JL Daeschler, pioneering subsea engineer and BOE contributor, recounted a frightening incident in 1976, a year after UK North Sea production began:
We found ourselves in a drastic situation. While working on a subsea well, the wireline retrievable tubing safety valve got tangled up in the tree area. We had an open well situation and couldn’t cut the wire in the subsea tree. Further, the weather was bad, and keeping on location was difficult. The riser hydraulic release was faulty, so there was an imminent high risk of a “jammed ” subsea tree, bent/damaged riser, and uncontrollable well flow.
We got through this, but recognized that improved well control capabilities were needed during workover operations. Management decided that any future workover operations on a subsea tree/well would require a small diameter workover BOP with shearing capability immediately above the Xmas tree. A year later, we had the hybrid kit pictured below (with JL). Note that the guide funnels are slim to run on guide lines and not overshoot the guide base posts.
JL’s story reminds us once again that safety achievement is dependent on continuous improvement driven by experience, research, and technological advances.
When I was a young engineer with the US Geological Survey, the OCS safety regulator at the time, my boss and mentor Richard Krahl (known as “Mr. OCS” for his commitment to offshore safety) slammed😀 a copy of the first edition of API RP 14C (Analysis, Design, Installation, and Testing of Safety Systems for Offshore Production Facilities) on my desk and told me to read it carefully. That pioneering process safety document has grown with the offshore industry and is now in its 8th edition.
Similarly, API RP 2A-WSD (Planning, Designing, and Constructing Fixed Offshore Platforms— Working Stress Design) is now in its 22nd edition and API STD 53 (Well Control Equipment Systems for Drilling Wells) is in its 5th edition. There are countless other examples of the progression in safety equipment and practices.
As individuals, companies, agencies, and collectively as an industry, there can be no standing still. Nothing is routine and the challenges continue to grow: deeper wells, more complex geology, higher temperature and pressure, deeper water, harsher environments, remote locations, new security risks, and more. We get better or we get worse, and the latter is not an option. Onward!
The government’s decision to require that a capping stack be located in Guyanais prudent. Although the need for a capping stack is dependent on multiple barrier failures and is thus extremely low, the environmental and economic consequences of a prolonged well blowout warrant timely access to this tertiary well control option.
A capping stack must be properly maintained and deployable without delay. In that regard, BSEE has a good program for testing Gulf of Mexico capping stack readiness. Capping stack drills are an important post-Macondo addition to the unannounced oil spill response program that dates back to 1981.
“Troy Naquin, BSEE New Orleans District, observes as a capping stack is carefully lowered onto the deck of ship to be transported more than 100 miles offshore for a drill designed to test industry’s ability to successfully deploy it in case of an emergency, May 8, 2023.” BSEE photo/Bobby Nash
I had the pleasure of working with Jason Mathews when he was a young MMS engineer. He truly cared about our safety mission and has taken that commitment to the next level at BSEE. Jason shared this important, heartfelt message on the anniversary of the Macondo blowout.
One of the greatest gifts I ever received in life is having a little girl and having the opportunity to go home every evening and spending time with her at cheer, softball, doing homework, etc. I have a great deal of respect for the men and women who work offshore and put their lives on hold for 14-28 days to deliver much needed OCS production to meet US demand. Undoubtedly, they are better / tougher people than me.
Over the last year, my team has seen multiple incidents that had a high potential severity that could have led to a fatal / serious injury or major incident in the GOM. Although we can sit and debate the causal factors for hours, one that jumps to the top of the discussion is the Human Factor – Complacency. Of all the things a leader should fear, complacency heads the list. There is no doubt success breeds complacency, and complacency breeds failure.
To this day, I am still shook by the mindset and complacency of many onboard the Deepwater Horizon prior to the incident. During testimony in the public hearings, John Guide, the BP well team leader for the Horizon, believed that the rig crew had become “too comfortable” because of its good track record for drilling difficult wells. Ross Skidmore, a BP contractor on the rig on April 20, testified that the crew became complacent after completing drilling because “when you get to that point, everybody goes to the mindset that weʹre through, this job is done.” To me, the complacency on the Deepwater Horizon could be attributable to the crew not having access to all of the well data (OptiCem reports – cement job risk) available to BP personnel onshore and the well site leaders on the rig. Our investigation concluded, the overall complacency of the Deepwater Horizon crew was a possible contributing cause of the kick detection failure.
As regulators, we have special roles in the GOM as it relates to safety:
Driving the avoidance of complacency and risk-free mindsets of the offshore employees
Understanding we can’t be selfish – Our success is not our individual personal growth / gains, but it is being unwavering in your promotion of offshore safety to ensure all offshore employees return home to their families safely
Holding each other (internally) and industry (externally) accountable when necessary
In order to achieve greatness offshore, we ,as a regulator, have to believe we can, and never sit still until we achieve it.
Everyone on this email has a very critical function and role. Never underestimate the value of what you do, have the proper mindset, and avoid complacency.
Do whatever it takes to ensure the people offshore are gifted the same gift we receive every day – going home to our families.
All In –
Jason P. Mathews, Petroleum Engineer, Field Operations – OSM
Friday Night LIghts: Coach Mathews and his daughter
I am again sharing this touching tribute to the 11 men who lost their lives on the Deepwater Horizon on April 20, 2010. The video is introduced by country singer Trace Atkins, a former Gulf of Mexico rig worker. The video and Trace’s song serve as a memorial to the 11 Deepwater Horizon workers and others who have died exploring for and producing oil and gas around the world. Please take a moment to watch.
Houston, TX, March 29, 2024. Beacon Offshore Energy LLC (“Beacon”) announced today the completion of the divestment of its non-operated interests in certain fields in the deepwater Gulf of Mexico in accordance with a previously executed definitive agreement with GOM 1 Holdings Inc., an affiliate of O.G. Oil & Gas Limited. The divestment includes Beacon’s 18.7% interest in the Buckskin producing field, 17% interest in the Leon development, 16.15% interest in the Castile development, 0.5% interest in the Salamanca FPS/lateral infrastructure, and 32.83% interest in the Sicily discovery.
According to BOEM records, GOM 1 HOLDINGS INC, a Delaware company, registered with BOEM effective 3/15/2024. The parent entity, O.G. Oil & Gas Limited, is a privately held E&P company incorporated in 2017 and based in Singapore.
O.G. Oil & Gas Ltd is part of the Ofer Global Group, “a private portfolio of international businesses active in maritime shipping, real estate and hotels, technology, banking, energy and large public investments.”
After a partial takeover by O.G Oil & Gas Limited in 2018, New Zealand Oil and Gas is now 70% owned by the Ofer Global Group. Among other interests, NZ Oil and Gas produces from fields offshore Taranaki, NZ.
Because they are jointly and severally liable for safe operations and decommissioning, minority investors should take a strong interest in safety management and financial assurance. Investors should remember that partners are adversely affected by the mistakes of the operating company. Anadarko and Mitsubishi took a hit following the Macondo blowout. To what extent had they been monitoring bp’s risk and safety management programs for drilling operations?
On January 28, 1969, well A-21, the 5th well to be drilled from Union Oil Company’s “A” platform began flowing uncontrollably through fractures into the Santa Barbara Channel.
The absence of any well casing to protect the permeable, fractured cap rock meant that the operator couldn’t safely shut-in a sudden influx of hydrocarbons into the well bore (i.e. a “kick”). Shutting-in the well at the surface would create well bore fractures through which oil and gas could migrate to shallow strata and the sea floor. The probability of an oil blowout was thus essentially the same as the probability of a kick (>10-2). Compare this with the historical US offshore oil blowout probability (<10-4) and the probability of <10-5 for wells with optimal barrier management.
Here, in brief, is the well A-21 story:
Well drilled to total depth of 3203′ below the ocean floor (BOF).
13 3/8″ casing had been set at 238′ BOF. The well was unprotected from the base of this casing string to total depth.
Evidence of natural seeps near the site suggested the presence of fracture channels
The well was drilled through permeable cap rock and a small high pressured gas reservoir before penetrating the target oil sands.
When the well reached total depth, the crew started pulling drill pipe out of hole to in preparation for well logging.
The first 5 stands of drill pipe pulled tight; the next 3 pulled free suggesting the swabbing of fluids into the well bore..
The well started flowing through the drill pipe. The crew attempted to stab an inside preventer into the drill pipe, but the well was blowing too hard. The crew then attempted unsuccessfully to stab the kelly into the drill pipe and halt the flow.
The crew dropped the drill pipe into the well bore and closed the blind ram to shut-in the well.
Boils of gas began to appear on the water surface. Oil flowed to the surface through numerous fracture channels. The above sketch by former colleague Jerry Daniels (RIP) depicts the fracturing, which greatly complicated mitigation of the flow.
We need to continue studying these historically important incidents, not just the technical details but also the human and organizational factors that allowed such safety and environmental disasters to occur. The idea is not to shame, but to remember and better understand.
As we approach the 55th anniversary of the Santa Barbara blowout (more to follow), pioneering subsea engineer JL Daeschler reminds us of a lesser known, but very serious, drilling blowout that occurred the same year offshore Northern Australia.
As is the case with most historic incidents, the lessons learned are still pertinent today and should be studied by those involved with well operations. Training sessions should consider what went wrong then, how technology and practices have changed since, how similar incidents could still occur, and innovations and improved practices that could further mitigate well control risks.
While well control technology and procedures are much improved, the fundamental issues discussed in the attached video remain the same. Well control must always be considered a work in progress with continuous improvement being the objective.
(The Sedco 135G semisubmersible that drilled this well is of the same design as the Sedco 135B rig that sank offshore Borneo in 1965.)
Firstly, taking 2.5 years to publish an investigation report is unacceptable for an organization with BSEE’s talent, resources, and safety mandate. Unfortunately, such delays now seem to be the rule as the summary table (below) for the last 4 panel reports demonstrates. The most recent report implies that the actual investigation was completed in 2-3 months. Why were another 2+ years needed to publish the report? (Note that the lengthy and complex National Commission, BOEMRE, Chief Counsel, and NAE reports on the Macondo blowout were published 6 to to 17 months after the well was shut-in.)
incident date
report date
elapsed time (months)
incident type
5/15/2021
10/31/2023
29.5
fatality
1/24/2021
7/24/2023
30
fatality
8/23/2020
2/15/2023
30
fatality
7/25/2020
2/15/2023
31
spill
Four most recent BSEE panel reports
The subject (May 2021) fatality occurred during a casing integrity pressure test, and some of the risk factors were familiar:
The platform was installed 52 years prior to the incident, and had been shut-in for more than a year.
The well of concern (#27) was drilled in 1970, sidetracked in 1995, and last produced in February 2013.
Diagnostic tests clearly demonstrated communication between the tubing, production casing, and surface casing.
In light of the known well integrity issues and the absence of production for more than 8 years, the prudent action would have been to plug and abandon the well in a timely manner. However, under 30 CFR 250.526 as interpreted at the time, Fieldwood had another option – submit a casing pressure request to BSEE to confirm the integrity of the outermost 16″ casing and (per p. 10 of the report) “continue to operate the well in its existing condition.” Given that the well had not produced for 8 years and that the platform had been shut-in for more than a year, the option to continue operating the well should not have been applicable.
The only issue for Fieldwood to resolve with the regulator should have been the timing of the plugging operation. Additional well diagnostics would only serve to create new risks and further delay the well’s abandonment.
The resulting pressure test of the outermost (16″) casing was solely for the purpose of confirming a second well bore barrier. Per the report (p.10), there is a “known frequency of outermost casings in the GOM experiencing a loss of integrity as a result of corrosion.” Whether or not the 16″ casing passed the test, the inactive well had clear integrity issues and should have been plugged.
Fieldwood proceeded with the pressure test rather than correcting the problem. The regulations, as interpreted, thus facilitated the unsafe actions that followed. These factors heightened the operational risks:
Extensive scaffolding and a standby boat were needed for the test.
Process gas via temporary test equipment was used to conduct the test.
The Field-Person In Charge (PIC) heard about the test for the first time on the morning of the incident.
The PIC and victim had no procedures to follow, and had to figure out how to conduct the test on the fly.
A high pressure hose was connected without a pressure regulator or pressure safety valve.
The digital pressure gauge had two measurement modes, one to display pressure in psi and the other in bars. (One bar is equivalent to 14.5 psi. Assuming that the readings were in psi rather than bars would thus result in serious overpressure of the casing.)
Seconds after the victim told the field-PIC the pressure was 175 psi (presumably 175 bar and 2538 psi), the casing ruptured. The force of the explosion propelled the victim into the handrail approximately 4 feet away, which bent from the impact. The victim’s hardhat was projected 60 to 80 feet upwards, lodging into the piping.
The investigation report fails to address the wisdom of conducting the pressure test and the regulatory weaknesses that enabled Fieldwood to defer safety critical well plugging operations. The pressure test option in 30 CFR § 250.526, was not intended for long out-of-service wells with demonstrated well integrity issues. The only acceptable option was corrective action (plugging the well) without further delay. The pressure test option added risks without addressing the fundamental problem and helped enable the operator to further delay decommissioning obligations.
Postscript: According to BOEM data, the lease where the fatal incident occurred expired on 7/31/2021. Per the BSEE Borehole and structures files, neither the platform (#14) nor any of the other 4 structures remaining on the lease have been removed, and the well (#27) has yet to be plugged.
Per the DOI regulatory agenda published on 7/27/2023 (excerpt below), the final BSEE well control rule was published in June. Of course, that did not happen, but the update tells us that the final rule should be published soon. The delay is probably in the internal review process which moves at the pace of continental drift 😉.
BOE comments on the proposed rule are attached here.
12. Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control Revisions [1014–AA52]
Legal Authority: Not Yet Determined [BOE note: This is rather comical since the OCSLA authority was specified in the preamble to the proposed rule and you would never publicly imply that you didn’t know the authority for a final rule. 😉]
Abstract: This rulemaking revises the Bureau of Safety and Environmental Enforcement (BSEE) regulations published in the 2019 final rule entitled “Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control Revisions,” 84 FR 21908 (May 15, 2019), for drilling, workover, completion and decommissioning operations. In accordance with Executive Order (E.O.) 13990 (Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis) and the E.O.’s accompanying “President’s Fact Sheet: List of Agency Actions for Review,” BSEE reviewed the 2019 final rule and is updating to subpart G of 30 CFR part 250 to ensure operations are conducted safely and in an environmentally responsible manner.
Bud's Offshore Energy (BOE) 