BSEE Final Well Control Rule Published
On April 29, 2016, the U.S. Department of Interior’s Bureau of Safety and Environmental Enforcement’s (BSEE) long-anticipated and controversial final “Well Control Rule” was published in the Federal Register. The final rule represents a culmination of more than five years of work driven by the 2010 Deep Water Horizon incident, focusing on blowout preventers (BOPs), well design, well control, casing, cementing, real-time well monitoring, and subsea containment requirements. The final rule purports to incorporate more than 176 public comments BSEE received to the proposed rule, which resulted in some changes in the final rule, but, at a time when offshore operators are already struggling with depressed oil prices and the looming threat of the Bureau of Ocean Energy Management’s supplemental bonding requirements affecting such operators on the U.S. Outer Continental Shelf (OCS), there are significant concerns about the shortcomings of the final rule and its ultimate benefits when balanced against the costs.
The Final Rule
The final Well Control Rule mandates stringent design requirements and operational procedures for critical well control equipment used in subsea oil and gas operations. BSEE has incorporated into the final rule a number of American Petroleum Institute (API) and American National Standards Institute standards, which were not previously required by rule, but were typically implemented by operators, including, among others, API Recommended Practice 53. BSEE consolidated existing well operational and equipment requirements with the new provisions of the final rule into the previously reserved 30 C.F.R. Part 250 at Subpart G.
A primary focus of the Well Control Rule is on the design, operation, and maintenance of BOPs, including performance testing and the reporting of the results of such testing to BSEE-approved verification organizations (BAVOs). A complete breakdown and inspection of the BOP system must occur every five years. Subsea BOP must use double shear rams and the BOP systems must have the capability to center the drill pipe in the shear ram. Personnel inspecting, maintaining or repairing BOP-related equipment must meet new training standards. The final rule includes enhanced reporting requirements to BSEE and Original Equipment Manufacturers (OEM). For example, the weekly Well Activity Reports (WAR) must include a report of any leaks associated with BOP control systems. The WAR must also document actions taken to address the leak. Operators must suspend operations if the problem “cannot be resolved promptly.” The operator must share information with the OEM related to the performance of their BOP system equipment and must report any significant problems with the well-control equipment to BSEE.
The Well Control Rule imposes safe drilling practices including real-time monitoring (RTM) requirements for deep water and high temperature, high pressure drilling activities, and maintaining safe drilling margins.
Analysis of Changes to Rule Provisions that Received Significant Comment During the Rulemaking Process
Three of the areas that multiple operators and industry associations commented on were the requirements for safe drilling margins, RTM, and BOP major inspections (including a complete breakdown). As described below, BSEE made limited changes in response to comments on the proposed rule.
Revised Safe Drilling Margin Standard
One of the more controversial provisions of the proposed rule is the establishment of safe drilling margins. BSEE proposed to revise the safe drilling margin portion of the drilling prognosis required in an Application for Permit to Drill (APD) to require that the static downhole mud weight must be at least 0.5 pounds per gallon (ppg) below the lesser of the casing shoe pressure integrity test or the lowest estimated fracture gradient.
This proposal drew comments noting that a prescriptive 0.5 ppg margin would lead to operational problems such as limiting the selection of drilling fluids, and requiring more casing strings or smaller production casing sizes. In addition, commenters asserted that the proposed standard would decrease production from smaller hole sizes and prevent operators from developing certain reservoirs because they would be unable to set additional casing to reach them.
In response, BSEE set the 0.5 ppg drilling margin as a default standard, but allowed the use of an alternative drilling margin if applicants submitted adequate documentation to justify the alternative equivalent downhole mud weight. Examples of such documentation include risk modeling data, off-set well data, analog data, and seismic data. The rule does not indicate how BSEE would evaluate a request to use an alternative drilling margin or the circumstances under which the agency would approve it.
The proposed RTM requirements were another area of focus for commenters. Under the proposal, BSEE would have required that an RTM system gather and immediately transmit data on all aspects of the BOP control system, the well’s fluid handling systems on the rig, and the well’s downhole conditions with the bottom hole assembly tools. The proposal would have required this data be sent to an onshore facility monitored by qualified personnel in continuous contact with rig personnel during operations. The proposal also would have required the RTM data to be preserved, stored, and made available to BSEE upon request. BSEE District Managers would have had to be immediately notified of any loss of RTM capability during operations.
Commenters expressed concern that the proposed RTM rule would erode the authority of offshore personnel and shift operational decision-making to onshore personnel. In particular, they asked BSEE whether onshore personnel would be able to override offshore personnel’s operational decisions based on the RTM data. BSEE responded in the final rule’s preamble that the rule requires RTM data to be transmitted onshore to personnel who are able to monitor the data and contact rig personnel if unusual data warrants, with a potential for evaluation by offshore personnel. As a result, the final rule preamble indicates that onshore personnel “must have the capability to contact rig personnel during operations,” and no longer indicates that onshore and offshore personnel “must be in continuous contact.”
Commenters also asserted that it would be impractical to require immediate notification of the District Manager when RTM capabilities were lost. BSEE agreed. The final rule requires that a real-time monitoring plan, which the proposed rule included, now include a protocol for responding to significant and/or prolonged interruption of RTM capabilities, and how BSEE will be notified of such interruptions.
BSEE also received comments asking who was responsible for fulfilling the RTM obligations. In response, BSEE asserted that the lessee, designated operator, and the person (including a contractor) actually performing the activity were jointly and severally responsible for complying with the RTM rule. BSEE clarified that contractors do not need to maintain duplicate records and do not need to determine whether a lessee or operator is fulfilling its RTM obligations.
Finally, the rule clarifies the scope of the data to be monitored. Rather than requiring monitoring of “all aspects of” the well, the rule limits RTM obligations to recording, storing, labeling, and transmitting data regarding the BOP control system, the well’s fluid handling system, and the well’s downhole conditions.
Major Inspections of BOPs
The proposal would have required a complete breakdown and inspection of the BOP and every component associated with it every five years. Under the proposal, BSEE required that a BAVO document the inspection, any problems encountered, and the corrective action. The proposal did not allow the major inspection to be performed in phased intervals. Commenters expressed concern that requiring all components to be inspected at one time would put many rigs out of service for extended periods of time.
In response, BSEE revised the rule to allow a phased approach for five-year inspection, provided that the operator maintain proper documentation of each component inspection to ensure that BSEE can verify the inspections ultimate completeness. In addition, the final rule clarifies that the five-year cycle begins to run on the latter of (1) the date the equipment owner accepts delivery of a new build drilling rig with a new BOP system, (2) the date the new, repaired, or remanufactured equipment is initially installed into the system, or (3) the date of the component’s last five-year inspection.
Extended Compliance Timelines
BSEE extended the compliance deadlines for the following provisions:
- Installation of a gas bleed line with two valves for the annual preventers (comply within 2 years of April 29, 2016);
- Capability to shear and seal tubing with exterior control lines (comply within 2 years of April 29, 2016);
- Use of BAVOs (comply within 1 year of publication of a list of BAVOs)(in the interim, operators must use independent third-parties to perform the certifications, verifications and reports that will be required of BAVOs after designation);
- Real Time Monitoring requirements (comply within 3 years of April 29, 2016);
- Have dedicated subsea accumulator capacity for autoshear and deadman function on subsea BOPs (comply within 5 years of April 29, 2016);
- Install dual shear rams on subsea BOPs (comply within 5 years of April 29, 2016);
- Install surface BOPs on floating facilities (comply within 3 years of April 29, 2016);
- Install BOP systems that have the capability to center drill pipe during shearing operations (comply within 7 years of April 29, 2016);
- Install remotely controlled locks on surface BOP sealing rams (comply within 3 years of April 29, 2016); and
- BOPs must be able to shear electric-, wire-, and slick-line (comply within 2 years of April 29, 2016.)
Operators must comply with the other requirements of the Well Control Rule within 90 days of the April 29, 2016 publication of the Rule in the Federal Register.
For more information, please contact Vinson & Elkins lawyers Larry Nettles, George Wilkinson, Larry Pechacek, or Matthew Dobbins. Visit our website to learn more about V&E’s Environmental and Natural Resources practice, or email one of the practice contacts.
This information is provided by Vinson & Elkins LLP for educational and informational purposes only and is not intended, nor should it be construed, as legal advice.