CO-OP REFINERY EXPLOSION AND FIRE ON 12-24-2013: a
bypass line froze AND RUPTURED. Once the
air temperature warmed, the petroleum product was released through the line,
resulting in an explosion and subsequent fire.
Regina, Saskatchewan – The Technical Safety Authority of Saskatchewan (“TSASK”) has
finalized its investigation into the December 24, 2013 explosion at the Co-op
Refinery Complex (“CRC”) in Regina.
INCIDENT SUMMARY
On December 24,
2013 at approximately 3:25 pm local time, an explosion occurred in the Polymerization Unit 27 (PMU) at the Co‐op Refinery Complex
(CRC) in Regina, Saskatchewan. The ensuing
fire was extinguished at
approximately 9:00 pm local time on December 24, 2013. The blast and fire
destroyed the equipment
and structure around reactors 1, 2 and 3 in the PMU. The remaining five reactors
in the PMU suffered
blast and post incident freezing
damage, and were rendered
unusable. Blast damage also occurred to CRC
buildings and equipment outside
of the
PMU. Blast effects were also felt at
locations outside the
refinery complex. No personnel
were injured in the incident or
in the subsequent emergency response. Figure 1
shows a partial view of the
explosion from a CRC surveillance
camera. In Figure 1, the PMU is
not within the view of the
surveillance camera, but is located
outside the upper left of the
image.
The investigation
has concluded that a bypass line of Polymerization Unit 27 froze following a
maintenance procedure. The stress of the freezing process ruptured the
bypass pipe. Once the air temperature warmed, the petroleum product
was released through the line, resulting in an explosion and subsequent fire.
The event was not
related to a malfunction of pressure equipment. TSASK’s report from the
investigation has been provided to CRC for action. A copy of the report is
available on the TSASK website at www.tsask.ca.
FINDINGS AND RECOMMENDATIONS
1.
Procedures for cold weather shutdown should be revised to improve
decision making and
the identification of conditions when cold weather shutdown
is permissible and conditions when it is not.
·
Procedures for cold weather shutdown were inadequate, as they did not consider the high
risks posed by extreme
cold.
2.
Procedures for incident investigation should be revised to
ensure that corrective actions are implemented so that incidents do not repeat.
·
A similar
pipe rupture due to freezing
occurred in December, 2008, where the resulting
vapour cloud did not ignite.
Effective corrective actions were not implemented.
3.
CRC should establish a written freeze protection program that includes the identification, mitigation, management
of change and audit requirements
for equipment at risk due
to
freezing.
4. Procedures for water floating should
be revised to ensure that instrumentation and process controls are effective and maintained. Additional redundancy in instrumentation, controls
and verification methods should
be developed.
·
The primary electronic instrument for water
level measurement at the combined feed drum water boot was a Fisher 2500
pneumatic level transmitter. This instrument was found to be defective when tested during the
investigation. Historical data from the instrument was reviewed and
confirmed that the instrument was
defective on November 26, 2013.
·
A sight glass served as a secondary instrument for
the water level measurement in the combined
feed drum water boot. This sight glass was operational,
but was difficult to read because
the appearance of water and poly
feed are nearly identical.
5.
Thawing procedures
should be revised to ensure all areas are addressed systematically,
especially dead legs.
·
Thawing procedures
were inadequate in that they
did not systematically thaw all vulnerable locations. Thawing
relied upon operator
knowledge and memory of
vulnerable locations as opposed
to a documented and systematic
approach.
6.
CRC should adopt the
deadleg definition set out
in the American Petroleum Institute
standard 570 and ensure this definition is
understood across the organization.
·
In the course of the investigation differing interpretations of what constitutes a deadleg
were apparent at CRC.
7. Deadlegs in piping
should be systematically identified, documented
and eliminated or otherwise mitigated wherever possible. Deadlegs
that must remain should be highlighted and given special attention
throughout operations and maintenance activities.
·
The deadleg
on bypass line 123BPL
allowed water to become trapped. This water
subsequently froze and
ruptured the line, causing the
hydrocarbon leak and explosion of December 24, 2013.
8.
Maintenance procedures should be
revised to ensure that critical
sensing and monitoring equipment remains functional.
·
The Fischer
2500 pneumatic level
transmitter at the combined feed drum water boot was
found to be defective.
9.
CRC should systematically identify where installed piping differs from the design
specifications. The differences should be
analyzed and suitably addressed as necessary. CRC should investigate whether corrosion
survey data could be used to identify where piping does not conform to design specifications.
·
Although not a cause
of this incident, in the course
of the investigation bypass
line 123BPL was found to be
2” Schedule 80, while design documents specified this line to be 2” Schedule 160. 2” Schedule 80 has a
wall thickness when new of 0.218”,
whereas 2” Schedule 160 has a
wall thickness when new of 0.344”.
·
Thickness monitoring locations (TML) on
bypass line 123BPL were located at the top elbow and the bottom elbow, both
locations being well
away from the ruptured area. CRC thickness monitoring data
of October
29, 2013 shows a wall thickness of
0.220” at the top elbow and a wall thickness of
0.200” at the bottom elbow.
10.
CRC should revise its corrosion survey procedures to
assess corrosion under insulation
(CUI) on jacketed and insulated components. The corrosion
survey procedures should utilize
methods to identify and assess areas
where corrosion is the greatest.
·
Although not a cause of
this incident, significant exterior corrosion was found
on bypass line 123BPL. Bypass
line 123BPL was jacketed and insulated.
·
Data from thickness monitoring locations (TML) on bypass
line 123BPL did not
detect the exterior
corrosion that was found. The TML’s were not located at the
area where the CUI was found.
·
CUI on bypass line 123BPL resulted in a wall thickness loss of up to 27%.
·
The placement of steam lances
inside insulation jackets for the
purpose of thawing frozen
lines is a common practice at CRC, and this may play a role in CUI.
GLOSSARY OF TERMS AND ABBREVIATIONS
BPD – barrels
per day
Bypass Line 123BPL – The 2” poly feed bypass line located near the north
side of polymerization reactor
#2. This
bypass line diverts poly feed
flow around polymerization reactors #1, 2 and 3. This
bypass line is designated on CRC drawings as 27‐P1070‐FA5A‐2”IH.
CRC ‐ Co‐op Refinery Complex CUI – Corrosion Under Insulation
Deadlegs ‐ Components of a piping system that
normally have no significant flow. Some examples include
blanked branches, lines with normally closed block valves, lines with one end blanked, pressurized dummy
support legs, stagnant
control valve bypass piping, spare pump piping, level bridles, relief
valve inlet and outlet header piping, pump trim
bypass lines, high‐point vents, sample points,
drains, bleeders, and
instrument connections.
FCCU – Fluid
Catalytic Cracking Unit PMU – Polymerization Unit 27
PSIG – Pounds per square inch,
gage. A measure of pressure.
RFPS – Regina Fire
and Protective
Services TML – Thickness Monitoring Location
TSASK – Technical Safety Authority
of Saskatchewan
