EA ) to evaluate the potential integrity impacts related to reactivating the Pembina Redwater Connection at the Edmonton Terminal (the Project ) to ship light crude oil at a higher flow rate of 1184 m 3 /hr. This reactivation includes piping downstream of the Redwater inlet including the NPS 12 inlet isolation valve as well as a section of NPS 12 pipe in the pipe rack connecting manifold 106 and manifold 205. The two pipe sections consist of approximately a 33 meter pipe segment at the Redwater connection in manifold 106 and approximately 24 meters of pipe in the pipe rack. 8 All applicable information was reviewed in accordance with the current Canadian Standards Association: Oil and Gas Pipeline Systems (CSA Z662 15) requirements and applicable Enbridge Design Standards. All available operating and maintenance history, related integrity inspection reports, and release history was used to validate the existing hazard identification assessment. Expected operating conditions, along with the scope of affected assets was used to identify any new threats to the integrity of the system. Finally, an evaluation was conducted to ensure that the risks associated with each of the identified threats are either adequately mitigated by existing activities or will be adequately mitigated through recommendations in this report. Assessment of the available inspection data shows no corrosion, no critical flaws, and that Enbridge s integrity management programs confirm that all integrity threats are adequately managed and that the revised conditions do not pose any additional threats to the integrity of these facilities. This EA confirms that the Project can proceed as proposed and will operate safely and reliably in the expected operating conditions. 2 Introduction 2.1 Background Pembina Pipeline Corporation ( Pembina ) plans to bring in deliveries of light and medium crude through the Redwater line of the Edmonton Terminal ( EP ). The line was deactivated in January 2016 [MO ]. The proposed operating conditions for this reactivation application include an increase in flow rate compared to that which the piping was originally operated at. Due to this increase in flowrate, product will be redirected from manifold 106 (MF106) to a new constructed manifold 105 (MF105) which is better equipped to manage the increased flow. 2.2 Objective of Assessment The objective of this EA is to evaluate Enbridge s facilities associated with the Project in accordance with CSA Z and to determine whether additional risk mitigation measures are needed to ensure safe and reliable operation. 2.3 Scope of Assessment The scope of this EA involves reactivating currently deactivated piping sections. The two sections to be Page 3 of 18

5 reactivated were deactivated in January The reactivation scope of work at the Edmonton Terminal includes piping from the NPS 12 inlet isolation valve at tie point TP 19 to tie point TP 1, as well as the pipe rack connecting manifold 106 to manifold 205 from TP 5 to TP 10 are within the scope of this EA. Figures 2.1 and 2.2 show the highlighted piping of interest, which was previously deactivated in January The deactivated sections of interest were flushed with hot oil, drained, and filled with nitrogen. They have been maintained in this deactivated state in order to be suitable for future reactivation. 1 Figure 2.1 Existing Redwater connection between TP 19 and TP 1 deactivated January Figure 2.2 Existing pipe rack section between TP 5 and TP 10 deactivated January 2016 The two sections outlined in Figures 2.1 and 2.2 are proposed to be reactivated in the same locations according to Figures 2.3 and 2.4. Page 4 of 18

6 3 Figure 2.3 Proposed reactivation of Redwater connection between TP 19 and TP 1. 4 Figure 2.4 Proposed reactivation of pipe rack between TP 5 and TP 10 The spool immediately upstream of valve 106 V 061 at TP 19 is rated as PN 100 and may be modified or replaced in order to accommodate for a replacement valve. This spool will be hydrotested before being placed in line. A PN 100 spacer, which will be replaced by a check valve is located immediately downstream of valve 106 V 061, located at TP 19. The spec break to PN 20 piping occurs downstream of the PN 100 spacer. A 2 PN 20 valve is located immediately downstream of the spec break. 5 There is one ¾ threaded vent located within the reactivation scope, located between TP 19 and TP 1. This high point vent will be hydrostatic tested for integrity and will remain in place. If the vent does not pass the hydrostatic test, it will be replaced. The previously noted vent between TP 5 and TP 10 has been moved out of the reactivation scope and will be replaced with a new spool. The currently deactivated piping within manifold 106 that is not being reactivated within this scope will either remain in a deactivated state or be removed. The deactivated piping will be maintained in the same method as is currently in place. The specific piping within manifold 106 to remain deactivated and be removed is shown in Figure 2.5. Page 5 of 18

7 6 Figure 2.5 Piping within manifold 106 to remain deactivated and to be removed. 2.4 Team The EA has been prepared by members of the Facilities Integrity department of Enbridge and the Pipeline Engineering department of Fluor. Table 2.1 Team Person Company Group, Role Kimberly Pierce Enbridge Facilities Integrity Mike Sereda Enbridge Facilities Integrity Mark McTavish Enbridge Facilities Integrity Richard Boodoo Enbridge Project Manager Deepak Mahajan Enbridge Project Engineer Kevin Olson Fluor Pipeline Engineering, Manager Kendra MacKay Fluor Pipeline Engineering, EIT 2.5 Methodology and Applicability The methodology used in the EA was designed to meet the requirements established in CSA Z Section 3.3. The methodology used consists of three (3) main components: 1. Historical Records a. Design, materials, construction, operating and maintenance history, and b. Results of related integrity inspections; 2. Hazard / Threat Identification; and 3. Assessment of identified hazards / threats. The review of historical records included consideration of the design, materials, construction, operation, inspection, maintenance, and release history. Also a current threat assessment and the mitigation activities relative to the Facilities were reviewed. Based on the records reviewed and understanding of proposed future operations, a hazard/threat identification and assessment was completed to determine whether any Page 6 of 18

8 changes were required to the current threat assessment as a result of the proposed changes in operating conditions. A review of each hazard was then completed to evaluate the effectiveness of the current integrity management programs in managing the identified threats. Where appropriate, requirements are provided to further mitigate identified threats. 3 Assessment 3.1 Design Basis of the Pipeline System Design Conditions The design pressure was calculated based on CSA Z662 15, clause : Where 2 P = design pressure, MPa S = specified minimum yield strength, as specified in the applicable pipe standard or specification, MPa t = design wall thickness, mm D = outside diameter of pipe, mm F = design factor = 0.6 L = location factor = 1 J = joint factor = 1 T = temperature factor = 1 Enbridge uses a design factor of 0.6 for facility piping, rather than 0.8 as per CSA Z Thus, the Enbridge design factor is more conservative. The calculated design pressure based on the pipeline properties, design factor and size is higher than the Maximum Operating Pressure ( MOP ) in both cases in Table 3.1. Page 7 of 18

9 9 Material Table 3.1 Pipe Properties of Redwater Piping Redwater Inlet Piping CSA Z245.1 Gr. 241 CAT I Pipe Rack CSA Z245.1 Gr. 241 CAT I Material Wall Thickness mm Nominal Pipe Size (NPS) in Outside Diameter mm CSA Class Designation PN SMYS MPa Construction Date Year Calculated Design Pressure of Pipe Flange Rating Design Pressure Approximate Length of Piping and Components kpa kpag m Operating Pressure kpag Operating Conditions The expected operating conditions are to be similar to those for which the piping was originally constructed and commissioned. The expected flow rate is to be higher than that with which the piping had previously been operated under. Due to this increase in flow rate, flow will be redirected from the Redwater line in manifold 106 to manifold 105, which contains a larger prover (20 ). This will accommodate for the increased flowrate. The output flow from the prover will be directed to manifold 205 using the existing NPS 12 pipe rack. The Redwater line historically saw flow rates between 100 m 3 /hr to 120 m 3 /hr, with a temperature range of 3 C to 20 C depending on the season. The backpressure on this line was held at 300 kpa. The expected minimum and maximum operating flow rates upon reactivation of the piping are 320 m 3 /hr and 1,184 m 3 /hr respectively, with a temperature range of 7.6 C to 23 C. The maximum allowable velocity for crude as per Enbridge design standard D is 6.1 m/s. Operating at the maximum design flowrate of 1,184m 3 /hr will result in a maximum velocity of 4.5 m/s through the NPS 12 piping. Hence the existing piping is found to be suitable under these operating conditions. 10 The Redwater piping was held in a deactivated state with nitrogen while deactivated. The design pressure of 1,900 kpa for the Redwater piping within EP will not change as a result of the project. Light crude oil, Redwater crude ( RW ), was the only commodity carried in the Redwater piping from 1998 to The piping was deactivated in June 2009 and subsequently reactivated in January Upon reactivation in 2013, Pembina Condensate ( CPM ) and Pembina Light Sour for SLE ( PLS ) were the two commodities carried in the Redwater piping, until January 2016 when the piping was deactivated again. Total Sulphur ranged from 0.09 to 0.86 weight %, and the density was to kg/m 3. The crude characteristics from 1998 to 2015 are shown in Table 3.2. Page 8 of 18

10 Year Product Identifier Crude Type (Long Name) Table to 2015 Crude Characteristics Total Sulphur (% by wt.) Pour Point ( C) Reid Vapour Pressure (kpa) Density (kg/m 3 ) Viscosity (cst) at Specified Temperature ( C) RW Redwater RW Redwater 0.56 < RW Redwater RW Redwater RW Redwater RW Redwater 0.48 < RW Redwater 0.47 < RW Redwater RW Redwater RW Redwater RW Redwater RW Redwater Piping stopped receiving volumes June 2009 Refer to NEB Application to Deactivate/Reactivate A42207 Piping reactivated January 2013 Refer to NEB Application to Deactivate/Reactivate A CPM Pembina Condensate 0.1 < Pembina PLS Light Sour For SLE CPM Pembina Condensate 0.09 < Pembina PLS Light Sour For SLE CPM Pembina Condensate 0.1 < Pembina PLS Light Sour For SLE Piping deactivated January 2016 Refer to NEB Application to Deactivate A63435 Chemical properties of product to be shipped are shown in Table 3.3. The future commodities to be shipped will be classified as light or medium crude and have densities similar to previous products. The total Sulphur content may be higher than products previously shipped in this line, but will remain at or below 2.0% by weight. Commodity H 2 S content is expected to range from 0 wppm to 200 wppm, which is not classified as sour service as per CSA Z The descriptions in Table 3.2 indicating sour refer only to the fact that the crude has more than 0.5 weight % Sulphur, and are not related to H 2 S content and sour service as defined by CSA Z Page 9 of 18

11 Commodity ID Total Sulphur (wt %) Table 3.3 Properties of Future Commodities Density (kg/m 3 ) Viscosity 1 10 C Viscosity 2 10 C RVP (kpa) Condensate Blend CRW 0.08* Mixed Blend Sweet SW 0.40* Sour Light Edmonton SLE Shell Synthetic Light SSX * Results from 2015 Crude Characteristics Steady State Loading Conditions 11 The steady state loading conditions are similar to those for which the piping was originally constructed and for which it has experienced under previous operation. The significant change in operating conditions when compared to the past is the operating flow rate. The expected maximum flowrate is 1,184 m 3 /hr, which is greater than the historic maximum flowrate of 120 m 3 /hr. This increase in flowrate from past conditions will have negligible effect on the rate of erosion. With a design pressure of 1,900 kpa, the minimum required wall thickness is mm as per CSA Z662 15, clause The actual wall thickness of the pipe is mm, providing an extra mm of wall thickness. Since the actual wall thickness is significantly greater than the required wall thickness, erosion will have little impact on the integrity of the line. The differences in steady state loading conditions when compared to past operation are therefore considered minimal Transient Impact Assessment The maximum expected pressure due to transient events is similar to those for which the piping was originally designed. These pressures are still within the maximum allowable pressure for the piping and the piping will experience similar pressure and dynamic loads due to transient events Material Specifications & Properties Piping material, which will remain the same after the Project, was determined from material test reports and procurement records of the piping system. Piping material is listed in Table 2, and is CSA Z category I. The nominal pressure of both piping sections is PN 20. The diameter of the two sections of pipe is mm (NPS 12) and both were constructed in All piping, fittings, and flanges comply with Enbridge internal design standard D and CSA Z Manufacturing Process & Installation Method Piping was manufactured in accordance with CSA Z and Enbridge internal design standard D No new piping is being supplied; hence additional manufacturing and installation are not included in the scope of this EA Construction and Testing Specifications Piping was originally constructed in 1992 in compliance with SOR/ and Enbridge internal design standard D Page 10 of 18

12 3.1.8 Configuration of Pipeline System The configuration of the two sections of piping discussed in this EA is displayed in Figures 3.1 and 3.2. The inlet piping to be reactivated is downstream of the NPS 12 inlet isolation valve and situated between tie point TP 19 and tie point TP 1. The pipe rack section to be reactivated lies between tie point TP 5 and tie point TP 10. Note that the dimensions provided are in millimeters and have been approximated. Figure 3.1 displays the configuration between TP 19 and TP 1. Immediately downstream of the inlet valve is a spacer. This spacer is intended to be reactivated along with the downstream piping. A 2 inch PN 20 valve is located downstream of the spacer, just upstream of the first elbow within the downstream piping. There are a total of seven (7) elbows within this piping configuration. A ¾ threaded vent lies on the high point of the piping and ties into a vent header on top of a platform. 12 Figure 3.1 Isometric of Redwater piping between TP 19 and TP 1 The configuration of the pipe rack to be reactivated is shown in Figure 3.2. Both tie points (TP 5 and TP 10) are located on the horizontal leg of the pipe rack. There are no flanges, fittings, or valves located within this section of piping. Page 11 of 18

13 3.2 Threat Assessment Condition of Piping Figure 3.2 Isometric of pipe rack between TP 5 and TP 10 a. Internal Corrosion One section of the Project piping was inspected by Acuren on February 13, The inspection location is shown in Figure 3.3. This location is a low point on the line, which would be most susceptible to internal corrosion occurring if there was a corrosive environment on the line. The piping was inspected visually and by Automatic Ultrasonic Testing ( AUT ). No internal or external corrosion was found at this location. In January 2016 the piping associated with the Project was deactivated and flushed with hot oil and corrosion inhibitor, drained and filled with nitrogen to 15 psig on the line thus removing product from the line, and the corrosive environment. The pressure has been monitored since this time. The piping was isolated (blinded) from the active system. The intention when the system was deactivated that it be maintained in a deactivated state in such a manner that it would be suitable for reactivation at a future date if required. Page 12 of 18

14 Figure 3.3 Acuren NDE inspection location, February 2012 b. External Corrosion All of the Redwater piping is above grade and the external surface of the pipe is directly visible. No external corrosion was found by Acuren during the February 2012 inspection of the Redwater piping. Since 2007 several inspections have been done on station piping within EP. External corrosion of above ground piping is effectively mitigated through external painting. Historically, external corrosion has not been a large risk within EP, and no reportable external corrosion has been found in any of the inspections. There have historically been no leaks due to external corrosion within EP. c. Mechanical Damage The external visual inspection of the pipe verifies the mechanical condition of the pipe since the entire outer surface of the pipe is exposed and any defects can be easily detected. Inspection of the piping shows no significant mechanical damage (with regards to regulatory requirements or standard industry practice). d. Coating The entire section of Redwater piping is above ground, and is painted per Enbridge Standard D During the site visit, August 2016, the coating was found to be in good condition. As part of our maintenance programs any sections requiring repainting will be repainted as a part of regular maintenance within EP Release History All release data throughout Enbridge is collected and categorized to quantify and incorporate associated risk into program activities and projects. The release history of the assets associated with the Project was reviewed. The Project will not affect the probability of future releases from historical release causes. The Redwater line at EP has not experienced any leaks or ruptures. Table 3.4 reviews each identified threat and existing mitigation. These are then used to assess the impact of the Project. When a release is first reported in Enbridge s Leak Reporting Database, the release cause is identified and subsequently categorized by main cause, sub cause, and Pipeline Performance Tracking System item to Page 13 of 18

15 ensure that existing programs are prioritizing and focusing on the hazards and threats identified. Corrective action plans are developed to minimize the likelihood of similar future releases. In addition, regulatory and code requirements are taken into account when considering hazards and threats Risk Assessment The effects of the Project are summarized below in Table 3.4, as well as the existing mitigative measures in place to reduce the risk. The project impact is compared to when the pipe was previously in service. All identified threats will be adequately mitigated through existing mitigative measures. The threats have been classified based on: a) CSA Z Annex H (normative) Pipeline failure records, H.2.6 Failure Cause; and, b) Investigation and classification of historical Enbridge releases. Table 3.4 Impact to Threats Threat Project Impact Rationale Existing Mitigation Piping Material Loss Equipment Metal Loss External Piping Corrosion Internal Piping Corrosion Erosion External/Internal Storage Tank Corrosion External/Internal Pressure Vessel Corrosion Above ground. Existing facility no new conditions. Products meeting the original specifications and similar products after the Project. Coating Assessment Surveys Inspection and Repair/Replacement Station piping program prioritize inspections based on threat R&D: Internal Corrosion Monitors Real time Increase in flow rate, though lower than Velocity limits velocity limits, and no BS&W limits erosion expected. No tanks in scope API 653 Inspection and repair program No vessels in scope API 510 Inspection and repair program Cracking Stress Corrosion, Sulphide Stress, Hydrogen Induced, Pressure ranges will remain the same. Page 14 of 18 Hydrotests and Nondestructive examination on new pipe/welds

16 Threat Project Impact Rationale Existing Mitigation Structural Degradation External Interference Material or Manufacturing Related Mechanical Damage Delayed, Corrosion Fatigue, Fatigue Mechanical or environmentally assisted degradation specific to reinforced composites Employee/ Contractor/ Third Party Defective Weld No reinforced composites in scope No construction activity No new piping being supplied. (where applicable) Small Diameter piping upgrades based on Vibration Assessments, Finite Element Analysis, and Installation reviews Not applicable Enbridge field construction specifications Enbridge Operating and Maintenance Procedures Vendor Pre qualification Hydrotests and Nondestructive examination on new pipe/welds (where applicable) Defective Weld No new welding supplied. Field Contractor Prequalification Weld Procedures Weld Inspection (during construction) Construction Defective Pipe or Component Body No new piping being supplied. Field Contractor Prequalification Field Construction Specifications Pipe Inspection (during construction) Wash out/ Erosion/Freeze Thaw No changes as a result of project. Above grade piping. Enbridge Operating and Maintenance Procedures Page 15 of 18

17 Threat Project Impact Rationale Existing Mitigation Geotechnical Construction or Undermining No changes as a result of project. Field Contractor Prequalification Field Construction Specifications Inspection during construction Seal or Packing Failure Ancillary Equipment Gasket Other Valves Pumps Booster and Mainline Defective or Damaged Ancillary Piping, Tubing, Connections or Equipment Leaking Flange Gasket Control System Malfunction Improper Operation Lightning/Fire No valves in scope. Vendor Pre qualification Design Standards/Equipment Specifications No pumps involved Vendor Pre qualification Design Standards/Equipment Specifications No ancillary equipment No change to existing flanges, Similar number of flanges, installation and torqueing procedures checks based on Enbridge best practice. Thorough commissioning procedures prior to inservice. Standard pipeline system. No change to previous operation. No change as a result of this project. Design Standards/Equipment Specifications Field Contractor Prequalification Inspections during construction Enbridge Operating and Maintenance Procedures Operational/Control Philosophy Commissioning Checks Operating Procedures Training Design Standards/Equipment Specifications The effects of the Project are summarized above in Table 3.4, as well as the existing mitigative measures in Page 16 of 18

18 place to reduce the risk. All identified threats will be adequately mitigated through existing mitigative measures Risk Assessment Results Probability Analysis Corrosion has not historically caused any releases from this portion of the system. Integrity visual inspections conducted within EP confirm that external corrosion of above ground Redwater piping is effectively mitigated. Above ground piping is externally painted to mitigate external corrosion. Also based on the inspections, the products that are pumped through the lines have not created an internal corrosion concern. Products shipped through the line will be monitored for total Sulphur content, to highlight any needs for increased inspection of the line. Deactivated piping was drained, and inhibited to prevent corrosion during the time the line was stagnant to arrest internal corrosion. New products to be shipped are similar to what was previously shipped, and similar to other products on our system. Integrity inspections are conducted to assess internal corrosion and this inspection program effectively mitigates the risk of facility releases from that cause. The velocity will be increased, but the velocity is well below where we would expect to see erosion issues on the line. BS&W limits, and velocity limits keep the piping well below erosion rates. We have not had any erosion issues at EP historically. Consequence Analysis Facility releases are designed to be contained within the site. There are no changes by the Project that will affect the consequence of a release. Risk Analysis Since the probability of a release is expected to be the same and the consequence of a release is unchanged, the reactivation of Redwater does not increase the risk of a release. 4 Assessment Recommendations 4.1 Activities Prior to Startup All typical activities prior to startup need to be conducted including: Hydrostatic Testing between TP 19B to TP 1 Pre commissioning checks; 13 Visual inspection of coating; and Reactivation. 4.2 Activities Post Startup There are no additional activities required as a result of this assessment. All typical activities post startup need to be conducted, including: Visual inspections during flooding for signs of release or vibration; and Operation functional checks including vibrational assessment Page 17 of 18

19 4.3 Changes to Integrity Management Plan for Affected Asset There are no required changes to the integrity management plan as it relates to this Project. All identified risks are effectively being mitigated. Enbridge will continue to conduct inspections, analyze history, and continually improve our integrity management program based on any revised threat assessment. The integrity of EP will continue to be managed through Enbridge Facilities Integrity Management Programs and other stakeholder processes. Page 18 of 18