Bud's Offshore Energy (BOE)

Q. Commissioner: Over the course of this Inquiry, I’ve been keen to engage Alert Well Control myself, unsuccessfully up until this point of time. Does that surprise you?
A. Mr. Jacob (PTTEP COO): Yes. I’m surprised.

It is good to see that the Commissioner is pressing the issue of testimony by ALERT, PTEEP’s well control contractor.  My guess is that there has been a glitch in communications between the Commission and ALERT, and that the company will cooperate.  If not, I would assume that the Commissioner can compel them to testify.

Highlights of an interesting day:

1. The Commissioner asked questions about the risks associated with a surface capping operation.  We need to hear from ALERT on these issues, and the specifics of ALERT’s capping plan.  As previously noted, a surface capping operation would have been very difficult, and may not have been feasible.  ALERT’s testimony is very important.
2. There was some questioning about the availability of the Ocean Shield to drill the relief well.  Issues associated with the relief -well rig selection, particularly the contractual concerns, need to be fully explored.  Do regulators need to require that relief well contracts be executed in advance?  I hope not, but these contractual issues need to be fully aired.
3. The Commissioner asked good questions about igniting the flowing well.  While igniting the well would have destroyed the rig and platform and complicated the resumption of operations at Montara, ignition would have significantly reduced the environmental damage.  On balance, I think the correct decision (not to ignite) was probably made.  However, that decision should have been made by the Federal official leading the response (in the US that would be the Coast Guard’s On Scene Commander), not by PTTEP.
4. The mud weight needed to kill the well was significantly higher than had been initially calculated by the well control specialists.
5. Mr. Abbott (PTTEP attorney) drew attention to the burden of questions and input from multiple agencies and organizations during the emergency response.  In this regard, I think Mr. Abbott has a good point.  During an emergency response, all communications should be through a single Federal official (e.g. the On Scene Commander).
6. Mr. Abbott also pointed to confusion resulting from the  multiple safety cases.  Again, this may be a good point.  In my view, one party should be accountable for all operations within a licensed area.
7. I have never heard of a case where (1) the operator waited for government to investigate before conducting an internal review or (2) a company asserted attorney-client privilege to withhold an accident investigation report from a government authority.
8. Apparently, PTTEP only recently considered the condition of the other wells at Montara.
9. PTTEP’s spill estimate (400 bopd) is based solely on visual observations.  I agree with the commissioner that flow modeling should have been conducted.
10. According to testimony, PTTEP operates other facilities in the Timor Sea including 2 FPSO’s.   What is their safety and compliance record?
11. PTTEP considered developing Montara with subsea wells before opting for a production platform.

Other quotes of interest:

Jacob: When the safety case regime came into play in 2005, it was a fairly significant change from the previous one, in
that it then identified facility operators, being a rig contractor, a diving support vessel, a lay barge operator, et cetera, as having legal responsibility for the safety of the workforce at that site and a safe site. It was not the traditional way that things had worked in the past. Previously, it had been the titleholder who had had ultimate responsibility across everything.

Q. Howe: You see, sir, the evidence you are giving gets close to an assertion that you kept yourself in a state of
steadfast ignorance as to what was being offered to this Inquiry concerning the possible causes of the blowout.  Do
you agree with that?
A. Jacob: I can see how you can come to that, yes.

Q. Howe: I want to suggest to you an alternative way of approaching the evidence, namely, that PTT, at a corporate
level, seems to have accepted a level of responsibility only when it became apparent that it could not do
otherwise?
A. Jacob: I wouldn’t agree with that.

Q. Howe: Will you accept, sir, that the nature of the evidence canvassed in the course of this Inquiry indicates
deficiencies right up the line to and including the CEO of PTT?
A. Jacob: Yes, based on the line of questioning you have been following, yes.

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Q. Howe (Commission): I want to suggest to you, sir, that you have rather reversed the direction of responsibility, in giving that answer, because PTT should have placed itself in a position properly to assist this Commission rather than taking a passive role, sending you along to listen to the evidence so that you could find out what had happened; do you agree with that?
A. Jacob (PTTEP): Yes, that would not be an appropriate response, and I don’t believe it was the intent of the company to do that.

Comment: PTTEP has seemingly been as passive in their investigation as they were in their well planning.  Why has there been no modeling of well fluid movement prior and subsequent to the removal of the 9 5/8″ cap?

Jacob: I was advised that, on an initial assessment, there was a high risk of a fatality should the capping option be followed through; that the Alert personnel were willing to carry it out. I called a management meeting, and that was presented to us by the well construction manager, Craig Duncan, and at that point the company’s decision was that the capping operation was not an acceptable solution at that time, that they were to continue looking at it as to ways to improve the safety ability of it.

Comment: Given the status of batch tieback operations at the time of the blowout, a surface capping operation would have been extremely dangerous and perhaps infeasible.  Not only was the well left with no barriers, it was also left in a state that virtually precluded surface capping.  Only the 20″ casing was accessible and there was no cement in the 20″ x 13 3/8″ annulus.  Even if they were able to slip BOPE or some other type of specialty valving over the 20″ and seal it hydraulically (or by some other means), the 20″ casing would not have had sufficient integrity to shut-in or kill the well.  To kill the well, they would have probably had to tie-back  the 13 3/8 with the well flowing and connect BOPE.   If feasible, that would be very risky.

That said, PTTEP’s submission and testimony advise that ALERT, a well control specialist company, had a plan for a surface capping operation.  According to Mr. Jacob,  ALERT was willing to proceed with that plan.  ALERT is an emergency well control responder, and their plan should have been fully vetted with the regulators.  I cannot understand why the Commission has no plans for ALERT to testify at these hearings.  How do you assess the blowout response without questioning ALERT?

Other comments:

1. Will there be any questioning about the selection process for the relief well rig?  The reasoning provided in the PTTEP submission raises contractual issues that should not be a factor in an emergency response.
2. PTTEP’s report to NOPSA (Federal regulator) included information on key Montara issues that was (at best) misleading.
3. Mr. Jacob made several comments about how the company has learned from its mistakes.  Should the company be given that opportunity?  While the industry as a whole must learn from disasters like this, should the responsible company be allowed to simply return to business?  Australia should consider legislation that allows the regulator to disqualify companies that so flagrantly disregard their safety management responsibilities.
4. More evidence was presented that drilling contractor safety cases have created confusion about accountability and responsibility.
5. According to the testimony, the Northern Territory Department of Resources converted to a non-prescriptive regulatory regime in 2004.  Why are they still approving well plans and deviations?  This would seem to be contrary to the “operator responsibility” regulatory philosophy.  What standards are applied by NT in their reviews?  How do they act on significant program revisions (e.g. substituting corrosion caps for cement plugs) so quickly?
6. PTTEP’s attorney spent most of his time drawing attention to how hard Mr. Jacob and his staff worked after the blowout.  Is the Commissioner supposed to be surprised? Impressed? Sympathetic?
7. Like Mr. Jacob, I had no idea what “tendentious” meant.  According to Mr. Howe, it means “seeking to persuade in terms of allaying such concerns as the regulator might have.”  Not exactly the dictionary definition, but highly apt in this case 🙂

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Firstly, my sincere condolences to the families, friends, and colleagues of the miners who lost their lives in the tragic accident in West Virginia.   Miners have contributed greatly to  our society and economic development.  I hope that the lessons learned from this terrible accident will be applied, that workplace risks for miners will be reduced, and that lives will be saved.

While the Montara blowout was a horrible accident, no one was killed and no one was injured.  The offshore industry has a commendable safety record, but we need to keep advancing.  These hearings are important so that we can apply the findings and protect workers and the environment even better.

Today’s comments and observations:

1. Mr. Duncan returned to the stand and discussed the installation of the corrosion cap and the manual application of torque.  In my opinion, the pressure holding capabilities of the cap should never have come into question, because the cap should have been installed in addition to (not in lieu of) a secondary cement or mechanical barrier in the well bore.  That said, I am still hoping to hear testimony about how corrosion caps are pressure tested in situ.
2. PTTEP is 100% owner of the license, so there were no partner issues.
3. The consensus view that a pressure test on the 9 5/8″ casing  should have been conducted (after the cement set) is consistent with that of Mr. Ross, an outside expert.
4. Contrary to PTTEP’s manual and accepted industry practice, the cement plugs installed as barriers in other Montara wells were not tested.
5. Regulator acceptance of drilling contractor safety cases may create confusion about responsibility and accountability.  While these cases provide useful information, perhaps they should be considered attendant documents (to the operator/licensee drilling program), not separate regulatory actions.  In my view, the operator has to be the accountable party and all approvals and regulatory actions should be through the operator.
6. Apparently, PTTEP was expected to adhere to the 14-day BOP pressure-test interval specified in the Atlas safety case.  However, there is evidence that more than 14 days elapsed on at least one occasion.
7. Mr. Jacob, PTTEP COO, followed Mr. Duncan, and was challenged on PTTEP’s failure to release its internal review of the incident.  PTTEP is claiming that the report was prepared for their attorneys and is thus protected by attorney-client privilege.  So, PTTEP’s lawyers want the full story so they can assist with the defense, but they only want the regulators and the commission to have part of the story.  At least that’s the way it appears to this observer.
8. I wish there was some discussion about the H-1 casing program.  Based on Mr. Duncan’s testimony and information gleaned from the Montara submissions, other observers and I believe the casing program was deficient.  While these deficiencies (other than the cementing aspects) may not have been contributing factors in this blowout, they are an indication of the operator’s risk tolerance.  Also, the fact (per Mr. Duncan) that the 13 3/8″ surface casing was not cemented back to surface (i.e. was not cemented up into the 20″ x 13 3/8″ annulus) precluded attaching the BOP to the 20″ (even if it was otherwise feasible).

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The hearings resume tomorrow.  Catching up on what I missed:

1. I’d like to have a dollar for each time one of the witnesses said “in hindsight.”  I guess saying “in hindsight” is a way of acknowledging that you were wrong without admitting you made a mistake.  After all, how could anyone have known that a float leak wouldn’t cure itself, that an underbalanced well would start to flow, that oil and gas might pass through the channels in the shoe, that well barrier requirements have a real purpose (beside challenging your cost-cutting creativity), and that gas bubbles might be actually be a reason for concern?  When you do a proper risk assessment, you consider all of the future possibilities and how decisions made in the present could affect the outcomes.  You are thus taking advantage of hindsight BEFORE an accident occurs.
2. The “Not My Job” attitude seemed to be prevalent at Montara.  Did the famous Arizona highway worker use the “in  hindsight” defense?  (In hindsight, I should have removed the dead armadillo before striping the highway.)
3. I guess I’m slow, because it took me until Day 12 (more than 1000 pages of transcripts) to realize that the mudline suspensions were not really mudline suspensions, but that the wells were hung from the jacket (just above the splash zone?).  The tops of the wells during the suspension of operations were thus in a highly corrosive environment, so the damage to the unprotected 13 3/8″ casing threads is not surprising.
4. I’m still scratching my head about that “shudder” that was felt on the platform the night before the blowout (see Tom Maunder’s comments below).  Was there a seismic event?  I checked the USGS records and didn’t see anything for that area and time.  Apparently PTTEP checked with the Australian government.  Is the seismic grid sufficient to detect small quakes in that portion of the Timor Sea?
5. So now we know that the integrity of 3 of the 5 Montara wells was compromised.  Gas bubbles were observed in the annulus of the G-1 and there were significant cementing issues with the H-2.
6. None of the PCC’s were pressure tested in situ.  I’m still waiting for a tutorial on how that is done.  Would the 9 5/8″ PCC have been pressure tested against the casing?  If so, perhaps that test would have identified the channels in the casing shoe?

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There is a small cadre of experienced oil and gas professionals who have been following the Montara transcripts religiously, and I have received a number of email messages about the testimony.  Pasted below is a message from Tom Maunder, a well engineer working in Alaska.   Tom has extensive industry and regulatory experience, and actually lived on the Alexander Kielland while working offshore Norway.

I have highlighted a couple of Tom’s observations in bold.  Like the Montara Commission, I had largely dismissed the possibility that a seismic event was a contributing factor to the blowout.  Also, I don’t think the Commission has sufficiently considered the effect of the horizontal well section on the delayed gas migration and flow following the removal of the corrosion cap.

Based on the statements regarding GOC and OWC, it appears that the reservoir is saturated and stratified with a gas cap over oil over water as would be expected.  What went unstated is that at reservoir conditions, the oil contains some amount of solution gas. Based on the testimony, it seems clear that any cement inside the bottom of the casing was contaminated with sea water and likely oil based on where the shoe was set.  Some amount of seal probably was established by holding pressure to allow the cement to set.  Although the plugs were bumped, the float failure and subsequent “check” allowed cement and oil to be let into the casing and that also resulted in lifting at least the top plug some distance up into the casing.  It is possible that this lifting reversed the fins essentially making the top plug worthless as a separating device for the cement and sea water displacement fluid.  This would seem to be supported since the testimony indicates that it was not possible to rebump the plug.  There is much discussion regarding the pore pressure and displacement weights or EMW.  I believe the seawater did not have sufficient weight to counter the formation pressure.  If ther was any overbalance it was very slight.  In either Seadrill’s or PTTEP’s submissions and in recent testimony the possibility of some seismic event is considered and then dismissed.  Based on reported experiences in Cook Inlet Alaska, I believe the “event” was real and it was likely whatever cement seal that had been formed at the bottom of the casing finally failing.  There have been a couple of deep production casing failures on wells drilled from Cook Inlet platforms.  In each case, the people on the platform reported feeling a “jolt”. It is not unlike shooting drill pipe conveyed perforating guns.  There is also testimony regarding the “time delay” between removing the 9-5/8” PCC to the initial burp and then the final unloading.  I don’t think any one is considering the horizontal portion of the well.  Movement along that section would be significantly different and likely much slower than movement in the more vertical portion of the wellbore. With little vertical depth change the evolution of solution gas as the pressure drops would be slower in the horizontal section.  I remember that well control school problems were changed to incorporate separate calculations for the horizontal versus vertical sections since the pressure change per time or volume in the horizontal section would be much, much smaller than in the vertical.

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