Asset Integrity – Page 3 – Asset Integrity & Reliability Services

My Lubrication Program- What Should I Know?

Posted by boilerrockllcon February 1, 2018in Asset Integrity, Lubrication, Reliability, Rotating EquipmentLeave a comment

My name is Terry Roehm, Rotating Equipment Specialist and today’s author for the BoilerRock Blog. I will be discussing Lubrication Programs and some of the basics of a good program in part 1 for this topic.

The rotating equipment used in a plant is essentially the heartbeat of the plant. Rotating equipment is used to move gases and liquids throughout the plant, allowing the different production process units to perform their intended duties. To provide the desired on-stream production rates of these units, the rotating equipment must be reliable. Maintaining the equipment’s reliability at the desired high level is a process that requires many different people’s abilities and skills. The rotating equipment must be both maintained and operated in a manner that allows continuous on-stream production in-order to stay competitive. While improving the reliability of the rotating equipment, safety will be improved for both the productions unit and the equipment itself.

One of the reliability programs that is associated with rotating equipment is the lubrication program. Rotating equipment has components that rotate, slide or move requiring the friction to be reduced to prevent wear resulting in failure. The goal of a well-developed lubrication program is to ensure that all equipment receives and maintains the required levels of quality lubrication such that no equipment fails due to inadequate or improper lubrication while performing its intended purpose. A quality lubrication program will reduce the mean time between failures (MTBF) of the rotating equipment thus bringing down the maintenance costs. With higher MTBF’s, the rotating equipment will operate longer which reduces operating costs that are associated not only the repairs, but potential unit outages and incidental costs.

Each plant should develop a lubrication program that fits that site while providing ownership and accountability.

• lubrication program requires management’s buy-in and leadership.
• lubrication program is to define its purpose, details, person in charge, expectations and training of the program’s activities.
• it is crucial that the program is well understood throughout the plant with all people.
• to ensure that the program is providing the expected benefit, key performance indicators (KPI’s) are to be established and tracked.
• if the program is not providing the expected results it needs to be modified or replaced.
• audit performed by an outside source can provide benefits for the success or failures of the programs

A lubrication program is more than here is what
is to be lubricated

The lubrication program is more than here is what is to be lubricated. The lubricant program is to ensure that:

• equipment requiring lubrication is identified
• lubricant requirements are identified
• lubricant selection is rationalized and suitable for the application
• lubricant is provided by a reputable supplier per the determined requirements
• lubricant is stored in an appropriate manner
• lubricant is replenished with the right type, frequency, quantity and method
• lubricant is sampled in an appropriate manner
• oil testing/analysis requirements are chosen based on the requirements of the equipment
• appropriate action is taken based on analysis results
• lubricant stock is rationalized
• history is maintained in an appropriate CMMS

Rotating equipment included in the program should include any rotating equipment, critical (typically unspared equipment that can cause business interruptions/losses) and non-critical (typically spared or equipment that does not greatly affect business losses).

lubrication program may be a cultural change

Implementing and performing a lubrication program may be a cultural change for a plant. Any changes will not be implemented overnight and needs to be slow and steady to achieve the goals. Not all people will react the same and working shoulder to shoulder with management’s direction will help with the cultural changing. Building a culture of continuous improvement will provide a direction that all people can associate with and will hopefully want to get on board.

Actions to Take:

1) Review your current lubrication program against this guideline and what is included in your current lubrication program.
2) Do you currently have KPI for your lubrication program? Review which way your KPI’s are trending.
3) Review your current training strategy.
4) Take a field trip–Review your current oil storage area and talk with your Maintenance/Operations staff about their knowledge of your lubrication program.

If any of this seems overwhelming or you need help with your lubrication program, BoilerRock can assist with the establishing, identification, development, training or auditing that will benefit your plant.

Terry Roehm is a Rotating Equipment Specialist with 40+ years experience in both the upstream and downstream businesses of the Oil and Gas Industry. He is a member of the American Petroleum Institute (API) serving on task forces for the mechanical subcommittee and is a past advisory committee member for the Texas A&M Turbomachinery Symposium. He has held various positions in maintenance and engineering involving specification, selection, procurement, testing, installation, startup, troubleshooting and turnaround planning for the rotating equipment. He has established programs, provided and developed training opportunities and has completed audits for companies to improve their operating and maintaining of rotating equipment. He Mechanical Engineering Degree from Purdue University and is a registered Professional Engineer in the states of Kentucky and Texas.

Lessons Learned- How to Prevent the Next Major Incident

Posted by boilerrockllcon January 4, 2018in Asset Integrity, Process Safety Management, ReliabilityLeave a comment

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

Posted by boilerrockllcon November 28, 2017in Asset Integrity, ReliabilityLeave a comment

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?

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.
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.
Keep up to date with industry NDE techniques for finding CUI damage.
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.

What do I need to know about Corrosion Under Insulation (CUI)?

Posted by boilerrockllcon October 23, 2017in Asset Integrity, UncategorizedLeave a comment

As I mentioned in my first blog post, these blog posts will be short and to the point with the intent of providing useful information to remember without using much of your valuable time. The first corrosion issue we will be discussing is Corrosion Under Insulation (commonly referred to as CUI). So you have a system that has very little corrosion potential and then you get the call that you have a leak- what happened..? Being an external corrosion mechanism, CUI can get you regardless of the any other corrosion issues. CUI is a very damaging corrosion mechanism caused by moisture under insulation or fireproofing.

The following are few important CUI facts that you should understand:

1. Corrosion (pitting & localized loss + cracking in stainless steel) is possible at the following temperatures for carbon and stainless steels:

Carbon and low alloy Steels: 10°F (–12°C) and 350°F (175°C)
Austenitic and duplex Stainless Steels: 140ºF (60°C) and 400ºF (205°C)

2. Corrosion rates increase with increasing metal temperature.
3. Cyclic systems with varying process temperatures or intermittent service can increase corrosion.
4. Insulating materials that hold moisture or wick can increase corrosion.
5. Airborne contaminants can accelerate corrosion.

a. Chlorides from cooling tower drift or marine environments
b. SO2 from nearby stack emissions
c. Salt water environments on Offshore platforms

What should I do/Actions to Consider?

i. Verify that your current CUI program is considering the proper temperature ranges for carbon and stainless steels in your plant.

ii. Do you have any Cyclic Systems in your plant? Verify with your process conditions with your process specialist to insure your covering all operating conditions for your equipment.

iii. Verify that your CUI program is taking into account other factors that cannot be identified from the office. Do you have insulated systems near cooling towers, stacks or vents? Do you have steam tracing leaks? Do you have damaged insulation?

All comments and questions are appreciated!