Want to Save your Company Money?

In the big corporate world, there is always opportunities to become more efficient and save some money for your company. But in the oil and gas industry one of the largest expenses and the biggest maintenance expense is your turnaround/shutdown (TAR) work. Some companies have been focused on improving their TAR maintenance for years and have the costs/barrel operating cost to prove it. Others have not taken the required efforts to ensure TAR success and have left significant cost and risk reduction on the table. There are a number of ways to improve your TAR maintenance, but there is one simple trick you can use to insure you’re in a position to execute a successful TAR at your plant. What is this trick? Well its really not a trick or a secret, but too many facilities still don’t do TAR Readiness Assessments prior to their TAR to insure they are prepared.

When a TAR requires hundreds or even thousands of temporary employees to complete, even a day or two overrun on the planned TAR schedule can be in the millions of dollars of additional cost. What is a TAR readiness assessment and why should I use this tool? A TAR assessment uses highly experienced TAR management professionals to review your plant’s readiness throughout your organization. This will include your TAR Organization, Planning, Maintenance, Inspection, Operations, Projects, Safety, Technical Services, Warehouse, and Procurement organizations. Any weaknesses in any of these areas will lead to additional costs and potentially a poorly executed TAR.

TAR maintenance requires the entire organizations focus and preparation to be successful. The problem is that the entire organization has a duty to keep the plant running as efficiently and safely as possible on a day to day basis and finding the time and resources to focus on the approaching TAR can be difficult. A TAR assessment will help your organization to identify areas that need attention/gaps as well as bringing focus to the organization on the need for attention on an approaching TAR. When should I do a TAR assessment? An effective TAR assessment is best completed far enough in advance to a TAR to allow the identified gaps to be closed. Twelve months prior to the TAR is best for the initial assessment, with a follow-up assessment 3 to 6 months prior to the start date. Even if you’re getting close to your TAR start and have no done an assessment, its best to complete one even if it’s only to verify that you should consider delaying your TAR. A delayed TAR will cost you much less money than a poorly organized and executed TAR.

TAR assessments are best completed by resources outside of your plant. This allows for an outside, unbiased and objective assessment of your organization’s readiness. As a Plant Leadership Team or TAR Manager, the cost of a good TAR assessment plan for your plant is negligible compared to the benefits of identifying required actions that can be tracked to completion to insure a successful TAR. As a TAR professional/leader for a good portion of my career, I can guarantee there is no better way to get the attention and focus of an organization than a good TAR assessment. The action items generated will need to be tracked and corrected of course, but the cost savings and peace of mind that you are prepared for the biggest maintenance event of the year is priceless.

Dave Bryan Joins BoilerRock

Dave Bryan joins BoilerRock as Partner and Technical Director after completing 36 years with Marathon Oil. He brings Engineering, Maintenance and Reliability expertise from both the upstream and downstream sectors of the Oil and Gas industry. After graduating from Purdue University with a degree in Mechanical Engineering, Dave worked as a project engineer in Marathon’s Pipe Line and Refining organizations. He went on to roles as Refinery Inspection Supervisor, Corporate Fixed Equipment Subject Matter Expert and Refinery Maintenance Manager.

After 26 years in the downstream, Dave transferred to the Marathon’s upstream organization where he served as corporate Fixed Equipment Integrity Manager and Technical Authority/Reliability Manager for World Wide Production. Dave has extensive experience working with diverse cultures, applying engineering fundamentals and maintenance best practices. He is recognized for developing sustainable fit-for-purpose strategies and processes to improve facility reliability.

Initiatives that Dave can help clients with include:
• Mechanical Integrity Program Assessments/Audits
• Reliability & Integrity Strategy Effectiveness
• Turnaround Scope Challenges/Readiness Reviews
• Turnaround Planning & Management
• Risk-based Assessments & Applications
• PSM & API 751 (HF) Audits
• Root Cause Analysis/Incident Investigations
• Maintenance Optimization & Benchmarking
• Project Support (Fixed Equipment Engineering & QA/QC)

Dave currently holds API 510 and 570 certifications (previously held API 653 and NBIC) and is active on several API committees. He is a registered Professional Engineer in Indiana and Illinois. Dave’s been active for over 25 years with industry organizations focused on pressure equipment inspection and integrity.

Corrosion and Damage Mechanisms – How do I Learn More? “An example”

As we discussed in last month’s blog, Loss of Primary Containment (LOPC) or simply leaks in our process facilities is an all too common event. Sometimes we get lucky and it is a minor event but relying on luck is not any way to keep our plant’s safe and reliable. However, other times the leak leads to a serious event and we make the local or national news or worse yet; someone gets injured or loses their life! Today’s blog will be focus on a simple example of using API-571 “Damage Mechanisms affecting Fixed Equipment in the Refining Industry” to improve your corrosion and damage mechanism knowledge.

In today’s example, I will assume that I am the area inspector or engineer working in my refineries Crude unit. Therefore, the first thing I do is review the Process Flow Diagram for the Crude Unit/Vacuum in Figure 5-65. (See example in blog photo) For this example, I’m interested in the atmospheric tower side draw piping. So what damage mechanism do I need to worry about for this area of the Crude unit?

DM#1 Sulfidation
DM#6 Naphthenic Acid Corrosion

So, I need to understand more about damage mechanism DM #1 -Sulfidation—Looking at the DM table of contents, we see that Sulfidation is covered in Section 4.4.2 on pg 4-159. Moving to page 4-159 you will find six pages of information related to sulfidation, including pictures, graphs and other details including: High Level Description of Sulfidation, Affected Material, Critical Factors, Affected Units & Equipment, Appearance of Sulfidation, Prevention/Mitigation, Inspection & Monitoring, and Related Damage Mechanisms. Sulfidation (also known as sulfidic corrosion) is the corrosion of carbon steel and other alloys resulting from their reaction with sulfur compounds in high temperature environments. (>500F) There are eight Critical Factors related to Sulfidation discussed with one of them being the alloy composition (determined by the alloys ability to form protective sulfide scales), temperature (increased corrosion as temperatures increase) and concentration of corrosive sulfur compounds.

Section 4.4.2.7 gives you information about the how to Inspect and Monitor for Sulfidation Corrosion:

  • Evidence of thinning can be detected using external ultrasonic thickness measurements and profile radiography.
  • Process conditions should be monitored for increasing temperatures and/or changing sulfur levels. See API 584-Integrity Operating Window (IOW) for more information on issues that may assist in the development of an IOW program.
  • Proactive and retroactive PMI programs are used for alloy verification and to check for alloy mix-ups in services where sulfidation is anticipated. Note: Inadvertent mixing of Alloy material in a piping circuit has led to several major incidents in the Oil and Gas industry.

The remainder of the section contains additional information related to Sulfidation including graphs giving you information on corrosion based on the affects of temperature, Sulfur content and Alloys in your system.

Now, follow the same review of 571 for DM#6- Naphthenic Acid Corrosion and you will have a good understanding of what you need to look for and how to find it for the Crude Atmospheric Tower Side Draw Piping.

API-571 is an excellent resource to use for improving your corrosion knowledge and that of your work force. I hope this very simple example will encourage you to review API-571 for your area of responsibility or area of corrosion knowledge that you would like to learn more. Additionally, API has an API-571 Certification Program available for anyone with a keen interested in corrosion and potentially becoming a technical resource for your facility. See http://www.api.org for additional information.

Actions to Take:

  1. Complete a quick review of API-571.
  2. Review the damage mechanism PFD for your unit or unit you would like to learn more about.
  3. Have one of your employees present an overview of one damage mechanism for their area during a weekly meeting. The employee and those present will all learn from this type of exercise.

Please contact BoilerRock if you need assistance with any of your Reliability or Asset Integrity issues.

Reference: “API Recommended Practice 571, Second Edition. Washington DC: API Publishing, 2011”

Lessons Learned- How to Prevent the Next Major Incident

Since the Process Safety Management (PSM) standard was introduced by OSHA in the 1990’s, no other industry sector has had as many fatal or catastrophic incidents related to the release of highly hazardous chemicals as the Oil and Gas industry. If you’re not familiar with the PSM standard, it outlines 14 elements to follow which assist facilities in implementing management system requirements needed to prevent loss of containment and associated fire, explosion and loss of life incidents. In response to the large number of fatal or catastrophic incidents in the industry, OSHA initiated the Petroleum Refinery Process Safety Management National Emphasis Program (NEP), in June 2007. The purpose of the NEP was to verify the employers’ compliance with the required PSM elements. Since the start of this review over 10 years ago, the industry has made many improvements and advances but continues to have deaths and major incidents. We must take the lessons learned from other facilities and not repeat the same issues again and again.

This summary highlights 5 elements (5 of 14) of the PSM standard where OSHA issued the most citations during the NEP program review, with the Mechanical Integrity element being the worst actor.

■ Mechanical Integrity (MI) – 6 repeat findings
■ Management of Change (MOC) – 5 repeat findings
■ Process Safety Information (PSI) –4 repeat findings
■ Process Hazards Analysis (PHA) –3 repeat findings
■ Operating Procedures – 2 repeat findings

The 20 most cited reoccurring OSHA findings are as follows:

MI:
• Equipment Deficiencies not properly addressed
• Inspection, Testing and Maintenance Procedures not followed
• Thickness measurements not properly managed
• Inspection frequencies not properly managed
• MI Data not properly reviewed, and anomalies resolved
• Site Specific inspections and Tests not properly established

MOC:
• Changes in equipment design not properly reviewed and documented.
• Changes in operating procedures not properly reviewed and documented.
• Changes in Inspection & Test procedures not properly reviewed and documented.
• Changes to non-process facilities not properly reviewed and documented.
• Time limitations on Temporary Changes not established

PSI:
• Relief System Information not properly documented
• Facility Siting modeling and protection employees
• P&ID’s not accurate
• Relief System Design & Design Basis not documented or followed

PHA:
• Recommendation Resolution not properly addressed
• Facility siting factors not included in PHA review
• Human Factors not included in PHA review

Operating Procedures:
• Emergency S/D procedures not properly addressed
• Safe work practices not adequate

I will dive deeper into a few of these repeat OSHA findings in the future, but if you would like additional details the entire 2017 OSHA publication is available here.

Actions to Take:
1) Review the list of OSHA repeat findings and verify that your PSM or Company Management System addresses these repeat findings sufficiently.
2) If any of the repeat findings are of interest/concern, review the attached OSHA document for additional details.
3) If you are not familiar with your role in your companies Process Safety Management (PSM) program discuss with your supervisor or the PSM/Management System leader at your facility.

What Do I need to know about Corrosion Under Insulation- part II

As we discussed in the previous post on CUI corrosion it can be very damaging to your plant equipment and an inherent risk to your plant for leaks, fires and explosions. Also, we discussed in the first CUI blog that there is a potential for corrosion between 10°F to 400°F and it is very dependent on insulation system quality and external conditions. Detecting CUI issues and knowing where to look cannot be done from the office, it will required your inspectors to be in the field looking for damaged insulation, wet insulation, vents and drains, steam tracing leaks and any complex joints where moisture can enter the insulation. One other location that must be reviewed are inspection ports in the insulation. (the very location used for monitoring internal corrosion can be creating a separate CUI issue!) Based on the field reviews and NDE techniques discussed below, the inspection should be completed to determine if external corrosion is present or if simply the damaged insulation needs to be repaired.
Normally CUI corrosion is localized to the area of insulation damage or ingress of moisture under the insulation, therefore basic Ultrasonic (UT) thickness measurements are of no value in finding CUI damage. There are a number of techniques available for inspecting for CUI damage and include the following:

  • Use of an Infrared (IR) camera looking for wet insulation.
  • Visual inspection of damaged area. This is generally cost prohibitive, but is very effective if the insulation is being removed for repair/replacement. Coordination/communication between your insulator and inspector is critical.
  • Real Time Radiography (looking for corrosion scale with follow up inspection required)
  • Guided Wave UT
  • Pulse Eddy Current Testing

Additional and improved technology is continually progressing to detect this difficult to find, but dangerous corrosion mechanism. There is a current American Petroleum Institute project between industry and NDE technology companies to improve/develop better ways for detecting CUI. If you have had good success with any of the inspection techniques mentioned above, please share with others on this blog post.
Preventing CUI in the first place should be a consideration as well by reviewing and designing new process systems with prevention of CUI in mind. In the past, insulation was installed on process systems simply for personnel protection to prevent a potential burn to employees. Although positive for personal safety, alternate methods of personnel protection should be used in new designs. A bird cage type arrangement or thermal barrier coatings should be considered.

What should I do/Actions to Consider?

  1. Talk with your inspection department to determine how CUI inspection locations are determined. Determining the CUI locations from the office or looking in the easiest locations is compliance only and will not improve your plant reliability.
  2. Verify with your process engineer that the insulation is required for process reasons. If is not required, consider removing the insulation. Additionally, ensure that any new projects do not install insulation for personnel protection without investigating other alternatives.
  3. Keep up to date with industry NDE techniques for finding CUI damage.
  4. Verify that your CUI program includes inspection for corrosion under Fireproofing as well.

If you are interested in reading in detail about CUI issues and inspection techniques the following documents are available- API RP 583- Corrosion Under Insulation & Fireproofing, API-571 and NACE RP 0198.