The Honor Roll companies for 2022 (listed alphabetically) are Anadarko (Oxy), bp, Cantium, Chevron, Contango, Hess, LLOG, Murphy, and Shell.
Our criteria:
Must average <0.3 incidents of noncompliance (INCs) per facility-inspection.
Must average <0.1 INCs per inspection-type. (Note that each facility-inspection may include multiple types of inspections (e.g. production, pipeline, pollution, Coast Guard, site security, etc). On average, each facility-inspection included 3.25 types of inspections in 2022. Here is a list of the types of inspections that may be performed.)
Must operate at least 3 production platforms and have drilled at least one well (i.e. you need operational activity to demonstrate compliance and safety achievement).
May not have a disqualifying event (e.g. fatal or life-threatening incident, significant fire, major oil spill). Due to the extreme lag in updates to BSEE’s incident tables, investigation and news reports are used to make this determination.
Pacific and Alaska operations will be considered separately.
Foremost energy experts like Daniel Yergin understand that oil and gas will be critical to our economy and security for decades, and that offshore production is an important component of our energy supply chain. Unfortunately, our massive outer continental shelf has, from an oil and gas standpoint, been effectively reduced to the central and western GoM.
Opportunities in the GoM are being seriously constrained by the extended pause in leasing. A lease sale has not been held for 615 days, the longest US offshore leasing gap since the 1950’s.
Reserve replacement and sustained production are dependent on exploration. The charts below illustrate the decline in GoM exploratory drilling and the reduced activity by some of the more important operating companies.
Per BSEE data, the number of exploratory well starts averaged only 3/month for the last 18 months (chart 2). This level of activity is the lowest since the early days of deepwater operations (chart 1). There was even more drilling during the post-Macondo moratorium (2010-2011).
ConocoPhillips and Exxon have not drilled a GoM exploratory well since 2016 and 2018 respectively. Activity by other operators has also declined significantly (chart 3). BP has not spudded an exploratory well since Sept. 2021.
Operating companies (listed alphabetically): Arena, Anadarko (Oxy), BHP, bp, Cantium, Chevron, Hess, Murphy, Shell, and Walter
Criteria:
Must average <0.3 incidents of compliance (INCs) per inspection. (This is less than half the GoM 2022 YTD average of 0.64 INCs/inspection.)
Must operate at least 3 production platforms.
Must have drilled at least one well.
Pacific and Alaska operations will be considered in a separate post.
Comments:
Impressive performance by Hess: 21 inspections and no INCs
Cantium and Walter averaged less than 0.1 INCs/inspection. The INC rates for Anadarko (Oxy), BHP, and BP were only slightly higher.
Among the Honor Roll companies, Shell (highest production, 9 deepwater platforms, and 13 well starts) and Arena (115 shelf platforms and 12 well starts) were the deepwater and shelf activity leaders.They thus had the highest INC exposure.
Although CSI and FSI INCs are typically more significant than W INCs, that is not always the case, so the INCs have not been weighted by type.
As has been previously noted, more inspection data should be readily available online. At a minimum, the specific INC (type) numbers (e.g. P-103, G-110, etc) should be posted so the public can better assess performance. Absent this information, interested parties are left to speculate about the significance of the violations.
While compliance is not synonymous with safety, most experienced observers believe there is a strong correlation. In the 1990’s, John Shultz, a PhD candidate at Carnegie Mellon Univ., studied US offshore facilities and safety data and developed expert and regression models to predict the likelihood of accidents and spills. That was a data rich era in that there were ~4000 US offshore platforms (more than twice the current number) and ~100 well starts/month (>10 times the current rate). In John’s thesis, he found that INCs are a very good predictor of accidents and spills. The offshore world has changed and further study of the correlation between compliance and safety performance is highly recommended.
bp: Only 15% of shareholder votes backed a call for the company to accelerate its energy transition, compared with the 21% in favor in a similar vote last year.
Oxy: Only 17% of investors backed a call for emissions-reduction targets. (I wonder how Buffett voted 😀)
Marathon: 16% supported a measure calling for the company to report on how its transition plans affected workers and communities
ConocoPhillips: 42% supported an emissions-reductions targeting measure vs. 58% last year.
Operating companies that produced >1 million bbls of oil or >1 BCF of gas in 2021 are listed in descending order based on oil production.
Both the total number of well starts and the number of exploratory wells are indicated
An INC is an Incident of Noncompliance (i.e. a violation). W=warning, CSI=component shut-in, and FSI=facility shut-in are the enforcement actions.
All of the below data are publicly available on the BSEE-BOEM websites.
2021 oil (MMbbls)
2021 gas (BCF)
2021/22 well starts total-expl
2021/22 INCs W-CSI-FSI
Shell
149.8
190.8
28-12
11-14-4
bp
114.0
82.7
5-2
6-3-4
Chevron
83.7
42.2
8-8
1-1-3
Anadarko (Oxy)
67.7
57.8
8-6
8-5-1
Hess
27.5
61.7
2-2
7-4-0
Murphy
25.1
50.0
7-7
4-8-1
LLOG
20.4
29.0
3-0
1-1-1
Talos
17.7
23.0
5-0
25-26-14
BHP
14.5
5.9
3-2
2-3-0
Exxon
13.2
2.3
–
1-1-1
Beacon
10.5
15.7
1-0
0-0-0
Fieldwood
10.4
24.7
–
685-235-91
EnVen
9.6
12.6
6-0
2-6-3
Kosmos
9.4
8.4
1-1
1-0-0
Arena
8.6
27.9
32-0
68-45-19
Walter
8.1
36.2
2-2
3-1-2
Cox
6.2
30.3
–
237-169-3
Eni
4.7
13.6
2-0
8-0-2
W&T
5.0
27.2
1-0
65-40-7
Cantium
4.5
5.5
18-0
23-15-2
QuarterNorth
4.2
8.3
–
no data
GoM Shelf
2.3
4.8
–
52-5-2
ANKOR
1.4
2.5
–
0-0-1
Byron
1.0
4.4
–
5-8-2
Renaissance
0.7
1.6
–
20-9-3
Sanare
0.3
4.5
–
38-20-3
Helis
0.2
1.2
–
1-0-2
Contango
0.03
5.0
–
4-0-0
Samchully
0.02
1.2
–
no data
Comments:
“Energy transition” companies Shell and bp still love the Gulf of Mexico, which is a good thing for them and us. Together they accounted for 42.4% of the 2021 oil production.
The top 4 producers, Shell, bp, Chevron (includes Unocal), and Anadarko accounted for 2/3 of GoM oil production, nearly all of which was from deepwater leases.
Those are impressive production numbers for Anadarko (Oxy). No wonder Warren Buffett likes Oxy stock.
The relative number of deepwater exploratory wells is mildly encouraging given our concerns about sustaining production.
Exploratory well determinations are rather subjective and may not be entirely consistent.
Understandably, no exploratory wells were drilled by Arena or Cantium, the companies responsible for most well operations on shelf (shallow water) leases.
Overall, the INC numbers are impressively low for the deepwater operators, with Chevron and LLOG standing out. BSEE does not post the specific violation information (more on this in an upcoming post), so it’s difficult to properly assess a company’s compliance record.
Unfortunately, incident data could not be included on the scoreboard. BSEE’s incident tables are badly out of date, and no 2021/2022 summaries have been posted.
Exxon production is limited to the Hoover Diana spar, which was installed 22 years ago. The largest US oil company has only drilled one GoM exploratory well (2018) in the past 5 years. Currently, their main GoM interest seems to be the sequestration (disposal) of onshore emissions. (More on this topic in an upcoming post.)
[Disclosure: I assisted the legal team that defended Bob Kaluza. That said, I completely disagreed with the charges against him and Don Vidrine before my involvement in the case.]
Bob Kaluza (L) and Don Vidrine
Unsurprisingly, there was a lot of tough guy talk in Washington DC after the blowout:
“Our job is basically to keep the boot on the neck of British Petroleum”
It was therefore predictable that the Department of Justice (DOJ) would choose to prosecute BP employees individually. There were BP managers who would have been good candidates, but instead DOJ chose to criminally prosecute the working stiffs – the two BP well site leaders on the rig. They were the lowest ranking BP employees associated with the incident. This was apparently acceptable to BP, since their plea agreement blamed Kaluza and Vidrine’s for their role in overseeing the negative pressure test (#blametheworker). Never mind that:
BP management was responsible for the well planning and shortcuts that were the root causes of the blowout (see the previous posts in this Macondo series).
the extent to which the negative pressure test was misconducted and misinterpreted was and remains a topic of dispute.
there were no regulations or standards requiring this test or explaining how it should be conducted, and BP’s internal guidance was woefully inadequate.
Bob Kaluza was a temporary replacement for the regular well site leader, had worked primarily onshore, and had never conducted or witnessed a negative pressure test.
Kaluza and Vidrine were themselves victims and were fortunate to have survived the incident.
Despite all of this, DOJ still chose to prosecute the two well site leaders. However, the weaknesses in the DOJ case became more obvious over time, and DOJ dropped all but a misdemeanor water pollution charge. Vidrine, who had health issues that were exacerbated by the case, accepted a plea deal. Kaluza was confident of his innocence and chose to make his case in court. His defense team was very strong, and the trial was essentially a walkover. After less than 2 hours of deliberation, the jury fully acquitted Bob Kaluza (2/25/2016). Sadly, Don Vidrine passed away the following year.
Contrary to national and regional planning documents and the associated response exercises, Energy Secretary Chu, whose department had no jurisdiction over offshore oil and gas operations or the emergency response, assumed the leadership role on the well control aspects of the blowout. Secretary Chu is a Nobel prize winning physicist and had the President’s support to get involved with the response. Although he was not a drilling engineer or geologist, he soon became the dominant figure on well control decisions.
BP’s top kill operation (see diagram above) was intended to overcome and halt the flow of oil by pumping heavy mud into the well bore. Per an excellent paper by Dr. Mayank Tyagi and colleagues at LSU (Analysis of Well Containment and Control Attempts in the Aftermath of the Deepwater Blowout in MC252), the operation was not successful because the pumping rate and mud weight did not generate sufficient pressure.
Consistent with Dr. Tyagi’s analysis, the well would likely have been killed on 5/28/2010, shortening the blowout by 48 days, had Secretary Chu not stopped the top kill operation over the objections of BP engineers. While it was reasonable for the Secretary and his team to be concerned about possible casing leaks and the fracturing of subsurface formations, the subsequent (7/15/2010) closure of the capping stack demonstrated that the well had sufficient integrity to support the top kill operation. Questions about the aborted top kill effort and how that decision was made are therefore important and merit careful review. Did the Macondo well flow unnecessarily into the Gulf for an additional 48 days (5/28-7/15)? Did the National Incident Command facilitate or delay source control?
Keep in mind that the National Incident Command almost made a similar mistake in July. Even after the capping stack successfully shut-in the well on 7/15, Incident Commander Thad Allen (USCG) continued to call the closure of the capping stack a temporary test and threatened to require BP to resume flow from the well. We thus had a bizarre situation where the Federal Incident Commander was threatening to require the resumption of a blowout. Fortunately, informed input from experienced engineers prevailed. The well remained shut-in and the static well-kill operation was successful.
While the previously discussed planning, cementing, and well suspension issues allowed the well to flow, there were many other equipment, operational, and management deficiencies that elevated the incident to a disaster. Below are those that bother me the most:
Blowout Preventers
The Deepwater Horizon BOP stack had a single blind shear ram. Regardless of what the regulations allowed, you don’t drill a complex well like this without redundant shearing capability (and at the time of the blowout most deepwater drillers were using rigs with dual shear rams). All well control emergencies requiring the emergency disconnect sequence, deadman, and autoshear functions are dependent on effective shearing capability. You can have redundancy in every other BOP element, but without dual shear rams, you don’t have a redundant BOP system. Further, for full redundancy both shear rams should be capable of sealing the well bore after shearing. In that regard, the present regulations and the applicable standard (API S 53) require only one shear ram capable of sealing. They are thus deficient and should be updated.
The DWH BOP system did not have full bore shearing capability (available at the time) which may have sheared the deflected drill pipe.
The DWH BOP system was not properly maintained and recertified as required by regulation.
Transocean’s “condition based maintenance” was a euphenism for “fix it when it fails.” Perhaps worse, BP authorized the continuation of operations knowing that an annular preventer was leaking.
The initial flow from the well was directed to the mud-gas separator instead of being routed overboard via the diverter. Routing the flow to the diverter would have provided additional time for the crew to safely evacuate.
Gas detectors
Not all gas detectors were fully operational. As justification, Transocean’s report expressed concerns about alarm fatigue, a weak excuse. Alarm issues can be effectively managed without disabling the devices.
The gas detectors did not automatically shutdown the generators, the source of the initial explosion. This is somewhat understandable on a dynamically positioned rig that is dependent on power to maintain position. However, someone should have shut down the generators as soon as gas was detected.
Engine overspeed devices didn’t work, and apparently weren’t tested regularly. Had they worked, the engine room explosion may have been prevented.
The crew had time to activate the Emergency Disconnect Sequence, but did not.
Industry standards are critical to safety achievement. They represent best practices as determined by leading experts in the many disciplines that support oil and gas exploration and development. Another plus for standards is that, unlike regulations, they can be developed in a timely manner, particularly where there is an immediate need. However, industry mergers and streamlining have reduced the diversity of input, and some companies either do not participate or participate primarily to promote or protect their particular interest. The need for a consensus can also result in “lowest common denominator” outcomes that lack the necessary rigor.
Minerals Management Service (MMS) reviews indicated that cementing issues were the leading contributing factor to well control incidents between 1992 and 1996 (see chart below). On August 16, 2000, MMS challenged a new API cementing work group to improve zonal isolation, reduce the occurrence of sustained casing pressure, and prevent annular flow incidents before, during, and after cementing operations. Unfortunately, the standard was long delayed because of internal disagreements within the work group. Feedback indicated that some participants preferred a watered down, less rigorous version.
It is undisputed that the primary cement at Macondo failed to isolate hydrocarbons in the formation from the wellbore—that is, it did not accomplish zonal isolation. If the cement had set properly in its intended location, the cement would have prevented hydrocarbons from flowing out of the formation and into the well. The cement would have been a stand-alone barrier that would have prevented a blowout even in the absence of any other barriers (such as closed blowout preventer rams, drilling mud, and cement plugs).
API Standard 65-2, Isolating Potential Flow Zones During Well Construction, if completed in a timely manner and complied with would likely have prevented not only the Macondo disaster, but also the 2009 Montara blowout in Australia. (The Montara investigation hearings were covered extensively on this blog in 2010.) This important standard was ultimately finalized in a reactive manner after the Macondo well blew out.
Standard 65-2 focuses on the prevention of flow through or past barriers that are installed during well construction. A few key elements that are pertinent from a Macondo perspective:
Companies are required to perform a risk assessment prior to utilizing foamed cement and make sure that the results of this assessment are incorporated in the cementing plan. In setting the production casing on the Macondo well, foamed cement was used in an oil-based mud environment, destablizing the cement and contributing to the failure to isolate the highly productive oil reservoir.
The framework in Annex D of the standard does a good job of outlining the questions that should be asked in conducting a cementing risk assessment. These issues identified in the Chief Counsel’s report, which includes an outstanding review of the technical and management issues associated with the cementing/zonal isolation of the Macondo reservoirs, should have been addressed by BP and their contractors before initiating the well suspension program:
narrow pore pressure/fracture gradient;
use of nitrogen foamed cement;
use of long string casing design;
short shoe track;
limited number of centralizers;
uncertainty regarding float conversion;
limited pre-cementing mud circulation;
decision not to spot heavy mud in rathole;
low cement volume;
low cement flow rate;
no cement evaluation log before temporary abandonment; and
temporary abandonment procedures that would severely underbalance the well and place greater stress than normal on the cement job.
Unfortunately, such an assessment was not conducted and critical operational decisions were made in a rash manner with the objective of saving time. We know the outcome – 11 lives lost, massive pollution, and enormous social costs
Despite making multiple changes over the last nine days before the blowout, the Macondo team did not formally analyze the risks that its temporary abandonment procedures created. The Macondo team never asked BP experts such as subsea wells team leader Merrick Kelley about the wisdom of setting a surface cement plug 3,000 feet below the mudline to accommodate setting the lockdown sleeve or displacing 8,300 feet of mud with seawater without first installing additional physical barriers. It never provided rig personnel a list of potential risks associated with the plan or instructions for mitigating those risks.
Almost every decision the Chief Counsel’s team identified as having potentially contributed to the blowout occurred during the execution phase.
Bud's Offshore Energy (BOE) 