02U 18-Jun-14 Issued for Use D. Trask K. Tonn H. Farrell K. Tonn 01R 16-Jun-14 Issued for Review D. Trask K. Tonn H. Farrell K. Tonn Rev. Date Reason for Issue Prepared Checked Approved Approved
Title:
Removal of Beach Valve Station Isolation Valve
Assembly (P74-SDV-011) Assessment
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penal
provisions of the law.
TECHNICAL NOTE
Topic:
Removal of Beach Valve Station Isolation Valve Assembly (P74-SDV-011)
Assessment
Background:
The Deep Panuke gas export pipeline is approximately 175km in length and
comprised of an offshore and onshore section. The offshore and onshore
pipeline sections are approximately 172.3km and 2.7km in length respectively.
The onshore pipeline is located from landfall to the interconnection with the
Maritimes and Northeast Pipeline (M&NP). The pipeline has two onshore
facilities referred to as the Beach Valve Station (BVS) and Gas Export Pipeline
Terminus (GEPT). The BVS is located at landfall and contains a valve (i.e.
P74-SDV-011), which can be opened or closed either remotely via the PFC or locally
by an individual on site. The GEPT is located adjacent to the M&NP facility and
contains a pig receiver and a valve (i.e. P74-SDV-021) which can be opened or
closed either remotely via the PFC or locally by an individual on site. The valves
are opened or closed via a gas over hydraulics actuator. Details of the onshore
pipeline and facilities are located in document DMEN-O22-PD-PR-74-0002
“P&ID – Onshore Pipeline, Beach Valve Station and GEP Terminus” which is
located in Appendix A.
A plan view of the onshore facilities and pipeline right of way locations is located
in Appendix B.
An isometric view of the beach valve station assembly above and below grade
piping is located in Appendix C.
On April 23, 2014, an in-line inspection tool was launched from the offshore
Production Field Center (PFC) with an expected arrival at the gas export pipeline
Digitally signed by David Trask DN: cn=David Trask, o=Encana, ou=Deep Panuke, [email protected], c=CA Date: 2014.06.23 10:06:13 -03'00'
Digitally signed by Karl Tonn DN: cn=Karl Tonn, o=Encana Corp, ou=Deep Panuke, [email protected], c=CA Date: 2014.06.23 12:38:07 -03'00'
Digitally signed by Hugh Farrell DN: cn=Hugh Farrell, o=Encana, ou=Deep Panuke, [email protected], c=CA Date: 2014.06.23 10:15:58 -03'00'
Digitally signed by Karl Tonn DN: cn=Karl Tonn, o=Encana Corp, ou=Deep Panuke, [email protected], c=CA Date: 2014.06.23 10:08:29 -03'00'
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
terminus onshore receiver of April 24, 2014. At approximately 10:45 am on April
24, 2014, the inline inspection tool arrived at the beach valve station; however,
the tool did not arrive at the onshore receiver and was subsequently confirmed to
have stopped at the beach valve assembly. The approximate tool location was
determined to be upstream of the first 6-inch tee based upon the receiving the
22Hz transmitter signal from the Wavetrack device located on the inline
inspection tool.
On June 11, 2014, digital radiography was performed on the excavated pipe
section which has confirmed that the inline inspection tool is located upstream of
the first 6-inch tee as illustrated in Appendix D.
Discussion – Inspection Tool Removal Plan
Encana has now concluded that it is highly unlikely that the in-line inspection tool
will become dislodged on its own and is now planning to remove the in-line
inspection tool by performing on-line isolation and cut-out.
The proposed removal plan involves performing line isolation both upstream and
downstream of the beach valve assembly, removing the beach valve assembly
(complete with in-line inspection tool) and re-installing a straight section of
linepipe. The planned steps include the following:
•
Weld on split tee fittings (both upstream and downstream of beach valve
assembly) rated to the approved pipeline maximum operating pressure
(MOP)
•
Weld on purge and equalization fittings
•
Perform hot tap through fittings
•
Insert double isolation (ie. T.D. Williamson - Stopple Train) both upstream
and downstream of the beach valve assembly
•
Depressurize and gas free isolated section
•
Cut and remove the beach valve assembly which includes from a location
upstream of the inline inspection tool and downstream of the second
6-inch tee as illustrated in Appendix E.
•
Install new straight section of linepipe and oxygen free
•
Remove isolations (i.e. TDW Stopple Train)
•
Install completion plugs and blind flange assembly on hot tap locations
The target date for the removal of the beach valve assembly (complete with
in-line inspection tool) is September 2014. Once removed, surplus certified in-linepipe
will be used to reinstate the gas export pipeline.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
Due to required procurement lead times, new valve and extruded headers (tee
section) would be unable to be procured in time to re-install in the line during the
anticipated September 2014 line isolation program.
Since the Deep Panuke gas export pipeline is currently considered “Class 1” in
accordance with CSA Z662-11, the isolation valve at the beach valve station is
not required. A detailed discussion on the requirement of the beach isolation
valve is contained in the next section.
In the event that future development adjacent to the onshore pipeline occurs,
which requires the class of pipeline to be changed to Class 2, the isolation valve
will be reinstated with a similar line isolation methodology. The line isolation
would not require a new hot tap but rather a re-entry would be performed via the
existing hot tap locations.
Discussion – Requirement for Beach Isolation Valve (P74-SDV-011)
The onshore pipeline is located within an industrial park and CSA Z662 (Section
4.3.3, Table 4.1, Note 2) requires that “If it is likely that there will be future
development in the class location assessment area sufficient to increase the
class location designation, consideration shall be given to designing, pressure
testing, operating, and maintaining the pipeline in accordance with the
requirements applicable to the higher class location”.
During the design phase of the onshore pipeline, both a petrochemical and a
LNG import terminal were proposed to be located adjacent to the onshore
pipeline route by Keltic Petrochemical and Maple LNG. As a result, if these
developments were built, the Deep Panuke pipeline would be a Class 2
designation. Thus as these proposed developments were under consideration at
the time of the development application and possibly could be approved, it was
decided to design the onshore pipeline for Class 2 requirements. This would
require a maximum valve spacing of 25km for the onshore pipeline section in
accordance with Table 4.7. As a result, valve P74-SDV-011 was installed at the
landfall location on the assumption that these projects would proceed.
Subsequent to the onshore pipeline design phase, both the Keltic Petrochemical
and Maple LNG import facility projects have been cancelled and no development
has occurred.
As a result, the Deep Panuke pipeline is currently “Class 1” in accordance with
CSA Z662-11, and the isolation valve at the beach valve station is not required
as described in the following sections.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
Regulatory Requirement:
The onshore pipeline section is regulated by the National Energy Board (NEB) in
accordance with the Onshore Pipeline Regulations. The Onshore Pipeline
Regulations (OPR) have no specified requirement for valve locations and
spacing; however, Section 4(1) states that the pipeline is required to be
designed, constructed, operated or abandoned in accordance with CSA Z662.
Section 42 of the NEB Onshore Pipeline Regulations state: “If the class location
of a section of a pipeline changes to a higher designation that has a more
stringent location factor, the company shall, within six months after the change,
submit the proposed plan to deal with the change to the Board.”
(See Appendix F for OPR Section 4(1) and 42).
In addition, a variance of Certificate GC-111 in accordance with Section 21 of the
NEB Act is required in order to remove this valve.
CSA Z662 Requirement:
The Deep Panuke onshore pipeline has been designed, constructed and
installed in accordance with CSA Z662 as per the OPR.
Section 4.4 of CSA Z662 (See Appendix G) provides requirements for isolation
valve location and spacing and states that “Isolating valves shall be installed for
the purpose of isolating the pipeline for maintenance and for response to
operating emergencies”.
The number and spacing of these valves must comply with Table 4.7 or
otherwise can be determined by an engineering assessment. Table 4.7 specifies
the maximum valve spacing based upon the type of pipeline and class location.
The class location is specified in Section 4.3.2; in particular, Table 4.1.
The current type of pipeline and Class location for Deep Panuke is as follows:
Type of Pipeline = Gas
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
Note:
The basis for Class 1 is that currently no dwellings, building, outside
occupied areas or industrial installation are located along the onshore pipeline
route.
The onshore pipeline is located within an industrial park and the only nearby
structures present are three (3) wind turbines for which with no persons are
present during normal use.
Thus in accordance with Table 4.7, for a gas pipeline with Class 1 designation,
there is no code requirement with regards to isolation valve locations and
spacing based upon the current development status near the onshore pipeline
route.
Safety Considerations:
Encana has requested that PSRM Services perform a technical review of the
Onshore Safety Concept Analysis and other relevant project documentation to
determine the potential impact to the Project Target Levels of Safety (TLS) from
continued operations based upon current land use in the Goldboro area on the
basis that the beach isolation valve (P74-SDV-011) is removed.
The review concluded that the project remains within acceptable limits for the
Deep Panuke Target Level of Safety, applicable land use risk acceptability
criteria for Goldboro and the industry accepted ALARP range; therefore, no risk
reduction recommendations have been deemed necessary. This technical review
is located in Appendix H.
Discussion – Future Requirement for Isolation Valve (P74-SDV-011)
Since the onshore pipeline is located in an industrial park, there is a potential for
a change to “Class 2” if an industrial installation or building occupied by 20 or
more persons during normal use is situated next to the onshore pipeline as per
CSA Z662 Table 4.1.
Currently, an LNG import terminal is being proposed for the Goldboro industrial
park with the earliest in-service date of 2020. In the event that the LNG export
facility (or any other future facilities) are approved for construction and is situated
next to the onshore pipeline such that it would increase the class location
designation, then the beach isolation valve will be necessary. The existing
isolation valve assembly will be reinstated, with a similar line isolation
methodology. The line isolation would not require a new hot tap but rather a
re-entry via the existing hot tap locations.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
Encana will continue to monitor future developments in the industrial park to
determine if they will result in a class location designation change. In the event
that a change occurs and a beach isolation valve is required, the required
components will be procured and installed.
Conclusions and Recommendations
The Deep Panuke gas export pipeline is currently considered as “Class 1” in
accordance with CSA Z662-11, and thus no beach isolation valve is required. In
addition, a technical review of the onshore Concept Safety Analysis was
performed and concluded that Deep Panuke remains within acceptable limits for
the Target Levels of Safety if the beach isolation valve is removed.
As a result, the plan to remove the beach isolation valve assembly (complete
with inline inspection tool) and replace with an existing certified linepipe section is
considered acceptable. However, a variance of Certificate GC-111 in
accordance with Section 21 of the NEB Act is required in order to remove this
valve.
Encana will continue to monitor the future developments in the industrial park to
determine if they will result in a class location designation change. In the event
that a class location change occurs and a beach isolation valve is required, the
required components will be procured and installed. The isolation valve assembly
would be reinstated with a similar line isolation methodology. The line isolation
would not require a new hot tap but rather a re-entry via the existing hot tap
locations.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DEEP PANUKE ONSHORE PIPELINE R.O.W. BEACH VALVE STATION GOLDBORO INDUSTRIAL PARK WINDFARM Betty’s Cove Brook SOEP GAS PLANT M&NP METERING FACILITY Encana GAS EXPORT
PIPELINE TERMINUS FACILITY EXXON MOBILE ONSHORE PIPELINE R.O.W. INDUSTRIAL PARK BOUNDARY
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
DM
EN
O22
TN PL
74
0005
02U
Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penaltyprovisions of the law.
Page 1 of 7 The below text provides the technical review and support, for the continued operation of the onshore Deep Panuke facility with the removal of beach valve P74‐SDV‐011. The below review confirms that the Deep Panuke onshore facility will remain within both the Project Target Levels of Safety and the applicable land use risk acceptability criteria for Goldboro and the industry accepted ALARP range if the beach valve is removed and that no risk reduction recommendations have been deemed necessary. A previous technical review was conducted to confirm that the Deep Panuke facility could operate safely without a functioning beach valve; that review confirmed that in effect the Projects Target Levels of Safety were not affected by the functionality of the valve given the occupancy of the surrounding areas. Introduction On April 23rd, 2014, an in‐line inspection tool was launched from the PFC and the expected arrival at the gas export pipeline terminus onshore receiver was April 24th, 2014. The tool did not arrive at the onshore receiver and was subsequently confirmed to have stopped at the beach valve assembly. Digital radiography was performed on the excavated pipe section which confirmed that the inline inspection tool was located just upstream of the first 6” tee. Previous problems with beach valve P74‐SDV‐011 had already prompted a review of the Deep Panuke onshore pipeline and functionality of the beach valve actuator and concluded that the function (and hence presence) of the valve did not affect the Project Target Levels of Safety. Further it has been proposed that since the Deep Panuke gas export pipeline is currently considered “Class 1” in accordance with CSA Z662‐11, the isolation valve at the beach valve station is not required per regulation. As the Class 1 designation is contingent on the absence of adjacent industry, it is acknowledged that in the event that future development adjacent to the onshore pipeline occurs which could result in a change in the class of the pipeline, the isolation valve could be reinstated with a similar line isolation methodology to the removal. From a safety perspective the prior review which considered the impact on the Project Target Levels of Safety from an inoperable beach valve P74‐SDV‐011 is very similar to the proposed removal case. As such, this review will look at the Concept Safety Analysis (DMAE‐X00‐RP‐LC‐90.0001.07R ‐ completed by ESR Technology, July 2011) and other relevant project documentation to determine the potential impact to the Project Target Levels of Safety (TLS) from continued operation without the ability to isolate the gas export pipeline at the beach. The approach to this technical review is to take a high level look at the data (typical input parameters which ESR would have used in developing their QRA – leak frequency, isolation, ignition frequency and type, population/occupancy, hazard range/effect, etc…) which form the basis for the individual risk for the onshore project to confirm the relative impact which would be seen from removing the isolation valve and associated assembly at the beach valve location. Note that within the current QRA (Concept
Page 2 of 7 Safety Analysis Section 5 ‐ QUANTITATIVE RISK ASSESSMENT OF ONSHORE RELEASES) there are numerous conservative assumptions which have now been eliminated (due to other adjacent projects being cancelled) and a factor of failure (9%) was already placed on this beach valve. The focus of this review will be the risk to personnel in line with the Concept Safety Analysis identified hazards and in accordance with the Project TLS and land use criteria. Note that the Concept Safety Analysis did look at environmental risk as well but during the hazard identification process no high risks to the environment were identified. Given the noted CSA evaluation of environmental risk and that this is a natural gas pipeline system with no liquids nor hazardous levels of H2S we have not considered environmental risk further in this review. Acceptance Criteria The Target Levels of Safety (TLS) for the Deep Panuke facilities are defined in the Design Memorandum, and are summarized in Table 1.
No. Description Target Level of Safety (freq./year)
1 Individual Risk <1 x 10‐3 2 Group Risk†† (based on 68 POB) <1.36 x 10‐3 (≥ 10 fatalities per year) <2.72 x 10‐4 (≥ 50 fatalities per year) 3 Environmental Risk ALARP 4 Production Facility Impairment (includes TLS for PFC primary structure, TR impairment frequency, escape route and evacuation system) <1 x 10‐3 Loss of integrity to the installation’s key safety functions from all major accident events. <1 x 10‐4 Loss of integrity to the installation’s key safety functions from any single major accident events.
Table 1: Target Levels of Safety
The onshore facilities at Goldboro are also subject to the Major Industrial Accident Council of Canada risk acceptability criteria summarized below in Table 2.
Individual Specific Risk (ISR)
Intolerable > 10‐4 pa
Grey 10‐6 < ISR < 10‐4 pa
Insignificant < 10‐6 pa
Table 2: Land Use Criteria Technical Sensitivity Review
The approach taken in this review is to consider the key components which go into defining the Location Specific Individual Risk (LSIR) and Individual Risk (IR) values and for each one to consider whether the beach valve has any bearing on the assessment and if it does to determine to what extent its removal would affect the contributing risk value.
Page 3 of 7 QRA as being: Immediate ignition leading to a jet fire Delayed ignition leading to either a flash fire or a vapour cloud explosion, burning back to a jet fire. Our focus is the risk to individuals; as such we are looking at the events which would lead to personnel being within the hazard envelope of a flash fire or jet fire heat flux with lethal doses (Note: vapor cloud explosion was considered in the original FEED QRA, this is discounted now and explained below). When considering the event potential from a QRA perspective we would have three starting cases. 1. Event failure (release frequency) with NO ignition. 2. Event failure (release frequency) with immediate ignition. 3. Event failure (release frequency) with delayed ignition.
Note that the distance from surrounding facilities to the beach valve is not the main factor with regards to the risk contours. It is the leak source proximity to the SOEP Gas Plant and M&NP Metering Facility that dictates the risk contour arrangement. The leak source is considered as the base input to
the QRA as being an assumed frequency per unit length for the pipeline section and based on part
counts for the beach valve location and the Terminus (next to the M&NP Metering Facility). As such,
worst case scenarios (rupture) have been assumed at all points along the onshore pipeline section
from the beach valve to the Terminus. The greatest risk to the SOEP Gas Plant facility from the Gas
Export Pipeline (GEP) system would come from the points closest to the SOEP, based on their assumed
likelihood of failure with consequence radii that could impact the SOEP for small, large and rupture
cases. This defines the location specific individual risk and the group risk would then need to account for likelihood of occupancy in that area reaching the levels required to exceed the set group risk criteria.
The QRA risk contours are based on small, large and rupture case events. The risk contours take these entire event cases combined to form the individual risk contours provided within the CSA. If we were to focus on worst case alone, breaking out the individual risk contour for just the rupture case, this would mean we consider only a small portion of the contributing risk to personnel and the risk contour
would reduce. For example, if we look at the risk contours corresponding to the individual risk
considering just the worst case scenario (rupture), they do not cross the existing SOEP Gas Plant
boundary at the levels dictated by our Target Levels of Safety for Individual Risk (<1 x 10‐3), and will
remain compliant with the Land Use Criteria of < 10‐6 pa (per annum) for Individual Specific Risk.
Group risk has not been considered in the original QRA and ESR CSA update as the pipeline and
Page 4 of 7 As mentioned the area is predominantly unmanned and hence detection and action would normally rely on the pipeline leak detection system. The CSA assumed that the pipeline leak detection system was capable of detecting leaks of 2% normal steady flow and greater. Based on the pipeline leak detection system in place the design QRA also assumed that full ruptures would be detected in 5 minutes, 10% leaks in 10 minutes, 5% leaks in 25 minutes and 2% leaks in 50 minutes. As immediate ignition is assumed to occur within 5 minutes and all delayed ignition occurs after 5 minutes, and given that it is considered unlikely that any leak from our system would be detected within 5 minutes, it is assumed that all immediate ignition cases will occur before there would be any remote or manual attempt to close the beach valve if present. The isolated nature of the location and lack of human presence in the immediate surrounding areas further supports this assumption. As such, all immediate ignition cases will happen regardless of whether the beach valve is installed and functioning or not installed and therefore has no impact on whether the beach valve is provided or not. In support of the above statement, it has been considered that without isolation the inventory of the subsea pipeline is greater than the isolated onshore pipeline section and therefore the leak release conditions will decay much slower than a smaller isolated inventory. However, in our assessment we consider all factors of risk including likelihood which addresses the occupancy of the area and the
reaction of personnel, not just the consequence envelope. Additionally for immediate ignition the
impacted area will be at it’s greatest with the highest pressure, at the start of the release. This is the
same for both cases whether isolation is achieved or not – in fact this is the same for a period of 5
minutes in the case of a full rupture which is the time considered by the QRA and CSA for action to be taken to remotely close the beach valve (10 minutes for leaks of 10% volume and 25 minutes for leaks
of 5% volume). As we have immediate ignition we are dealing with jet fire cases only and as per the
QRA and CSA all immediate ignition cases are assumed to occur within 5 minutes. As isolation was not
considered by the QRA to occur within 5 minutes and considering that all immediate ignition cases
occur within 5 minutes, the immediate event would be the same regardless of whether the beach
valve is functional and present or not. The QRA and CSA assume that jet fire cases will result in 100%
fatality at 37.5 kW/m2, 50% fatality at 25 kW/m2, 10% fatality at 12.5 kW/m2 and 1% fatality at 9.5
kW/m2. The only differences in consequence from having an isolating beach valve compared to no
isolation are that the jet fire exposure area will not reduce as quickly. However, it is important to note that the consequence envelope will not increase, we do not consider that people will walk into the jet fire envelope, we have no temporary refuge buildings where we the jet fire could become an issue for trapped personnel, all areas provide relatively free access for escape of any individual that is in the area and not affected by the initial immediate ignition jet fire event. Also note that the QRA and CSA show that immediate ignition events dominate the risk accounting for 78% of the risk profile. As such and as noted the functionality of the beach valve therefore can only have an impact on the remaining 22% of the risk profile (discussed in the next few paragraphs). Following on from the above reasoning if there is no ignition, then there is no consequence and no risk. As such, the only cases where the function of the beach valve could have an impact on our risk levels are the delayed ignition events.
Page 5 of 7 Explosion events were considered in the FEED and design QRA, these were predominantly associated with the potential congestion of the Maple LNG Facility. As neither the Maple LNG Facility nor the Keltic Petrochemical Facility materialized, the explosion events associated with the locations have no relevance to the beach valve removal or not. The CSA did consider within the consequence section that there were potential noted congested areas within the SOEP Gas Plant. The area considered is located at 480 m from the gas export pipeline. The maximum LFL range considered was 550 m for LFL and 834 m for ½ LFL. The QRA considers that these levels are achieved at a leak flow rate of 5240 kg/s which is the maximum instantaneous rupture release case seen. This release rate decays rapidly and the predicted release rate after 2 minutes (un‐isolated as no isolation is assumed to occur before 5 minutes) would have dropped to 63 kg/s as referenced in the QRA. At this flow rate the release case produces a maximum LFL range of 78 m and a maximum ½ LFL range of 137 m. The CSA goes on to state in section 5.3.2 that “Since the initial rupture release rate of 5240 kg/s decays very rapidly and would lead to very pessimistic hazard ranges, it is more reasonable to use the average release rate over the first 2 minutes (879 kg/s in the case of ruptures) when assessing the “immediate” ignition jet fires, whether isolated or not. For the delayed ignition cases, the release rate will depend on whether or not the release is isolated. It is reasonable to consider delayed ignition as taking place after 5 minutes, corresponding to an isolated rupture release rate of 0.7 kg/s. Later ignition would result in even smaller isolated release rates. In the case of un‐isolated, delayed ignition rupture releases, we conservatively use the normal operational flow rate of 74 kg/s, although it is unlikely that normal flow rate could in reality be sustained following a rupture. For unisolated, delayed ignition large and small leaks, we use the release rate after 2 minutes, as compared to after 5 minutes for the isolated, delayed ignition leaks.” Based on the above the CSA and the QRA did not consider the consequence envelope associated with the instantaneous release rate of 5240 kg/s due to the rapid decay and, we assume, inability to sustain the cloud volume. They considered instead a conservative basis for the consequence modelling input to the risk calculation of un‐isolated delayed ignition cases as being based on the continuous volumetric flow rate from the platform. This case would produce an LFL and ½ LFL radii similar to the 63 kg/s case previously noted and are well outside of the 480 m spacing between the GEP and the SOEP congested areas. As such the CSA and QRA did not consider within the risk calculations delayed ignition cases which could have reached the SOEP congested areas. Given that the Maple LNG Facility along with the Keltic Petrochemical Facility did not materialize and as the SOEP facility was considered within the QRA as having no potential for vapour cloud explosion (blast overpressure effects) there are no other congested areas left within the LFL range for the structures present today (tree’s in the area are routinely cleared). This further reduces the events that could be affected by the beach valve removal. This also removes the vast majority of the risk associated with the pipeline failure cases and essentially all of the risks from the beach valve removal as the areas within the range of hazard envelopes predicted by the consequence modelling are now unmanned and restricted access.
Page 6 of 7
The main remaining difference is from an un‐isolated delayed ignition event around the SDV and pig receiver location where a failure to isolate the beach valve will result in a prolonged release rate higher than for the isolated case. Hence the hazard envelope will be slightly larger and when we consider the probability of being exposed to the hazard effect we have a slightly increased area to consider.
Isolation Hole Category Hole Size (m) Release Rate at Ignition
(kg/s) Isolated Small 0.02 0.0352 Un‐isolated Small 0.02 0.39 Isolated Large 0.1 16.2 Un‐isolated Large 0.1 25.2 Isolated Rupture 0.541 0.72 Un‐isolated Rupture 0.541 74.1
Table 3: Onshore Export Pipeline Release Rates for Delayed Ignition Case
Based on the above and the QRA assessment consequence data, jet fire hazard ranges to critical heat flux levels for flow rates of 0.7 kg/s and lower do not generate a lethal heat dose. As such isolation of the beach valve or no isolation of the beach valve will have no impact to the individual risk from small release cases and jet fire hazard events. The same applies to the LFL cases and flash fire events for small leaks. As small leak cases contribute 80% of the leak frequencies overall and 90% for the main SDV and pig receiver location this finding further reduces the impact that the beach valve has on the target levels of safety for the onshore facility. Additionally the hazard envelopes for the large hole categories that equate to the difference in release rate amount to an approximate 20% increase in hazard envelope size. To be conservative we have factored a 100% increase into our assessment over the contributing risk from the large cases. Given the significant difference between flow rates for the rupture case we have considered 100% fatality from the delayed ignition cases – this area is the most noticeable impact from removal of the beach valve but contributes only a small amount to the overall risk for the facility. It should also be mentioned now that there are a very small percentage of leaks which would go undetected and still contribute to the hazard events which would determine the risk for the facility. For these undetected leaks the provision of a beach valve or not has no impact on the event outcomes (as with no detection there is no action to close the valve) and hence would not factor into this comparison. As mentioned above, now that the Maple LNG Facility along with the Keltic Petrochemical Facility have been cancelled the beach valve area and onshore piping section upto the SDV and pig receiver location adjacent to the M&NP Custody Transfer Station has effectively no normal personnel activity or presence and no public exposure (other than intruders for which signage has been posted). As such these two areas contribute very little to the overall individual risk for the Onshore facility which makes the main focus the SDV and pig receiver location where personnel attendance may be required and where the Terminus has its closest proximity to the adjacent M&NP custody transfer station. Further it should be considered that as a result of removing the beach valve and all associated instrument tubing we would be decreasing the overall risk associated with leak sources from that location.
Page 7 of 7 would pessimistically change the LSIR (Location Specific Individual Risk) from 6.1 X 10‐6 per year to approximately 9 X 10‐6 per year. This is an increase in overall location specific individual risk at this location of over 150% and contains a number of conservative assumptions. Such a conservative basis would result in an equivalent IR of 1.8 X 10‐7 per year. This level of individual risk is still well below the widely accepted ALARP level of 1 X 10‐6 per year and would be classified as “insignificant” in accordance with the Major Industrial Accident Council of Canada land use risk acceptability criteria. This level also falls well below the Encana Project Individual Risk (IR) Target Level of safety of <1 x 10‐3. This sensitivity study is based on very conservative assumptions; a more detailed assessment would further reduce the difference between the IR levels seen when comparing the effect of removing the beach valve from the gas export pipeline. This technical review indicates that the removal of the beach valve will not impact the Project Target Levels of Safety or the more stringent land use criteria. Yours Sincerely, Colin Sewell Managing Director 19th June 2014
