Respondent is the owner and/or operator of a gas processing plant that has on-site for use/storage 55,126 pounds of sulfur dioxide, 8,240 pounds of anhydrous ammonia, 130,000 pounds of butane, and over 10,000 pounds of hydrogen. Respondent has three RMProgram level 3 covered processes, which store or otherwise use sulfur dioxide, butane, and hydrogen. Sulfur dioxide, butane, and hydrogen are stored or used in amounts exceeding their applicable thresholds of 5,000 pounds, 10,000 pounds, and 10,000 pounds, respectively. Anhydrous ammonia is stored below the applicable threshold of 10,000 pounds; however, in extreme caution, the Respondent has registered the chemical for RMProgram level 3.
On September 28, 2021, the EPA conducted an on-site inspection of the RMProgram related records and equipment to assess the Respondent’s compliance with the RMProgram requirements and the implemented recognized and generally accepted good engineering practices (RAGAGEP) for its covered processes at its Facility. At the time of the inspection, or as otherwise indicated, EPA observed the following:
a. the Respondent maintained an aboveground storage tank containing hydrogen at more than the RMP threshold quantity of 10,000 pounds applicable to flammable substances. The Respondent had not included hydrogen as an RMP-regulated substance in its historical RMP submissions to the EPA. The EPA notes that this issue was identified as Recommendation No. 1.1 in the Respondent’s March 2021 Process Safety Management/ Risk Management Program (PSM/RMP) Compliance Audit without a corresponding date of completion or responsible official assigned.
b. The following equipment did not comply with RAGAGEP.
i. The inspectors observed inadequate and inconsistent labeling of process piping and equipment throughout the Facility. Specifically, piping was not labeled to indicate contents and direction of flow in the following areas:
(1) on sulfur dioxide (SO2) and ammonia piping leading from the loading and anhydrous ammonia storage tank area to the process;
(2) on SO2 piping leading from the storage tank to the process;
(3) at the SO2 injection point into the Hydrotreater;
(4) at the ammonia injection point into the Hydrotreater; and
(5) throughout the butane storage and blending area.
Lack of clear piping and equipment labeling is inconsistent with the following RAGAGEP:
Section 3.1 of The American Society of Mechanical Engineers (ASME) A13.1-2015 states, “Positive identification of the contents of a piping system shall be by lettered legend, giving the name of the contents in full or abbreviated form … Arrows shall be used to indicate direction of flow. Where flow can be in both directions, arrows in both directions shall be displayed. Contents shall be identified by a legend with sufficient additional details such as temperature, pressure, etc., as are necessary to identify the hazard.”
ii. Inspectors observed that the anhydrous ammonia storage tank was not provided with any protective bollards to protect from potential vehicular impact from anhydrous ammonia delivery trucks. Facility personnel indicated that tanker trucks delivering ammonia drive up to and park immediately adjacent to the tank to facilitate bulk loading of ammonia into the system once every six (6) weeks.
Section 5.6.6 of The American National Standards Institute – Compressed Gas Association (ANSI-CGA) G-2.1 (2014) states, “Adequate provisions shall be made to protect all exposed piping from physical damage, which could result from impact by moving machinery, automobiles or trucks, or any other equipment at the facility.”
Section 6.7.1 of ANSI-CGA G-2.1 (2014) states, “Containers and appurtenances shall be located or protected by suitable barriers to avoid damage by trucks or other vehicles.”
iii. Inspectors observed that the anhydrous ammonia unloading area lacked an emergency shutdown button that could be used to shutdown tank loading operations in the event of an emergency.
Section 7.4.2 of ANSI-CGA G-2.1 (2014) states, “A check valve shall be installed on the tank liquid fill connection if it is located below the maximum liquid level. A remotely operated shutoff valve shall be installed on other connections located below the maximum liquid level.”
iv. Inspectors observed that the nameplate on the bulk butane storage tank was illegible and was not clearly marked with the required information. Section UG-116 of the 2010 ASME Boiler and Pressure Vessel Code (2011a Addenda; dated to July 1, 2011), and Section 5.2.8.3 of NFPA 58 (2014) require official certification marks, maximum allowable working temperatures and pressures, minimum design metal temperature, Manufacturer’s serial number, and year built.
c. The EPA requested annual operating certification records to show that operating procedures were being reviewed annually to ensure they are current and accurate. The Respondent did not provide these records as part of its post-inspection response to the EPA. In an October 28, 2021 email to the EPA, the Respondent indicated: “Do not have these records but will begin documenting these in our training platform (XXXXXXXXX) going forward.”
d. The Respondent did not demonstrate that inspections and tests were performed on process equipment, inspection and testing procedures follow RAGAGEP, and the frequency of inspections and tests of process equipment are consistent with applicable manufacturers’ recommendations and good engineering practices, and occur more frequently if determined to be necessary by prior operating experience. Specifically:
i. API 510, Section 6.2.1.1 (2014) states that pressure vessels shall be inspected by an inspector at the time of installation. Facility personnel reported that they did not have a U-1A form for the bulk butane storage tank, and Respondent had not conducted the tests or inspections required. Also, the Respondent was unable to provide records of inspections or tests conducted on the SO2, anhydrous ammonia, or butane storage tanks, either at the time of initial installation or since.
ii. API 570 (2016), Section 6.2.1 states that piping shall be inspected in accordance with code of construction requirements at the time of installation, which should document baseline thickness measurement to be used as initial thickness readings for corrosion rate calculations. Process piping associated with the butane storage and blending area was installed at the time of the bulk storage tank, in approximately 2016. SO2 and ammonia process piping was installed at the time those two processes were constructed at the Facility in 2017. Facility personnel were unable to provide records of inspections or tests conducted on any process piping at the Facility.
iii. American Petroleum Institute (API) 510 section 5.1.2.1 requires an inspection plan to be developed by the inspector and/or engineer and a corrosion specialist to be consulted when needed to designate potential damage mechanisms and specific locations where damage mechanisms may occur. While onsite, inspectors observed areas of surface corrosion on piping, specifically in the butane storage and blending area. In addition, facility personnel indicated that an incident occurred in 2017 related to corrosion and a tank weld issue on the bulk SO2 tank that necessitated an internal tank inspection. Also, in response to EPA’s request for mechanical integrity inspection and testing reports, including any available non-destructive testing (NDT) for the bulk SO2, anhydrous ammonia, and butane storage tanks and associated piping, the Respondent only provided records of four (4) recent external visual inspections for the bulk anhydrous ammonia tank conducted by the third-party company that owns the tank. Therefore, Respondent had not developed or implemented an appropriate inspection plan to address corrosion.
e. The Respondent indicated that it performed a pre-startup safety review (PSSR) in advance of bringing the Hydrotreater online in 2017, which included installation and start-up of the SO2 and anhydrous ammonia loading and storage processes. Inspectors reviewed the PSSR checklist that the Respondent filled out for this project in 2017 and observed that several items within the checklist were not completed or designated with a “Yes,” and that the checklist was missing final signature and approval to denote that all action items identified during the PSSR process were completed prior to startup.
f. The first compliance audit conducted for the butane storage and blending process was completed on December 17, 2020, more than four years after the date of the Respondent’s initial submission for the process, September 07, 2016. The first compliance audit for a covered process is due three years after the initial submission date.
g. The Respondent produced the most recent incident investigation report; however, the date the investigation began was not identified and there was no way for the inspection team to confirm when the investigation began.
ALLEGED VIOLATIONS
Based on EPA’s compliance monitoring investigation, the EPA alleges that the Respondent violated 40 C.F.R. Part 68, the codified rules governing the Act’s Chemical Accident Prevention Provisions and Section 112(r) of the Act, 42 U.S.C. § 7412(r), when it:
a. Operated a process with more than a threshold quantity of a regulated substance, as determined under 40 C.F.R. § 68.115, without complying with the requirements of 40 C.F.R. Part 68 by no later than the date on which the regulated substance was first present above a threshold quantity in the process, as required by 40 C.F.R. § 68.10(a)(3);
b. Failed to document that equipment complies with RAGAGEP, as required by 40 C.F.R. § 68.65(d)(2);
c. Failed to review the operating procedures as often as necessary to assure that they reflect current operating practice, including changes that result from changes in process chemicals, technology, and equipment, and changes to stationary sources. Respondent did not certify annually that these operating procedures were current and accurate, as required by 40 C.F.R. § 68.69(c);
d. Failed to perform inspections and tests on process equipment; inspection and testing procedures did not follow RAGAGEP; and the frequency of inspections and tests of process equipment were not consistent with applicable manufacturers’ recommendations and good engineering practices, as required by 40 C.F.R. § 68.73(d)(1)-(3);
e. Failed to confirm in the PSSR that prior to the introduction of a regulated substance to a process, safety, operating, maintenance, and emergency procedures were in place and are adequate, as required by 40 C.F.R. § 68.77(b)(2);
f. Failed to certify that it had evaluated compliance with the provisions of 40 C.F.R. Part 68, Subpart D at least every three (3) years to verify that procedures and practices developed under this subpart were adequate and being followed, as required by 40 C.F.R. § 68.79(a); and
g. Failed to prepare a report at the conclusion of an incident investigation which included the date the investigation began, as required by 40 C.F.R. 68.81(d)(2).
TERMS OF PAYMENT
Respondent consents to the payment of a civil penalty, which was calculated in accordance with the Act, in the amount of $174,095.00, which is to be paid within thirty (30) calendar days of the Effective Date of this CAFO.
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