1. Wet Gas Gathering Pipeline Failure – Internal Corrosion
Application of Root-Cause Analysis to Determine Cause(s)
Quick-and-Easy Template

2. Root Cause Event Tree - Wet-Gas Gathering
SITUATION
Wet sour-gas gathering pipeline leak
internal corrosion
Failure at 9-months after start-up
10-times faster than maximum calculated corrosion rate (deWaard & Milliams)
Actual corrosion distribution pattern different than predicted
Internal corrosion damage limited to initial 100 metres of pipeline
No corrosion defects after 100 metres (2.5 km of pipeline with no defects)
Corrosion expected to be distributed within isolated regions along pipeline where stagnant water trap can form, and subsequent reduction of local pH
EVIDENCE
UWI Severity Score 0.98 (max 1.0)
Aggressive pitting along pipeline for initial 100 metres
Pitting along entire length of damaged pipe
Pigging pattern is not expected distribution
Pitting rate is 10-times higher than maximum calculated corrosion rate

3. Root Cause Event Tree - Wet-Gas Gathering
Conclusions from Root-Cause Investigation
SUSCEPTIBLE MATERIAL
ACTUAL CORROSIVE CONDITION NOT PROPERLY CHARACTERIZED
Detrimental fluid flow
Corrosive material remained stagnant in the pipeline
Corrosive fluids accelerated corrosion rate
Actual corrosion rate 10-times anticipated
Highly corrosive fluids entered the pipeline at well-start-up
UWI Severity Index for the well is within top 98 percentile in AB
CORROSION NOT DETECTED PRIOR TO FAILURE
Monitoring & Inspection Plan did Not Detect Corrosion Activity Prior to Leak
MITIGATION PROGRAM NOT EFFECTIVE FOR THE CONDITIONS
Mitigation standards not effective
Mitigation application not effective

4. Wet-Gas Gathering Pipeline Leak
Root Cause Event Tree - Wet-Gas Gathering
EVENT =
Wet-Gas Gathering Pipeline Leak OR
Thermal Stress
Corrosion
3rd Party Damage
Weld Failure
Construction
Operator Error
Other OR
Internal
External
Third Party Assessment Confirms Internal Corrosion
Additional Information Required
No Data to Support
TO PAGE 2
Evidence
PAGE 1

5. Corrosion Not Detected
FROM PAGE 1
Root Cause Event Tree - Wet-Gas Gathering
Corrosion - Internal
AND (All Conditions Must Exist for Leak to Occur)
Susceptible Material
Corrosive Fluids
Detrimental Flow
Active Corrosion
Corrosion Not Detected
TO PAGE 3
TO PAGE 4
TO PAGE 5
Monitoring & Inspection Plan
did Not Detect Corrosion
Activity Prior to Leak
Bare Carbon Steel
Construction Material
Direct Contributor
No Data to Support
Evidence
PAGE 2

6. Root Cause Event Tree - Wet-Gas Gathering
FROM PAGE 2
Corrosive Fluids OR
Produced Water from Upstream Production Source(s)
Glycol / Water Carry-Over from Upstream Processing Facility
AND
CO2 Partial Pressure = 96 kPa
H2S Partial Pressure = 542 kPa
Temperature = 22 C
Chloride = 90,000 mg/l
Not applicable – source of production into
the pipeline is from primary producing well
with single UWI 00/ W6M
deWaard & Milliams Indicates Maximum
Unmitigated CO2 Pitting 8 years
and an adjusted Pigging 16 years
attributed to formation of protective iron sulphide
Direct Contributor
Additional Information Required
Evidence
PAGE 3

7. Root Cause Event Tree - Wet-Gas Gathering
FROM PAGE 2
Detrimental Flow
Observation of pitting within initial 100 m of pipeline suggests accumulation of detrimental fluids / solids on the bottom-of-pipeline.
Pitting pattern suggests direct contact of the bottom-of-pipeline with highly corrosive fluids occurred – protective iron sulphide scale is not intact, was not permitted to be repaired, and
Pitting rate penetrated the pipeline within 9-months of operations vs expected 8 years (or 16 years with consideration of beneficial iron sulphide scale).
Actual corrosion rate is 10-times predicted CO2 corrosion rate and 20-times predicted corrosion rate with adjustment for H2S:CO2 protective scale.
Direct Contributor
Evidence
PAGE 4

8. Root Cause Event Tree - Wet-Gas Gathering
FROM PAGE 2
Root Cause Event Tree - Wet-Gas Gathering
Active Corrosion OR
Corrosion at Expected Corrosion Rate
Corrosion at Elevated Corrosion Rate
AND
Protective Film Does not Exist
A Corrosion Rate Accelerator is Introduced OR OR
Oxygen
Bacteria
Detrimental
Well Fluids
Ineffective Mitigation
Non-Protective Scale OR
No Inhibitor
Inappropriate
Inhibitor
Ineffective Inhibitor
Standards
Corrosion pitting morphology is consistent with ingress of detrimental fluids from upstream well.
Upstream UWI score is within the top 0.99 percentile of 350,00 UWI events with respect to expected contribution to internal corrosion of downstream pipelines.
Continuous inhibitor, batch inhibitor,
routine pigging performed
Batch inhibitor application method and/or frequency not sufficient to avoid pitting initiation
Batch inhibitor application not sufficient to stop growth of active corrosion
TO PAGE 6
PAGE 5

9. Environment Promotes Protective Scale
FROM PAGE 5
Root Cause Event Tree - Wet-Gas Gathering
Non-Protective Scale OR
Environment Promotes Protective Scale
Inappropriate Environment for Scale Formation
AND
Scale was Disrupted
Scale was not
Allowed to Repair OR
Actual observation of pitting pattern
confirms repair of disrupted iron sulphide film
did not occur.
High chloride levels competed with inhibitor within active pits preventing self-repair
Chemical
Mechanical
Acid Jobs
Dry Pigging
Inspection Tools
Improper
Suspension
Detrimental Flow Conditions
& Settling of Solids
Polysulphides
Direct Contributor
No Data to Support
Pitting location and morphology suggests the culprit fluids were not produced during steady-state operation, otherwise they would not impact the pipeline. The propensity of the pigging towards the initial 100 metres of pipeline length suggests highly corrosive material were deposited into the pipeline during non-steady-state well operation, and it is likely these fluids were extremely low pH based upon the pitting pattern, and high-rate pitting attack rate. UWI performance score supports extreme likelihood of harming downstream pipelines.
Evidence
PAGE 6