This is an interesting agreement, none like I have seen before. Had OSHA done this inspection, using their new Wilfull Instance-by-Instance Penalty Adjustments, this case could have exceeded $1M in fines. Yet, the case resulted in $0 in fines and a correction plan. This facility had two (2) releases (Oleum and Ammonia) in the same month last year, prompting the EPA inspection. They found many missed opportunities to address MI issues that had been identified in early MI inspections. The paper trail was wide and long, but there was a lack of action on the facility’s part. How these issues got negotiated down to $0 fines, even after two LOPC events in the covered processes, is amazing to me.
Respondent is a chemical company that owns and operates a caprolactam manufacturing facility. Respondent uses and stores toxic and flammable chemicals at the Facility that are used in the caprolactam manufacturing process.
On May 10-11, 2022, EPA inspected the Facility to determine whether Respondent complied with 40 C.F.R. Part 68 (referred to as the “Risk Management Program Regulations” or “RMP Regulations”) (“Inspection”).
The Inspection occurred in the aftermath of a March 29, 2022, release of oleum/sulfur trioxide from the Facility, which resulted in a shelter-in-place for two neighboring facilities, and a March 9, 2022, release of anhydrous ammonia from the Facility.
Based on its observations during the Inspection and its review of documents received from Respondent during the investigation, EPA determined that Respondent had the following chemicals present at its Facility, among other chemicals, in approximately the following amounts, from 2017 through 2022:
- 24,400,000 pounds of oleum (fuming sulfuric acid);
- 40,000,000 pounds of ammonia (anhydrous);
- 300,000 pounds of ammonia (concentration 20% or greater);
- 204,000 pounds of acetaldehyde; and
- 32,200 pounds of a flammable mixture containing hydrogen.
Respondent submitted risk management plans for the Facility on September 5, 2017, and August 30, 2022. According to the August 30, 2022 risk management plan, the caprolactam manufacturing process is subject to the Process Safety Management regulations promulgated by OSHA, at 29 C.F.R. 1910.119, and is subject to regulation under the Program 3 Prevention Program of the RMP Regulations, 40 C.F.R. Part 68, Subpart D. S
EPA has determined that more than a threshold quantity of regulated substances oleum (fuming sulfuric acid), ammonia (anhydrous), ammonia (concentration greater than 20%), acetaldehyde, and flammable mixture are present in a process at the Facility.
Based on its investigation, EPA has determined that Respondent did not fully comply with Section 112(r)(7) of the CAA and the RMP Regulations by failing to comply with certain mechanical integrity, process hazard analyses, and process safety information requirements, as outlined in more detail below.
Mechanical Integrity – Piping Support Issues
The term “recognized and generally accepted good engineering practices” for purposes of the design and maintenance of the caprolactam manufacturing process at the Facility includes the following five industry standards:
- MSS SP-58, Pipe Hangers and Supports-Materials, Design, Manufacture, Selection, Application and Installation (2006) (MSS SP-58);
- American Petroleum Institute 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, 3rd ed. (November 2009) (API 570);
- American Petroleum Institute Recommended Practice 574, Inspection Practices for Piping System Components, 3rd ed. (November 2009) (API RP 574);
- National Association of Corrosion Engineers SP0294, Standard Practice – Design, Fabrication, and Inspection of Storage Tank Systems for Concentrated Fresh and Process Sulfuric Acid and Oleum at Ambient Temperatures (2006) (NACE SP0294); and
- National Association of Corrosion Engineers Publication 6G197/SSPC-TU 229, Design, Installation, and Maintenance of Coating Systems for Concrete Used in Secondary Containment- Information Report and Technology Update (February 1997) (NACE 6G197/SSPC-TU 229).
In the Facility’s Marine Operations area, EPA inspectors observed that the piping associated with oleum tanks VT-518 and VT-519 was not properly supported in several locations. Specifically, piping was suspended from other pipes with hangers, which appeared to be carrying too much load, causing the pipes to bend under pressure.
In the Facility’s Kellogg Unit around ammonia tank VT-520, EPA inspectors observed piping support brackets rising from ammonia pipes to support other ammonia pipes, wooden block piping supports, cinder block piping supports, and piping with missing insulation jackets. In the piping associated with ammonia-filled Horton Spheres HST-1 and HST-2, EPA inspectors observed piping lying atop other piping, piping on the ground, piping with missing jackets, piping supporting other pipes with cuts into insulation jackets, and piping with no protective insulation shields on the piping where hangers were located.
Support issues with the oleum and ammonia piping have existed at the Facility and were known to management for some time. According to a 2016 inspection report for oleum tanks VT-518 and VT-519, inspectors observed broken pipe hangers and hangers being misused in vertical locations. The Facility’s piping inspection report from 2015 for piping associated with tank VT-520 similarly describes “corroded/damaged or missing pipe supports” and improper wood block supports for pipes. The same conditions were present in 2020 for tank VT-520, with descriptions including “rope supports, “damaged hanger,” “wire hanger,” “loose support,” “needs support,” “pipe resting on the ground,” “pipe resting on rock/conduit,” “damaged pipe support,” “corroded supports,” “pipe supporting other pipe,” “piping not in contact with support,” and “pipe supported by wood.”
Industry-standard API RP 574 sets forth inspection practices for piping systems. With respect to supports, it states, “External visual inspections are performed to determine the external condition of piping, insulation system, painting/coating systems, and associated hardware, and to check for signs of misalignment, vibration, and leakage.” API RP 574, § 10.1. The standard goes on to specify problems to look for in piping supports during the visual inspection:
a) deterioration of protective coatings or fireproofing;
b) evidence of corrosion, especially at or near the foundation attachments;
c) distortion;
d) general physical damage;
e) movement or deterioration of concrete footings;
f) failure or loosening of foundation bolts;
g) insecure attachment of brackets and beams to the support;
h) restricted operation of pipe rollers or slide plates;
i) insecure attachment or improper adjustment of pipe hangers…;
j) broken or defective pipe anchors; and
k) restricted operation of pulleys or pivot points in counterbalanced piping systems.
API RP 574, § 10.1.4.1.
With respect to piping lying on the ground, the standard also specifies that inspection plans for piping plans should include the soil-to-air interface. API RP 574, § 7.2(g). As API 570 explains, the soil-to-air interface is an area in which external corrosion may occur on partially buried pipe, and thus the standard calls on owners/users to provide specific attention to the need for inspection of piping systems for specific types and areas of deterioration, including the soil-to-air interface. API 570, §§ 3.1.87 and 5.4.2.
Industry-standard MSS SP-58 states, “Pipes shall not be suspended directly from each other unless formal calculations are performed and accepted by the responsible Piping Design Engineer. If no calculations have been made, the individual hanger for each horizontal pipe in a vertical bank shall have the load transmitted directly to the rods, not the pipe above. Care shall be taken to size the rod appropriately for the total load at the support point.” MSS SP-58, § 6.13.
Industry-standard API 570 provides that external inspections “shall include surveys for the condition of piping hangers and supports. Instances of cracked or broken hangers, “bottoming out” of spring supports, support shoes displaced from support members, or other improper restraint conditions shall be reported and corrected.” API 570, § 5.5.4. For cold piping systems carrying ammonia, industry standards do not recommend wooden or concrete supports. See MSS SP-58, § 5.5.1 and Table A1.
Industry-standard MSS SP-58 states, regarding insulated lines: “For piping systems using Type 40 protection shield for insulated piping, see Table A3 for spacing. Insulation protection shields shall be provided to protect the vapor barrier of insulation on cold lines. Under no circumstances shall hangers, supports or guides be applied directly to horizontal pipe or tubing on vapor barrier lines.” MSS-SP-58, § 5.5.1. The standard further provides: “The connections to pipe attachments shall be outside the insulation so that movement of the line shall not cause damage to the insulation.” MSS-SP-58, § 5.5.2.
The condition of the oleum and ammonia piping at the Facility, with its supports, either improper or damaged, piping lying atop other piping, and missing insulation protective shields, is contrary to acceptable limits, as defined in MSS SP-58.
Respondent’s inspections were deficient in not identifying the piping support deficiencies in the oleum tanks (VT-518 and VT-519), and in the ammonia tanks (VT-520, HST-1, and HST-2), in violation of the requirement that inspections and tests performed on process equipment follow recognized and generally accepted good engineering practices. 40 C.F.R. § 68.73(d)(2).
In not timely addressing the piping support deficiencies at its Facility, Respondent violates the mechanical integrity requirements of the RMP Regulations at 40 C.F.R. § 68.73(e).
Mechanical Integrity – Ammonia Piping Insulation Damage, Corrosion, and Icing
EPA inspectors observed that, in some areas, ammonia piping associated with Horton Spheres HST-1 and HST-2 was lying on the ground, not insulated, with atmospheric corrosion. EPA inspectors also observed suspended piping with missing insulation jackets, exposed piping ends, and brackets piercing insulation in the absence of protective shields to spread the load of the brackets, resulting in breached vapor barriers, icing, and corrosion. EPA inspectors also observed that insulation jackets were missing from ammonia piping associated with tank VT-520, exposing foam insulation.
The exposed insulation core allows moisture to reach the carbon steel piping, which can lead to “corrosion under insulation” or “CUI.” Industry-standard API RP 574 discusses the need for a thorough CUI inspection to gauge whether CUI could occur, stating in the relevant part: “External inspection of insulated piping systems should include a review of the insulation system integrity for conditions that could lead to CUI and signs of ongoing CUI. API 570 documents requirements of a CUI inspection program. Sources of moisture can include rain, water leaks, condensation, deluge systems, and cooling towers. The two forms of CUI are localized corrosion of carbon steel and chloride [stress corrosion cracking] of authentic stainless steels. See API 571 for additional details on CUI mechanisms.” API RP 574, § 7.4.4.
The standard also discusses insulated piping systems susceptible to CUI, stating as follows: “Certain areas of piping systems are potentially more susceptible to CUI, including: … e) carbon steel piping systems, ones insulated for personnel protection, operating between 10F (-12C) and 350F (175C); CUI is particularly aggressive where operating temperatures cause frequent or continuous condensation and reevaporation of atmospheric moisture. … k) piping systems with deteriorated insulation, coatings, and/or wrappings; bulges or staining of the insulation or jacketing systems or missing bands (bulges can indicate corrosion product buildup) … .” API RP 574, § 7.4.4.1.
The Respondent’s representative indicated that the typical operating temperature of the Horton Spheres and associated piping is between 20F and 30F, indicating that the ammonia piping system is potentially more susceptible to CUI.
The companion standard, API 570, states about CUI Inspection:
Inspection for CUI shall be considered for externally-insulated piping in areas ortemperature ranges that are susceptible to CUI shown as indicated in API 574. CUI inspections may be conducted as part of the external inspection. If CUI damage is found during spot checks, the inspector should inspect other susceptible areas on the equipment.
Although external insulation may appear to be in good condition, CUI damage may still be occurring. CUI inspection may require removal of some or all insulation. If external coverings are in good condition and there is no reason to suspect damage behind them, it is not necessary to remove them for inspection of the equipment. CUI damage is often quite insidious in that it can occur in areas where it seems unlikely.
Considerations for insulation removal are not limited to but include:
a) history of CUI for the specific piping system or comparable piping systems;
b) visual condition of the external covering and insulation;
c) evidence of fluid leakage (e.g. stains or vapors);
d) whether the piping systems are in intermittent service;
e) condition/age of the external coating, if known;
f) evidence of areas with wet insulation;
g) the type of insulation used and whether that insulation is known to absorb and hold water.
API 570, § 5.5.6.
The same piping areas associated with the Horton Spheres had been inspected by the facility, as referenced in 2016 and 2021 piping inspection reports. Piping diagrams related to ammonia piping under HST-1 and HST-2 include the following observations made about this piping during an April 4, 2016 visual inspection:
“missing/damaged insulation,” “minor general surface corrosion throughout,” “pipe & insulation observed to be wet,” “exposed pipe iced over throughout,” “missing insulation,” and “insulation and pipe wet.” Similar conditions were observed five years later during the visual inspection conducted on March 23, 2021. The 2021 diagram includes the following observations for the same areas: “missing/damaged insulation,” “minor general surface corrosion throughout,” “exposed pipe iced over throughout,” and “missing insulation/wet.”
The Facility’s piping inspection reports from 2020 for piping associated with tank VT-520 similarly describes: “Damaged, missing, and poorly sealed insulation was noted throughout the system” and “minor to moderate corrosion was noted on all exposed piping throughout the system experiencing coating failure” and recommended “repairing/replacing insulation” and “cleaning piping of corrosion scale and coating.”
Respondent’s own inspections in 2016 and 2021 identified conditions indicating likely CUI for the piping areas associated with the Horton Spheres. Further, the Respondent’s 2020 inspection report recommended repairing insulation and cleaning the piping of the corrosion scale to address the corrosion for piping associated with tank VT-520. At the time of EPA’s inspection, Respondent had not informed EPA of any plans to address the damaged insulation, icing or corrosion or to probe beneath the areas of insulation to ensure that corrosion was not occurring.
Respondent’s failure to ensure the integrity of its ammonia piping by conducting the full piping inspection called for in API 570 is a violation of the requirement that inspections and tests performed on process equipment follow recognized and generally accepted good engineering practices. 40 C.F.R. § 68.73(d)(2).
In not timely addressing the corrosion deficiencies at its Facility, Respondent violated the mechanical integrity requirements to address equipment deficiencies in the RMP Regulations at 40 C.F.R. § 68.73(e).
Mechanical Integrity – Condition of Oleum Containment Area
During the Inspection, EPA inspectors observed that the secondary containment area of oleum tank VT-746 was coated but that there was severe buckling, amounting to a coating failure, on the concrete floor of the containment area.
Industry-standard NACE SP0294 contains a section dealing with safety and environmental concerns, specifically containment areas for oleum storage areas. NACE SP0294 states: “The area around sulfuric acid and oleum storage tank systems should be arranged such that any spillage goes to an appropriate containment and neutralization system. NACE Publication 6G197/SSPC-TU 229 contains information on coating systems for containment areas. See NFPA 30, OSHA 29 C.F.R. 1910 (j), and 40 CFR 112 Subparts A, B, and D.” NACE SP0294, § 6.3 (emphasis added).
The standard referred to in the above quotation, NACE Publication 6G197/SSPC-TU 229, describes maintaining good adhesion to the concrete substrate as critical to the performance of the coating performance, which depends on both the properties of the concrete substrate and the properties of the primer. NACE Publication 6G197, § 4.5. The standard also discusses thermal effects, specifically shrinkage from cure and aging: “Polymers and coatings often shrink volumetrically due to cross-linking or solvent evaporation. … When the stress and movement from shrinkage exceed the tensile strength of the coating or adhesive strength between the coating and the concrete, the failure is usually evident as cracking in the coating and/or disbondment from the concrete. … Fillers, reinforcement, and thin coats are commonly used to reduce shrinkage and distribute shrinkage stress.” NACE Publication 6G197, § 4.6.1.
The severe buckling witnessed by EPA inspectors in the concrete floor of the oleum containment area indicates either a flaw in the adhesion, perhaps due to thermal effects, or in the quality of underlying concrete. EPA inspectors determined that the containment structure, buckled as it was, was not an appropriate containment system.
It is unknown how long the floor of the oleum containment area was in such a condition. In 2022, Respondent’s inspection report notes that the dike sealant was deteriorating, with a recommendation made to repair the sealant, just as with oleum tank VT-747. Respondent represents that it has a proposed plan to repair the containment areas of both VT-756 and VT-747.
By failing to timely address this evident process equipment deficiency, Respondent has violated the mechanical integrity requirements of the RMP Regulations at 40 C.F.R. § 68.73(e).
Mechanical Integrity – Insufficient Inspections of Oleum Tanks
During the investigation, EPA learned that Respondent conducted internal inspections of tanks VT-518 and VT-519, containing oleum, but Respondent did not utilize linear ultrasonic thickness (“UT”) scanning methods for the tanks to evaluate “bathtub ring corrosion.”
Industry-standard NACE SP0294 provides that “Linear UT scans shall be used if bathtub-ring corrosion or erosion-corrosion is suspected. The results of the external visual and UT inspections in accordance with Paragraphs 5.5 and 5.6 may indicate that internal inspection should be performed sooner. Tanks experiencing leakage should be inspected internally and repaired within 3 months after leakage was first discovered and mitigated.” NACE SP0294, § 5.1.3.1. The footnote explains that “Linear ultrasonic thickness scans are much more likely to detect bathtub-ring corrosion and local erosion-corrosion than spot UT measurements. UT scans are continuous thickness measurements (B-scans) along a straight path conducted manually or with a magnetic crawler.” NACE SP0294, FN 10. The footnote goes on to explain precisely how to conduct linear UT scans.
According to interviews conducted by a Respondent representative in April 2022, in the aftermath of the oleum release from VT-518, employees reported seeing fuming from underneath the insulation in the middle of the tank and oleum coming down the sides of the tank during the incident, and periodic smoking from the top of the tank during the months prior to the oleum release.
These visual observations by Respondent’s employees indicate that tank VT-518 was experiencing leakage that should have led to an internal inspection of tank VT-518 within three months of the initial observations, in accordance with the industry standard, NACE SP0294, § 5.1.3.1.
EPA reviewed inspection reports for tank VT-518 dated June 2, 2014 (internal), March 27, 2019 (external), July 13, 2020 (internal) and March 30, 2022 (external). The 2014 inspection report contains observations and photographs consistent with bathtub-ring corrosion. The narrative of the inspection report dated June 2, 2014 identifies the following issues, among others: several instances of corrosion in the tank and “Grooving in shell beneath 2008 flush patch repair,” which the report describes as “possibly the result of a weak acid attack.” Photographs from Respondent’s 2014 full internal inspection report includes one entitled “Grooves Below Flush Patch,” which EPA has identified as “bathtub-ring corrosion.”
EPA has determined that the thickness testing done on the oleum tanks was insufficient to identify bathtub-ring corrosion. Respondent conducted ultrasonic thickness testing (“UT”) scans on tank VT-518 on April 16, 2013, March 27, 2019, April 14, 2020, and March 23, 2022. The scans Respondent conducted do not appear to be linear UT scans, as NACE SP0294 indicates should be performed if bathtub-ring corrosion is suspected.
The inspection reports for tank VT-518 dated March 27, 2019 (external), July 13, 2020 (internal) and March 30, 2022 (external) indicate continued corrosion issues with tank VT-518, including an observation in 2020 of “[m]ultiple holes noted in roof towards the center of the tank at 90 and 180” and the following observation documented in 2022:
Crystallized Product was noted on and around the first shell course manway at 180, the first shell course behind the tank insulation as well as on the support grillage and floor sections at 180. The suspected source is from the roof at 180° where epoxy type temporary repairs are present on the roof edge, an 18″ roof nozzle and a ~2″ nozzle near the 18″ nozzle. Insulation jacketing has corroded away in an area directly beneath the temporary repairs. These repairs appear to be failing in areas around the 18″ roof nozzle.
VT-518 External Visual Inspection Report, March 30, 2022.
Based on its review of these internal tank inspection reports, EPA believes bathtub-ring corrosion was present in tank VT-518 in 2014 and corrosion continued to manifest itself in the following years. In not conducting a linear UT scan of tank VT-518 as indicated by the tank inspection reports and in accordance with NACE 0294, AdvanSix violated the mechanical integrity requirement in the RMP Regulations that “inspections and tests performed on process equipment follow recognized and generally accepted good engineering practices.” 40 C.F.R. § 68.73(d)(2).
In not timely addressing the corrosion deficiencies on tank VT-518 at its Facility, it violated the mechanical integrity requirement in the RMP Regulations to address equipment deficiencies at 40 C.F.R. § 68.73(e).
EPA also reviewed inspection reports for the companion tank also containing oleum, tank VT-519, dated March 27, 2014 (external), April 17, 2017 (internal), April 20, 2017 (external), and February 28, 2020 (external). The inspection reports contain observations and photographs of corrosion, with possible bathtub-ring corrosion. The narrative of the inspection report dated April 17, 2017 for the internal inspection conducted between April 3-7, 2017, notes the following corrosion issues, among others:
“The roof has 2 holes (temporarily patched) and severe corrosion in the vicinity of the conservation vent nozzle. In this vicinity, the roof to rim angle weld has through wall corrosion in 2 places.”
“2 areas of severe localized corrosion were observed in the upper shell course at approximately 0 degrees. (Beneath temp patch)” An internal scab patch was observed on the shell beneath the RV nozzle at approximately 31’ elevation. Severe localized corrosion was observed on the patch. A corner of the fillet weld had corroded through wall. A pinhole was observed in the termination of the patch longitudinal weld (patch is made of 2 sections welded vertically). Severe corrosion was observed on the shell beneath the patch, and adjacent to this area.”
“UT thickness inspection and follow up thickness scans identified areas of the lower shell course where external corrosion had resulted in material wastage to below or near shell course minimum allowable thickness.”
The corrosion in tank VT-519 appears to be located around the same height, the filling height, as the corrosion present in tank VT-518. EPA also reviewed a set of photographs associated with the 2017 internal inspection of tank VT-519. EPA believes that photographs DSCN5884, DSCN5885 and IMG_1997 of tank VT-519 exhibit bathtub-ring corrosion. The facility conducted UT scans on tank VT-519 in 2017. However, the UT scans Respondent conducted do not appear to be linear UT scans, as NACE SP0294 indicates should be performed if bathtub-ring corrosion is suspected.
The inspection reports for tank VT-519 dated March 27, 2014, April 17, 2017, April 20, 2017 and February 28, 2020 also indicate corrosion issues with tank VT-519. For example, the external inspection report from 2020 notes that, “Moisture is getting between the shell insulation and the tank due to a gap in the insulation and the shell where it meets the roof.”
In its investigation findings after the oleum release, Respondent noted that holes in the roof of tank VT-518 were caused by intermittent breathing through the conservation vent when the vent scrubber line (SE-141) became plugged. The holes in turn allowed the infiltration of moisture.
Respondent had previously identified holes in the tops of oleum tank VT-518 in inspections in 2019 and 2020, and in oleum tank VT-519 in 2017. In oleum tanks, introducing moisture can create dilute sulfuric acid.
Internal corrosion of unlined carbon steel tanks by dilute sulfuric acid is addressed by industry code NACE SP0294. The code explains: “Dilute sulfuric acid causes rapid attack of carbon steel. Dilute acid can be formed by absorption of moisture from the outside air, entry of rainwater, or improper cleaning. Entry of moisture from the outside should be controlled by proper venting and by minimizing air movement caused by natural convection.” NACE SP0294, § 2.8.1.1.
To ensure the continued integrity of its oleum tanks with conservation vents, Respondent must ensure that moisture is not introduced into the tanks via these roof holes by promptly identifying and addressing the cause of the holes and timely repairing the holes.
Based in its review of these tank inspection reports, EPA believes bathtub-ring corrosion was present in tank VT-519 in 2017 and continued to manifest itself in the years following. Given that the 2017 photographs of tank VT-519 indicate possible bathtub-ring corrosion, and tank VT-518, a tank in similar service to tank VT-519, also exhibited bathtub-ring corrosion, Respondent should have considered this hazard in managing tank VT-519.
In not conducting a linear UT scan of tank VT-519 after seeing its tank inspection reports in accordance with NACE 0294, Respondent violated the mechanical integrity requirement in the RMP Regulations that “inspections and tests performed on process equipment follow recognized and generally accepted good engineering practices.” 40 C.F.R. § 68.73(d)(2)
In not timely addressing the corrosion deficiencies on tank VT-519 at its Facility, Respondent violated the mechanical integrity requirement in the RMP Regulations to address equipment deficiencies at 40 C.F.R. § 68.73(e).
Process Hazard Analysis
One of the industry standards Respondent identified as applying to the oleum tanks, VT-518 and VT-519, is NACE SP0924. This industry standard identifies bathtub-ring corrosion as a hazard for tanks with corrosion and infiltration issues. NACE SP0924, § 5.1.3.2.1
Based on EPA inspectors’ review of the Marine Operations process hazard analysis (“PHA”) from 2017 for oleum tanks VT-518 and VT-519, the PHA did not consider the potential hazard of bathtub-ring corrosion in the oleum tanks. Specifically, the process hazard analysis did not identify bathtub-ring corrosion as a deviation, an intermediate event, or a significant process safety scenario, nor did the PHA identify any safeguards to put in place to prevent bathtub-ring corrosion or make any recommendations with regard to the risk.
Moreover, the PHA conducted after the oleum release, the May 5, 2022 Marine Operations PHA revalidation report, also did not identify bathtub-ring corrosion as a potential hazard.
Respondent’s failure to consider and address the potential hazard of bathtub-ring corrosion identified by industry standard NACE SP0294 in its PHA is a violation of the requirements for PHAs in the RMP Regulations, at 40 C.F.R. § 68.67(a), (c)(1).
Process Safety Information
EPA also determined that Respondent’s oleum tanks VT-518 and 519, acetaldehyde pressurized vessel tank HT-187 and ammonia tank VT-520 were not labeled in accordance with industry standards.
Under the RMP Regulations, owners and operators of stationary sources must compile and maintain up-to-date safety information related to the regulated substances, processes, and equipment, including codes and standards used to design, build, and operate the process. See 40 C.F.R. § 68.48(a). Further, owners and operators must ensure that the process is designed in compliance with recognized and generally accepted good engineering practices. See 40 C.F.R. § 68.48(b).
The relevant recognized and generally accepted good engineering practices for purposes of the caprolactam manufacturing process at the Facility includes the following three industry standards:
- American Petroleum Institute Standard 650, Welded Steel Tanks for Oil Storage, 10th ed. (November 1998) (API 650);
- American Society of Mechanical Engineers VIII, Boiler & Pressure Vessel Code (2004) (ASME VIII); and
- National Fire Protection Association 400, Hazardous Materials Code (2010) (NFPA 400).
With respect to oleum tanks VT-518 and VT-519, tank drawings, inspection documentation, responsive documentation provided by Respondent, and field observations for oleum tanks VT- 518 and VT-519 indicate the tanks are inspected to API 653 and NACE SP0924 standards, and that both tanks are constructed to API 650 standards.
During the field inspection, EPA inspectors observed no legible nameplates on tanks VT-518 and VT-519.
Industry Standard API 650 states: “A tank made in accordance with this standard shall be identified by a nameplate similar to that shown in Figure 8-1.” API 650, § 8.1.1. Nameplates identify information such as the tank standard, diameter and height, capacity, design metal temperature, maximum operating temperature, and fabrication manufacturer. Id.
Respondent’s reports for the external inspections of tanks VT-518 and 519 in March 2019 and February 2020, respectively, noted as an issue in each report that the tanks were neither marked nor labeled and recommended that a label be applied to the tanks.
In the years since the reports were issued, Respondent did not address the lack of labeling on either tank VT-518 or VT-519.
With respect to ammonia tank VT-520, a concrete tank, industry-standard NFPA 400 provides, “Visible hazard identification sign in accordance with NFPA 704, Standard System for the Identification of the Hazards of Materials for Emergency Response, shall be placed … (1) On stationary aboveground tanks.” NFPA 400, § 6.1.8.2.1.
EPA inspectors observed during the Inspection that tank VT-520 had no NFPA 704 placard, although an NFPA 704 placard was on the stairway leading to the roof of the tank. Respondent’s failure to comply with the process safety information standards set forth in industry standards API 650, ASME VIII, and NFPA 400 violates the requirements in the RMP Regulations to “ensure that the process is designed in compliance with recognized and generally accepted good engineering practices.” See 40 C.F.R. § 68.48(b).
ORDER
Respondent agrees to undertake the action and provide the information specified below (the “Work”).
a. Within thirty (30) days of the effective date of this Order, identify a person, subject to acceptance by EPA, competent to undertake the Work specified herein;
b. Within thirty (30) days of receipt of EPA’s written acceptance of the person competent to undertake the Work, Respondent shall submit to EPA for approval a work plan and schedule (“Work Plan and Schedule”) for the implementation of improvements to the Facility to address the conditions described in Paragraphs 17 through 95, above.
The Work shall be consistent with the safety protection provided by the industry standards MSS SP-58-2009, API 570, API RP 574, NACE SP0294, NACE 6G197/SSPC-TU-229, API 650, ASME VIII, and NFPA 400.
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