Technical Safety Authority of Saskatchewan Executive ... · Technical Safety Authority of...

EXECUTIVE REPORT

CO ‐OP REF INERY COMPLEX INC IDENT DECEMBER 24, 2013

Technical Safety Authority of Saskatchewan Execu ve Report October 2014

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Technical Safety Authority of Saskatchewan

EXECUT IVE REPORT CO ‐OP REF INERY COMPLEX INC IDENT – DECEMBER 24 , 2013

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.

Figure 1: Explosion at 3:25 PM December 24, 2013


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REFINERY DESCRIPTION Located in Regina, Saskatchewan, the Co‐op Refinery Complex (CRC) is a wholly‐owned subsidiary of

Federated Co‐opera ves Limited (FCL) which owns and operates the Co‐op Refinery Complex (CRC)

facili es.

The CRC was incorporated on April 1, 1934, and on May 27, 1935 produc on of 500 barrels of crude oil per

day began. The CRC celebrated its 79th year of opera on in 2014.

CRC Facts and Highlights:

Occupies 575 acres of land in North Regina;

Employs over 800 people on a permanent basis;

Employs and contracts over 1,000 addi onal people during peak maintenance periods and

turnarounds;

A $2.7 billion project to expand and revamp the Co‐op Refinery Complex was completed in 2013;

The expanded CRC currently has a balanced product capacity of 130,000 BPD and poten al for

145,000 BPD;

Approximately 36.5 million barrels of crude were processed in 2013, a 20 per cent increase over

2012 and the largest volume processed in the history of the CRC.

INVESTIGATIVE PROCESS The inves ga on began with emergency response by Regina Fire and Protec ve Services (RFPS) on the day

of December 24, 2013. RFPS secured the scene and began ini al assessments and evidence collec on on

December 25, 2013. The Technical Safety Authority of Saskatchewan (TSASK) ini ated its ini al data

collec on and assessment on December 24, 2013. On January 7, 2014 TSASK and RFPS formed a joint

inves ga on team comprised of members from both organiza ons.

PMU DESCRIPTION The purpose of the PMU is to take light olefins resul ng from the Fluid Cataly c Cracking Unit (FCCU)

process and pass them over a phosphoric acid catalyst inside polymeriza on reactors to produce a higher

molecular weight product called poly gasoline. The PMU reactors operate at approximately 1060 psig

internal pressure at 390°F. The PMU had a total of eight polymeriza on reactors and a dis lla on sec on

for propane, butane, and gasoline separa on. The "front end" of the unit includes an amine treatment

sec on and caus c and water washes to remove contaminants from the feedstock. Figure 2 illustrates the

PMU prior to the incident. The unit is designed to:

1. Collect "poly‐feed", propane, butane, and olefins for charge to the reactors; 2. Treat "poly‐feed" for hydrogen sulfide, mercaptan, and nitrogen compound removal; 3. Process olefins over a catalyst bed to create poly gasoline; 4. Distill and separate out propane, butane, and poly gasoline products.


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OPERATIONS IMMEDIATELY PRECEDING THE EXPLOSION Prior to the incident on December 24, 2013, the PMU was opera ng within normal parameters for flows,

pressures and temperatures. Operators did not observe anything out of the ordinary during process

opera ons that day. The first indica on of a problem in the PMU, as reported by witnesses, was a whistling

noise a number of seconds prior to the explosion. Instrumenta on for poly feed flow to reactors #1 and #3

in the PMU recorded bad data quality signals 16 seconds prior to the appearance of the explosion on a

surveillance camera. The bad data quality signals were caused by the escape of poly feed from a rupture in

the piping in the PMU.

Figure 2: Polymeriza on Unit 27 (PMU) Before


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INCIDENT ANALYSIS

Preceding Maintenance Outages

In the weeks before the December 24, 2013 incident, there were two PMU maintenance outages, as

follows:

Outage 1: The PMU was shut down between November 26, 2013 and December 4, 2013 due to a

maintenance outage on the upstream fluid cataly c cracking unit (FCCU). Since this resulted in

shutdown of the poly feed from the FCCU to the PMU, opportunity was taken to perform

maintenance in the PMU. A number of maintenance items in the PMU were iden fied and

completed.

Outage 2: The PMU was shut down between December 12, 2013 and December 18, 2013 due to

another maintenance outage on the upstream FCCU. This outage again resulted in shutdown of

feed from the FCCU to the PMU, although there was no maintenance performed in the PMU during

this outage.

Outage 1: November 26, 2013 – December 4, 2013

In order to prepare the FCCU for the maintenance ac vi es during outage 1, a water floa ng procedure

was used to purge hydrocarbons from the FCCU piping and vessels. Water floa ng had historically been

used for the purpose of purging hydrocarbons. Water floa ng is a process that u lizes water to flush

hydrocarbon residue from the system and render the piping and vessels free of explosive hydrocarbons and

safe for work. The intent was for the water floa ng procedure to introduce water up to the water boot on

the combined feed drum, which is located upstream of the PMU reactors. It was intended that

instrumenta on and a sight glass on the water boot of the combined feed drum would be used to detect

the water level to enable the introduc on of water to be properly stopped at that point. The combined

feed drum was located upstream of the PMU reactors, and limi ng the water at the combined feed drum

water boot would preclude any water from reaching the PMU reactors.

During outage 1, the water floa ng procedure was ini ated during the night shi of November 26, 2013, as

planned, but the process failed to stop the water at the combined feed drum water boot. The

instrumenta on at the water boot was defec ve and the sight glass was difficult to read. Water was

pumped past the combined feed drum and into the PMU piping and reactors. The pumping of water into

the PMU piping and reactors was not intended. The shutdown guidelines for both outages specified that

the polymeriza on reactors were to be purged with nitrogen gas as they were taken offline. Figure 3

illustrates the planned and es mated actual extent of water floa ng, as well as a schema c representa on

of a poly feed bypass line.

Maintenance personnel began draining water from the PMU on November 27, 2013, however, issues with

freezing water were encountered as this process was undertaken, especially as temperatures dropped at

night. Water draining and ice thawing ac vi es con nued through the remainder of outage 1. Thawing


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methods included the wrapping of steam trace lines around process lines, as well as the inser on of steam

lances into piping insula on jackets.

During outage 1, outdoor temperatures dropped considerably toward the end of the outage, as can be seen

in the meline and temperature data shown in Figure 4.

Figure 3: Water Floa ng Extent


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Nov. 26, 2013

Outage 1 begins.

Maintenance work in FCCU and PMU is performed during this outage.

Water floating procedure done on night of Nov. 26 accidentally introduces water into the PMU including bypass line 123BPL.

Dec. 5, 2013

Operations resume. Numerous frozen lines in the PMU require thawing. Bypass line 123BPL was found frozen and was thought to have been thawed.

Dec. 24, 2013

Operations are within normal parameters with no indication of a problem.

Rapidly rising temperatures cause the ice plug in bypass line 123BPL to thaw and allow high pressure poly feed to escape from the rupture in the bypass line.

The hydrocarbons ignite causing an explosion in the PMU.

Dec. 19, 2013

Operations resume and are within normal parameters during Dec. 19 – 23 with no indication of a problem.

At some point, ice formation in bypass line 123BPL causes the bypass line to rupture.

An ice plug remains inside bypass line 123BPL, preventing the escape of poly feed Dec. 12, 2013

Outage 2 begins.

Maintenance done to pressure relief valve in FCCU resulting in feed outage to the PMU.

Water floating not done in this outage.

Dec. 23, 2013

The coldest temperatures during the period Nov. 26 – Dec. 24 are reached during the early morning hours of Dec. 23.

Figure 4: Timeline of Events – November to December, 2013


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Unit Operation December 5, 2013 – December 11, 2013

As the FCCU and PMU were gradually brought back to opera on a er outage 1, many frozen process lines

con nued to be found and required thawing in order to make progress. The PMU reactor inlets and outlets

were found frozen. The reactor feed bypass line 123BPL was also found frozen. Gradually, process lines

were thawed and unit opera on was achieved by December 6, 2013.

Reactor feed bypass line 123BPL, located adjacent to PMU reactor 2, is a part of the PMU and serves to

divert feedstock flow around PMU reactors 1, 2 and 3 when flow through the reactors is not needed. Flow

through reactor feed bypass line 123BPL was not necessary during the start up and opera on of the PMU,

and this line is normally closed during PMU opera on. Bypass line 123BPL, shown in Figure 5, forms a

natural deadleg when the block valves located at the bo om of the line are closed. Deadlegs are

components of a piping system that normally have no significant flow. Deadlegs can accumulate water and

freeze more readily than piping that is open to flow. Deadlegs frequently require greater a en on when

thawing and draining in order to achieve complete clearing. Operators were under the belief that they had

thawed and drained bypass line 123BPL during their efforts to achieve unit opera on. The thawing and

draining of the frozen lines was not systema c and documented, but relied on operator exper se and

memory. The inves ga on determined that bypass line 123BPL, in fact, was not properly drained of water.

During the period of opera on from December 5, 2013 to December 11, 2013 temperatures were cold

throughout as can be seen in the meline and temperature data shown in Figure 4.

Outage 2: December 12 ‐ December 18, 2013

The purpose of outage 2 was to repair a failed pressure relief valve in the FCCU, again resul ng in shutdown

of the PMU due to an interrup on of feed from the FCCU. During this outage, procedures were revised in

order to mi gate the freezing issues experienced during outage 1, and water floa ng did not impact the

PMU reactors and piping. Addi onally, no maintenance ac vi es were performed in the PMU. The

shutdown and subsequent startup a er outage 2 went rela vely smoothly, with no addi onal freezing

issues.

The inves ga on determined that the bypass line 123BPL likely remained filled with water through outage

2.

During outage 2, temperatures warmed up considerably, peaking at 0° C on December 16, 2013, and then

dropped drama cally to a sta c low of ‐24° C with a wind chill low of ‐34° C at the end of outage 2 on

December 18, 2013, as shown in Figure 1.


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Figure 5: Ruptured Bypass Line 123BPL


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Unit Opera on December 19, 2013 – December 24, 2013

There were no freezing issues that affected unit startup and opera on during December 19 to 24, 2013.

The PMU func oned within normal parameters for pressures, temperatures and flows during this period.

Operators were not aware of any process problems that could lead to a component failure during this

period.

Outdoor temperatures were very cold from December 19, 2013 to December 21, 2013. Beginning on

December 22 and con nuing into December 23 outdoor temperatures dropped drama cally to a sta c low

of ‐35° C at 2:00 AM on December 23 and a wind chill low of ‐47° C at 6:00 AM on December 23. These

were, in fact, the coldest temperatures since the water floa ng procedure of November 26, 2013.

The bypass line 123BPL deadleg contained water throughout the cold weather that occurred between

November 26, 2013 and December 24, 2013. Water in the line froze and ruptured the line due to

hydrosta c overstress at some point during this period. An ice plug existed within the line and created a

seal which prevented the escape of highly vola le poly feed through the pipe rupture.

Beginning at 6:00 AM on December 23, 2013 the temperature began to rise drama cally, peaking at ‐2° C at

2:00 PM on December 24, 2013.

On December 24, 2013 unit opera ons were within normal parameters. Due to the Christmas holiday, a

number of opera ons staff had le early that day, resul ng in much fewer than normal personnel around

the PMU as the day progressed.

As outdoor temperatures warmed, combined with heat from unit opera ons, the ice plug in bypass line

123BPL thawed and eventually gave way to the high pressure poly feed. At 3:25 PM this caused a sudden

release of hydrocarbons into the PMU, followed by a large explosion and ensuing fire. The explosion and

fire were centred on PMU reactors 2 and 3, resul ng in extensive damage to the PMU structure around

reactors 1, 2, 3. The explosion caused blast damage to other areas of the PMU as well as to surrounding

buildings in other units. The blast was felt in areas of Regina well outside the refinery complex.

Figure 5 shows the ruptured bypass line 123BPL a er the incident. Figure 6 shows the extent of damage to

the PMU.


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Figure 6: Damage to the PMU


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FINDINGS AND RECOMMENDATIONS 1. Procedures for cold weather shutdown should be revised to improve decision making and the

iden fica on of condi ons when cold weather shutdown is permissible and condi ons 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 inves ga on should be revised to ensure that correc ve ac ons are

implemented so that incidents do not repeat.

A similar pipe rupture due to freezing occurred in December, 2008, where the resul ng vapour

cloud did not ignite. Effec ve correc ve ac ons were not implemented.

3. CRC should establish a wri en freeze protec on program that includes the iden fica on,

mi ga on, management of change and audit requirements for equipment at risk due to freezing.

4. Procedures for water floa ng should be revised to ensure that instrumenta on and process

controls are effec ve and maintained. Addi onal redundancy in instrumenta on, controls and

verifica on methods should be developed.

The primary electronic instrument for water level measurement at the combined feed drum

water boot was a Fisher 2500 pneuma c level transmi er. This instrument was found to be

defec ve when tested during the inves ga on. Historical data from the instrument was

reviewed and confirmed that the instrument was defec ve 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 opera onal, but was difficult to read

because the appearance of water and poly feed are nearly iden cal.

5. Thawing procedures should be revised to ensure all areas are addressed systema cally, especially

dead legs.

Thawing procedures were inadequate in that they did not systema cally thaw all vulnerable

loca ons. Thawing relied upon operator knowledge and memory of vulnerable loca ons as

opposed to a documented and systema c approach.

6. CRC should adopt the deadleg defini on set out in the American Petroleum Ins tute standard 570

and ensure this defini on is understood across the organiza on.

In the course of the inves ga on differing interpreta ons of what cons tutes a deadleg were

apparent at CRC.


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7. Deadlegs in piping should be systema cally iden fied, documented and eliminated or otherwise

mi gated wherever possible. Deadlegs that must remain should be highlighted and given special

a en on throughout opera ons and maintenance ac vi es.

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 cri cal sensing and monitoring

equipment remains func onal.

The Fischer 2500 pneuma c level transmi er at the combined feed drum water boot was

found to be defec ve.

9. CRC should systema cally iden fy where installed piping differs from the design specifica ons. The

differences should be analyzed and suitably addressed as necessary. CRC should inves gate

whether corrosion survey data could be used to iden fy where piping does not conform to design

specifica ons.

Although not a cause of this incident, in the course of the inves ga on 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 loca ons (TML) on bypass line 123BPL were located at the top elbow and

the bo om elbow, both loca ons 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 bo om elbow.

10. CRC should revise its corrosion survey procedures to assess corrosion under insula on (CUI) on

jacketed and insulated components. The corrosion survey procedures should u lize methods to

iden fy 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 loca ons (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 insula on jackets for the purpose of thawing frozen lines

is a common prac ce at CRC, and this may play a role in CUI.


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GLOSSARY OF TERMS AND ABBREVIATIONS

BPD – barrels per day

Bypass Line 123BPL – The 2” poly feed bypass line located near the north side of polymeriza on reactor

#2. This bypass line diverts poly feed flow around polymeriza on 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 Insula on

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 connec ons. FCCU – Fluid Cataly c Cracking Unit PMU – Polymeriza on Unit 27

PSIG – Pounds per square inch, gage. A measure of pressure.

RFPS – Regina Fire and Protec ve Services

TML – Thickness Monitoring Loca on

TSASK – Technical Safety Authority of Saskatchewan

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