OSHA has identified the following mistakes found at PSM facilities nationwide. These mistakes were identified at refineries; however, almost all can be found within any PSM-covered process. I have revised OSHA’s wording so that we can ALL learn from these mistakes. PLEASE do not fall for the old trap of “Bryan, we are not a refinery.” We all have to meet 1910.119, and in fact, MOST of the MI RAGAGEPs used at a refinery are used in most PSM-covered processes.
Examples of non-compliant inspection and testing procedures include:
- Not establishing and implementing adequate procedures to clearly set the specific number and locations of thickness measurement locations (or condition management locations) for each pressure vessel and sections of piping, and to address anomalous inspection data, such as increasing thickness measurement values for pressure vessels.
- Failure to list specific requirements for welder qualifications in the inspection and testing program when the procedure establishes that all systems that are inspected must contain the welders’ qualifications.
- Failing to establish and implement adequate procedures for inspecting, repairing, and maintaining pressure vessels, piping, and other process equipment resulted in an inadequate evaluation of a leaking tube in a heater unit and a multitude of inadequately recorded piping inspections.
- Not updating procedures to reflect a recently initiated practice of changing the piping inspection interval.
- Failure to inspect for corrosion under insulation resulted in pressure vessels, process equipment, and piping being subjected to corrosive environments without assurance that exterior corrosion would be found during routine inspections.
One common non-compliant condition found during inspections was corrosion under insulation (CUI). Insulated vessels and piping circuits can harbor advanced corrosion sites under the insulation. Several critical factors can influence corrosion under insulation, including equipment subjected to cyclic temperature processes, poor design that allows moisture to accumulate, insulating materials that retain moisture, and specific local environments or emissions that can accelerate corrosion. Facilities must be prepared for this type of corrosion and adequately inspected under insulation.
The MI section of the PSM standard also requires that “inspection and testing procedures shall follow recognized and generally accepted good engineering practices,” and “the frequency of inspections and tests of process equipment shall be consistent with applicable manufacturers’ recommendations and good engineering practices, and more frequently if determined to be necessary by prior operating experience.”
The most commonly cited inspection and testing RAGAGEP deficiencies involved piping and pressure vessels. During NEP inspections, OSHA found
(A) insufficient thickness measurements, and
(B) Unacceptable/unestablished inspection frequencies for these types of equipment, based on the employer’s selected RAGAGEP or lack thereof.
Moreover, a significant portion of citations were issued due to an inadequate or complete lack of inspection of covered process equipment.
Thickness Measurements RAGAGEP
Citations with respect to thickness measurements involved:
- Actual corrosion rates exceeding the expected rate, and being uncorrected or accounted for.
- Failure to properly inspect multiple pressure vessels, specifically citing a lack of ultrasonic thickness testing.
- Failure to inspect a boiler at appropriate location points, as specified by the employer’s RAGAGEP.
- Failure to ensure an appropriately certified individual performed pressure testing.
- Failure to calculate corrosion rates to determine appropriate thickness measurement intervals.
Employers are reminded that in the lifetime of a pipe, especially those used in corrosive service, thickness measurements must be taken at predetermined locations, called Condition Monitoring Locations (CMLs), to establish the integrity of the pipe. For instance, API 570: Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, an example RAGAGEP, states that CMLs must be taken not just at various locations along the length of a pipe, but at susceptible areas of deterioration – such as injection points, mixing points, and dead legs. The final number of CMLs is determined by considering the potential worker health and safety impacts, expected corrosion rates, and system complexity of the piping system.
Inspection Frequency RAGAGEP
The most commonly cited equipment for non-compliant inspection frequencies (of any type, not only thickness measurements) has been piping circuits, followed by pressure vessels, relief devices, and monitoring alarms. As part of the inspection program, an appropriate inspection frequency must be established for equipment to determine whether the pipe or vessel thickness is decreasing as expected. API 570 identifies three (3) classes of piping services and recommends a thickness measurement inspection frequency based on the class. For example, Class 1 includes:
■ Flammable,
■ Pressurized services that may rapidly vaporize and explode upon release,
■ Hydrogen sulfide,
■ Anhydrous hydrogen chloride,
■ Hydrofluoric acid
■ Piping over water of public throughways, and
■ Flammable services operating above their auto-ignition temperature.
As discussed in API 570, Class 1 requires a thickness measurement inspection frequency of at least every five (5) years. Classes 2 and 3 require a thickness measurement frequency of at least every 10 years. The inspection interval for specific piping is established by the inspector or piping engineer in accordance with the owner/user’s quality assurance system, but not to exceed the limits set by API 570.
Employers must follow their selected RAGAGEPs for appropriate equipment inspection frequency requirements, unless prior operating experience shows more frequent inspections are necessary. Recommended sources include the equipment manufacturer, an employer’s corporate/company-specific procedures, and industry/consensus standards.
API publications are examples of piping/vessel inspection RAGAGEP. Specifically, API 510: Pressure Vessel Inspection Code, API 570: Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, and API 580: Risk-Based Inspection.
Resolve Anomalous Data
During MI inspection and testing, if it is believed that a testing result is inaccurate or irregular, the uncharacteristic result must be retested, not disregarded. Upon retesting, if the result remains irregular or anomalous, action must be taken to determine the cause of the anomalous condition, and then the issue must be resolved. According to CCPS’ Guidelines for Mechanical Integrity Systems, “[inspection, testing, and preventive maintenance] data should be reviewed for anomalies so that suspicious information can be verified or corrected.”
Inspections conducted under the NEP found multiple instances where employers failed to address inconsistencies in testing measurements. In some cases, thickness measurements were increasing, and the employer took no action to investigate the anomaly. CCPS recommends that employers establish a means to efficiently analyze data and highlight anomalies. Also, personnel should be empowered to identify abnormal component parts. Any anomalies must be taken seriously to prevent an incident. This same principle for resolving anomalous inspection data is addressed in API 570 (2016), Section 6.5.4, Data Analysis.
Ensure Proper “Site-Specific” Inspections and Tests
It is also important that all inspections and testing be tailored to the specific equipment and environment of the process equipment. General industry standards and corporate-wide, or “boiler-plate,” procedures will not be applicable in all situations and may be lacking necessary hazard information. As such, employers must tailor site-specific MI procedures to address their unique PSM-covered processes . CCPS notes that “simply assimilating information published in standards may not be appropriate… some failure modes are very service- or process-specific.” Employers must train each employee involved in maintaining the on-going integrity of process equipment in an overview of that process and its hazards and in the procedures applicable to the employee’s job tasks to ensure that the employee can safely perform the job tasks.
During NEP inspections, OSHA found that all instances where equipment was not inspected or tested (or was inspected or tested inadequately) were the result of an inadequate site-specific inspection or test procedure. Examples include:
- Employer failed to inspect and test gas monitors on a regularly scheduled basis and failed to inspect and calibrate flow alarms, temperature alarms, flame detectors, auxiliary burners, level alarms, shutdown alarms, and control valve alarms. The monitoring devices and alarms were inspected only when there was a malfunction.
- Employer failed to adequately inspect and test process equipment by failing to ensure that the pressure gauges were calibrated on a periodic basis.
- Employer failed to adequately inspect and test process piping.
- Employer failed to adequately inspect and test heat exchangers, resulting in nuts being loose or missing on anchor bolts. Employer also failed to inspect steel vessel supports and failed to inspect the grounding cables for deficiencies.
Employers must ensure that their inspection and testing procedures are tailored to their specific covered processes; otherwise, equipment may be inadvertently omitted from the MI program. OSHA states in the non-mandatory appendix of PSM “The first step of an effective mechanical integrity program is to compile and categorize a list of process equipment and instrumentation for inclusion in the program.”
CCPS also states that facility personnel need to establish boundaries and develop a list of equipment to include in their MI program.
Source: https://www.osha.gov/sites/default/files/publications/OSHA3918.pdf