# Presentation: 667815

**INDEPENDENT RISK**
**ANALYSIS FOR**
**THE LIBERTY PIPELINE**
**September 2000**
**MMS Contract No. 01-00-RQ-16148**

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Project Objectives

- Overall
- Risk Evaluation for the Liberty Pipeline
- Specific
- Compare four basic pipeline design alternatives
- Better understand the sources of risk and mitigating factors

## Project Scope

- Evaluate risk in 4 designs developed by INTEC

-  no modifications to
-    designs considered

- Steel Pipe-in-HDPE

- Single Wall Steel Pipe

- Steel Pipe-in-Pipe

- Flexible Pipe

## Project Scope

- Risk quantified numerically using:
- Sound engineering techniques
- Reliable data
- Clearly identified engineering judgment
- Risk = Failure Prob. X Consequence
- Pipeline failure defined by oil release event
- Consequence of failure expressed as quantity of oil released
- Risk = expected volume of oil released

## Project Scope

- Analysis fixed parameters
- Life of line = 20 years
- Oil flow rate = 65,000 bbl/day
- Pipeline monitoring & detection
- Fitted with PPA/MPLBC  & LEOS
- Assumed to be operational
- Consider offshore pipeline segment only

## Project Scope - Limits

- Project not intended to consider:
- Pipeline design optimization
- Pipeline cost
- Consequences other than oil release
- Significance of differences in expected oil release volumes (risk)
- Acceptable risk threshold
- Life cycle risk assessment - only service life
- Construction or design uncertainty

## General Approach

- Part 1 – Hazard Analysis
- Establish expected number of pipeline failures
- Identify hazards and their initiating events
- Estimate probability of initiating events
- Calculate pipeline response to initiating events
- Establish pipeline failure criteria
- Calculate probabilities of failure

## General Approach

- Part 1 – Hazard Analysis
- Establish expected number of pipeline failures

## General Approach

- Part 2 – Consequence Analysis
- Establish consequence of failure
- Define oil release event process
- Quantify release rates
- Assess effect of monitoring systems
- Calculate release volume (consequence)

## General Approach

- Part 2 – Consequence Analysis
- Establish consequence of failure

## General Approach

- Part 3 – Risk Assessment
- Calculate & review design alternative risk
- Risk level for each design alternative
- Risk of spills greater than 1000 bbl
- Expected maximum risk
- Sensitivity of risk to:
- Water depth
- Monitoring system performance
- Secondary containment assumptions
- Operational failure assessment
- Failure mode

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Hazard Identification

- Environmental Hazards
- Ice gouging
- Strudel scour
- Permafrost thaw settlement
- Thermal loads
- Operational Hazards
- Third party damage
- Operational events
- Maintenance Hazards
- Corrosion

## Hazard Identification – Ice Gouge

- Ice Gouge
- Created by ice keel grounding

- Risk =
-   RiskZone 1
-   + RiskSingle Pass Zone 2
-   + RiskMulti Pass Zone 2

## Hazard Identification – Ice Gouge

- Ice gouge data from field surveys
- Frequency
- Width & depth stats

**1997 Liberty Site Survey**

**Sonar Image **

## Hazard Identification – Ice Gouge

**Hazard Identification – Ice Gouge**

- Hazard Assessment

- Zone 1

- Prob Contact
- Depthgouge
-      Depthburial

- Zone 2
- - Single Pass

- Zone 2
- - Multi Pass

- Prob multiple
- gouges

- Prob gouge
- depth & width

- Sub-gouge
- soil displ model

- Prob sub-gouge
- soil displ

- Prob gouge
- depth & width

- Sub-gouge
- soil displ model

- Prob sub-gouge
- soil displ

## Hazard Identification – Ice Gouge

- Gouge Depth Probability

## Hazard Identification – Ice Gouge

- Single Gouge – Subgouge Displ.

## Hazard Identification – Ice Gouge

- Multiple Gouge – Depth Probabilities

**Gouge width = 18 ft**

**Depth of first gouge**

## Hazard Identification – Strudel Scour

- Strudel Scour
- Created by surface water drainage

- Risk =
-   RiskUnsupported Pipe
-   + RiskUpheaval Buckling

## Hazard Identification – Strudel Scour

- Strudel scour data from field surveys
- Frequency
- Width & depth stats

## Hazard Identification – Strudel Scour

**Hazard Identification – Strudel Scour**

- Hazard Assessment

- Unsupported
- Span

- Partial Cover

- Prob scour
- depth & width

- Prob of reduced
- pipe cover

- Prob scour
- depth & width

- Prob pipe free
- span width

## Hazard Identification – Strudel Scour

- Pipe Free Span Probability

## Hazard Identification – Strudel Scour

- Pipe Cover Loss Probability

## Hazard Identification – Permafrost Thaw

- Permafrost thaw settlement
- Structures on "thaw-unstable" permafrost may settle if the large amounts of ice are melted

- Risk =
-   RiskUnsupported Span

**Pipe Settlement**

*“**Thaw-unstable”* = Poorly drained, fine grained soils (silt & clay) with large amounts of ice. Thawing can result in strength loss, excessive settlement & soil flow.

## Hazard Identification – Permafrost Thaw

- Permafrost thaw subsidence statistics
- Nixon - analysis has proven to be accurate based on experience with Norman Wells
- ILI capability to monitor settlement
- Use results from Hovey and Farmer
- 0.5 % of total no. of failures
- 0.0003 occurrences over the life of the line

## Hazard Identification – Thermal Loads

- Thermal Loads
- Differences in installation and operating temperatures lock in thermal stress

- Risk =
-   RiskUpheaval buckling

**Service**

**Construction**

**30****o****F**

**150****o****F**

## Hazard Identification – Thermal Loads

- Thermal Load Events
- upheaval buckling can be addressed by backfill during design
- ILI will provide indications on pipe movement
- Use results from Hovey and Farmer
- 0.5% of total no. of failures
- 0.0003 occurrences over life of the line

## Hazard Identification – Op’l Failures

- Operational Failures
- Pumping against a closed valve
- communication problems after maintenance
- remote valves drive to closed pos’n
- vapour columns
- SCADA system failure
- lost communications due to power outages, electrical storms
- operator response , leak detection alarms

## Hazard Identification – Third Party Damage

- Third Party Damage
- Most frequently listed form of damage
- Original construction, maintenance, third party activity in the vicinity of the pipeline
- Contact often results in ruptures, leading to the greatest spill volumes

## Hazard Identification – Maint. Failures

- Pinhole Leaks - not detected by leak detection systems
- Corrosion - Internal or External
- Stress Corrosion Cracking
- Weld Defects - Long Seam or Girth Welds

## Hazard Identification – Failure Statistics

- Failure Statistics - limited applicability of existing databases
- MMS: Gulf of Mexico and nearshore Pacific
- DOT, Concawe: onshore, populated
- Most lines only have 10% of girth welds xrayed
- include lines that cannot be internally inspected

## Hazard Identification – Failure Statistics

- Norman Wells, Alyeska Pipelines - most applicable to Liberty Pipeline
- remote and low population density
- single product lines
- modern technology
- 100% of girth welds inspected
- repair histories available

## Hazard Identification – Failure Statistics

- Limitations of Norman Wells, Alyeska
- onshore pipelines, whereas Liberty is offshore
- Liberty has lower D/t ratio - this would lead to overly conservative failure rates for the Liberty Pipeline

## Hazard Identification – Failure Statistics

**Hazard Identification – Failure Statistics**

**Summary**

## Hazard Identification – Failure Statistics

- TAPS and Norman Wells failure histories were used to establish the combined failure rate due to:
- operational failures
- third party damage
- weld defects
- excluded failures from TAPS, i.e. Exxon Valdez, Atigun pass

## Hazard Identification – Failure Statistics

- TAPS and NW results were scaled, based on the number of miles and years of operation
- TAPS - 800 x 19 = 15,200 mile-years
- NW - 540 x 15 = 12,600 mile-years
- Liberty - 6.12 x 20 = 122 mile-years
- Spill volumes determined for leaks (<100 bbl) and ruptures (>100 bbl)

## Hazard Identification – Failure Statistics

**Hazard Identification – Failure Statistics**

## Hazard Identification – Failure Statistics

- Internal Corrosion
- Alyeska - primarily in dead legs, rates as high as 75 mils/yr
- No corrosion where flow exceeds 3.5 to 4 ft/s
- NW - no repairs for internal corrosion
- Liberty
- 65,000 bpd: 6 ft/s
- 40,000 bpd: 3.5 ft/s
- ILI, inhibitors will be used to mitigate corrosion

## Hazard Identification – Failure Statistics

- External Corrosion - summary of Alyeska corrosion by Vieth et al(1997)
- first ILI high resolution inspections in 1989
- Comparison of results to 1994
- most corrosion < 75 mils, but some pits exceed 200 mils
- worst case assumption 200 mils/12 yr
- Liberty corrosion rates are expected to be less due to improved coatings, CP

## Hazard Identification – Failure Statistics

- Corrosion Failure Frequencies
- considered Concawe results to be most representative for Liberty
- assumed that failures were due primarily to external corrosion
- improved corrosion frequency based upon:
- improved coatings
- comprehensive ILI schedule
- tool improvements

## Hazard Identification – Failure Statistics

- Corrosion failure frequencies (cont’d)
- internal corrosion occurs 20% less than external corrosion
- Highest damage frequencies occur for the pipe in pipe systems, primarily due to:
- damage to external coating of carrier pipe
- inability to monitor external coating of outer pipe

## Hazard Identification – Prevention

**Hazard Identification – Prevention**

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Pipeline Response & Failure Modeling

- Analyze Pipeline Response to Translate Initiating Environmental Events Into Pipeline Response with Limits

## Pipeline Response & Failure Modeling

- Approach:
- Identify response for each hazard
- Develop models to evaluate response over range of inputs
- Identify limit on response initiating failure

## Pipeline Response & Failure Modeling

- Ice Gouge Lateral Displacement
- Displ. controlled model considering:
- Subgouge soil displacement
- Soil and pipe stiffness
- Pipe thermal and pressure loads
- Pipe properties
- Two models developed:
- Single wall pipe (GSC & FTL models)
- Pipe-in-pipe (FTL models)

## Pipeline Response & Failure Modeling

- Single Wall Pipe

**X**

**Y**

**Zone 1 - 44 elements @ 60 ft = 2640 ft**

**Zone 2 - 6 elements @ 40 in = 20 ft**

** ****Zone 3 - 60 elements @ 10 in = 50 ft**

**Zone 1**

**Zone 1**

**Zone 2**

**Zone 2**

**Zone 3**

**GSC & FTL Models**

## Pipeline Response & Failure Modeling

- Single Wall Pipe – Soil & Pipe Displacement

## Pipeline Response & Failure Modeling

- Single Wall Pipe – Axial Force Response

## Pipeline Response & Failure Modeling

- Single Wall Pipe –Response to Soil Displ.

## Pipeline Response & Failure Modeling

**Pipeline Response & Failure Modeling**

- Pipe-in-Pipe

**X**

**Y**

**Zone 1 - 180 elements @ 10 in = 1,800 in**

**Zone 2 - 318 elements @ 120 in = 38,160 in**

**Zone 2**

**Zone 1**

**Inter-Pipe Contact**

**Inner Pipe**

**Outer Pipe**

## Pipeline Response & Failure Modeling

- Pipe-in-Pipe – Soil & Pipe Displacement

## Pipeline Response & Failure Modeling

- Pipe-in-Pipe – Bending & Axial Strain

## Pipeline Response & Failure Modeling

- Pipe-in-Pipe – Response
- Strains < 70% of single wall pipe strains
- More specific behavior required more detailed design data
- Sensitivity analyses demonstrated effect of:
- Pipe diameter
- Spacer separation
- Inner to outer pipe thermal gradient
- Spacer location w.r.t. peak curvature

## Pipeline Response & Failure Modeling

- Strudel Scour Upheaval Buckling Response
- Consider conditions leading to buckling
- Palmer upheaval buckling formulation including
- Pipe properties
- Locked in stress
- Cover depth
- Post-buckled pipe state
- Non-linear FE model

## Pipeline Response & Failure Modeling

- Strudel Scour Upheaval Buckling Occurrence

## Pipeline Response & Failure Modeling

- Strudel Scour Upheaval Buckling Model

**X**

**Y**

**Zone 1 - 44 elements @ 60 ft = 2640 ft**

**Zone 2 - 99 elements @ 80 in = 660 ft**

**Zone 3 - 123 elements @ 10 in = 100 ft**

**Zone 1**

**Zone 2**

**Zone 3**

**Imperfection**

## Pipeline Response & Failure Modeling

- Strudel Scour – Buckled Pipe Displ.

## Pipeline Response & Failure Modeling

- Strudel Scour – Buckled Pipe Response

## Pipeline Response & Failure Modeling

- Pipeline Unsupported Span
- Used to evaluate strudel scour
- Analytic model considering
- Pipe properties
- Settlement depth

## Pipeline Response & Failure Modeling

- Unsupported Span / Settlement - Response

## Pipeline Response & Failure Modeling

- Pipe Material Response Limit
- Critical Strain Level
- Material properties
- Design codes
- Welded pipe bend tests

## Pipeline Response & Failure Modeling

- Pipe Material Response Limit – Material Data

## Pipeline Response & Failure Modeling

- Pipe Material Response Limit – Design Codes

_**Design Code**_
**CSA Z662**
**CSA Z662 - Sec 11**
**CSA Z662 - App. C**
**DNV**
**BSI**
**GL**
** **
**  **
**SAA**
**API**

_**Strain Limit**_
**No Explicit Limit (Elastic Analysis)**
**2.5% Principal Strain**
**0.53% (2.5%)**
**0.2% (2.0%) Plastic Longitudinal Strains**
**0.1% Plastic Equivalent Strain**
**D/t Dependent Longitudinal Strains < 1.0%**
** ****or < 1.5% for controlled deformation**
**or < 2.0% for local discontinuities **
**No Explicit Limit (Elastic Analysis)**
**No Explicit Limit (Elastic Analysis)**

## Pipeline Response & Failure Modeling

- Pipe Material Response Limit – Bend Tests
- Northstar weld integrity tests
- Pressurized pipe with simulated girth weld flaw
- No failure (leakage) at strain of 10.6%
- Japanese straightening of pressurized bent pipes
- Demonstrated capability to sustain 25% strain
- Leakage observed at a strain of about 40%
- University of Alberta eccentric compression
- Pipes develop wrinkles or buckles with strains > 9%
- Plastic strain reversal (load removal)
- Low cycle fatigue, repeated until cracking & leakage
- Three or four post yield cycles to failure

## Pipeline Response & Failure Modeling

- Pipe Material Response Limit
- Single Load Cycle
- 10% Von Mises strain limit
- Reversal of Plastic Strain
- Cumulative Von Mises strain of 15%
- Conservatism of Strain Limit
- Test report test final strain not failure strain
- Test strains are uni-axial while strain limit is equivalent strain
- Sense of the calculated strains are not considered

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Pipeline Failure Mechanisms

- Need to describe pipeline failure mechanism associated with each failure mode to evaluate consequence
- Three failure mechanisms were defined:
- Rupture – separation of the pipeline
- Crack – leakage through crack or flaw
- Pinhole leak - seepage

## Pipeline Failure Mechanisms

**Pipeline Failure Mechanisms**

-      _Hazards_
- Ice gouging
- Strudel scour
- Permafrost thaw
- Thermal loads
- 3rd party damage
- Opn’l events
- Corrosion

-      _Response_
- Lateral Def.
- Buckle/Span
- Span
- Buckle
- Puncture
- Flaw
- Wall Loss

-      _Criteria_
- Strain
- Strain
- Statistics
- Statistics
- Statistics
- Statistics
- Statistics

-      _Mechanism_
- Rupture
- Crack
- Crack
- Crack
- Crack
- Crack
- Pinhole

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Monitoring & Leak Detection Systems

- MBLPC - mass balance line pack compensation
- PPA - pressure point analysis
- these two independent systems are expected to detect:
- large leaks within 30 seconds
- small leaks (> 97.5 bbl/day) within 24 hours
- LEOS - leak detection and location
- detect leaks < 97.5 bbl/day

## Monitoring & Leak Detection Systems

- MBLPC and PPA rely on SCADA information from pipeline system
- reliability and accuracy of SCADA based leak detection depends on:
- false alarms
- accuracy of input information
- polling rates
- difficulties with start-up and shutdown

## Monitoring & Leak Detection Systems

- Mass balance - measures flows in/out of the system and compares the results
- at least 5 minutes between readings are needed to be able to detect a discrepancy of 5% of flow (225 bbl)
- Discrepancies of 100 bbl can be detected over 24 to 48 hours

## Monitoring & Leak Detection Systems

- Pressure point analysis - determines leaks by “looking at the behavior of the pressure or velocity as it transitions from one steady state to another
- Involves the following:
- establish normal operating conditions
- determine if next reading is significantly different, and if it is a leak
- notify operator

## Monitoring & Leak Detection Systems

**Pressure Point Analysis**
**Breach Pressure Fluctuation **

## Monitoring & Leak Detection Systems

- Reviewed literature on PPA to establish the following capabilities:
- Response time:
- 32 sec at < 5% of flow
- 8 sec at > 5% of flow
- Demonstrated sensitivity:
- 0.125% of flow
- can also detect leaks during line shutdown

## Monitoring & Leak Detection Systems

**LEOS Installation**

## Monitoring & Leak Detection Systems

**LEOS Response**

## Monitoring & Leak Detection Systems

- LEOS system performance and field verification testing suggested that performance is affected by:
-  water levels
- clay content
- distance to leak source
- background gases
- Limitations can be addressed in design

## Monitoring & Leak Detection Systems

- LEOS represents best available technology for supplemental monitoring
- expected detection level of 0.3 bbl/day

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Failure Consequence Modeling

- Consequence model developed to calculate the oil volume released in a failure event
- Considers failures:
- detected by PPA/MBLPC system (rupture / crack)
- not detectable by PPA/MBLPC system (pinhole)

## Failure Consequence Modeling

- Model considers parameters affecting oil spill rate & total spill volume:
- Pipeline internal pressure
- oil physical properties
- pipe dimensions
- shape of the opening
- leak detection thresholds
- remedial action delays

## Failure Consequence Modeling

## Failure Consequence Modeling

- Step-wise release model considers:
- Failure mechanism & Repair state to determine
- Leakage rate
- Duration of leakage
- Failure mechanism
- Status of repair

**1**

**2**

**3**

**4**

**Time**

**Total Release Volume**

**1) Line Breach**
**2) Leak Detected**
**3) Remedial Action Taken**
**4) Repair Leak**

## Failure Consequence Modeling

- Leakage Rate Estimation

- Fluid Flow Model

- Oil Properties

- Oil Pressure

- Opening Size

- Release Rate

## Failure Consequence Modeling

- Leakage Rate Estimation
- Opening size is failure mode specific
- Rupture	- pipe cross-section
- Crack  	- largest stable crack
- Pinhole	- corrosion pit or tight crack
- Oil pressure is leakage event specific
- From breach to detection & remedial action
- MOP is assumed
- After remedial action to breach repair
- Static head is assumed

## Failure Consequence Modeling

- Event Durations
- Detection time depends on:
- Monitoring system
- Leakage rate or total volume released
- Reaction time depends on:
- Time to make a decision & initiate action
- Repair time depends on:
- Breach repair time
- Empty the line
- Evacuate the line

**Potential Seepage Volume**

## Failure Consequence Modeling

- Consequence model sensitivity investigation was performed to consider:
- Event durations
- Monitoring system
- Location of breach
- Leakage rates

## Failure Consequence Modeling

- Ice Gouge – Release Volume By Event Step
- Ice gouge event (rupture)

## Liberty Pipeline Risk Assessment

**Liberty Pipeline Risk Assessment**

**Project Scope & Objective Review**

**Hazard Identification & Prob. Calculation**

**Pipeline Response & Failure Modeling**

**Pipeline Failure Mechanisms**

**Failure Consequence Modeling**

**Risk Calculation & Comparison**

**Monitoring & Leak Detection Systems**

## Risk Assessment Results

- Pipeline Failure Modes for the Base Case
- Rupture:
- Ice gouging
- Flow through the maximum stable crack
- Strudel scour
- Major 3rd party & operational failures (> 100 bbls)
- Permafrost thaw subsidence
- Thermal loads
- Seepage:
- Minor 3rd party & operational failures (< 100 bbls)
- Corrosion

## Risk Assessment Results

- Secondary Containment
- Single steel pipe & Flexible pipe – none
- Steel pipe-in-pipe
- Hazards with large displacements (ice gouging, strudel scour, thaw subsidence, thermal loads) – none
- Corrosion & 3rd party & operational failures:
- Case 1 – only inner pipe fails – oil released during repair
- Case 2 – None - inner and outer pipes both fail
- Pipe-in-HDPE
- Hazards with large displacements (ice gouging, strudel scour, thaw subsidence, thermal loads) – none
- Corrosion & minor 3rd party & operational failures (< 100 bbls):
- Only the inner pipe fails – oil released during repair
- Major 3rd party & operational failures (> 100 bbls):
- None - Inner and outer pipes both fail

## Risk Assessment: Base Case Results

- Single Steel Pipe: Total Risk: 28;28 bbls
- Major 3rd Party & Operational Failures: 20;20 bbls
- Minor 3rd Party & Operational Failures: 7;7 bbls
- All other hazards: 1;1 bbl
- Steel pipe-in-pipe: Total Risk: 8;13 bbls
- Major 3rd Party & Operational Failures: 2.4;4.7 bbls
- Minor 3rd Party & Operational Failures: 4.3;7.5 bbls
- All other hazards: 1.3;0.8 bbl

## Risk Assessment: Base Case Results

- Pipe-in-HDPE: Total Risk: 24;24 bbls
- Major 3rd Party & Operational Failures: 20;20 bbls
- Minor 3rd Party & Operational Failures: 3;3 bbls
- All other hazards: 1;1 bbl
- Flexible pipe: Total Risk: 29;28 bbls
- Major 3rd Party & Operational Failures: 20;20 bbls
- Minor 3rd Party & Operational Failures: 7;7 bbls
- All other hazards: 2;1 bbl

## Risk Assessment: Base Case Results

- Pipe Designs:
- Steel pipe-in-pipe has the least risk
- The other 3 designs are equal
- Reason: Effect of secondary containment
- Risk Components
- 3rd party & operational failures are the most significant hazard
- All other hazards are minor
- Main Reason: low prob. of failure associated with all other hazards

## Expected Large Spill Risk

- Objective for Assessing Large Spill Probability:
- Key parameter for environmental risk assessment -Probability of a Spill > 1000 bbls
- Single steel pipe: 1.4*10-2; 1.4*10-2
- Steel pipe-in-pipe: 1.6*10-3; 2.3*10-3
- Steel pipe-in-HDPE: 1.4*10-2; 1.4*10-2
- Flexible pipe: 1.4*10-2; 1.4*10-2

## Risk Assessment: Sensitivity Analyses

- Parameters Investigated
- Ice Gouging – gouge impact rate & subgouge displ.
- Strudel scour – generation rate & width
- 3rd Party & operational failures – occurrence frequency
- Thermal loads - occurrence frequency
- Permafrost thaw subsidence - occurrence frequency
- Corrosion - occurrence frequency
- Water depth – affects consequence
- Pipeline failure mode
- Secondary containment
- Monitoring system performance

## Risk Assessment: Sensitivity Analyses

- Insignificant Parameters
- Ice Gouging – gouge impact rate & subgouge displ.
- Strudel scour – generation rate & width
- Thermal loads - occurrence frequency
- Permafrost thaw subsidence - occurrence frequency
- Corrosion - occurrence frequency

## Risk Assessment: Sensitivity Analyses

- Effect of Worst-Case Water Depth
- Single steel pipe: 35;35 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 9:15 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 31;31 bbls (vs 24;24 bbls)
- Flexible pipe: 35;35 bbls (vs 29;28 bbls)

## Risk Assessment: Sensitivity Analyses

- Effect of Worst-Case Monitoring System Performance
- Single steel pipe: 51;51 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 14;26 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 51;51 bbls (vs 24;24 bbls)
- Flexible pipe: 51;51 bbls (vs 29;28 bbls)

## Risk Assessment: Sensitivity Analyses

- Effect of Presuming That No Secondary Containment is Provided
- Single steel pipe: 28;28 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 28;28 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 28;28 bbls (vs 24;24 bbls)
- Flexible pipe: 29;28 bbls (vs 29;28 bbls)

## Risk Assessment: Sensitivity Analyses

- Effect of Worst-Case Occurrence Frequency for 3rd Party & Operational Failures
- Single steel pipe: 69;69 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 18;22 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 65;65 bbls (vs 24;24 bbls)
- Flexible pipe: 69;69 bbls (vs 29;28 bbls)

## Risk Assessment: Sensitivity Analyses

- Failure Mode: Range of Values for all Ruptures to all Seepage Failures
- Single steel pipe: 9-153;9-153 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 2-39;4-75 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 9-154;9-154 bbls (vs 24;24 bbls)
- Flexible pipe: 9-153;9-153 bbls (vs 29;28 bbls)

## Risk Assessment: Sensitivity Analyses

- Summary Results
- Water Depth – increases risk by 10 to 25 %
- Monitoring System – most significant for the single steel pipe and the flexible pipe
- No secondary containment – most significant for steel pipe-in-pipe
- Worst-Case Occurrence Frequency for 3rd Party & Operational Failures – increases risk greatly (by 2 to 2.5 times) for all designs
- Failure Modes – highly significant for all designs

## Expected Maximum Risk

- Expected Maximum Risk: Objective
- Determine maximum risk for the pipeline as a result of the 5 major risk augmentation factors
- Single steel pipe: 45 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 24 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 44 bbls (vs 24;24 bbls)
- Flexible pipe: 45 bbls (vs 29;28 bbls)

## Conclusions

- Basis for Conclusions
- Evaluate hazards & associated prob. of pipeline failure
- Identify & quantify the hazards
- Analyze the response of the pipeline
- Establish failure criteria
- Determine prob. of failure
- Evaluate consequence of pipeline failure
- Quantify the steps in the oil release process
- Establish the pipeline failure mode for each hazard
- Quantify the effect of the monitoring systems being used
- The risk to the Liberty pipeline
- Evaluate risk for a base case
- Evaluate sensitivities

## Conclusions

- Summary Risk Results for the Base Case
- Single steel pipe: 28; 28 bbls
- Steel pipe-in-pipe: 8:13 bbls
- Steel pipe-in-HDPE: 24;24 bbls
- Flexible Pipe: 29; 28 bbls

## Conclusions: Base Case Analyses

- Effect of Pipe Design
- Steel pipe-in-pipe has the least risk - the other 3 designs are equivalent
- Reason:
- Secondary containment provided by the outer pipe
- Most Significant Hazard
- 3rd party & operational failures pose the greatest risk

## Conclusions: Sensitivity Analyses

- Most Significant Factors
- Performance of the monitoring systems used
- The water depth at which the hazard occurs
- Secondary containment
- Occurrence frequency for 3rd party & operational failures
- Pipeline failure mode
- Insignificant Parameters
- Ice gouge & strudel scour parameters
- Occurrence frequencies for failures due to corrosion, permafrost thaw subsidence & thermal loads

## Conclusions: Maximum Expected Risk

- Risk augmented from base case by:
- Performance of the monitoring systems used
- The water depth at which the hazard occurs
- Secondary containment
- Occurrence frequency for 3rd party & operational failures
- Pipeline failure mode
- Expected Maximum Risks
- Single steel pipe: 45 bbls (vs 28;28 bbls)
- Steel pipe-in-pipe: 24 bbls (vs 8;13 bbls)
- Steel pipe-in-HDPE: 44 bbls (vs 24;24 bbls)
- Flexible pipe: 45 bbls (vs 29;28 bbls)

## Conclusions: Maximum Expected Risk

- Effect On:
- Total Risk:
- Risk increased vs base case for all designs
- By about 1.6 times for the steel single pie, the pipe-in-HDPE, and the flexible pipe
- By about 2-3 times for the steel pipe-in-pipe
- Ranking of the pipe designs with respect to risk:
- No change vs base case
- But the difference in risk between them (% wise) is reduced

## Conclusions

- Probability of a spill exceeding 1000 bbls
- Single steel pipe: 1.4*10-2; 1.4*10-2
- Steel pipe-in-pipe: 1.6*10-3; 2.3*10-3
- Steel pipe-in-HDPE: 1.4*10-2; 1.4*10-2
- Flexible pipe: 1.4*10-2; 1.4*10-2
- Pipe design ranking:
- Lowest probability for the steel pipe-in-pipe
- The other three designs are equivalent
- Reason: secondary containment provided by the steel pipe-in-pipe