Solutions to X Refinery Problems - Case Study Example

Table of Contents 1.0.Solutions to X Refinery Problems 1 1.1.Engineering solutions to failure path followed by X 2 1.1.1.Integration of Process Hazard Analysis 2 1.1.2.Elimination of Hazards 5 1.1.3.Controlling Freezing Temperatures 8 1.1.4.Fireproofing 10 1.1.5.Emergency Isolation and Shutdown 15 1.1.6.Adoption of Inherently Safer Alternatives 19 1.1.7.Process Hazard Analysis (PHA) 20 1.1.8.Regulatory Analysis 22 2.0.References 22 1.0. Solutions to X Refinery Problems It was noted in the earlier submission that engineers responsible for projects have contribution to the minimization of failures projects can be subjected to. The submission through critical analyses of issues at hand suggested significant ways engineers can contribute in the minimization of the identified failures. In the subsequent submission, the project outlined a case study on X as a refinery industry by also assessing factors that were behind its ultimate failure. Though the analyses recognized that the X had regular checks on most of its machines in particular and the plant in general, there were recognized errors committed by engineers that also contributed towards the ultimate failure. For instance, units such as pumps, towers, boilers and filters were shut down for a period of one month because engineers wanted to engage them in repairs and maintenance. According to the Refinery’s mission statement, such shut-downs were targeted for general maintenance thus extending life spans of the entire plant and also all related equipment and machines. This was indicators according to the previous submission that in as much as engineers contributed immensely for the sustenance of the project, there were identified errors and omission that led to the shut-down of the plant. This is the point of departure in this report; critically provide solutions, in this case, engineering related solutions that ought to have done to the project to avoid the failures that was witnessed. To provide the linkage with the latest works submitted, this assessment will review failures highlighted previously vis-à-vis the engaged engineers as sub-contractors for doing the periodic maintenance. Subsequently, the case study will link the earlier discussed hypotheses, theoretical frameworks and approaches to project failure minimization will be linked. 1.1. Engineering solutions to failure path followed by X 1.1.1. Integration of Process Hazard Analysis As noted, the main problem started from the piping known as 4-sidecut/number 4 Crude Unit; one of the existing process streams within x. A plot plan shows that the sub-contracted engineers failed to notice the corrosion in the pipe. Additionally, it was recognized that the first problem related to this rupture was failure by the sub-contracted engineers to notice suldification corrosion in the pipe. The first solution for this problem is that engineers did not recognize or address dead-leg. To be specific, piping and instrumentation (PID) drawing update project for propane deasphalting (PDA) unit that was completed in 2006 only identified dead-logs that were visually apparent especially one formed when a control valve shown in figure 1 of the previous work (also shown below as figure 1) was physically removed and its flanged connections slip-blinded. However, the best solution that engineers ought to have done was to ensure that piping and instrumentation detect the propane mix control station dead-leg which according to Layer of Protection Analysis (2013) report was formed by closing block valves in the piping that finally ruptured as per the figure below. Figure1: Rupture on 4-sidecut The above suggested solution also conforms to a Process Hazard Analysis (PHA) that was performed on the PDA unit by Center for Chemical Process Safety (2013). The analysis examined that freezing was a threat to piping integrity since it was made in a manner that piping and instrumentation did not detect the propane mix control station dead-leg. Furthermore, had the engineers implement the McKee Refinery freeze protection programme as suggested to them before beginning their routine check then the rupture as shown above could have been averted. This is not the only problem with refinery industries; this assessment can attribute the problem as noticed in figure 1 to Saint Mary's Refining Company when engineers failed to notice and act on sulfidation corrosion. The same problem led to complete shut-down on their plant. Had the engineers followed Process Hazard Analysis on the PDA unit they would have noticed corrosion in the carbon steel piping that was having low levels of silicon. To conclude on this solution, one thing is apparent from the figure 1 above, and that is there was corrosion that was neglected by the servicing engineers prior to the shut-down. The best solution that is also related to the Process Hazard Analysis is that there are guidelines provided by American Petroleum Institute offers providing for guidelines for avoiding sulfidation (sulfidic) corrosion failures in oil refineries. This when well followed, is a solution to cases of sulfidation corrosion as seen. 1.1.2. Elimination of Hazards Secondly, when engineers are summoned to carryout analyses of refinery in this case X, one of the basic practices that should not be ignored is the aspect of reliability, unreliability, availability or unavailability. This analysis will not highlight these concepts as they were detailed in the last two submissions. Instead, this section provides solutions to the aspects of reliability, unreliability, availability or unavailability that were ignored. Still referring to the figure 1 above, the plant was unreliable since it had experienced or by the time of maintenance, experienced the first failure or had failed in one or several occasions which could be inferred in terms of time interval zero time to time (t) assuming that the maintenance given to it repaired it to a like a new condition at time zero. Based on the tenets of reliability, unreliability, availability or unavailability that was apparently ignored by the engineers, the solution to these problems is to carry out inherently safer approach. Going by safety guidance as postulated by Center for Chemical Process Safety (CCPS), the best way engineers was to control problems as seen in figure 1 and subsequently promote reliability, unreliability, availability or unavailability was to eliminate hazards where possible. Additionally, the best way of minimizing corroded parts of plants especially ones such as propane mix control is to remove them completely. However, in the instances where removing them become difficult, other approaches such as decreasing protective value could be the best way. The figure below could help understand why inherently safer approach was a solution to the plant. Figure 2: Damaged Propane inlet on extractor No. 1 The figure 2 above according to Kletz et al. (2010) was taken prior to the shut-down the refinery. Basically, it is apparent from the figure that inherently safer approach as a solution to the above problem ought to have considered three approaches; first, positively isolating the dead-leg by doing the installation of slip blinds. Secondly, freeze-protecting the corroded regions and lastly, developing procedures to constantly monitor and drain water that the report from Kletz et al. (2010) indicated as being from low points. The connectedness of the solution as suggested with the aspect of reliability, unreliability, availability or unavailability is that reliability for instance, allows the comparison of unavailability and unreliability values rather than availability and reliability of the materials as the image shows. In addition, the numerical values of both the unavailability and availability are shown as probability from 0-1 and no units of which is engineers discover that the plant depicts what is shown above then probability from 0-1 cannot be given by plants thus a need for inherently safer approach or removal of the hazard all together. Considering this prior to the rupture, the tube was either operating or not operating; the above statement is conceptualized using the expression below: A (t) + Q (t) = 1….equation (2). Unavailability Q (t) ≤ Unreliability F (t). For a non-repairable component or tube: Unreliability F (t) = Unavailability Q (t). These expressions further conceptualise the need for safer approach thus providing a solution to the problems. While this stands to be the case, there is an essential issue with the refinery that must be highlighted. That is, engineers failed to follow what were inherently safer systems. Inherently safer materials and technologies are relative. While the first group of the sub-contracted engineers described materials they introduced while doing their maintenance as inherently safer, it seems the materials used did not consider specific hazard and or risk. This is the reason why it is essential to check on reliability and its connectedness with inherently safety approaches and so is the reason why it has become part of solutions to the identified problems as per the Centre for Chemical Process Safety. To explain on this, the Centtre has come up with “a near miss.” According to the Centre, this is an extraordinary event that is able to lead to reasonably unexpected negative result but was actually mitigated (U.S. Environmental Protection Agency, 2014). 1.1.3. Controlling Freezing Temperatures The third solution that X needed to avert the aftermath shutting in some of its components has relevant connection with programmes introduced in McKee Refinery. X is located in area where there are below-freezing temperatures between the months on February and April. In so doing, engineers should protect piping and other related equipment from freezing during such periods. According to U.S. Environmental Protection Agency (2014), such protections should be done by insulating and tracing the pipes and the equipment with steam-filled tubing or where necessary electric heat tape. Therefore engineers who carried out inspection erred in reviewing and repairing freeze protection components instead of insulating cracks that were already eminent. To understand how insulation of some areas of the pipe is indeed a solution to what was witnessed; figure 2 below has been introduced. Figure 3: Temperature damaged coating on sphere and location of sphere deluge valves Going by the figure, there is relative thickness of low silicon piping appearing deluge valve location and extractors. On the other hand, there is high silicon piping on the damaged coating. However, the report suggested that divulge valve location was not fully insulated and had only 0.01% of silicon. In as much, there is 0.16% of silicon at the upstream elbow. Basically, this is not the recommended thickness of the piping especially when engineers are already aware of the changes in temperature. What these engineers failed to do with regard to these materials was application of simple calculation of failure rates of tubes and conductor materials thus proceeding to insulate appropriately. As noted in the literature review, one method of determining rate of failure is to use accelerated high temperature operating life tests that can be performed on the tubes. Therefore, a simple rate of failure calculation basing on figure 2 above would follow the equation below: λ∞1/TDH*AF. Where THD is the total device hours, AF acceleration factor (the AF allows extrapolation of failure rates from accelerated test conditions to use conditions and λ is the failure rate. Proceeding to insulate will give the engineers, based on the rate of failure obtained above, the duration the valve ought to have taken before in failure is realized. While discussing this, it was noted from the report that inspection programme concentrated only on long-term corrosion issues but ignoring acute freeze hazards (U.S. Environmental Protection Agency, 2014). In related incidences, there was a brochure, Understanding the Hazard: Freeze released by FM Global (ASTM Standard, 2013) that cited 150 freeze incidences in refinery industries with average estimated gross loss and or ultimate shut-down of the plant which cost about $120,000 per incident from 1995 to 2006. To cite examples in connection to this argument, in January 1996, Total Petroleum, Denver, CO experienced freezing as a result of temperatures below the normal operations. The abandoned pump gland oil piping under process pressure froze and burst slighted above a vacuum bottom pump causing a fire and ultimate shut of the refinery. When the plant was revived, insulations were done on the deluge valves. This was also the same case with Bethlehem Steel, Burns Harbour that froze in 2001, Chevron, Pascagoula, MS where a freeze related fire was reported in January 2008 and ultimately controlled through insulations. Freeze protection through insulation is one of the best solutions in this case since it is both a mechanical integrity as well as operational issue which require integrated approach to be implemented. Other than the solution that this analysis offers with regard to incidences of freezing, what X requires is the guideline from FM Global’s Freeze brochure guidelines that gives full description and guidelines on how to avoid such risks. To be specific, the guideline provides that there should be periodic engineering evaluation of susceptible piping systems within the refinery with particular interest for the pipes and valves in the areas where sudden changes in temperature affect there sustainability. 1.1.4. Fireproofing Beginning from case studies witnessed, non-fireproofed structural pipes spanning a 100-foot wide open area of Chevron, Pascagoula Refinery collapsed thereby increasing the magnitude of the fire within the plant. This was the same case with X refinery. Figure 3 below has been incorporated to necessitate the argument. The support according to the figure 3 below was located on major E-W pipe racks which were also outside the fireproofing distances that were recommended by American Petroleum Institute (API) guidance as well as engineering recommended standards. The collapse of the pipes shown in figure 3 below brought about multiple lines that carried combustible and flammable materials from other areas of the refinery thus contributing significantly to the damage that was experienced by the units that were adjacent to like the figures 2 and 3 above. These damages further complicated time the refinery was down for repairs. Figure 4: Pipe Bridge without Fireproofing Support Additionally, after plant shut-down, a naphtha hydrotreater unit (located on the pipe rack support that was not fireproofed) was found to be cracked extensively. This was also attributed to the cub-contracted engineers doing maintenance. Upon further examination, there were initial transverse cracks from unit. However, what these engineers did was to fail to fireproof surfaces of this unit with at least a fairly thick powdery deposit to prevent significant cracks. An intergranular failure was also noticed in the unit; something the engineers failed to notice prior the shut-down. This is the point where we can apply the aspect of reliability engineering with regard to the Weibull Distribution and fireproofing being the ultimate solution. It is from this perspective that the best solution is for engineers to engage in fireproofing. Fireproofing is a passive defense that is able to maintain the integrity of protected structures until a fire is controlled. When applied to structures as the ones identified in figure 4 above the chances of a plant shut-down is equally minimized. According to Guidelines for Avoiding Sulfidation (2009), the main reason why fireproofing is essential for minimization of refinery structures is to control the extent of fire a given point. It is on this basis that the assessment advices that fireproofing be directed at shutting down therefore isolating fuel supplies that may be channeled to the fire thus also enabling evacuation of persons in events of fire. Subsequently, this assessment also recognizes the fact that there were elements of fireproofing done to some of the tubes and metal but such did not conform to the requirements as per API publications that engineers ought to follow when fireproofing. Therefore any process of fireproofing in this refinery will incorporate key guideline for fireproofing in refineries as per different publications by API. Such include but not limited to publications such as Fireproofing Practices in Petroleum and Petrochemical Processing Plants (Publication 2218) and Design and Construction of LPG (liquefied petroleum gas) Installations (Publication 2510A). Just like what these recommendations suggest, it will be prudent therefore to fireproof pipes as shown in figure 4 with pipe rack that are supported by steel that are also about 20 to 40 feet from fuel sources that are for general refinery services and up to about 60 feet from liquefied petroleum gas vessels. Relating this suggestion to already successful case, McKee Refinery listed fireproofing of pipe rack support steel which also included the E-W pipe rack north of the PDA unit. This was done as top priority for the site fireproofing programme. This is can be compared with rack which had not been fireproofed at the bottom of the incident. Still on McKee Refinery, the failed inlet flange to the No.1 extractor that was located about 78 feet away from the buckled pipe bridge support that also collapsed the pipe bridge was the source of jet fire according to ASTM Standard (2013) report. The closest major process vessel (according to Center for Chemical Process Safety 2013 the No.2 Extractor) was 51 feet away from the support---a distance exceeding both the Valero and API recommended fireproofing distances. A clear picture of the details above can reflect exactly what happened at X Refinery. Looking at figure 5 below, it can be realized that collapsed areas including chlorine shed were not fireproofed and other the other hand, the fireproofed sections as indicated in the figure 5 above remained intact thus preventing further damage caused by fire. Figure 5: X extractor towers (upper right) and collapsed pipe rack A point of concern however that in is as much as fireproofing is a solution to the problems witnessed with X the inspections on x appear to be lacking in many sectors even if they had engineers working on the same annually. Fire pumps, life rafts and emergency lighting did not appear to have received attention according to the prescribed code of conduct. In so discovering, even if fireproofing is done, little can be done to salvage the situation as it happened. This explains why there were cracks that must have been ignored during the periodic maintenance. To be specific, minimal response to inspection by the last group of engineers was a factor that weakened pumps especially edge of PDA unit as shown in the figure 5 above. The most sensitive maintenance problem was the carelessness with which PSV 504 was removed and further replaced without proper tagging thus putting the pumps as shown in figure 2 and 3 out of service. Still on case studies, in the Formosa-Point Comfort, Texas, propylene/propane fire that broke out in October 2005 that was investigated by U.S Chemical Safety and Hazard Investigation Board (CSB) found that even if there are cracks in tubes and valves when fireproofing is properly done, spread of fire can be mitigated thus limiting the shut-down of the plant (ASTM Standard, 2013). When doing fireproofing, it will be essential to fireproof steel columns. 1.1.5. Emergency Isolation and Shutdown Preliminary report from X suggested that engineers contracted in the design of this Company lacked specific fire criteria in design of structure and refinery in general. Also noted was that prior to the shut-down of the project, engineers constantly checked suitability of the specific fire criteria in design of the structure but there was not point where these engineers suggested a change to the same the anomalies that were so apparent. Secondly, the report by Center for Chemical Process Safety (2013) noted that these engineers failed to link fire loads in the design of the project structure in the same way they did with wave loads. Lastly, there was a report by ASTM Standard (2013) indicating that there were abnormal cases such as damaged blades (due to localized explosions, high temperatures), loss of fuel efficiency and damaged nozzles (due to high temperatures) but engineers could not do anything to avert such cases thus plunging the plant into more problems. All the above problems brought together, need well integrated solution and the solution is to develop emergency isolation and shut-down. Though the PDA of X refinery had large inventories of high-pressure propane, there was lack of remotely operable shut-off valves. This is where the solution should start with. Engineers should install remotely operable shut-off valves as this will rapidly stop the release of propane. However, installation of remotely operable shut-off valves should be handled with care if this is the way engineers opt to go since they will only be effective if they are used in facilities like the PDA unit where effective and fast isolation is needed to ultimately reduce the effect of major hazardous release. This assessment has suggested a typical example of remotely operable shut-off valves that engineers should install in the refinery to mitigate problems as discussed above. Figure 6: Suggested Insurer-recommended locations for remotely operable shut-off valves Additionally, when installing remotely operable shut-off valves it must be done on large inventories of highly flammable materials. In this case, X has downstream pumps as shown in figure 3 therefore when this is done these pumps will no longer produce pressurized release. Engineers should also ensure that such pumps as shown in figure 3 should be interlocked to shut down when remotely operable shut-off valves are closed. Other than the installation of remotely operable shut-off valves API has recommended for what they term as Fire Protection in Refineries coded as API 2030 and Application of Fixed Water Spray Systems for Fire Protection in the Petroleum Industry. In their submission, API discussed the application of isolation valves for emergencies within refineries. In as much as this recommendation practices directs remotely operable isolation valves, when installed, they will focus on fire-and heat-actuated valves and their limitations. Additionally, in 2010 API 521 released another solution to the challenges described above. This was Pressure-relieving and Depressing Systems. When these systems are installed in X refinery they will tackle the limitations of pressure relief systems when protecting against jet fires. As a guide to engineers, the recommendation reads, “unlike incidences of pool fire, a jet fire as mostly seen with refineries can, in essence, be controlled or turned off by isolation and depressurization of the jet fire source” (Chemical Emergency Preparedness and Prevention Office, 2009). Unfortunately, though API 2030 provides detailed analysis of what ought to be done as a solution to challenges as the one witnessed in X refinery, none of the recommendation give a unique and specific guidance on the location, design and use of remotely operable shut-off valves for the rapid isolation of liquefied petroleum gas (LPG). Also related to emergency isolation and shutdown is that prior to rapture that was witnessed as per figure 4 above, engineers found that there was a 480-560 psi pressure available in the Slurry Settler which was required for the rupture and the operating temperature which was above 6200F. This was an indication that there was poor servicing and or recommendations at the Slurry Settler. On the other hand, calculations on the blast effect were found to be around 130-190 pounds TNT. This was dangerous for its operation and it was surprising that the sub-contracted engineers did not detect the abnormality because it is definite that air was trapped inside the vessel during its start up. It is from these findings that when introducing emergency isolation and shutdown as a solution to the problems identified above, integrating Valero Emergency Isolation Valve (EIV) Standard is essential. According to Center for Chemical Process Safety (2013), EIV requires that there should be installation and evaluation of ROSOVs (remotely operable shut-off valves) when new construction projects as well as application of the standard during PHA revalidation in existing process units like the PDA. Therefore it will be prudent to advice engineers working on the refinery that EIV standards specifies giving priority to the installations of EIV’s on the refinery’s vessels. Since the report by Center for Chemical Process Safety (2013) showed that some vessels in X refinery contained over 10,000 pounds of class 4 propane, installation and evaluation of ROSOVs is mandatory to avoid raptures. The same report cites that both the low-and high-pressure accumulators (so was with the extractors) contained well above 10,000 pounds of propone prior to the rapture of valves and the tubes. These tubes were also reported to be working under abnormal conditions yet none of the valves and tubes were equipped with ROSOVs neither did the engineers apply SP-40-01 as recommended during 2006 PDA unit PHA revalidation. Basing on the amount of leakage that was reported after fluid catalytic cracking unit which further damaged slurry pumps, slurry settler, steam blow-down drum, piping, structures, steam super-heater exchanger and instrumentations suggest that the engineers ought to have installed ROSOVs in the PDA unit as a solution. Instead, the action item seemed to have been incorrectly closed out as having been completed. 1.1.6. Adoption of Inherently Safer Alternatives To understand how adoption of inherently safer alternatives is itself a solution needed by the refinery, it is essential to highlight areas that required the engineers to adopt inherently safer alternatives during the maintenance periods in the refinery. First, preliminary investigation indicated that there was a vessel for mono-ethanolamine absorber adjacent to pipe number 4 (Crude Unit) and this absorber had been in X for over ten years. Conversely, the same vessel was found to have one-inch thickness and ASTM A516 Gr 70 steel plates welded and rolled with full submerged arc but without post weld heat treatment. Secondly it was reported that engineers failed to adhere to the safety standards and even went as far as failing to monitor the functionality of the absorber so as to make it raise alarm should there be a change likely to affect the performance. Assessing from the exponential distribution approach discussed before, there was no evidence that the sub-contracted engineers designed and put in place on-board “quick-test routine” which in this case ought to have been dynamic thyristor diagnostic (DTD) to minimizes the failure by monitoring the load in real-time and thyristor unit. With the identified engineering problems with the refinery, the best solution to be offered is to engage the refinery in inherently safer alternatives. By applying inherently safer alternatives to the areas aforementioned, the best way to engage this will be to control hazards. Controlling hazards on the other hand signify the elimination of the same hazards. However as Center for Chemical Process Safety (2013) notes, sometimes elimination is not feasible especially owing to the fact that a number of valves and tubes within the refinery are already damaged. In this case engineers should be advised to replace dangerous or hazardous materials with less dangerous ones being re-examined. This solution has been suggested as it has been successful in Saint Mary's Refining Company and such is compounded by the fact that its basic principles were detailed by process safety expert Trevor Kletz, who explained that “what you do not have cannot cause a leak to a process” (Layer of Protection Analysis, 2013, p.301). In its practicability within the refinery, adoption of inherently safer alternatives should be done by also introducing safer materials that can be used to control biological growth in cooling towers. Additionally, there is need to replace chlorine that is found in the cooling water treatment at all the refineries as one so the safety goal. Based on the report by Layer of Protection Analysis (2013), the refinery was using ton container quantities of gaseous chlorine to serve the purpose of cooling water biocide. This is dangerous and the simplest safety replacement that ought to have been done was to substitute it with sodium hypochlorite (known as bleach) for chlorine especially in its number 4 cooling tower especially when the refinery had PDA unit reconstructions. 1.1.7. Process Hazard Analysis (PHA) Going by Layer of Protection Analysis (2013), PHA within X is a formal method that when adopted, identify process hazards. The evaluation done by U.S. Environmental Protection Agency (2014) in the refinery indicates that the revalidation on the refinery did not address hazards that ultimately caused the rapture and shut-down to the plant. To be specific, the PHAs that were done on the water treatment systems LPG storage spheres was not extensive enough to examine sitting issues and problems to the near-miss incidents as figures 1 and 2 above can reveal. Additionally, some of the issues rose such as engineers failing to know exact location of telecom/radio and control rooms. Basing on the control room, the sub-contracted engineers had been servicing this Company for over 12 years and strangely; failed to notify relevant authority that electrical classification for instance was a determinant of the design criteria. Therefore when number 4 Crude Unit ruptured, it would have been easy to save some of the structures such as absorbers. These kinds of anomaly are caused when there is no PHA prior to servicing of the refinery. In addition to the areas that have been identified above, the report identified a number of areas within the refinery where PDA unit PHA was not included or was ineffective in the identification of hazards that ultimately contributed to the incident in the refinery. As it was documented in figure labeled 2 above, the process safety information that was developed for the PDA unit PHAs failed to identify the propane mix control station as a dead-log, which according to proper standards of practice by engineers could be subject to freezing. The solution in this particular case ought to have been addressing the dead-leg which could in turn prevent the propane release. The node size that was selected for the HAZOP PHA method was generally too large for the functionality of the entire valve. This was definitely going to lead to the propane mix control station not being able to be reviewed. As witnessed in figure 2, the PHA failed to apply the Valero Emergency Isolation Valve standard which in this case was supposed to be SP-40-01. This was supposed to identify locations that required or likely to have significantly reduce the severity of the incident. 1.1.8. Regulatory Analysis This option has been considered as a solution in this refinery to help standards of practices aiming at helping the X avoid shut-down conform to EPA Risk Management Program (RMP-40 CFR Part 68) and OSHA PSM (29 CFR 1910.119). Connecting this point with actual problem noticed, previous engineers did not apply accident sequence approach where p(X) denoted the probability of an even of the engineering project per time unit (of the operation, p(X|Y) as the conditional probability of the factor X given Y, p(X,Y) was the joint possibility or probability of X and Y, IEi was the possible initiating events of failure of projects by engineers (or accident sequences) which is indexed in i and F representing the (cumulative or total7) technical failures of a given project. Process Safety Management however, requires engineers to carryout effective programmes that can protect workers within refineries. In Risk Management Programme for instances has been included in the practice since it includes elements of process safety management and adds requirements that help in evaluating off-site consequences, community outreach ad emergency response. According to U.S. Environmental Protection Agency (2014), the regulations as cited above are applicable to processes that contain hazardous materials above a given threshold quantities. Additionally, LPG and PDA storage areas were not covered under both regulations. 2.0. References API RP 939-C. "Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries.” 1st ed., Section 4, May 2009. ASTM Standard A53/A53M-12 (2013). "Standard Specification for Pipe, Steel, Black and Hot Dipped, Zinc-Coated, Welded and Seamless." Center for Chemical Process Safety (CCPS) (2013). “Layer of Protection Analysis – Simplified Process Risk Assessment.” Chemical Emergency Preparedness and Prevention Office, “RMPs Are on the Way! How LEPCs and Other Local Agencies Can Include Information from Risk Management Plans in Their Ongoing Work.” November 1999. http://www.epa.gov/osweroe1/docs/chem/lepc-rmp.pdf (accessed April 3, 2014). Kletz, Trevor, and Paul Amyotte (2010). “Process Plants: A Handbook for Inherently Safer Design.” 2nd ed., Section 1.1, Page 14. Layer of Protection Analysis (2013): Simplified Process Risk Assessment. Center for Chemical Process Safety of the American Institute of Chemical Engineers. U.S. Environmental Protection Agency (2014), “General Guidance on Risk Management Programs for Chemical Accident Prevention (40 CFR Part 68).” Page i. March 2009. http://www.epa.gov/oem/docs/chem/Intro_final.pdf (accessed April 3, 2014). Read More

Figure 2: Damaged Propane inlet on extractor No. 1 The figure 2 above according to Kletz et al. (2010) was taken prior to the shut-down the refinery. Basically, it is apparent from the figure that inherently safer approach as a solution to the above problem ought to have considered three approaches; first, positively isolating the dead-leg by doing the installation of slip blinds. Secondly, freeze-protecting the corroded regions and lastly, developing procedures to constantly monitor and drain water that the report from Kletz et al. (2010) indicated as being from low points.

The connectedness of the solution as suggested with the aspect of reliability, unreliability, availability or unavailability is that reliability for instance, allows the comparison of unavailability and unreliability values rather than availability and reliability of the materials as the image shows. In addition, the numerical values of both the unavailability and availability are shown as probability from 0-1 and no units of which is engineers discover that the plant depicts what is shown above then probability from 0-1 cannot be given by plants thus a need for inherently safer approach or removal of the hazard all together.

Considering this prior to the rupture, the tube was either operating or not operating; the above statement is conceptualized using the expression below: A (t) + Q (t) = 1….equation (2). Unavailability Q (t) ≤ Unreliability F (t). For a non-repairable component or tube: Unreliability F (t) = Unavailability Q (t). These expressions further conceptualise the need for safer approach thus providing a solution to the problems. While this stands to be the case, there is an essential issue with the refinery that must be highlighted.

That is, engineers failed to follow what were inherently safer systems. Inherently safer materials and technologies are relative. While the first group of the sub-contracted engineers described materials they introduced while doing their maintenance as inherently safer, it seems the materials used did not consider specific hazard and or risk. This is the reason why it is essential to check on reliability and its connectedness with inherently safety approaches and so is the reason why it has become part of solutions to the identified problems as per the Centre for Chemical Process Safety.

To explain on this, the Centtre has come up with “a near miss.” According to the Centre, this is an extraordinary event that is able to lead to reasonably unexpected negative result but was actually mitigated (U.S. Environmental Protection Agency, 2014). 1.1.3. Controlling Freezing Temperatures The third solution that X needed to avert the aftermath shutting in some of its components has relevant connection with programmes introduced in McKee Refinery. X is located in area where there are below-freezing temperatures between the months on February and April.

In so doing, engineers should protect piping and other related equipment from freezing during such periods. According to U.S. Environmental Protection Agency (2014), such protections should be done by insulating and tracing the pipes and the equipment with steam-filled tubing or where necessary electric heat tape. Therefore engineers who carried out inspection erred in reviewing and repairing freeze protection components instead of insulating cracks that were already eminent. To understand how insulation of some areas of the pipe is indeed a solution to what was witnessed; figure 2 below has been introduced.

Figure 3: Temperature damaged coating on sphere and location of sphere deluge valves Going by the figure, there is relative thickness of low silicon piping appearing deluge valve location and extractors. On the other hand, there is high silicon piping on the damaged coating. However, the report suggested that divulge valve location was not fully insulated and had only 0.01% of silicon. In as much, there is 0.16% of silicon at the upstream elbow. Basically, this is not the recommended thickness of the piping especially when engineers are already aware of the changes in temperature.

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