The previous chapter provided background information on offshore oil and gas operations, introduced the potential safety concerns and challenges of offshore operations, and explained how these operations have been changing over the past 20 years. Chapter 3 discusses relevant information about the Bureau of Safety and Environmental Enforcement’s (BSEE’s) role in overseeing these offshore operations. The chapter begins by reviewing the Outer Continental Shelf Lands Act (OCSLA) and how the statute guides BSEE’s mission before describing BSEE’s organization and overall budget. The chapter discusses the agency’s regulatory framework under Title 30 of the Code of Federal Regulations and the types of requirements mandated in the regulations. The chapter describes aspects of BSEE’s inspection workforce, including staffing, training, and the types of inspections conducted—including the kinds of enforcement actions available to the inspector. The chapter then reviews current strategies used by BSEE to target and conduct inspections, relevant procedures for analyzing incident investigations, and recent initiatives for collecting and analyzing data. The chapter closes by examining best practices of domestic and international regulators.
BSEE’s Mission and OCSLA
The OCSLA is the main governing statute that granted authority to the U.S. Department of the Interior (USDOI) for administering federal laws governing mineral exploration and development of the U.S. outer continental
shelf (OCS). As discussed in Chapter 1, USDOI assigned responsibility for administration of the law to two newly created agencies, the Bureau of Ocean Energy Management (BOEM), which awards and manages leases, and BSEE, which issues and enforces regulations intended to ensure safe and environmentally responsible exploration and production.1 These agencies were created from the Minerals Management Service (MMS) in the aftermath of the Deepwater Horizon event.
According to the agency’s website, BSEE’s mission2 is to “promote safety, protect the environment, and conserve resources offshore through vigorous regulatory oversight and enforcement.” When it was created in 2011, BSEE inherited federal responsibility of submerged lands on the OCS and for the offshore safety program from MMS, which had earlier inherited the program from the U.S. Geological Survey. OCSLA3 dictates that OCS lessees are responsible for the safety of all activities on their leases and facilities. Specifically, OCSLA (see Box 3-1) states that lease holders “maintain all places of employment within the lease area or within the area covered by such permit in compliance with occupational safety and health standards and, in addition, free from recognized hazards to employees of the lease holder or permit holder or of any contractor or subcontractor.” OCSLA mandates the use of Best Available and Safest Technology (BAST) on all new drilling and production operations, “wherever practicable” and “economically feasible.” BSEE has developed a three-stage process4 for identifying candidate technologies for BAST determinations, and BSEE recently initiated an annual evaluation process to assess critical safety barriers used in drilling operations and production operations to determine if certain currently used equipment meets the definition. As discussed in more detail below, OCSLA requires BSEE to schedule an annual on-site inspection of each facility on the OCS, as well as periodic unannounced on-site inspections.
Sharing responsibility with BSEE, BOEM manages the development of offshore resources in an environmentally and economically responsible way. BOEM’s jurisdiction includes resource assessments; providing appropriate
1 Initially, oversight authority under OCSLA rested with the U.S. Geological Survey. MMS had authority for offshore oil and gas operations from 1982 to 2010. In June 2010, MMS was renamed the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) as a response to the Deepwater Horizon incident. On October 1, 2010, BOEMRE’s royalty and revenue management functions were transferred to a new bureau, the Office of Natural Resources Revenue. On October 1, 2011, USDOI reorganized the remainder of BOEMRE into BSEE and BOEM.
access to energy and mineral resources; environmental, economic, and fiscal reviews; scientific research; and leasing, plan approvals, and lease management throughout the life cycle of OCS energy projects. As of February 2020, BOEM managed more than 2,600 active leases on the OCS.
Organization and Budget
BSEE,5 headquartered in the Washington, DC, area, sets policy through its six national programs,6 but those policies are implemented and the agency’s inspection work occurs in one of three geographic regions—the Gulf of Mexico (GOM), the Pacific, and Alaska.7 The GOM region is divided into five districts: New Orleans, Houma, Lafayette, Lake Charles, and Lake Jackson (see Figure 3-1). BSEE’s total offshore safety and environmental enforcement budget for fiscal year (FY) 2020 was just more than $188 million and is similar to budget amounts for the two previous fiscal years—$187 million for FY2019 and $186 million for FY2018. These amounts do not include the nearly $15 million provided each year for Oil Spill Research.8
BSEE is funded partially through offsets from cost recovery fees, inspection fees, and a portion of OCS rental receipt collections, which have averaged $69 million over the past 3 years.9 After personnel costs (approximately 50 percent of BSEE’s overall budget), aviation services is the next largest budget item. For the current year (FY2020),10 BSEE has roughly
880 total employees, compared to 776 employees in 2019 and 819 in 2018. Almost half of the 880 total employees for the current fiscal year work in the three regions.
As noted above, OCSLA mandates BSEE to implement and enforce offshore safety and environmental regulations and broadly outlines its responsibilities for complying with federal law, as do other statutes—such as the Federal Oil and Gas Royalty Management Act (FOGRMA) and the National Environmental Policy Act.11 These statutes, along with agreements with other agencies12 such as the U.S. Coast Guard (USCG), the Pipeline and Hazardous Materials Safety Administration, and the U.S. Environmental Protection Agency (USEPA), provide the framework for BSEE to implement its offshore inspection program. For example, USCG regulations cover the safety of vessels—such as mobile drilling rigs and floating platforms—and include issues such as seaworthiness and evacuation and fire protection capacity. The agreement between the two agencies generally involves the
division and coordination of inspection duties and other matters. In its current form, BSEE has jurisdiction over the safe and responsible exploration, development, and production of offshore energy resources, which it implements through a comprehensive program of permitting, regulations, compliance monitoring and enforcement, technical assessments, inspections, preparedness activities, and incident investigations.13 The next section discusses BSEE’s regulatory framework under 30 CFR Chapter II that the agency uses to enforce safety and environmental regulations.
30 CFR Chapter II—Bureau of Safety and Environmental Enforcement
BSEE regulates all phases of oil and gas operations on the OCS with the rules contained in 30 CFR Chapter II (Bureau of Safety and Environmental Enforcement, U.S. Department of the Interior).14 Mostly contained in 30 CFR Subchapter B, these regulations (see Box 3-2) cover drilling operations (e.g., casing, cementing, and drilling fluid requirements), well completion (e.g., pressure management), well operations and equipment (e.g., rig and blowout preventer requirements), production safety systems (e.g., emergency shutdown and firefighting systems), platforms and structures (e.g., design and construction), decommissioning activities (e.g., permanently plugging wells and clearing sites), and Safety and Environmental Management Systems (SEMS). Also, the regulatory requirements for oil spills appear in 30 CFR Part 254.15
Shaped over many decades following the original passage of OCSLA in 1953, the majority of the requirements of 30 CFR Part 250 are from standards and recommended practices incorporated into the regulation by reference from organizations such as the American Petroleum Institute (API), the American National Standards Institute, and other private standards development organizations.16 Examples of standards incorporated in 30 CFR Part 25017 include API Recommended Practice (RP) 14J for Design and Hazards Analysis for Offshore Production Facilities (§ 250.800(b) and (c)); 250.901(a) and (d); API RP 2D for Operation and Maintenance of Offshore Cranes (§ 250.108); and API Standard 53 for Blowout Prevention Equipment Systems for Drilling Wells (§ 250.730).
The regulations in 30 CFR Part 250 provide detailed, prescriptive requirements that mandate specific actions as a way to achieve compliance.
16 T. Trosclair, BSEE, presentation to the committee, March 2019.
Such BSEE requirements target specific aspects of an ultimate problem in oil and gas operations and have been characterized as “micro level” (TRB 2018). As an example, the cementing and setting requirements for well casings and liners in § 250.462(e) are provided in a detailed table. The requirements further specify that the pressure integrity test (as in § 250.427) is to be conducted “below the surface casing or liner and all intermediate casings or liners,” and “after drilling at least 10 feet but no more than 50 feet of new hole below the casing shoe.” BSEE regulations can focus on specific “means” to achieve an action in drilling fluid-handling areas, such as installing a specific safety device, ventilation system, or gas monitor as in § 250.459 (TRB 2018). Inspectors examine safety equipment using a list (Potential Incidents of Noncompliance [PINCs])18 of inspection items derived from safety and environmental regulations under 30 CFR Part 250.
PINCs are more prescriptive and tend to focus on hardware-related issues and whether the hardware is maintained according to a particular standard.
BSEE regulations can also command the achievement of certain “ends,” such as the ability to evacuate all personnel from a facility or ensuring the “structural integrity for the safe conduct of” operations while considering the specific conditions of the facility’s location (see § 250.900). In addition, regulations to achieve certain “ends” can often mandate that “a given practice or component possess a certain capability.” As an example, § 250.490(p)(5) states that the use of welding is to be kept to a minimum, and that “welding must be done in a manner that ensures resistance to sulfide stress cracking” (TRB 2018). PINCs generally map to a type of offshore facility (see Table 3-1).
After the Deepwater Horizon explosion in 2010, BSEE was criticized for the regulations in 30 CFR Part 250, which consisted mostly of detailed, “micro-level” requirements. In the National Commission’s Report to the President, the authors questioned BSEE’s “command and control, prescriptive approach to regulation” that “did not adequately address the risks generated by the offshore industry’s new technologies” and push into deeper water (Chief Counsel 2011, p. 68). A separate study questioned whether such technical requirements, shaped over several decades, were able to keep up with the rapid technological advances that allowed industry to drill in deeper water (NAE and NRC 2012, p. 112). Yet, this criticism tends to overlook the agency’s supplemental requirement of submitting a Deepwater Operations Plan (DWOP)19 when an operator uses nonconventional production or completion technology.
In the past decade, BSEE mandated the SEMS rule, which is based on API RP 75. These requirements were considered more “performance based,” focused on a broader program goal or problem, and can be described as “macro-level” regulations. Examples for macro level include employing a hazard or risk analysis or ensuring that the workplace is free from recognized hazards (TRB 2018). The next section discusses BSEE’s safety management system requirements found under SEMS.
30 CFR Part 250—Subchapter S—Safety and Environmental Management Systems
BSEE mandated the use of the SEMS20 rule as a way to reduce risks and integrate and manage the safety of offshore operations, but not be a
TABLE 3-1 Types of Offshore Facilities and Associated BSEE PINCs
|Types of Drilling Rigs||Types of Production Platforms|
|PINC Category||Jack Up||Semi-Submersible||Drillship||Platform and Workover||Caisson and Well Protector||Minor Shallow Water||Major Shallow Water||Deepwater|
|G PINCs (General)||•||•||•||•||•||•||•||•|
|E PINCs (Pollution)||•||•||•||•||•||•||•||•|
|D PINCs (Drilling Operations)||•||•||•||•|
|B PINCs (Well Operations)||•||•||•||•|
|W PINCs (Well Workover)||•||•||•||•|
|C PINCs (Well Completion)||•||•||•||•|
|A PINCs (Decommissioning)||•||•||•||•|
|P PINCs (Production)||•||•||•||•|
|L PINCs (Pipelines)||•||•|
|M PINCs (Measurement and Site Security)||•||•|
|H PINCs (Hydrogen Sulfide)||•||•||•||•||•||•||•||•|
|I PINCs (Crane/Material Handling)||•||•||•||•||•||•||•|
|F PINCs (Platform Electrical)||•||•||•||•|
|Z PINCs (USCG/Personal Safety)||•||•||•||•||•||•||•||•|
|Office PINCs (G, E, D, C, W, A, B, P, L, R, M, O)||•||•||•||•||•||•||•||•|
NOTE: BSEE = Bureau of Safety and Environmental Enforcement; PINC = Potential Incident of Noncompliance; USCG = U.S. Coast Guard.
paperwork exercise.21 The SEMS rule requires the lessee to provide written plans and procedures for 17 elements, such as hazards analysis, management of change, safe operating procedures, and safe work practices (see Box 3-3), but the regulation does not target specific safety or risk reduction outcomes. For example, the rule directs the operator to have a hazard identification process but does not identify what that process should look like. SEMS intended to shift the focus of the industry’s safety efforts from meeting minimum standards of a PINC list to requiring that the lessee provide a written account of program goals, such as identifying and controlling all significant hazards. The lessee is responsible for implementing its SEMS tools effectively for itself and its contractors. Although it is considered a “macro-level” regulation, SEMS could be described more as a “means-based” approach (TRB 2018).
Operators are required to have the elements of their SEMS programs audited by an accredited third party within 2 years of implementing SEMS and starting operations, and every 3 years thereafter. API’s Center for Offshore Safety (COS), an accreditation body recognized by BSEE under 30 CFR § 250.1922, accredits and lists audit service providers (ASPs).22 COS also assists operators in implementing and maintaining an effective SEMS, offering support during the process by the sharing of SEMS resources, such as guidance documents, good practices, and industry performance measures. COS has recently released guidance for operators on audit plans (what should be in a written plan), audit reports (a standardized way of documenting results), and corrective action plans (CAPs) (how to respond to deficiencies in the audit report listed in the CAP).23 COS has also instituted a new program called “Safety Shares” that communicates one-page incident reports directly with offshore workers and companies. These reports review the details of incidents and near misses, as well as any lessons learned.24
As discussed above, BSEE was created in 2011 and inherited the offshore safety program from the MMS. OCSLA mandates that BSEE implement and enforce offshore safety and environmental regulations and conduct both an annual scheduled inspection and periodic unscheduled (unannounced) inspections of all oil and gas operations on the OCS; BSEE also investigates incidents and oversees industry spill preparedness.25 This section describes information about BSEE’s inspection workforce including staffing levels, experience, and allocated budgets. Next, the section discusses inspector training and the types of inspections conducted.
Inspection Workforce and Budget
As noted above, almost half of BSEE’s 880 total employees for the current fiscal year work in the three regions, and each region has an office for field operations that oversees all of the approximately 90 engineers and 120 inspectors who review application plans and conduct safety programs. In addition to managing the inspection process, the field operations office in the GOM also oversees functions in each of the five districts, such as
24 COS Safety Shares: https://www.centerforoffshoresafety.org/Guidelines-and-Reports/Safety%20Shares.
conducting incident investigations, administering helicopter contracts, and coordinating between the five districts.26 As shown in Table 3-2, aviation services is a large part of BSEE’s $200 million overall budget—approximately 16 percent to 20 percent over each of the past 3 years.
Since 2012, the agency’s overall budget has doubled, and BSEE was authorized to hire more inspectors in the GOM.27 Because of the pay gap between the federal government and private industry, BSEE instituted a specialty rate for inspectors and engineers to help hire and retain qualified personnel. BSEE has experienced considerable turnover since the Deepwater Horizon incident and has hired many new inspectors. A clear majority of the approximately 120 inspectors has less than 8 to 10 years of BSEE inspection experience (see Figure 3-2). Still, over the past 8 years, the average age of an inspector has remained around 45 years old.28
More than three-fourths of all inspection personnel are stationed in the GOM region, with each GOM district office grouped by well operations and production operations (see Figure 3-3). Supervisory engineers oversee all engineers, for both well and production operations, and all supervisory inspectors, who manage inspectors. Given the number of GOM facilities, the division of labor between well and production operations is reasonable. Field operations offices in the Pacific and Alaska regions also sort engineers and inspectors into well operations and production operations, yet operations in those regions demonstrate more cross training between operation types because of lower activity levels, fewer facilities to inspect, and a fewer inspectors to perform each task.
Table 3-3 presents staffing levels for each inspection and engineering position in each GOM district. New Orleans, Houma, and Lafayette have a larger proportion of the offshore platforms and more than two-thirds of the inspectors in the GOM region.
In 2013, the BSEE Director established a training framework for all personnel that inspect facilities on the OCS. Under Interim Policy Document (IPD) Number 2013-04,29 the agency identified four performance levels, each with its own coursework and on-the-job training requirements. Inspectors start at the first level and must demonstrate competency at each level before
26 T. Trosclair, BSEE, presentation to the committee, March 2019.
27 See budget justifications at https://www.bsee.gov/what-we-do/budget-planning-performance/budget.
28 T. Trosclair, BSEE, presentation to the committee, March 2019.
TABLE 3-2 BSEE Budget Obligations for Helicopters and Inspector Labor by Region and Fiscal Year
NOTES: BSEE = Bureau of Safety and Environmental Enforcement; GOM = Gulf of Mexico. Budget obligations by fiscal year, includes expenditures on helicopters and other transportation.
a GOM region FY2016 ($33.7 million) helicopter contract was funded in FY2015. Pacific region FY2017 ($1.5 million) helicopter contract was funded in FY2016.
SOURCE: Data provided by BSEE, June 25, 2020.
moving to the next level. The IPD also outlined training requirements for inspectors to maintain eligibility to perform inspections. As noted above, a majority of inspectors have less than 10 years of BSEE inspection experience, yet almost 90 percent have attained a performance level of 3 or 4.30
Although a training program has existed at the agency for more than 30 years, BSEE created the National Offshore Training Program31 in 2013, offering courses and programs for engineers and inspectors to help strengthen core skills and competencies. In 2016, BSEE developed competency modeling for mission-critical positions, such as Inspectors and Investigators under Series 1801 and Oil Spill Preparedness Analysts under Series 1301. This competency framework lists required skills or expertise, describes the attributes of the skill, and lists the proficiency necessary for each inspector level. The objective was to identify the knowledge and skills for current personnel and to help acquire and develop BSEE’s future workforce.32
By 2018, BSEE had initiated a revised Bureau Interim Directive (BID) to address issues with the agency’s training program. The goal of BID Number 2018-053N was to provide a framework for inspector personnel in well operations and production tracks to build skills and competencies through formal classroom training and on-the-job training that are necessary for work on the OCS. Building on the previous IPD, BID Number 2018-053N establishes minimum qualification and training standards, provides
30 T. Trosclair, BSEE, presentation to the committee, March 2019.
32 T. Trosclair, BSEE, presentation to the committee, March 2019.
TABLE 3-3 Number of BSEE Personnel in GOM District by Well and Production Operations
|New Orleans||Houma||Lafayette||Lake Charles||Lake Jackson|
|District Manager and Staff||5||3 + 2v||5||5||6|
|Well Ops.||Prod. Ops.||Well Ops.||Prod. Ops.||Well Ops.||Prod. Ops.||Well Ops.||Prod. Ops.||Well Ops.||Prod. Ops.|
NOTE: BSEE = Bureau of Safety and Environmental Enforcement; GOM = Gulf of Mexico; Ops. = Operations; Prod. = Production; v = vacant.
SOURCE: BSEE, data as of October 2019.
guidance for personnel to acquire skills and knowledge outside of the classroom environment, and formalizes training requirements and documentation for BSEE’s four performance levels.33 For example within 2 years, all Level 1 trainees are expected to achieve Level 2 status by completing eight core courses common to both well operations and production tracks and an additional three courses for each track. Additional specialized courses, such as Intermediate Incident Investigation and SEMS, are administered at various undetermined time frames during the training sequence.34 Much of the revised BID intended to address recommendations from a 2016 U.S. Government Accountability Office (GAO) report on the hiring, retaining, and training of staff at the U.S. Department of the Interior.35
In 2018, BSEE had received a report from Booz Allen Hamilton (BAH) that studied the agency’s current training program, reviewed similar programs at the federal level, and identified options and considerations that would allow BSEE to build a more comprehensive and consistent Talent Development Model for its inspectors. The BAH report noted that BSEE’s current certification system was often determined at the supervisory inspector’s discretion and lacked standardization and rigor. Occasionally BSEE will waive certain course requirements for newly hired inspectors if they have taken similar courses or training in previous jobs, but the process of how these courses can be waived appears to be performed in an inconsistent manner. BSEE does require inspectors to take 10 days of courses annually, but the agency does not have a requirement for regular recertification.36 While this annual requirement may encourage continual learning, it does not permit inspectors to demonstrate that the necessary abilities and knowledge for performing their jobs are maintained. In fact, BSEE inspectors have suggested that specific areas for improvement could include better on-the-job training and more advanced courses that help increase their knowledge base.37
BSEE’s current documentation processes are manual and paper based. Through more process standardization and automation and by using more electronic data systems, such as DOI Talent,38 the BAH report notes that BSEE could dedicate more resources to the training of inspectors instead of process administration and documentation.39
Currently, BSEE uses multiple “siloed” systems to evaluate and monitor inspector performance and advancement, including the federal General
33 T. Trosclair, BSEE, presentation to the committee, March 2019.
34 T. Trosclair, BSEE, presentation to the committee, March 2019.
36 T. Trosclair, BSEE, presentation to the committee, March 2019.
37 Teleconference with BSEE inspectors, November 2019.
39 T. Trosclair, BSEE, presentation to the committee, March 2019.
Schedule levels, the four-inspector-level model, and the individual inspector evaluation process. Integration of the systems is possible but requires the support and participation of the labor union and the development of a competency framework as a link between systems. Attempts to implement modifications would benefit from a change in management strategy. With the BAH report, BSEE has identified issues with its current training process and will pursue possible solutions. For example, BSEE will implement “in-house computer based training modules for inspection tasks.” The intent is to create training modules that demonstrate proper inspection procedures and include examples of actual “inspectable” components. To date, BSEE’s training program continues to transform and is still considered a work in progress.40
Inspections by Activity Type
Using multidiscipline teams typically ranging from two to four people, BSEE conducts regular safety and environmental inspections of offshore drilling rigs and production facilities and inspects equipment and control systems for well operations and production operations. Enforcement begins with the review of relevant paperwork. Inspection personnel usually approach the platform by helicopter and observe the facility and surrounding water.41 Once on the facility, inspectors walk around to view the general condition of the platform and examine components or equipment using a list of prescriptive PINCs,42 which tend to focus on hardware-related issues and whether the hardware is maintained according to a particular standard. PINCs are listed as questions that correspond to some of the regulations under 30 CFR Part 250. When the inspector identifies a PINC with an answer of “NO,” then the inspector can issue an Incident of Noncompliance (INC)43 to the operator, which alerts the operator of a violation.44 Depending on the severity, a violation can use one of two enforcement actions (warning or shut-in). Violations that are less severe will prompt a warning INC, which must be corrected within a certain amount of time. Shut-in INCs are more serious and are issued for a single component, a part of a facility, or the entire facility. An operator must correct shut-in violations before continuing the activity in question. Also, BSEE can impose a
40 T. Trosclair, BSEE, presentation to the committee, March 2019.
43 A list of all INCs issued by BSEE is found at https://www.data.bsee.gov/Company/INCs/Default.aspx.
44 Enforcement actions for violations include W, Warning; C, Component Shut-in; and S, Facility Shut-in.
civil penalty of up to $45,463 per violation per day if the operator does not correct the violation in the time permitted, or if the violation resulted in harm or damage to life or the environment.45
BSEE activities also include some of the following: supplemental inspections as part of its Risk-Based Inspection (RBI) program (discussed below), witnessing operators’ required SEMS audits, metering component inspections, pipeline inspections, incident investigations, witnessing blowout preventer tests, and pre-drill and pre-production inspections of offshore facilities. Table 3-4 shows the number of BSEE annual OCS inspections for all regions by all inspection types between 2009 and 2019. Inspections for well and production operations have been consistent over the past 8 years, while pipeline inspections have increased dramatically over the same period. Typically, meter inspections are done to ensure the accuracy of the meters used to determine royalty payments and are not considered safety inspections. As noted above, the total number of drilling rigs (see Table 2-3) and the total number of production platforms (see Table 2-4) decreased over this same period.
Although only mandated to inspect rigs once per year, BSEE inspects all active drilling rigs that are conducting drilling, completion, workover, and abandonment operations every month. BSEE also inspects a certain percentage of non-rigs conducting workover and abandonment operations on a more frequent basis. In addition, BSEE is mandated to conduct periodic unannounced inspections on rigs conducting drilling, completion, workover, and abandonment operations. BSEE personnel inspect systems or components such as blowout preventers or well control systems, accumulator or charging systems, mud- or fluid-handling systems, electrical systems, crane or material handling equipment, and emergency systems (such as emergency disconnect sequence and autoshear or deadman functions).46 Each inspection is different depending on the rig activity at that time, but inspectors generally know what activities they will perform based on the drilling reports that companies are required to submit regularly. However, rig conditions change frequently, and inspectors have the flexibility to change the focus of the inspection.47
46 J. Richard, BSEE, presentation to the committee, December 2018.
47 Teleconference with BSEE inspectors, November 2019.
TABLE 3-4 Number of BSEE Annual Inspections on U.S. OCS by Type Between 2009 and 2019
|Type of Inspection||2009||2010||2011||2012||2013||2014||2015||2016||2017||2018||2019|
NOTE: BSEE = Bureau of Safety and Environmental Enforcement; OCS = Outer Continental Shelf.
a Although included in the table, meter inspections are typically done to ensure the accuracy of the meters used to determine royalty payments and are not considered safety inspections.
SOURCE: Data provided by BSEE, December 2020.
OSCLA mandates that BSEE conduct an announced on-site inspection of all production facilities at least once per year, as well as periodic unannounced on-site inspections and investigations of incidents. Statutes also mandate that the agency conduct on-site meter witnessing and site security (for FOGRMA). Agency agreements48 require BSEE to conduct additional inspections on behalf of the USCG (e.g., manned production facilities), the U.S. Department of Transportation (e.g., pipelines), and the USEPA (e.g., pollution discharge and water quality). For production operations, BSEE inspects systems or components such as gas detection, fire detection and fire control, emergency shutdown, subsurface safety devices, surface and subsurface pumps, surface and subsurface wellhead and flowlines, pressure vessels, structural aspects, and systems for crane operations.49
The inspectors know the platform layout and existing components before reaching the facility and can review historical data for a specific platform prior to an inspection. All OCS regions review all testing paperwork and inspect and witness the testing of all primary safety components; however, in some circumstances, the GOM region will test a certain percentage of safety devices associated with the components, with an option of expanding the scope if any of the devices fail. In the Pacific Region, BSEE personnel are viewed as “another risk barrier” and perform two complete inspections of all components and safety devices every year, in addition to partial and follow-up inspections because of a lower level of activity. Table 3-5 shows the percentage of all annual inspections conducted by each region. The GOM region conducts more than 90 percent of all annual inspections, whereas the Pacific and Alaska regions conduct a much smaller percentage. As explained to the committee, while the Pacific Region has fewer facilities that are closer to shore, these platforms tend to be older and take longer to inspect. Also, the public tends to make a lot of “environmental demands” on the regulator.50
This section reviews relevant strategies used by BSEE to help prioritize inspections. The section discusses the annual inspection plans that are developed by each of BSEE’s three regions. Next, the section examines how BSEE uses SEMS audit results and incident data. The section then explains BSEE’s RBI program and how it is used to target facilities for additional scrutiny.
49 J. Richard, BSEE, presentation to the committee, December 2018.
50 Teleconference with BSEE inspectors, November 2019.
TABLE 3-5 Percentage of BSEE Annual Inspections Conducted on the U.S. OCS by Region
NOTE: BSEE = Bureau of Safety and Environmental Enforcement; GOM = Gulf of Mexico; OCS = Outer Continental Shelf.
SOURCE: Data provided by BSEE, December 2020.
The section closes by reviewing recent initiatives undertaken by BSEE that analyze existing data to better identify current and emerging hazards.
Annual Inspection Plans
BSEE Manual Chapter 650.1—Offshore Inspection Program provides the general directive for the agency’s Inspection Program. The BSEE director updated the Manual Chapter in November 2018 to include an overall strategy that uses the following three-tiered approach to ensure that the agency meets its inspection requirements:
- A nationally required inspections tier (known as the Red List) includes inspections required by statute, regulations, interagency agreements, other agency directives, and priorities identified by the BSEE Director.
- A regionally required inspections tier (known as the White List) is developed within the region and includes inspections required by regional agreements and regional directives, and priorities identified by the Regional Director.
- A supplemental inspections tier (known as the Blue List) includes inspections that can supplement the inspections defined in the Red List and White List. Blue Lists are developed within the region.
Manual Chapter 650.1 defines roles and responsibilities of the personnel involved and provides an overall time line for producing an annual inspection plan.51 Guided by this document, each region forms an Inspection Strategy Committee composed of relevant managers and subject-matter experts to develop its annual inspection plan—which outlines all inspection activities to be accomplished in the upcoming fiscal year. These plans include assessments of the available resources needed to conduct inspections on the number of projected “inspectable” units (which could be a complex, or individual facilities, or specific components within a facility). These regional committees use current analyses and relevant data (e.g., industry and incident trends) to identify potential gaps in resources required to perform Red List and White List requirements. An annual inspection plan includes all three inspection tiers (Red, White, and Blue Lists) that a region will implement for the upcoming fiscal year.52 The three regions (GOM, Pacific, and Alaska) perform all Red List and applicable White List inspections each year. Blue List inspections are undertaken on an ad hoc basis, depending
51 T. Trosclair, BSEE, presentation to the committee, March 2019.
52 L. Herbst, BSEE, presentation to the committee, September 2019.
on a region’s needs, priorities, and available workforce, but a region is not expected to complete the entire list.
Within each tier, the annual inspection plans for each region list each objective and define relevant procedures for carrying out the inspections. Whether announced or unannounced, inspections are conducted as complete, partial, or follow-up inspections for all well operations (such as drilling, completion, and workover) and production operations. Additional inspections are included for abandonment activities, pipelines, ancillary requirements (e.g., USCG and construction), regional measurement (e.g., meter proving), and environmental compliance.
Given the amount of activity in the GOM, its Annual Inspection Plan presents more detail and outlines the projected mandatory, required, and nonmandatory inspections and investigations for both well operations and production operations under the Office of District Field Operations. The plan ensures that all mandatory items are accomplished, but also identifies and describes additional regional inspections deemed important based on risk analysis. For example, mandatory national requirements (Red List) under well operations call for announced inspections at least once per year and unannounced inspections periodically throughout the year. Regional policy (White List) requires an additional inspection of rig operations once per month or to conduct sample inspections on production facilities flagged as a higher risk.53
Also, the GOM Office of Region Field Operations includes additional mandatory, required, and nonmandatory inspections that personnel in each district are expected to address. For example, district personnel are required to inspect the corrosion and asset integrity of structures as part of the annual announced inspections. In addition, the Office of Safety Management (OSM), as part of GOM’s regional office White List requirements, coordinates and works with district personnel to implement RBIs. As described to the committee, another OSM requirement calls for witnessing approximately 40 percent of all SEMS audits by third-party auditors to ensure compliance with applicable regulations; these inspections are also included on the White List for the GOM region.54
All three regions track completed inspections against the targets of their annual plans. Given potential fluctuations in oil and gas operations, BSEE reports that the three-tiered approach of the annual inspection plans provides flexibility to modify its overall inspection strategy and adjust activities as necessary to meet inspection goals.55
53 T. Trosclair, BSEE, presentation to the committee, March 2019.
54 T. Trosclair, BSEE, presentation to the committee, March 2019.
SEMS Audit Results
The 17 SEMS elements outline a framework of risk management practices that an operator must incorporate into its overall approach to safety and environmental risk management. As noted above, 30 CFR § 250.1900 dictates that the lessee (usually an operator) must develop, implement, and maintain a SEMS program, and that this program is required to be audited by an ASP. The operator must submit an audit plan to BSEE at least 30 days before the audit, and the agency reserves the right to modify the list of facilities proposed for auditing. The audit report (including findings, observations, deficiencies, and conclusions) and the CAP that addresses any deficiencies are required to be sent to the BSEE region that is overseeing them, along with a schedule for completing deficiencies or issues in the CAP.
As a rule, the regions have primary responsibility to monitor and receive audit reports and CAPs. Within the GOM region, BSEE OSM receives the audit results from the ASP, reviews the findings and CAP, and tracks the CAP through to completion. The OSM will then follow up with the operator to verify that the CAP issues were completed. This tracking activity occurs outside the annual inspection process, although the OSM does share some findings at a GOM monthly meeting if it determines that a SEMS issue should filter down to inspectors in the field.56 The OSM briefed the committee that it can include findings and deficiencies from SEMS audits as part of an operator’s profile when it targets and conducts an RBI (discussed below). Separate from and in addition to the formal audit process, the OSM will sometimes instruct inspectors to request supporting SEMS documents and inquire about a company’s SEMS practices.57
Outside of the SEMS audit cycle and CAP verification process, BSEE will evaluate potential gaps and look for trends in the operators’ SEMS elements. When evaluating and understanding these gaps, trends, and the operator’s profile at the regional level, BSEE’s OSM will note if this is a new operator, examine all incidents for this operator, and review any compliance notifications from the USCG. If, during a regular inspection, an inspector observes unsafe behavior by personnel on a facility, the inspector can forward these concerns to the OSM for follow-up. If this concern is warranted, then the OSM can conduct a Subpart O audit58 on an operator’s personnel to test training and relevant competency for well control and production
56 J. Mathews, BSEE, presentation to the committee, September 2019.
57 See BID Number 2018-033G: Risk Based Inspections. See https://www.bsee.gov/sites/bsee.gov/files/bid-2018-033g-risk-based-inspections.pdf; while BID Number 2018-033G was superseded by Directive Supplement Number 651.05-DS-G, dated October 2, 2018, the content is largely the same. Personal email communication, Tim McGraw, BSEE, July 6, 2020.
58 30 CFR Part 250, Subpart O—Well Control and Production Safety Training: https://www.law.cornell.edu/cfr/text/30/part-250/subpart-O.
safety training. In addition to Subpart O audits, the OSM has piloted the use of a “safety culture” or safety management form (see Box 3-4) that can be used during inspections. In use since March 2019, the form contains six questions that inspectors can answer about observations during their visits to facilities. If inspectors notice a cultural or management issue while on a facility based on answers to these questions, then they can document that concern and send it to the OSM, which could then conduct a more focused inspection.59
Information from incident, investigation, and audit reports can be used to modify an operator’s audit scope or can be used to justify a BSEE-directed audit per 30 CFR § 250.1925. According to the Bureau’s Manual Chapter 503.1 on SEMS oversight and enforcement, a BSEE-directed audit is prompted by a referral from the region. While the Manual Chapter does list perceived SEMS deficiencies that warrant enforcement, no INCs have been issued, and even if they were, it would typically result in only a “warning” to submit the required information as soon as possible. A BSEE-directed audit can be triggered by an operator’s performance, for example, if the company has a history of incidents and does not appear to be managing safety risks well. These “directed audits” can focus on general topics, specific SEMS elements, or specific operations. As of March 2020, only two BSEE-directed audits had occurred. The use of the BSEE-directed audit
59 J. Mathews, BSEE presentation to the committee, March 2019.
authority was associated with improved workplace safety performance for the two completed audits and could be an effective enforcement tool in the future.60 For example, if flagged for a directed audit, operators with specific performance concerns (e.g., rates of injuries or mechanical failures) could be encouraged to propose approaches for assessing and addressing these performance gaps. In addition, directed audits could be used to verify that CAPs were completed appropriately and validate that the actions effectively addressed identified gaps.
As noted above, a large part of BSEE’s safety inspection program is to conduct announced and unannounced inspections every year to meet the agency’s statutory mandates and regional requirements and to perform inspections on behalf of other agencies. BSEE conducts thousands of these inspections annually, the vast majority of which occur in the GOM. BSEE promotes compliance through these inspections by examining components or equipment using its PINC list.61 Prior to the inspection, BSEE inspectors are able to review historical data for a specific platform prior to an inspection. When a violation occurs, BSEE inspectors can issue an INC depending on the severity of the incident. To help determine patterns, BSEE staff in the OSM review these data and other data points on regular basis. Table 3-6 lists the total INCs that BSEE has issued over the past 10 years by each PINC category.62 As noted above, the total number of platforms has decreased over the past 10 years. Still, the most frequently issued INCs are for violations of G PINCs (General Operations Category) and P PINCs (Production Operations Category), and in particular the top five INCs include G111, G110, G112, P412, and G115.63
These particular INCs are broad in nature and include wording such as:
G-111: DOES THE LESSEE MAINTAIN ALL EQUIPMENT IN A SAFE CONDITION TO PROVIDE FOR THE PROTECTION OF THE LEASE AND ASSOCIATED FACILITIES?
60 S. Kaczmarek, BSEE, presentation to the committee, March 2020.
61 A list of all INCs issued by BSEE is found at https://www.data.bsee.gov/Company/INCs/Default.aspx.
63 J. Mathews, BSEE, presentation to the committee, September 2019.
TABLE 3-6 Total Number of INCs Issued by BSEE by Year and PINC Category
|A PINCs (Decommissioning Activities)||1||0||0||2||26||14||12||5||0||1||0|
|B PINCs (Well Operations and Equipment)||0||0||0||0||0||0||0||48||75||44||33|
|C PINCs (Oil and Gas Well-Completion Operations)||7||6||8||12||16||15||9||5||0||0||0|
|D PINCs (Oil and Gas Drilling Operations)||31||39||92||56||72||51||30||8||5||5||11|
|E PINCs (Pollution)||119||162||113||136||144||101||115||114||71||83||58|
|F PINCs (Platform Electrical Systems)||97||136||133||100||173||139||110||79||62||47||50|
|G PINCs (General)||821||1,204||1,048||1,099||1,115||939||954||844||608||590||720|
|H PINCs (Hydrogen Sulfide)||31||9||19||8||13||5||6||4||11||2||3|
|I PINCs (Crane/Material Handling Equipment)||73||93||56||71||84||64||35||45||18||27||32|
|L PINCs (Pipelines)||81||142||101||95||95||131||88||82||66||27||54|
|M PINCs (Production Measurement and Site Security)||128||167||170||168||256||438||182||174||151||52||45|
|P PINCs (Production Operations)||705||908||814||839||785||767||774||681||473||401||527|
|W PINCs (Oil and Gas Well-Workover Operations)||11||8||24||45||29||19||8||11||3||2||2|
|Z PINCs (USCG/Personal Safety Guidelines)||244||230||183||153||132||115||214||122||120||91||143|
NOTE: BSEE = Bureau of Safety and Environmental Enforcement; INC = Incident of Noncompliance; PINC = Potential Incident of Noncompliance; USCG = U.S. Coast Guard.
SOURCE: Data provided by BSEE, December 2020.
G-110: DOES THE LESSEE PERFORM ALL OPERATIONS IN A SAFE AND WORKMANLIKE MANNER AND PROVIDE FOR THE PRESERVATION AND CONSERVATION OF PROPERTY AND THE ENVIRONMENT?64
The OSM looks at many indicators when assessing an operator’s individual performance, such as the INC-to-component ratio. This particular indicator, for example, evaluates an operator’s compliance for production operations, by looking at a ratio of the number of INCs issued to the number of components inspected. For well operations, INCs are compared to individual rig inspections, and not components.
By regulation (30 CFR § 250.188), operators are required to notify BSEE of multiple types of incidents, such as fatalities, serious injuries, loss of well control, or fires.65 BSEE reviews all such incident reports and determines the scope and type of investigation that takes place. BSEE conducts two types of formal investigations (Panel and District) and lists them all, along with their status, on the BSEE website.66Table 3-7 shows the number of each type of formal investigation by year. The information from these investigations is also used to generate data points that BSEE uses to determine trends.
Panel investigations BSEE will convene a panel to investigate more serious incidents, including fatalities, serious injuries, or significant pollution events. Panels include personnel from BSEE Headquarters and across the region, and investigations usually take a longer period to complete (sometimes 1 year or more) and require more resources than a “district” investigation. At its conclusion, the panel issues a report that explains how the incident occurred, provides details on possible causes and regulatory violations, and suggests recommendations to prevent recurrence. These recommendations can also lead to BSEE issuing a safety alert, a safety bulletin, or some additional follow-up enforcement action. Panel investigation reports are posted on the BSEE website.67
65 For a list of incident types, see https://www.bsee.gov/what-we-do/incident-investigations/ offshore-incident-investigations or https://www.law.cornell.edu/cfr/text/30/250.188.
TABLE 3-7 Number of Panel and District Investigations by Year
|Year||District Investigations||Panel Investigations|
NOTE: Each investigation is based on the year the incident occurred.
a Data as of December 1, 2020.
District investigations BSEE will conduct a standard investigation of an incident that involves a narrower scope and less serious events using local personnel from where the incident occurred. These district investigations also describe the event, provide details of possible causes and violations, and can suggest recommendations, but are completed in less time and require fewer resources. District investigation reports are posted on the BSEE website.68
Risk-Based Inspection Program
As early as 2008, BSEE (MMS at the time) initiated a risk-based program in two districts (Houma and Lake Jackson District) of the GOM region. This pilot program sought to define both higher-risk and lower-risk facilities and proposed that higher-risk facilities would be inspected every fiscal year, while only half of lower-risk facilities would be inspected every fiscal year.69 Although management in the GOM region recommended expanding this program, the events of the Deepwater Horizon incident in 2010 delayed
69 E. Danenberger, Independent Consultant, presentation to the committee, December 2018. Also, GAO (2017, p. 13) notes that USDOI’s Office of the Solicitor determined that inspecting only half of lower-risk facilities using a component sampling technique would not meet the OCSLA mandate.
its implementation and prompted the agency to reassess its approach to RBIs (GAO 2017). Not until 2013 did BSEE restart a risk-based program by engaging Argonne National Laboratory (ANL) to develop a simple quantitative model that attempted to estimate the risk levels of offshore facilities. As part of the pilot program, BSEE also incorporated aspects of the 2008 pilot program called “blitz inspections” used prior to the Deepwater Horizon incident.
In March 2018, BSEE’s GOM region implemented a formal RBI program supplementing its current annual inspection program. As outlined in BID Number 2018-033G,70 this program would take a more “systematic approach” by employing a quantitative model and subjective performance and risk information to identify facilities with higher risk profiles and focus the appropriate resources. BSEE believed that this program would allow the agency to better monitor those facilities and operational risk profiles, recognize best practices for offshore operations and risk management, and confirm that companies have properly identified, managed, and mitigated risks. Also, the program would promote continuous improvement in risk management for offshore operations and permit BSEE to learn about potential best practices on higher-risk facilities that are exceeding the “norm” (BSEE 2019, p. 3). BSEE’s RBI program is exclusively in the GOM region and consists of two components—facility-based risk inspections and performance-based risk inspections. Each RBI component is a tiered approach that builds on and supplements BSEE’s annual inspection programs (see Figure 3-4) for well and production operations.71 When identifying facilities for each RBI component, BSEE uses a quantitative risk metric and incorporates other qualitative risk factors, such as past inspection performance and operator profiles (e.g., SEMS data, changes in ownership, etc.).
Facility-Based Risk Inspections and the Argonne Model
In 2013, BSEE approached ANL to develop a simple quantitative model that used existing data from the Technical Information Management System database to estimate the potential risk indicator of an offshore complex. As presented to the committee, the ANL model is more of a screening tool and was intended to help BSEE augment its mandatory annual inspections by assigning each production complex a risk metric, indicating its perceived risk and the need for additional inspections. Only
70 See BID Number. 2018-033G: Risk Based Inspections. See https://www.bsee.gov/sites/bsee.gov/files/bid-2018-033g-risk-based-inspections.pdf. Although BID Number 2018-033G was superseded by Directive Supplement Number 651.05-DS-G, dated October 2, 2018, the content in both documents is largely the same. Personal email communication, Tim McGraw, BSEE, July 6, 2020.
71 J. Mathews, BSEE, presentation to the committee, March 2019.
relevant to production platforms in the GOM, the model parameters do not show causation, but provide indicators that a platform has a higher potential for an incident. Common to most risk calculations, the ANL model attempts to define risk as
Risk = Frequency × Consequence
To calculate risk, ANL analyzed platform characteristics and past platform performance data to find any correlation to future platform incidents. The analysis looked at platform characteristics and performance values to determine good indicators of future incidents. Platform characteristics included the component count, the slot count, and whether a complex was considered “major.”72 Inspection performance values included whether a platform had an incident 2 years prior and whether it had an INC or incident in the previous year. The likelihood of a future incident used an equation with five variables with a value of either 0 or 1, if the complex had the characteristic. Frequency factor F can range from 0 to 5, where 0 is
72 “A major platform is defined as a structure with either six or more completions or zero to five completions with more than one item of production process equipment.” See NTL No. 2006-G04: https://www.bsee.gov/sites/bsee.gov/files/06-g04.pdf.
the lowest likelihood of a future incident and 5 is the highest likelihood,73 and is defined as
F = Imaj + Islot + Iinc1 + Iincid1 + Iincid2
Imaj = indicator flag: major complex
Islot = indicator flag: slot count ≥15
Iinc1 = indicator flag: inspection with an INC in previous year
Iincid1 = indicator flag: incident in previous year
Iincid2 = indicator flag: incident 2 years prior
The component count was used to calculate consequence (where C = ncomp), because a larger number of components could indicate a greater production capacity and the presence of more workers on a complex. The risk metric is calculated as
R = (Imaj + Islot + Iinc1 + Iincid1 + Iincid2) × ncomp
An example of the model’s results is shown in Table 3-8.
When the frequency factor or component count is zero, the other factor is used as the risk metric. The results of the ANL model provide a quantitative inherent risk score for all GOM production facilities, but these results are not the sole factor in identifying platforms for additional scrutiny. How the results of the ANL model are used in the RBI flow process is explained
TABLE 3-8 Example of Results from BSEE ANL Risk Metric Model
|Islot||Slot Count ≥15||•||•|
|Iinc1||INC in Previous Year||•|
|Iincid1||Incident in Previous Year||•||•|
NOTE: ANL = Argonne National Laboratory; BSEE = Bureau of Safety and Environmental Enforcement; INC = Incident of Noncompliance.
SOURCE: J. Mathews, BSEE, presentation to the committee, March 2019.
73 J. Mathews, BSEE, presentation to the committee, March 2019.
below. While BSEE only considers it a screening tool, the ANL model may skew inspection priorities toward assets that have a high number of components, which may not be the only indicator of risk.
As presented to the committee, Facility-Based Risk Inspections (FBRIs) target high-consequence, low-frequency events at a unique facility—including both well and production operations. The OSM receives output from the ANL Risk Model, which identifies and ranks the top 25 percent of GOM platforms by their relative-risk metric. OSM staff then research each facility to evaluate other potential impacts associated with the risk of an event, such as the facility’s proximity to shore or environmentally important areas, INC or incident data, the facility’s current or proposed activities, the number of personnel on board, the facility’s production volume, or the operator’s safety record. This FBRI process is presented in Figure 3-5. Through these quantitative and qualitative factors, BSEE identifies the focus topics (or risk drivers) specific to each platform subject to the FBRI, such as hazard analysis, subsea leak detection, safe work practices, personnel training and competency, crane operations, or compressors.
A typical FBRI team consists of both inspectors and engineers. Regardless, the team would need the appropriate subject-matter experts to cover all assigned risk topics. Before scheduling the inspections, the team develops a protocol that includes onshore- and offshore-related questions connected to the focus risk topics identified earlier. The FBRI protocol consists of both the typical district compliance elements and some focused questions related to the operator’s SEMS plan. In part, these questions are to determine if a designated operator has implemented and maintained a SEMS Program that addresses these risk topics at the facility level. The offshore portion of the FBRI is conducted prior to the onshore portion at an operator’s headquarters. A closeout meeting is conducted with the operator to discuss preliminary findings and allow feedback on the FBRI process. After the closeout meeting, the FBRI team sends a conclusion letter with all findings and recommendation and a potential CAP if required to address any of the findings. BSEE reports conducting three FBRIs in 2018 and four in 2019.
Performance-Based Risk Inspections
As described to the committee, Performance-Based Risk Inspections (PBRIs) are focused on more narrow topics of potential risks of well and production operations in the GOM. The OSM reviews recent compliance and incident data to identify trends that might warrant additional attention, such as compressor fires, lifting incidents, or gas releases. Through this analysis, the OSM identifies operators, equipment, or processes with risk-specific concerns or a history of issues to create a list of potential facilities that may require increased oversight. Other facility criteria are also reviewed, such
as complexity, component count, and ANL risk ranking. PBRI can include multiple operators and facilities over several GOM Districts. The PBRI protocol questionnaire includes themes on SEMS and compliance-based topics related to the equipment or component of focus. Prior to the inspection, OSM also develops a document request list for follow-up review. The PBRI process flow is shown in Figure 3-6.
Teams receive training before conducting the unannounced, “blitz” inspections of 15 to 75 facilities (3 to 15 inspections per GOM district) over a 2- or 3-day period. For example, BSEE conducted PBRIs on 67 facilities in 2018 and 57 facilities in 2019. According to the BID Number 2018-033G, BSEE personnel are also instructed to assess effectiveness of an operator’s SEMS “by witnessing the application of safety management principle/processes applied to ongoing operations,” to evaluate the operator’s “understanding of risk and critical risk management principles associated with gas releases.”
After the offshore PBRI, the OSM conducts follow-up reviews in the office of two to three facilities in each GOM district. After an internal BSEE report, the OSM often releases industry safety alerts on findings from the PBRI.
Recent examples of Safety Alerts generated from PBRI include Safety Alert 332, on Crane Hazards, Safety Alert 341, on Fired Vessel Hazards, and Safety Alert 351, on Rig Operations Hazards.
Increased Oversight List
As part of its risk-based strategy, the OSM maintains an increased oversight list (IOL) consisting of GOM production operators who require additional inspection oversight. Once placed on the IOL, an operator can expect quarterly partial production inspections until the operator’s performance improves. An operator can be placed on the IOL74 for any of the following reasons:
- an INC for an incident that results in a shut-in, such as a fatality, serious injury, or pollution event greater than 1 barrel;
- an INC that is forwarded to OSM for civil penalty review;
- an on-site inspection that results in an INC-to-component ratio greater than or equal to 0.1;
- recommendation from regional or district management based on an operator’s history of poor safety or environmental performance; or • an operator that has filed for bankruptcy.
74 J. Mathews, BSEE, presentation to the committee, March 2019.
Monthly Regional Performance Meetings
As noted above, the OSM reviews multiple performance indicators, including daily incident and INC data, to identify its safety-related trends. To help disseminate these trends, OSM holds a monthly meeting with GOM inspectors75 where they consider risk factors of operators and any safety issues and trends that may warrant an increased inspection focus. Specific risk factors discussed include safety concerns such as INCs resulting in a shut-in enforcement action or identified for civil penalty review, operators on the IOL or facilities with a poor performance history, CAP issues noted from SEMS audits, higher INC-to-component ratios, operator financial issues, and uncorrected or failure to correct INCs. Indicators and risk trends can lead to risk-based inspections and increased operator oversight in the form of follow-up inspections or performance improvement plans. BSEE can also use this information to publish guidance documents76 in the form of safety alerts,77 safety bulletins,78 and notices to lessees.79 The number of issued safety alerts and bulletins has increased dramatically over the past decade. In 2010, only 5 safety alerts were issued, whereas 37 safety alerts and bulletins were issued in 2019. For 2020, 32 alerts and bulletins had been released (see Figure 3-7).80
Annual Operator Performance Review
While it monitors operator performance on a monthly basis, BSEE also meets with operators annually and holds an annual performance review to address any recurring safety and environmental concerns. Each year, the OSM meets with at least one-third of GOM operators to discuss their performance data, including the number and type of issued INCs, any relevant incident or investigation reports, findings from SEMS audits or CAP monitoring, and inclusion on the IOL.81
75 J. Mathews, BSEE, presentation to the committee, September 2019.
76 To help disseminate safety information to a larger number of offshore workers, BSEE created the BSEE!Safe program, which texts safety notices directly to frontline workers: https://www.bsee.gov/bseesafe.
81 J. Mathews, BSEE, presentation to the committee, September 2019.
Since the Deepwater Horizon incident, BSEE has initiated several programs that are intended to collect new data, analyze existing data, or make the review of records more efficient.
In an attempt to inform its inspection and SEMS programs, BSEE has stressed the collection and analysis of data from incident reports and near-miss reporting. To aid in this effort, BSEE enlisted the U.S. Department of Transportation’s Bureau of Transportation Statistics in 2013 to develop and manage SafeOCS, a voluntary and confidential near-miss reporting system.82 SafeOCS has since expanded to an industry-wide data repository for equipment failure data as required by 30 CFR §§ 250.730 and 250.803.
The current SafeOCS program collects and analyzes reports of equipment failure and near-miss events on the OCS and consists of three components:
- Well Control Rule. Mandatory reporting of equipment failures, including critical safety equipment failure in drilling and nondrilling operations.83
- Safety and Pollution Prevention Equipment. Mandatory reporting of critical safety equipment failures in production operations.84
- Industry Safety Data. Voluntary reporting of near-miss events on the OCS and other industry safety data.85
Reports are released to the industry, regulators, and interested parties and contain aggregated information, which is meant to complement other collected data and help to identify potential safety issues and trends.
Risk Analysis Committee
In December 2018, BID Number 2018-058N established the Risk Analysis Committee (RAC) and tasked it to focus on the offshore risks to health and the environment that are under BSEE jurisdiction. Relying on available data and the committee’s expertise, the RAC reviews annually the offshore risks with the potential for high-impact, process-safety events and ensures that any gaps in BSEE’s regulatory program are addressed. The RAC will limit its scope to those potential high-impact events protected by physical barrier envelopes—equipment in place to prevent release of energy (i.e., hydrocarbons). Once the RAC selects these events or areas, it will establish a subcommittee for each area, and each subcommittee will then assess the risks and gaps within BSEE’s regulations (including standards incorporated by reference) for their respective high-impact operation area.86
Safety Performance Enhanced by Analytical Review Program
To advise and support RAC and other data analysis committees, BSEE established a Safety Performance Enhanced by Analytical Review (SPEAR) committee to explore the potential use of advanced data analysis tools with current data to identify current and emerging safety and environmental hazards related to energy operations on the OCS. The SPEAR committee is exploring the use of potential data analysis vendors who could provide machine learning and artificial intelligence support services for data mining on existing BSEE data sources. Members on the SPEAR program team are
86 T. McGraw, BSEE, presentation to the committee, March 2020. See also BSEE FY2021 Budget Justification at https://www.bsee.gov/what-we-do/budget-planning-performance/budget.
collaborating with the Advanced Supercomputing Division at the National Aeronautics and Space Administration to assess machine-learning techniques and tools for use in helping BSEE determine precursors to significant incidents on the OCS.87
Vital Statistics Program
Launched in 2017, this initiative will use existing data and information relevant to BSEE’s mission and operations to assist the agency’s decision making through data visualization and trend analysis. Once implemented, the program will link information from across the agency to develop “crosscutting performance measures” that will support the analysis of current processes and programmatic functions. The vital statistics program will allow for more data analysis and discovery measures and will produce measures in the following seven focus areas: Lease Life Cycle Activities; Permitting; Environmental Stewardship; Inspections; Incidents and Investigations; Technical Resources; and Human Resources.88
Historically, inspectors have spent a significant portion of their time offshore reviewing records rather than conducting physical inspections. To help increase the time spent on physical inspections, BSEE initiated a process that allowed inspectors to review some records electronically before flying offshore. BSEE reports that the initiative has decreased overall costs and led to an approximately 10 percent increase in physical, offshore inspection time.89 However, the committee was briefed that not all operators make full use of eRecords software. Approximately 85 to 90 percent of (mostly deepwater) production operators currently use eRecords. Because there is not a requirement for digital record-keeping, it is not currently in use by well drilling operators.90
As part of its Statement of Task, the committee was asked about best practices employed by other U.S. regulatory agencies and international
87 T. McGraw, BSEE, presentation to the committee, March 2020. See also BSEE FY2021 Budget Justification at https://www.bsee.gov/what-we-do/budget-planning-performance/budget.
90 J. Richard and T. McGraw, BSEE, discussion with the committee, September 2019.
regulators that are applicable to and could be used, in the committee’s judgment, to enhance BSEE’s offshore inspection program. This section first reviews how the USCG uses a risk-based inspection methodology for offshore facilities. The section also examines the USCG’s use and oversight of third-party organizations that inspect commercial vessels. Next, the section looks at value-added practices and the use of safety management systems in the offshore regulatory regimes of Canada, the United Kingdom, and Norway.
U.S. Coast Guard
The USCG and BSEE share many of the jurisdictional and regulatory responsibilities for offshore energy development. In 2002, the USCG authorized BSEE (MMS at the time) to conduct safety inspections aboard oil and gas platforms on its behalf in accordance with 33 CFR Part 250, Subchapter N and collaborated with BSEE to develop procedures and a list of PINCs, also known as “personal safety (USCG) PINCs” or “Z-PINCs.”91 In addition to conducting safety inspections for the USCG, BSEE has established other Memoranda of Agreement (MOAs) with the USCG that involve cooperation and coordination of inspection duties, such as MOA OCS-07, which promotes and encourages consistent oversight of and cooperation between BSEE’s SEMS and USCG’s safety management systems (SMSs), and MOA OCS-05, which clarifies roles and responsibilities between BSEE and the USCG when investigating incidents on the OCS. This collaboration aims to reduce redundancy and ensure consistency, given the limited resources of both agencies.92
In 2016, the Eighth USCG District established a risk-based inspection methodology used as a targeting tool for inspecting certain OCS facilities.93 The methodology divides the potential inspection targets into three tiers or categories: Low Performers, Average Performers, and High Performers. Their goal is to create a risk ranking of facilities and to allocate inspection person-hours so that two-thirds are spent on the Low Performers, one-fourth is spent on Average Performers, and one-twelfth is spent on High Performers. The methodology establishes risk values for static criteria, such
93 See Policy Letter 03-2016 Risk-Based Resource Allocation Methodology at https://www.dco.uscg.mil/Portals/9/OCSNCOE/References/Policy%20Ltrs/D8/D8%20PL%20032016.pdf?ver=2018-12-04-184635-073.
as the regulatory scheme and age and class of the target facility as well as recurring elements, such as the time since the facility’s last inspection and its operational status. Including a range of performance indicators in its assessment allows the USCG to track performance, update rankings of facilities to reflect changes, and reallocate resources as necessary. In briefing the committee, the USCG acknowledged that this risk-based approach is a work in progress. The methodology is not a complete measure of risk—it does not include safety culture, for example, and it is not the sole source of information driving the USCG’s operational priorities. Inspection scheduling uses this tool in conjunction with other information sources.94 As part of its annual inspection plan, BSEE announced that it intends to use the USCG’s risk analysis methodology to conduct joint inspections on platforms for both well and production operations that are identified as highest risk.
Alternate Compliance Program (ACP)
Under the authority of 46 U.S.C. § 3316, the USCG can delegate to a recognized classification society certain statutory survey and certification functions for U.S. flagged vessels, such as reviewing and approving plans, conducting inspections, and issuing a certificate of inspection.95 Before being recognized, the classification society must request USCG approval per the requirements under 46 CFR Subchapter A. Once the USCG approves and recognizes a classification society (or recognized organization [RO]), the RO may use classification society rules, international conventions, and an approved U.S. Supplement (which ensures that class rules correspond to U.S. regulations) to perform the delegated functions relevant to commercial vessel review and inspection.96 Once an RO is part of the ACP,97 the USCG will accept functions performed by and statutory certificates issued by the RO as equivalent to those performed or issued by the Coast Guard, as long as the classification society maintains compliance with its agreement.98 The USCG performs oversight of the RO to ensure that its service complies with International Maritime Organization (IMO) and U.S. national requirements. Following the SS El Faro casualty and in response to the Marine Board of Investigation (MBI) report, the USCG revised its oversight process
94 CAPT. R. Holmes, USCG, presentation to the committee, September 2019.
95 For a list of functions, see 46 CFR Subchapter A, Part 8.
96 Guidance on the ACP can be found in the Marine Safety Manual, Sec. B, Ch. 9 at https://media.defense.gov/2017/Feb/27/2001704401/-1/-1/0/CCN_16000_2016_7_20.pdf, and the Navigation and Vessel Inspection Circular (NVIC) 2-95, CH-3 at https://www.dco.uscg.mil/Portals/9/DCO%20Documents/5p/5ps/NVIC/1995/n2-95ch3.pdf.
97 In addition to ACP, the other voluntary commercial vessel inspection alternatives include the Maritime Security Program and the Streamlined Inspection Program.
98 See 46 CFR Subchapter A, Part 8.
to better monitor current RO current activities, review and audit work completed, and verify management system processes.99
Oversight and Management System Verification
As part of its response to the MBI report, the USCG published guidance on the execution of its ACP program in Navigation and Vessel Inspection Circular (NVIC) 2-95, CH-3.100 The NVIC describes ACP responsibilities and procedures that instruct companies of their obligations to maintain vessels in a continuous state of compliance, clarify the mandatory requirements for ROs as they perform their delegated duties on behalf of the USCG, and discuss the USCG’s oversight of RO performance and compliance monitoring.
To be more risk based and data driven, the USCG has coordinated with ROs to develop 10 key performance indicators (KPIs) for both the ACP fleet and the ROs.101 The KPIs are used to assess RO performance of delegated functions and services and to direct additional oversight of RO performance.102 As explained in NVIC 2-95, CH-3, KPIs are also used to develop internal risk models, such as the fleet risk index for vessels enrolled in the ACP program, and to guide any necessary changes to the USCG oversight process. In accordance with RO Code 6.1.2,103 KPIs and related data must be provided to the USCG.
The “fleet risk index” is an internal program that calculates a relative-risk score for each vessel enrolled in the ACP. The risk score is a summation of points for each risk factor and used to identify vessels that could present a safety or environmental risk and require additional oversight. Risk factors assessed include elements such as vessel detentions (for both Port and Flag State), vessel-related marine casualties, marine violations/enforcement, documented major nonconformities issued under the International Safety Management (ISM) Code, vessel deficiencies, vessel type, and vessel age. As noted in the NVIC, the USCG has the right to modify assessed risk factors or assigned weights and can also add or subtract vessels on the index based on input from an Officer in Charge, Marine Inspection.104
99 See Final Action Memo from Commandant at https://media.defense.gov/2017/Dec/21/2001859858/-1/-1/0/EL%20FARO%20FINAL%20ACTION%20MEMO.pdf.
102 CAPT. M. Edwards, USCG, presentation to the committee, March 2019. KPIs include number of “Quality Cases,” RO detention rates; RO audit and survey findings, USCG deficiencies issued, fleet performance, and USCG field performance.
Under IMO regulations, the USCG is ultimately responsible for the effectiveness of all delegated functions performed on its behalf. In an effort to meet this responsibility, the USCG has implemented procedures to assess the effectiveness of a company’s SMS for U.S. flag vessels through a combination of verification and monitoring processes, such as the evaluation of equipment deficiencies for potential SMS process failures, the review of SMS documentation, and oversight of SMS activities performed by ROs.105 While the USCG has the authority to conduct SMS audits on vessels or companies, these are a function normally delegated to ROs. However, routine vessel inspections and investigation activities can provide the USCG opportunities to evaluate the effectiveness of SMSs, even if those inspections and investigations are not the primary purpose (see CVC-WI-003(3)).
Also, the USCG can conduct oversight with the presence of a potential failure or lack of effectiveness of the RO’s Quality Management System. By using a tool or procedure called a “Quality Case,” an inspector can request that an RO perform an internal investigation or root-cause analysis when “objective evidence”106 is established that the RO failed to meet a requirement as it relates to any delegated function.107 To pursue the quality case, any objective evidence must link to the elements of the RO Code108 or International Organization for Standardization (ISO) 9001, and by extension, any national legislation or USCG requirements.109
To improve its own oversight, the USCG established an internal SMS, based on an ISO 9001 Quality Management System, called the Mission Management System110 that allows the Coast Guard to assess and continuously improve its organizational responsibilities and performance. Understanding the importance of these new oversight responsibilities, the USCG is planning new workforce training, including a course for marine inspectors to meet the requirements for ISM Code internal auditors.111
105 USCG guidance is found at https://www.dco.uscg.mil/Portals/9/DCO%20Documents/5p/CG-5PC/CG-CVC/CVC_MMS/CVC-WI-003(series).pdf.
106 In accordance with 33 CFR § 96.120, objective evidence is any quantitative or qualitative information, records, or statements of fact pertaining to safety or to the existence and implementation of a safety management system element. See https://www.law.cornell.edu/cfr/text/33/96.120.
107 CAPT. M. Edwards, USCG, presentation to the committee, March 2019. See also CVC-WI-005(2) at https://www.dco.uscg.mil/Portals/9/DCO%20Documents/5p/CG-5PC/CG-CVC/CVC_MMS/CVC-WI-005(series).pdf.
109 CAPT. M. Edwards, USCG, presentation to the committee, March 2019.
111 CAPT. M. Edwards, USCG, presentation to the committee, March 2019.
Canada’s offshore industry is regulated by three separate agencies: the Canada-Newfoundland & Labrador Offshore Petroleum Board (C-NLOPB), the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB), and the Canada Energy Regulator (CER). The C-NLOPB and CNSOPB are responsible for the regulation of petroleum activities in the Canada-Newfoundland & Labrador Offshore Area and the Canada-Nova Scotia Offshore Area, respectively. The CER is responsible for petroleum exploration and production activities in various other areas, including but not limited to submarine areas (not within a province) in the internal waters of Canada and the outer continental shelf (excluding areas under the sole jurisdiction of the C-NLOPB or CNSOPB).
The three agencies’ principal responsibilities include worker health and safety (CER has delegated authorities from the Federal Labour Program); environmental protection; issuance of exploration and production licenses (CNSOPB and C-NLOPB only); conservation of petroleum resources; geoscience data management and distribution; and industrial benefits (CNSOPB and C-NLOPB only). These responsibilities are carried out by agency staff. Certifying authorities also provide independent third-party verification in some instances. For example, installation is fit for purpose and is maintained in compliance with the regulations without compromising safety and polluting the environment.
The three agencies have similar regulatory frameworks, which include both performance-based and some prescriptive requirements. Compliance verification to legislation and commitments and conditions of authorizations and approvals are assessed through monitoring of reports and other company–regulator interactions, comprehensive or targeted management system audits, and inspections.112 Overall risk, inspection results, and other performance outcomes are considered in establishing future oversight scope and frequency for regulated entities. As an example, in the C-NLOPB’s jurisdiction, programs involving drilling and production normally require one or more pre-approval audit(s) to be conducted prior to start of operations to verify compliance to the legislation and to commitments provided in the authorization respecting safety and environmental protection. Regulators normally inspect these installations three to five times each year and audit them at least once per year. Higher-risk drilling programs, such as ultra-deepwater or high-pressure and high-temperature wells, require additional oversight activities. Supplemental visits may be planned if a possible noncompliance is identified that requires further review onboard the facility. Where there are reasonable grounds to believe that an offense may have
occurred, a warrant is obtained to conduct a formal enquiry with prosecution as one of the possible outcomes.
United Kingdom Health and Safety Executive
The United Kingdom Health and Safety Executive’s (UK HSE’s) mission is to prevent work-related death, injury, and ill health. An important agency priority includes leading and engaging with those who undertake or influence health and safety through stakeholder engagement. Another priority is ensuring that the regulatory framework remains effective by supporting small firms and helping duty holders understand how to manage the risks they create in a proportionate way. In addition, the UK HSE attempts to secure effective management and control of work-related risks through a range of approaches including face-to-face contact, licensing regimes in certain higher-risk sectors, dealing with reported concerns efficiently and effectively, and holding people to account by enforcing the law. Finally, an important agency priority is reducing the likelihood of low-frequency, high-impact catastrophic hazards. The UK HSE inspectorate has broad technical expertise, which is applied to all regulatory functions. Certifying authorities or competent persons are permitted in certain technical areas as needed. The agency expects its inspectors to influence the effective management and control of risks. It recruits technical specialists with relevant industry experience but also requires advanced training to develop a range of regulation, legal, and organizational safety core competencies (TRB 2018).
The UK HSE achieves its objectives across the offshore oil and gas industry through safety case assessments,113 inspection of installations, noncompliance identification, incident investigations, and formal enforcement when necessary. The agency aims to visit larger offshore facilities at least once every year, while inspections at the smaller facilities will occur less frequently, the priority of which is determined using a risk-based approach. Duty holder performance and corresponding oversight scope and frequency are based on a range of factors including
- Compliance with their described SEMS;114
- Effectiveness of the corporate major accident prevention policy;
- Performance against strategic inspection topics;
- Number and extent of noncompliance issues raised by the Energy Division Offshore at inspection, assessment, or investigation;
- Enforcement history, including enforcement notices and prosecutions;
- Nature and extent of incidents, such as hydrocarbon releases;
- Operator’s own performance information, such as major hazard safety performance indicators;
- Effectiveness of an operator’s verification schemes; and
- Inherent risks associated with activities.
Norway’s Petroleum Safety Authority
Norway’s Petroleum Safety Authority (PSA) has regulatory responsibility for safety and the work environment within the country’s petroleum industry. The agency’s overall goal is to establish expectations for industry members across the petroleum sector, which maintain a high standard for health, safety, the environment, and emergency preparedness. The regulatory regime applies to offshore installations and exploration and production operations, as well as to their associated onshore processing facilities and refineries.
The PSA establishes regulations for petroleum operations pursuant to legislation and undertakes overall safety assessments and decision making related to regulatory approvals, sanctions, and exemptions. Before conducting offshore operations, the owner or operator of a facility must apply for an acknowledgment of compliance (AOC). An AOC is issued once the operator describes the technical conditions on the facility and the owner’s organization and systems for safety management. The PSA does not approve a “facility, equipment, components, procedures or qualifications.” The owner is responsible for ensuring that its organization, management system, and the technical conditions of a facility comply with the regulations at all times.115
The regulatory role involves defining the safety standards that companies must meet and conducting activities to verify the companies’ compliance with their respective management systems and regulations. These data points are used to inform their risk-based approach to determine scope and frequency of future oversight activities. Inspections and audits are focused on activities and factors where the risks of major accidents are considered to be greatest. Facility audits and inspections are carried out according to PSA guidelines, and a variety of methods may be used based on the identified need. Audits and inspections may be mono-disciplinary or multidisciplinary. Audits, status meetings with operators and their suppliers, investigations, and user survey guidelines and knowledge sharing are important regulatory techniques (TRB 2018). They vary from a systemic approach, such as reviewing operators’ safety management systems and
their internal follow-up of safety and environmental protection issues, to a more detailed approach, such as the physical and detailed evaluations offshore.116 These activities often involve interviews with relevant personnel (both onshore and offshore), field observations, and physical verification, among others. A cornerstone of the PSA approach is collaboration among the regulator, industry, and labor unions to identify relevant topics and promote continual improvement. Such efforts to engage in dialogue and build relationships foster knowledge sharing and improved awareness of critical issues, while also promoting a learning culture both inside the regulatory agency and among regulated entities (TRB 2018). The agency also conducts research and acts as a source of expertise externally for the industry, other government agencies, and the public. PSA staff are responsible for these varying regulatory functions with contractors being employed only under exceptional circumstances where the agency does not have the requisite expertise.
The experiences of the offshore oil and gas safety regulators from Canada, the United Kingdom, and Norway suggest that for a regulator to assess an operator’s SEMS program during inspections or incident investigations it must have personnel who have a strong understanding of offshore operations and their associated risks. These regulators recruit personnel with such operational and specialist backgrounds, and they are responsible for confirming that the customized safety management programs of operators are thorough and follow professional standards and well-established practices for identifying, assessing, and mitigating risks (e.g., conducting hazard and root-cause analyses and imposing barriers). Having a deep familiarity with such programs, these personnel are well positioned to assess program quality and implementation and to work with operators to continually improve their programs and their execution.
The current interpretation of OCSLA requires BSEE to implement and enforce offshore safety and environmental regulations and to arrange both an annual scheduled inspection and periodic unscheduled (unannounced) inspections of all oil and gas operations on the OCS, and BSEE also investigates incidents and oversees industry spill preparedness. Through formal agreements, BSEE also conducts inspections for other agencies. Getting to and inspecting the almost 1,800 facilities on the OCS continues to be a challenge for BSEE. In the GOM, inspectors review the records for all safety components, but only witness a sample of the corresponding safety devices tested. In the Pacific region, there are fewer facilities, and they tend
to be older, and so inspectors review all components and all safety devices. The Alaska region has one to two facilities and can inspect each more frequently.
Travel remains one of BSEE’s biggest challenges—getting offshore to conduct inspections, inspectors face potentially bad weather conditions preventing them from going, and a facility’s location and the distance needed to travel to some platforms could limit the amount of time they can spend conducting the inspection.
The foundation of BSEE’s inspection process relies on the examination of components or equipment using a list of prescriptive PINCs, which tend to focus on hardware-related issues and whether the hardware is maintained according to a particular standard corresponding to parts of the regulations under 30 CFR Chapter II. Since 2013, operators have been required to implement and maintain a SEMS program and have their SEMS plan audited every 3 years by an accredited third-party ASP. BSEE receives audit reports, findings, and any CAPs, which are tracked to closure. Some results are circulated to the GOM inspector force through the OSM.
In March 2018, BSEE’s GOM region implemented a formal RBI program that supplements its current annual inspection program. Consisting of FBRIs and PBRIs, the RBI program employs a quantitative model and subjective performance and risk information to identify facilities with higher risk profiles so that BSEE can focus the appropriate resources. When identifying facilities for each RBI component, BSEE uses a simple quantitative risk metric but also incorporates other qualitative risk factors, such as past inspection performance and operator profiles (e.g., past safety record and changes in ownership).
BSEE GOM staff reports that it reviews output from inspection data, including the number and types of INCs issued, incident investigations and reports, and some information contained in SEMS audit reports and CAPs. The OSM uses this and other data to maintain an IOL of operators that require additional enforcement actions because of ongoing incidents or a history poor safety and environmental performance. BSEE monitors operator performance and holds annual reviews to discuss recurring safety and environmental concerns.
The USCG has established a risk-based inspection methodology for inspecting OCS facilities that creates a risk ranking of facilities and that it uses to target and spend more time on “low performers.” Through its ACP, the USCG can delegate to an RCS certain statutory survey and certification functions for U.S. flag vessels, such as reviewing and approving plans, conducting inspections, and issuing a certificate of inspection. USCG has recently implemented procedures to assess the effectiveness of a company’s SMS for U.S. flag vessels, developed KPIs for both the ACP fleet and the RO, and created a fleet risk index for each vessel in the ACP.
While normally a function delegated to ROs, the USCG has the authority to conduct SMS audits on vessels or companies. Even if not their primary purpose, routine vessel inspections and investigation activities can provide the USCG opportunities to evaluate the effectiveness of a vessel or company SMS, and can help determine if an RO has failed to meet a requirement of any of its delegated functions. However, the USCG understands that its marine inspectors will need different workforce training to understand and evaluate SMSs, such as meeting the requirements for ISM Code internal auditors.
Safety management systems are a hallmark of the offshore regulatory regimes of Canada, the United Kingdom, and Norway. Operators must complete rigorous risk analysis and management planning and act in accordance with the safety management plans. While such approaches allow for more flexibility, operators are responsible and more accountable for identifying and managing their risks. For these regulators to assess an operator’s SMS program during inspections or incident investigations requires personnel who have operational and specialist backgrounds and a strong understanding of offshore operations and their associated risks. These are the personnel responsible for confirming that an operator’s safety management program follows professional standards and well-established practices for identifying, assessing, and mitigating risks. With this expertise and training, these regulators are able to assess program quality and implementation and work with operators to continually improve their programs and their execution.
BSEE (Bureau of Safety and Environmental Enforcement). 2019. A New Era of Management: Driving Safety Performance and Environmental Stewardship Improvements Beyond Regulation Through Innovation and Collaboration. Risk-Based Inspections Assessment Report, May. https://www.bsee.gov/sites/bsee.gov/files/reports/bsee-rbi-2019.pdf.
Chief Counsel. 2011. Macondo: The Gulf Oil Disaster. Chief Counsel’s Report, National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling.
GAO (U.S. Government Accountability Office). 2017. Oil and Gas Management. Stronger Leadership Commitment Needed at Interior to Improve Offshore Oversight and Internal Management. GAO-17-293. Washington, D.C., March. https://www.gao.gov/products/gao-17-293.
NAE and NRC (National Academy of Engineering and National Research Council). 2012. Macondo Well Deepwater Horizon Blowout: Lessons for Improving Offshore Drilling Safety. The National Academies Press, Washington, D.C.
TRB (Transportation Research Board). 2018. Special Report 324: Designing Safety Regulations for High-Hazard Industries. Transportation Research Board, Washington, D.C.
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