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UNITED STATES DISTRICT COURT

EASTERN DISTRICT OF LOUISIANA

IN RE: OIL SPILL BY THE OIL RIG * Docket 10-MD-2179DEEPWATER HORIZONIN THE *GULF OF MEXICO ON APRIL 20, 2010 * Section J

*Applies to: * New Orleans, Louisiana

*Docket 10-CV-02771, * March 18, 2013IN RE: THE COMPLAINT AND *PETITION OF TRITON ASSET *LEASING GmbH, et al *

*Docket 10-CV-4536, *UNITED STATES OF AMERICA v. *BP EXPLORATION & PRODUCTION, *INC., et al *

** * * * * * * * * * * * * * * * * *

DAY 13, AFTERNOON SESSIONTRANSCRIPT OF NONJURY TRIAL

BEFORE THE HONORABLE CARL J. BARBIER

UNITED STATES DISTRICT JUDGE

Appearances:

For the Plaintiffs: Domengeaux Wright Roy& Edwards, LLC

BY: JAMES P. ROY, ESQ.556 Jefferson Street, Suite 500Post Office Box 3668Lafayette, Louisiana 70502

For the Plaintiffs: Herman Herman & Katz, LLCBY: STEPHEN J. HERMAN, ESQ.820 O'Keefe AvenueNew Orleans, Louisiana 70113

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Appearances:

For the Plaintiffs: Cunningham Bounds, LLCBY: ROBERT T. CUNNINGHAM, ESQ.1601 Dauphin StreetMobile, Alabama 36604

For the Plaintiffs: Lewis Kullman Sterbcow & AbramsonBY: PAUL M. STERBCOW, ESQ.601 Poydras Street, Suite 2615New Orleans, Louisiana 70130

For the Plaintiffs: Breit Drescher Imprevento

& Walker, PCBY: JEFFREY A. BREIT, ESQ.600 22nd Street, Suite 402Virginia Beach, Virginia 23451

For the Plaintiffs: Leger & ShawBY: WALTER J. LEGER JR., ESQ.600 Carondelet Street, 9th FloorNew Orleans, Louisiana 70130

For the Plaintiffs: Williams Law Group, LLC

BY: CONRAD "DUKE" WILLIAMS, ESQ.435 Corporate Drive, Suite 101Houma, Louisiana 70360

For the Plaintiffs: Thornhill Law FirmBY: TOM THORNHILL, ESQ.1308 Ninth StreetSlidell, Louisiana 70458

For the Plaintiffs: deGravelles Palmintier Holthaus& Frug, LLP

BY: JOHN W. DEGRAVELLES, ESQ.618 Main StreetBaton Rouge, Louisiana 70801

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Appearances:

For the Plaintiffs: Williamson & RusnakBY: JIMMY WILLIAMSON, ESQ.4310 Yoakum BoulevardHouston, Texas 77006

For the Plaintiffs: Irpino Law FirmBY: ANTHONY IRPINO, ESQ.2216 Magazine StreetNew Orleans, Louisiana 70130

For the United States U.S. Department of Justice

of America: Torts Branch, Civil DivisionBY: R. MICHAEL UNDERHILL, ESQ.450 Golden Gate Avenue7-5395 Federal Bldg., Box 36028San Francisco, California 94102

For the United States U.S. Department of Justiceof America: Environment & Natural Resources

Environmental Enforcement SectionBY: STEVEN O'ROURKE, ESQ.

SCOTT CERNICH, ESQ.DEANNA CHANG, ESQ.

RACHEL HANKEY, ESQ.A. NATHANIEL CHAKERES, ESQ.Post Office Box 7611Washington, D.C. 20044

For the United States U.S. Department of Justiceof America: Torts Branch, Civil Division

BY: JESSICA McCLELLAN, ESQ.MICHELLE DELEMARRE, ESQ.JESSICA SULLIVAN, ESQ.SHARON SHUTLER, ESQ.MALINDA LAWRENCE, ESQ.

Post Office Box 14271Washington, D.C. 20004

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Appearances:

For the United States U.S. Department of Justiceof America: Fraud Section

Commercial Litigation BranchBY: DANIEL SPIRO, ESQ.

KELLEY HAUSER, ESQ.ELIZABETH YOUNG, ESQ.

Ben Franklin StationWashington, D.C. 20044

For the State of Attorney General of AlabamaAlabama: BY: LUTHER STRANGE, ESQ.

COREY L. MAZE, ESQ.

WINFIELD J. SINCLAIR, ESQ.500 Dexter AvenueMontgomery, Alabama 36130

For the State of Attorney General of LouisianaLouisiana: BY: JAMES D. CALDWELL, ESQ.

1885 North Third StreetPost Office Box 94005Baton Rouge, Louisiana 70804

For the State of Kanner & Whiteley, LLC

Louisiana: BY: ALLAN KANNER, ESQ.DOUGLAS R. KRAUS, ESQ.701 Camp StreetNew Orleans, Louisiana 70130

For BP Exploration & Liskow & Lewis, APLCProduction Inc., BY: DON K. HAYCRAFT, ESQ.BP America Production 701 Poydras Street, Suite 5000Company, BP PLC: New Orleans, Louisiana 70139

For BP Exploration & Kirkland & Ellis, LLP

Production Inc., BY: J. ANDREW LANGAN, ESQ.BP America Production HARIKLIA "CARRIE" KARIS, ESQ.Company, BP PLC: MATTHEW T. REGAN, ESQ.

300 N. LasalleChicago, Illinois 60654

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Appearances:

For BP Exploration & Covington & Burling, LLPProduction Inc., BY: ROBERT C. "MIKE" BROCK, ESQ.BP America Production 1201 Pennsylvania Avenue, NWCompany, BP PLC: Washington, D.C. 20004

For Transocean Holdings Frilot, LLCLLC, Transocean Offshore BY: KERRY J. MILLER, ESQ.Deepwater Drilling Inc., 1100 Poydras Street, Suite 3700Transocean Deepwater Inc.: New Orleans, Louisiana 70163

For Transocean Holdings Sutherland Asbill & Brennan, LLP

LLC, Transocean Offshore BY: STEVEN L. ROBERTS, ESQ.Deepwater Drilling Inc., RACHEL G. CLINGMAN, ESQ.Transocean Deepwater Inc.: 1001 Fannin Street, Suite 3700

Houston, Texas 77002

For Transocean Holdings Munger Tolles & Olson, LLPLLC, Transocean Offshore BY: MICHAEL R. DOYEN, ESQ.Deepwater Drilling Inc., BRAD D. BRIAN, ESQ.Transocean Deepwater Inc.: LUIS LI, ESQ.

355 S. Grand Avenue, 35th FloorLos Angeles, California 90071

For Transocean Holdings Mahtook & LafleurLLC, Transocean Offshore BY: RICHARD J. HYMEL, ESQ.Deepwater Drilling Inc., 600 Jefferson Street, Suite 1000Transocean Deepwater Inc.: Post Office Box 3089

Lafayette, Louisiana 70501

For Transocean Holdings Hughes Arrell Kinchen, LLPLLC, Transocean Offshore BY: JOHN KINCHEN, ESQ.Deepwater Drilling Inc., 2211 Norfolk, Suite 1110Transocean Deepwater Inc.: Houston, Texas 77098

For Cameron International Stone Pigman Walther Wittmann, LLCCorporation: BY: PHILLIP A. WITTMANN, ESQ.

546 Carondelet StreetNew Orleans, Louisiana 70130

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Appearances:

For Cameron International Beck Redden & Secrest, LLPCorporation: BY: DAVID J. BECK, ESQ.

DAVID W. JONES, ESQ.GEOFFREY GANNAWAY, ESQ.ALEX B. ROBERTS, ESQ.

1221 McKinney Street, Suite 4500Houston, Texas 77010

For Halliburton Energy Godwin Lewis, PCServices, Inc.: BY: DONALD E. GODWIN, ESQ.

BRUCE W. BOWMAN JR., ESQ.FLOYD R. HARTLEY JR., ESQ.

GAVIN HILL, ESQ.1201 Elm Street, Suite 1700Dallas, Texas 75270

For Halliburton Energy: Godwin Lewis, PCServices, Inc.: BY: JERRY C. VON STERNBERG, ESQ.

1331 Lamar, Suite 1665Houston, Texas 77010

For M-I, LLC: Morgan Lewis & BockiusBY: HUGH E. TANNER, ESQ.

DENISE SCOFIELD, ESQ.JOHN C. FUNDERBURK, ESQ.1000 Louisiana Street, Suite 4000Houston, Texas 77002

Official Court Reporter: Jodi Simcox, RMR, FCRR500 Poydras Street, Room HB-406New Orleans, Louisiana 70130(504) [email protected]

Proceedings recorded by mechanical stenography usingcomputer-aided transcription software.

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I N D E X

Page

Calvin BarnhillDirect Examination By Mr. Hymel: 4309Cross-Examination By Mr. Sterbcow: 4349Cross-Examination By Mr. Hartley: 4387Cross-Examination Mr. Brock 4446:

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CALVIN BARNHILL - DIRECT

AFTERNOON SESSION

(March 18, 2013)

* * * * *

(WHEREUPON, CALVIN BARNHILL, having been previously

duly sworn, testified as follows.)

THE COURT: All right. Please be seated. Good

afternoon, everyone.

All right. Mr. Hymel.

DIRECT EXAMINATIONBY MR. HYMEL:

Q. Mr. Barnhill, let's next talk about the converter. Is

there evidence that the crew diverted?

A. Yes.

Q. What was your basis for that statement?

A. I think both of the phone calls maybe indicated that they

were shutting the well and they were going to divert -- or had

diverted and were shutting the well in. I think the phone call

from Mr. -- in the interview or the post-incident notes of

Mr. Vidrine, I believe that was indicated. And I believe

Mr. Ezell in his phone call had indicated something to that

effect.

Q. What's the fact that the crew diverted mean to you?

A. Again, you know, that they recognized there was live fluid

in the riser, and they were diverting the flow.

Q. How long is the time from when the diverter is activated

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until the diverter closes?

A. Roughly around 45 seconds.

Q. Were you in the courtroom when Randy Ezell testified that

the diverter was lined up to the mud-gas separator?

A. I believe I was. I was aware of that fact. I believe I

was, yes.

MR. HYMEL: Please go to TREX-2210.2.TO.

BY MR. HYMEL:

Q. Have you seen these BP deepwater well control guidelinesbefore?

A. Yes, I believe I've seen those.

MR. HYMEL: All right. Let's go to 2210.17.1.TO.

BY MR. HYMEL:

Q. Have you seen these provisions?

A. Yes.

Q. What are the significance of these provisions?

A. Well, again, it indicates that when you close your

diverter that you're to direct fluid through the riser gas

buster. The gas buster is a slang term that we use for mud-gas

separator.

And then 13 says, When you have rapid expansion of

fluids near the surface, attempt to keep the flow going through

the gas buster as opposed to overboard lines to minimize

synthetic oil going into the Gulf, but be prepared to divert.

Q. So are these BP guidelines consistent with lining up the

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converter to the mud-gas separator?

A. They're consistent with that and then staying on the

mud-gas separator as long as you can.

Q. Do you have an opinion as to whether the Transocean drill

crew switched from the mud-gas separator to go overboard?

A. I don't know. The information I reviewed didn't indicate

that. I know Mr. Ezell testified that he saw fire coming out

of the diverter line. I have no reason to doubt that that's

what he saw. I just don't know one way or the other.Q. Let's next talk about the emergency disconnect system.

What is the emergency disconnect system?

A. The EDS system is a system that I think -- the emergency

disconnect system.

Q. Let me stop you, Mr. Barnhill. We put up D-6647. Now,

what does this show?

A. Basically, it shows the BOP stack that we looked at this

morning with the two sections showing -- you can see the dark

and plain area between the two sections, which is where the

disconnect would occur if you were EDS'g the well.

Q. And so how does the EDS work?

A. Basically, it's a process function that once you engage it

by activating the proper buttons, basically, there's a sequence

that goes into place that would culminate in the closing of the

blind shear rams and the disconnecting of the LMRP from the

lower marine stack -- the lower BOP stack.

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Q. Mr. Webster testified that Captain Kuchta should not have

waited to get information from other people; he should have

just EDS'd. What is your response to that?

A. I don't agree with that comment.

I think you have to have communication between the

rig floor and the bridge. The rig floor is where the well

control operations are being conducted.

To me, EDS'g is a terminal operation. Once you do

that, I mean, you're going to disconnect from that BOP stackwith that LMRP, you're going to lose that functionality. If

that well is not spaced out appropriately or if you haven't

worked through all your well control sequences, you're going to

cut off those possibilities.

Q. Now, we talked earlier today about the fact that the

VBR -- there was a pressure spike that indicated the VBR

sealed. What does that mean to you with regard to our

discussion here about EDS'd?

A. Well, again, there were operations that were going on post

the time that we believe the fluid blew up through the rotary

table, which would include the activation of the VBR which it

seemed -- which appeared to affect the seal for some period of

time.

Q. So does the fact that the VBR appeared to seal indicate

that the crew was going through the well control sequence?

A. Yes. I mean, it looked like they were working through a

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well control sequence at the time that the VBRs were closed.

Q. And if Captain Kuchta would have EDS'd immediately,

without calling the drill floor, he could have interrupted what

the drill crew was doing?

A. That sequence would have not -- they would have not gone

forward with that sequence.

Q. All right. Now, we've been discussing the events during

the displacement of the well. Now I want to kind of go before

this, and let's talk about the events leading up to thedisplacement.

A. Okay.

MR. HYMEL: Please put up D-6579.

BY MR. HYMEL:

Q. What is this document, and what does it demonstrate?

A. This appears to be a listing of the various TA procedures

or the versions of the TA procedures that were circulated back

into -- from the rig. I think there were five different

procedures or versions of the procedures that were actually --

maybe even six, looking at this -- that were sent to the rig

and back and to.

MR. HYMEL: Put up D-6646.

BY MR. HYMEL:

Q. I want to go back to our discussion earlier about how BP

intended to TA this well, and let's talk a little bit more in

detail. You stated in your report that it appeared that the

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lockdown sleeve kind of became a focus of the TA procedure.

Please explain that.

A. Well, the lockdown sleeve is a production apparatus that

basically locks the top of the casing into the wellhead area so

that as you're producing this well, you don't get unwanted

movement of the casing.

Deepwater wells, to be economically viable, just by

the cost of going and looking for them, have to be able to

produce high volumes of hydrocarbons in a short period of timeor a high rate of producibility to make them economically

viable.

So as you produce the reservoir fluids that are under

temperature and pressure down in the earth and they come up

through the wellbore, they tend to heat the tubulars in the

wellbore, and that tends to pressurize the wellbore. And the

combination of pressure and temperature tend to affect the

pressure in the various annuli of the well and in the casing so

the casing can actually try to expand on you as you're

producing or contracting your shut-in. So to lock the top of

the casing in place, you install the lockdown sleeve.

Q. What effect does installing the lockdown sleeve or

intending to install the lockdown sleeve at this point in the

well have on the TA procedure?

A. Well, it would have altered the TA procedure. We know

from the original TA procedure that was done, they set the

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surface plug 800 to 1,000 feet below the mud line. Here,

because the decision had been made to set the lockdown sleeve

and to set the lockdown sleeve last so that you wouldn't damage

it, because of the procedure that was required, that required

moving the surface plug deeper in the well.

That's the reason it moved from roughly about

5800 feet down to about 8300 feet, 8367, somewhere in that

range.

So one of the results was to move your plug deeperdown. Then the decision associated with that, to set the plug

in water, meant that you were going to remove more of the mud

out of the wellbore during the TA procedure.

So it looked like to me, in going through the TA

procedures, that the focus became more the successful setting

of this lockdown sleeve than the management of the well at the

end.

Q. Mr. Barnhill, you state at page 4 of the executive summary

of your report that "the displacement of the SBM" -- and what

does that mean?

A. Synthetic-base mud.

Q. -- "...with seawater reduced the hydrostatic pressure in

the Macondo well to a greater degree than normal."

What do you mean by that?

A. Typically, when we get ready to abandon or temporarily

abandon a well in a floating operation, you're going to remove

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the riser and the BOP stack. That goes with the rig.

So basically what you're doing is -- and remember, we

talked about how our primary well control was the hydrostatic

pressure created by the drilling mud, which was the length of

the column times the density of the fluid.

Well, we're going to be removing the riser in the BOP

system, so we're going to be greatly reducing the length of

column that's available. So to be able to do that -- and by

the way, that link that's associated with the riser is calledthe "riser margin." So when we remove the riser, we remove

that riser volume, we have to make sure that the well is

appropriately sealed with other types of flow barriers, in the

event the well's underbalanced, so that the well cannot flow on

us or have a well control problem.

Q. When did the lockdown sleeve need to be installed?

A. The lockdown sleeve is basically associated with the

production operations. It could have been installed in the

completion operations.

Q. And when you say "the completion operations," does that

mean the Deepwater Horizon could have TA'd the well and left

and another rig, whether it be the Deepwater Horizon or another

rig, come back and install the lockdown sleeve?

A. That's my understanding, yes.

Q. How would the TA procedure have been different if BP chose

to set the lockdown sleeve during completion and just TA the

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well the way it is, without setting the lockdown sleeve?

A. Well, if you were going to do, let's say, a more

traditional TA procedure, then basically, once they've got the

shoe track set and the determination was to use the shoe track,

the undisturbed shoe track was the bottom plug, then they could

have come in and conducted their negative test, which was based

along the kill line. They could have done it before they ran

their displacement string, before they did any displacement,

before they introduced any spacer into the well.That would have given them the equivalent of a

testing with the seawater gradient down to about 6500 feet. So

they could have tested, basically, what the equivalent setup of

the well was going to be after the TA was completed. Pretty

straightforward, just like they had done on the initial TA.

If they had done that, then they could have set the

upper plug, even in water, say from 5800 to 6000 feet, and we

wouldn't have been in the situation we ultimately wound up in.

Q. Let me make sure I understand this.

Let's talk about the negative pressure test that was

done. We haven't gotten to it yet, but I just want to set the

stage here. How was -- the negative pressure test that was

done on April 20th, how was it set up?

A. Basically, the negative test that was actually conducted

was embedded within the displacement. A fair portion of the

displacement had already occurred. They had basically

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displaced the displacement string with seawater and had

displaced the seawater all the way back up, with the game plan

being that the spacer material and the heavy or the weighted

mud would be above the BOP so that you could close the BOP and

then do your test.

So it was -- the term I use is the test was

"embedded" within the displacement.

Q. Okay. Now let's go back to what you said about how the

negative pressure test could have been performed if thelockdown sleeve was going to be set at another time. Explain

that to us.

A. Well, again, you could have basically done the test very

similar to what they did in the initial TA. If you go back --

I think it was the April 14th procedure -- it called for using

base oil -- displace the kill line with base oil down to the

wellhead.

If you do that, you're going to get about a 6500-foot

equivalent displaced in depth with seawater, which would have

put the depth of the seawater below where your surface plug

would have been set if you didn't have to make allowances for

setting the lockdown sleeve last.

Q. So when you say you could have displaced the kill line

with seawater and do the negative pressure test that way, are

you telling us you would not have to displace any of the water

or any of the mud in the wellbore; you would just be displacing

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the mud in the kill line?

A. Give me that question one more time.

Q. Sure. When you say you would displace the mud in the kill

line to do the negative pressure test, are you telling us that

you would then not have to displace any of the mud in the

wellbore?

A. If you would displace with base oil, which is lighter than

seawater, then the effective gradient would have been deeper

than the effect of seawater to the wellhead.My calculations indicate that that would have gotten

you down to about a depth of 6500 feet, which would be below

where you would have set the upper plug if you had set it in

seawater in the wellbore when you were abandoning the wellbore.

So, yes, you could have negatively tested with base

oil to the wellhead prior to displacing the mud out of the well

itself or removing the mud from the riser system.

Q. Okay. Let's move on. Let's talk about some of the

different things that were done during the displacement.

MR. HYMEL: And let's go to D-6643.

BY MR. HYMEL:

Q. Are you ready?

A. Yes.

Q. Let's talk about the production casing first. When did BP

run the production casing?

A. They ran it on April the 18th.

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Q. Were there any indications that the production casing was

successfully run?

A. Yes. I think, reviewing the drilling reports that I

reviewed, the indications from the rig would be that it was

really installed without any problems.

Q. And the production casing being successfully run indicated

what?

A. That you would have had a steel pipe or a steel liner

across the exposed or the hydrocarbon-bearing intervals thathad been exposed during the drilling of the well.

Q. Was there any information about the production casing that

the Transocean drill crew were not told?

A. I don't believe they were aware of the discussions about

long -- whether they were going to run a long string or a liner

or the use of -- how many centralizers they were going to run,

those type of discussions. I don't believe they were aware of

those.

Q. What were the risks associated with running the different

number of centralizers?

A. Well, there was indication from some of the work that

Halliburton had done that by running a minimal number of

centralizers, in this case, seven -- I think there were

actually six that were run -- then there was some indication of

a risk of severe gas flow.

Q. Let's move on to the production casing cement. When was

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the cement job run?

A. The cement job was run on April 19th and 20th. It ended

shortly after midnight on the morning of April 20th, 2010.

Q. Were there indications that the cement job was successful?

A. Yes. I think, from the guys on the rig's perspective, the

indication was that the cement job had gone well. There was

indication from the Halliburton guys and the BP guys that the

job had gone well. There was no loss circulation, there was

lift pressure. So I think the indications were that the cementhad gone well. There was a CVL crew standing by that got sent

in without being run.

Again, they would have been aware that some

centralizers were run, but not all of them. So I think the

indications, the feedback on the rig, would have been we had a

successful cement job.

Q. And the cement job being a success would indicate what?

A. Well, again, now you would have had cemented casing or

cemented pipe across those hydrocarbon-bearing zones, and what

remained to be done was to verify those barriers.

Q. Was there any information about the cement job that the

Transocean drill crew was not told?

A. I don't think they were aware of the status of the

incompleteness of the testing on the foam cement. That's my

memory.

Q. What was the next step in the TA procedure?

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A. Actually, there were positive tests that were run. Once

the casing was cemented in place, then they did a positive test

on the seal assembly, on the hanger, once it was set. They did

a positive test before stinging out of the hanger; then they

stung out of the hanger, and stung back in to make sure they

could get free with their running string.

They retested the seal assembly at that point in

time. Then they tripped out of the hole with their running

string. They picked up their combination displacement stringand cementing string. That was a tapered string. It had

3 1/2-inch tubing, 5 1/2-inch drill pipe, and 6 1/2 drill pipe

that composed -- or made up the string.

They ran that back into the hole to about 4800,

4900 feet, shut the blind shear rams, pumped up through the

kill line to do a pressure test, which would have tested the

blind shears, the seal assembly, the -- or the wellhead area,

the casing itself, down to the top wiper plug, and the top

wiper plug, assuming that that was what was holding.

Q. When were those tests performed?

A. That was, I believe, during the morning hours of

April 20th.

Q. Were there indications that the positive tests were

successful?

A. Yes. Everything I saw -- I mean, I think the term that I

saw from most of the reports and the indications from the folks

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were that it was rock solid.

Q. And the positive test being successful indicated what?

A. Well, again, that would be an indication that you have

done a test to confirm the barriers that you put in place, that

test had been successful. Back at this time frame, actually,

the positive test was the only required test under the

regulations. You weren't required to do, really, any more

testing than this. So this would have indicated a positive

outcome for both the cement and the casing that was installed.Q. What happened after the positive pressure test?

A. Basically, they opened their BOPs -- or opened the blind

shear rams, they ran the combination string on down to the

depth of 87- -- or 8367 feet and then they started doing their

displacement.

Q. How was the displacement set up?

A. Well, initially, they were pumped -- they pumped the

spacer material out of the tanks where the spacer material

would have been located on the rig out of the mud pump -- mud

pit area. That was followed with seawater out of the sea

chest. So that fluid was pumped down the drill pipe, around up

the annular space around the displacement string and the

production casing back up to a point -- I think the initial

plan had been to place the spacer above the top of the BOPs.

The calculations are kind of plus or minus on that.

Some calculations, I think, showed that it was slightly above

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it; some calculations showed that that spacer was still

actually in the BOPs at the time they stopped to do the

negative test.

Q. Where was the displacement set up to pump to?

A. The returns initially were being taken back on the rig in

the rig's pit area.

Q. Okay. And then after the sheen test, where was the

displacement set up to pump to?

A. After -- if the sheen test was successful, which wouldindicate that you were basically returning spacer back at that

point in time. Then it was set up for the returns to go

overboard.

Q. Okay. Now, when the returns were set up to go overboard,

how was the flow-out monitor?

A. The flow-out monitor after the sheen test would have been

monitored with the rig's HiTECH flow show; the Sperry-Sun sonic

flow show would have been bypassed.

Q. And with the well pumping water out of the sea chest, how

was the flow-in monitored?

A. Again, it would be a situation where you were looking at

pump volume versus strokes.

MR. HYMEL: Okay. Please put up TREX-40002.61.TO.

BY MR. HYMEL:

Q. This is from Dr. Bourgoyne's report, and he states that:

"When pumping from the sea chest, the total pump strokes times

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the pump volume factor is an accurate measure of the volume

pumped into the well."

Do you agree with that?

A. I do. That's how we've done it for years.

Q. Then moving on to the next sentence: "The accuracy of the

volumes measured from pump stokes is second only to volumes

measured in a metering tank."

Do you agree with that?

A. Yes.Q. So, Mr. Barnhill, with the flow-in being pumped from the

sea chest and monitored by the pump strokes versus the pump

volumes and the flow-out being monitored by the flow-out

sensor, how would you describe that displacement procedure?

A. Well, again, the displacement procedure, the way I would

describe it is it was an open-pit procedure. By that, I mean

you were sucking out of one system and returning to another

system or returning overboard. A closed system would be -- I

would be taking fluid out of and returning fluid back to the

same system, maybe a series of connected tanks, but it would be

the same system.

So basically, you were taking it out of either the

mud pit system or the sea chest and then returning it back to

the mud pit system at some point.

Q. What are the differences between an open-pit system and a

closed-pit system?

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A. Well, again, as I've just said, you have a situation

where, in a closed-pit system, you're taking out and returning

to the same system. In an open system, you're taking out of a

different point and you are returning it to a different point.

Q. What are the similarities between an open-pit system and a

closed-pit system?

A. The similarities are you're going to have a situation

where basically your volume in is going to be measured the same

way, and the volume out as related to flow -- returned flow isgoing to be essentially monitored the same way.

Q. So just to make sure I understand, even in an open-pit

system, you can monitor flow-in and flow-out?

A. You can. There is -- in the closed-pit system, you have

an additional component, but you can monitor those in an

open-pit system.

Q. Now, the displacement procedure and the way it was set up,

who created that displacement procedure?

A. I think the procedure itself was actually drafted up by

M-I.

Q. And who approved the displacement procedure?

A. BP would have approved it.

Q. Let's talk about the operations taking place during the

displacement.

What operations were taking place during the

displacement?

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A. My understanding is there were several concurrent

operations that were going on. These operations would be

routine-type of operations that would be dealing with mob-ing

or -- or demob-ing a rig, or preparing the rig for a rig move

away from the location, where things like the crane was

backloading or moving equipment around. There was fluid

being -- or synthetic-base mud being transferred to a vessel,

there was fluid movements on the vessel.

So just kind of routine operations of those type.Q. There's been some discussion about the transfers to the

supply boat, the MV Bankston. Do you think transferring mud to

the supply boat played any part in this well control event?

A. I do not. The transfers to the Bankston stopped at 5:17

in the afternoon, so I do not think it was a factor in the well

control situation or the way the well control situation was

done.

Q. How would you characterize the multiple operations that

were taking place during the TA procedure?

A. Well, again, they were routine-type of operations for a --

to prepare a rig for a rig move.

Q. Who approved the multiple operations?

A. Ultimately, it would have been BP. If BP would have

decided they didn't want those to occur at that time, then they

would not have occurred at that time.

Q. Let's go back to D-6643, and let's talk about the negative

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pressure test.

When was the negative pressure test performed?

A. It started at around 5:00 in the afternoon of the 20th and

I think it concluded around 8:00 in the afternoon on the 20th.

Q. Who had the ultimate authority on the rig to determine

whether the negative pressure test was successful?

A. The ultimate authority would have rested with BP. They

would have made the call whether to accept or reject the test

and move forward.Q. Who was responsible for designing the negative pressure

test?

A. The design of the test, as far as when you were going to

do the test, what part of the procedure the test was going to

be performed in. Basically, the type of fluids that you were

going to use, those type of issues would have all been designed

by BP.

MR. HYMEL: Okay. Connie, let's go back to 6579.

BY MR. HYMEL:

Q. We had this demonstrative up when we were talking about

the TA procedures, but I want to ask you a different question.

I want to ask you how many negative pressure test procedures

were in the different TA procedures.

A. Looks like four of the procedures had at least one, if not

two, forms of negative tests done.

Q. Did the negative pressure test procedures change as they

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went from one TA procedure to the other?

A. Yes, they did change.

Q. Let's go to TREX-5730.3.1.TO.

What is this document?

A. This document looks to me to be the -- to be the

April 16th document indicating the procedure that was approved

by the MMS.

Q. How many negative pressure test procedures do you see in

this document?A. They're not stated as -- both as negative tests but, to

me, I see effectively two negative tests in this document.

Q. Where is the first one?

A. The first one is line 1. It says: "Negative test casing

to seawater gradient equivalent to 30 minutes with the kill

line."

Q. Where is the second one?

A. The fact that once you displace the seawater, you're going

to monitor the well for 30 minutes. In effect, you're

monitoring to see what the effect of the differential created

by the seawater displacement is doing. It's, in effect, a

negative test.

Q. Did BP conduct the negative pressure test as specified on

this procedure approved by the MMS?

A. In my opinion, they did not.

Q. Did BP get approval to deviate from this MMS-approved

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procedure?

A. Not that I'm aware of.

Q. What's your understanding as to how the procedure got

changed?

A. It was my understanding that there was some discussion

surrounding what had been approved with what they were actually

trying to accomplish, which was to test with seawater displaced

to the depth of 8367 feet in the well. And so there was some

discussion about having to make some changes to make -- to makethe two compatible. I think, ultimately, my understanding is,

Mr. Guide decided instead of going with two tests, they would

go with a single test embedded within the -- within the

displacement procedure.

Q. Now, let's discuss the negative pressure test that was

performed on April 20th, 2010. How was that negative pressure

test initially set up to be monitored?

A. It was initially being monitored on the drill pipe.

Q. Okay. Let's go to TREX-547.

MR. HYMEL: Judge, I understand that there's been

some issues about the GMT time, and I want to warn you there's

a GMT time on this document. I wish I could explain it to you

as to why and what it really means. I can't. So 547, I think

this was sent out at about 10:46.

MR. REGAN: Rough justice, you can subtract about

four hours.

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MR. HYMEL: Subtract about four hours?

MR. REGAN: About four, yeah.

MR. HYMEL: Five hours?

THE COURT: Subtract about four hours?

MR. REGAN: Yes, sir.

MR. HYMEL: So this would be 3?

BY MR. HYMEL:

Q. Mr. Barnhill, unfortunately, my question is not about the

time.THE COURT: Is the time important?

MR. HYMEL: Well, you can -- you can -- just so it's

clear, I think everybody agrees this was sent out before the

negative pressure test on April 20th.

THE COURT: Four hours would be 11:36?

MS. KARIS: Your Honor, it's actually 10:36. It's

five hours because there's another document that indicates this

is 10:36.

THE COURT: So it's 10:36. So everybody agree with

that? Anybody disagree with that?

I'll take that as a stipulation. Okay.

BY MR. HYMEL:

Q. All right. Mr. Barnhill, my question to you is -- let me

find my question here: Is monitoring on the drill pipe, the

way the negative pressure test was set up on April 20th, is

that consistent with this April 20th, 10:36 a.m. procedure?

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A. I don't see anything in here that would prohibit you from

monitoring on the drill pipe. Certainly, the indications are

that the -- that you're using seawater in your kill line. But

there's no prohibition against monitoring on the kill line,

which should be full of seawater also.

Q. Okay. Let's go back to 2807.1.1.TO. This is the M-I

displacement procedure we looked at a little earlier.

Is monitoring the negative pressure test on the drill

pipe on April 20th, 2010, consistent with this M-I displacementprocedure?

A. That's -- again, there's no -- there -- actually on this

one, there's no indication where to monitor. You could monitor

on either. If your kill line was lined up, which -- certainly,

there's no reason you could not monitor on the drill pipe.

Q. Mr. Barnhill, could the negative pressure test have been

completed on the drill pipe?

A. It could have been. In my opinion, it was.

Q. Were any anomalies observed while monitoring the negative

pressure test on the drill pipe?

A. Yes.

Q. What were those anomalies?

A. Again, you had 1400 pounds -- well, at different times,

you would try to bleed the drill pipe pressure off and the

drill pipe would determine.

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BY MR. HYMEL:

Q. What was causing some of the pressure, at least?

A. Well, initially -- and I know this is kind of a matter of

semantics. Some people have talked about two negative tests,

some people have talked about a continuation of a single test.

Initially, when they set the test up and they tried

to bleed the drill pipe pressure off and the drill pipe

pressure came back. The action they took at that point, to me,

was consistent with my experience from working in the field.They started kind of investigating the surface

situation to see if they could -- see if there was some kind of

surface indication of what the problem might be. At some

point, somebody took a flashlight and looked down the riser and

saw that the fluid level had dropped in the riser, and that was

an indication to them that fluid was seeping through the BOP

and you had pressure contact with the -- on the annular side,

which would create an unbalanced column, which would give you

pressure on the drill pipe side.

They increased the closing pressure in the lower

annular, pressured that up, effected a seal, and then topped

off the riser and went forward with the test.

Q. You said that the annular was leaking. Was there anything

wrong with the annular?

A. No. Annulars are designed to seal from the bottom up.

The fact that you had a substantial differential across the

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annular from the top down, because of the heavier fluids --

much more heavier fluids in the riser space than underneath in

the well just meant that it required more closing pressure to

effect the seal.

Q. Would the negative pressure test being monitored on the

drill pipe have given a drill crew the correct result?

A. I think it did give them the correct result.

Q. What was that result?

A. That this negative test was not successful. There was asignificant question here that the operation should not go

forward.

Q. And based on what? What was being shown that they could

see that the negative pressure test was not successful?

A. Again, you had an anomaly. You had pressure that kept

returning on your drill pipe after you had indications that you

had solved the surface problem.

Q. Now, was the negative pressure test completed on the drill

pipe like the Transocean drill crew had set up the negative

pressure test?

A. It was not. It was completed on --

Q. Okay.

A. The monitoring of the test was completed on the kill line.

Q. And why?

A. That's -- based on the interview notes, it appears that

Mr. Vidrine believed he needed to do that to comply with the

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APD.

Q. All right. Pull up TREX-5.2.1.TO. This is interview

notes of Bob Kaluza where the notes state that -- Mr. Kaluza

said: "Don insisted that it must be done down the kill line.

Permit was for down kill line."

Is this consistent with your recollection?

A. It is.

Q. Let's go back to TREX-570.3.1. This is the MMS-approved

TA procedure that we looked at earlier.Now, line 1 requires: "Negative tests...30 minutes

with kill line."

Correct?

A. "Negative test casing to seawater gradient equivalent for

30 minutes with kill line."

Correct.

Q. Was that negative pressure test on line 1 conducted?

A. No. This test was designed to be done before -- based on

the steps here, before the 3 1/2-inch stinger was tripped to

8367, which did not occur.

MR. HYMEL: Connie, keep that up.

BY MR. HYMEL:

Q. Okay. So you talked about the second negative pressure

test in this procedure being on line 3. Does the TA procedure

require that the monitoring on line 3 be done on the kill line?

A. It does not require that the monitoring has to be on the

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kill line.

Q. So Mr. Vidrine moved the negative pressure test from the

drill pipe to the kill line; is that correct?

MR. BROCK: Objection, leading.

THE COURT: Sustained.

Restate your question.

BY MR. HYMEL:

Q. What were the results of the negative pressure test

performed on the kill line?A. There was an indication of no flow-out of the kill line.

So the field people or the folks on the rig that were

monitoring the tests on the kill line believed that this had

indicated that they had gotten a successful negative test on

the well.

Q. What was the pressure on the drill pipe at that time?

A. My memory is it was 1400 psi.

Q. What should the BP well site leader have done with those

results?

A. I think, with the anomaly, the operation should not have

gone forward. As I had discussed earlier -- I think it was

during my deposition -- to me, there are three possible

outcomes on a negative test: You can have an absolutely good

negative test where there's no question it's good; you can have

an absolutely bad negative test where there's no question it's

bad; or you can have an anomaly, an inconclusive negative test.

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This isn't baseball, the tie doesn't go to the runner, the tie

goes to the failed test.

So if it's good, it's good; if it's inconclusive or

if it's bad, it's not a good test. You don't need to go

forward.

Q. What did Mr. Vidrine do?

A. The operations went forward.

Q. What's your basis for your statement that the operations

went forward?A. Again, I think, as we had seen in one of the excerpts,

there was an instruction from Mr. Vidrine to proceed with the

dumping of the fluid.

Q. Did anybody declare the negative pressure test a success?

A. I've seen documents that -- and statements and

post-incident statements, I think one that was signed by both

company men, where they indicated that the belief was the

negative test was successful.

MR. HYMEL: Please put up TREX-51133-2.

BY MR. HYMEL:

Q. And this is a statement signed by Mr. Vidrine and

Mr. Kaluza. It's already been introduced into evidence. And

it states: "Successful negative test monitored at the kill

line."

Is that consistent with your recollection?

A. It is.

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Q. Mr. Bly suggested during his testimony that no flow from

the kill line was caused by the Transocean drill crew leaving a

valve closed.

What is your response to that?

A. It's possible. In my opinion, I think it's unlikely. I

think, when you look at the amount of time that this crew had

been on this rig, you also look at the number of times the kill

line had been functioning in this particular event, you know,

that's a possibility.But typically, when you line up something like that

and you're seeing a result, again, one of the things you do, if

you question that result, you're going to kind of double-check

your surface setup to make sure that, you know, basically,

everything is set up okay.

So, you know, to me, I think that's unlikely.

THE COURT: Wait, wait. What's unlikely? What

Mr. Bly said or that the kill line was just inadvertently

closed?

THE WITNESS: That there was a valve closed on the

kill line.

THE COURT: So you agree with what Mr. Bly said in

that respect?

THE WITNESS: I think he says -- and he thinks it's

likely that it was closed.

THE COURT: Oh, okay. So you think it's unlikely?

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THE WITNESS: I think it's unlikely.

BY MR. HYMEL:

Q. Mr. Barnhill, where was the drill crew during the negative

pressure test?

A. There were certain supervisory parts of the drill crew

that were in the drill shack during the conducting of the

negative test. There were other members of the drill crew that

were in different places on the rig.

Q. Would there have been an indication in the drill shack ifa valve on the kill line had been closed?

A. If it would have been one of the failsafe valves on the

kill line in the BOP stack, yes, there should have been a

red/green indicator light to indicate that position.

And then as far as the lineup on the trip tank, on

the panel itself on the screen, there should be an indication

on whether the valve is open or closed.

Q. What time did the negative pressure test start?

A. Again, I think it happened around 5:00 in the afternoon.

Q. What time did the negative pressure test end?

A. Again, around 8:00 in the evening.

Q. What does that indicate to you?

A. Well, again, this was a test that normally does not take

you three hours to perform. The fact that they spent three

hours indicates to me that the men on the rig were trying to

get this right, trying to understand it, and were trying to

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move forward accordingly.

Q. In forming your opinions, did you see any evidence that

the Transocean drill crew intentionally misinterpreted the

negative pressure test?

A. I did not.

Q. What do you make of the bladder effect?

A. It's -- I've not heard of that term in the context that

it's being used here. So, you know, I'm not aware of the

context that they've used it here. So it's just not a term I'mfamiliar with in this setting.

Q. You state in your report that if the Transocean drill crew

did relate the pressure to the bladder effect, and if the well

site leader relied on the drill crew, "this illustrates too

much reliance on the drill crew, in my opinion."

What do you mean by that?

A. Well, again, I think this drill crew was an experienced

crew, and they were very good at what they do.

I think, when you start talking about well conditions

and downhole conditions, the BP company man, that's kind of

their bailiwick. That's their responsibility, is the well.

And they basically have the BP engineering and operations group

onshore behind them.

So I think if you have a significant question about

that and you're unsure about it and you're even unsure about it

to the point where the guys are kind of teasing you on the rig,

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then at that point you go back to your technical support, which

would be the BP onshore people, and you confirm or deny whether

you think that's a good test or not.

Q. Now, you made a comment about the guys teasing you on the

rig. What do you mean by that?

A. I think Mr. Vidrine, in his -- in the post-incident

interview notes, had indicated that maybe even at some point

they were kind of picking at him a little bit for persisting to

question whether this had, indeed, been a good test or not.Q. Were the results of the negative pressure test ever

questioned?

A. Yes. In my opinion, they were.

Q. When?

A. There was a phone call at 8:52 between the senior drilling

engineer, where there was a discussion concerning the anomaly.

I think the senior engineer at that point in time questioned

whether the test could have been lined up properly.

At that point in time, you were still in the

situation where the procedure could have been stopped, the

displacement could have been stopped, the negative test could

have been repeated.

And, in fact, at that point, I think you would have

actually had a cleaner test because the spacer would have been

further up the hole and you could have circulated until you

got -- or you would have had good seawater both in the kill

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line and the drill pipe, and I think you would have gotten a

more definitive test.

MR. HYMEL: Please put up TREX-4447.6.1 TO.

BY MR. HYMEL:

Q. This has been shown already during this trial. It states:

"Vidrine told Mark that the crew had zero pressure on the kill

line, but that they still had pressure on the drill pipe. Mark

said he told Don that you can't have pressure on the drill pipe

and zero pressure on the kill line in a test that's properlylined up."


A. It is.

Q. What information did Mr. Hafle have available to him at

this time?

A. Well, I mean, he certainly had the information just given

to him by Mr. Vidrine. I think the interview notes also

indicate that maybe he had the well Insite system called up on

his computer so he could get the realtime feedback from the

wells also.

MR. HYMEL: Let's put up TREX-50964.3.1.TO.

BY MR. HYMEL:

Q. This is an interview -- these are Mr. Corser's notes of

that same interview of July 8, 2010, of Mr. Hafle. And it

states: "Mark had Insite up."


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A. It is.

Q. What does that mean to you, that Mr. Hafle had Insite up?

What could he have done with that?

A. Well, again, he could monitor along as they're doing this,

getting the information offshore. And so that would have given

him some ability to see what was happening.

Plus, like I said, the information from Mr. Vidrine,

to me, should have raised a question in his mind about the

validity of the test.Knowing that the TA procedure that was being followed

was going to significantly reduce the hydrostatic pressure in

this well, again, I think that would have been a good time to

call a timeout and repeat the test and confirm whether you,

indeed, had proper isolation of the barrier or not.

Q. Where did Mr. Vidrine go after the 8:52 call?

A. The interview notes indicate he went to the rig floor.

Q. And what did he do?

A. Basically, the indications are he checked, and everything

looked fine. He gave the instruction that -- at some point

during that -- to go ahead and dump overboard.

Q. What was the effect of dumping overboard?

A. Well, again, you're going to now take the spacer that's in

the riser, which is supplying some hydrostatic support, and

pump it overboard and replace it with seawater, so you're going

to further reduce the hydrostatic pressure more.

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Q. What does that mean, to further reduce the hydrostatic

pressure? What effect does that have?

A. Well, if you've got a seal, then it's going to do just

that. It's going to reduce the hydrostatic pressure in the

well.

If there is a communication pathway between the

formations that you've drilled through, then you're going to

increase the differential pressure across those barriers, or

those faulty barriers, whichever it is.So you're going to have a situation where if you've

got communication, then you're going to further underbalance

the well and allow the well control situation to develop.

Q. What do you mean by "communication"?

A. The fact that if you have a pathway -- that the pressures

and fluids within the formation that you've drilled through

have a pathway to communicate with the wellbore, and you're

reducing the pressure in the wellbore, then the fluids have the

ability to flow through that pathway into that wellbore.

MR. HYMEL: Connie, let's go back to D-6643.

BY MR. HYMEL:

Q. Let's continue your discussion about the negative pressure

test, Mr. Barnhill.

Were there indications on the rig that the well had

been secured and the barriers confirmed after the negative

pressure test?

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A. Give me that question one more time, please.

Q. Sure. Were there indications on the rig that the well had

been secured and the barriers confirmed after the negative

pressure test?

A. Yes. I think the people on the rig believed that the

negative pressure test had been successful.

Q. All right. Were there any indications about the negative

pressure test that the Transocean drill crew were not told?

A. I haven't seen anything to indicate to me that they wereaware of the questions raised or the issue raised by the senior

drilling engineer questioning whether the test could have been

properly lined up or not.

Q. Mr. Barnhill, of all of the information that we have

listed here that the crew were not told, what of that

information do you consider to be the most critical?

A. To me, the most critical piece of information would be the

problem identified by the senior drilling engineer as to the

veracity of the negative test that had just been conducted and

that was being relied on to confirm that you had, indeed, a

valid, in-place, tested, verified barrier that was testing the

fluid flow in the direction from the hydrocarbon-bearing zones

into the well.

Q. All right. Mr. Barnhill, let's talk about that. This is

our last series of questions. Okay?

Mr. Bly testified that he would want to know anything

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that was going to impinge on well integrity.

Do you agree with him?

A. I do.

Q. Did the findings of the negative pressure test, discussed

by Mr. Vidrine and Mr. Hafle, that there was pressure on the

drill pipe and zero pressure on the kill line, did that affect

the integrity of the well?

A. Yes. The fact that you had an anomaly had -- was a

potential indication that the integrity of the well had notbeen established and you had not verified those barriers.

Q. What is your response to the statement that Mr. Hafle did

not have the full context for what had transpired in the test,

and it wasn't clear to Mr. Hafle whether Don was talking about

the first or second negative test?

MR. BROCK: Your Honor, I'm going to object to

Mr. Barnhill making predictions or giving opinions about what

people were thinking at that point in time.

THE COURT: I'll sustain the objection to the way the

question was phrased.

MR. HYMEL: Just give me one second.

BY MR. HYMEL:

Q. Mr. Barnhill, Mr. Bly was asked a question during his

examination. Do you see where it says that "Mark said he

didn't have the full context for what had transpired in the

test, and it wasn't clear to him what Don was talking about,

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the first or the second test."

That's on page 1347 of Mr. Bly's testimony. What is

your response do that statement?

MR. BROCK: Your Honor, that's just asking him to

respond to a statement. He's reading the statement into the

record from the notes.

THE COURT: Yeah.

MR. BROCK: That's all he's doing.

THE COURT: I agree. I sustain the objection.You can ask him, you know, what he would have

done, I guess, if he was told that. That would be a fair

question.

Do you want to answer that? I'll ask it.

Mr. Hymel's having trouble asking the question.

THE WITNESS: I think that given the information at

that time with the anomaly, knowing that the procedure called

for significantly removing -- or removing significant

hydrostatic pressure from this well, I think at that point in

time, that should have been a red flag to stop the operation

and, if necessary, repeat the negative test.

And if he didn't have all the information, then

you needed to get what you needed to satisfy yourself.

BY MR. HYMEL:

Q. Mr. Barnhill, you've worked as a company man, haven't you?

A. I have.

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Q. And the company man is the same thing as a well site

leader?

A. They are.

Q. Is the information discussed during the 8:52 call,

pressure on the drill pipe and the zero pressure on the kill

line during the negative pressure test, the type of information

the well site leader would share with the drill crew?

A. If I had that information, then yes, I would share it.

Q. You've worked on a drill crew, too, haven't you?A. I have.

Q. Is the information discussed during the 8:52 call,

pressure on the drill pipe and zero pressure on the kill line

during the negative pressure test, the type of information the

drill crew would want to know?

A. Yes. If I was in a supervisory position with the drill

crew and there was information concerning the integrity of the

well, I'd want to know that. Yes.

MR. HYMEL: Those are all the questions I have.

Thank you, Judge.

THE COURT: All right. I don't know if we could

agree on the order now. We're in Transocean's case. Who wants

to go next? Do we have a volunteer?

Plaintiffs? Okay.

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CROSS-EXAMINATION

BY MR. STERBCOW:

Q. Mr. Barnhill, good afternoon.

A. Good afternoon.

Q. Paul Sterbcow. I'll be asking you questions on

cross-examination for the Plaintiffs' Steering Committee.

A. Okay.

Q. In your report you conclude that the surface blowout was a

culmination of multiple factors, decisions, oversights, andmistakes. Fair statement?

A. Fair statement.

Q. Wouldn't you agree with me, based on your education,

training, and experience, that a sound safety management

system -- be it BP, Transocean, or any of the other players

involved in the Macondo well -- would either be designed to

prevent or significantly reduce the risk of such multiple

oversights and mistakes? That's the goal?

A. I think the goal of any safety system, yeah, is to

eliminate as many unknowns as you can. Yes.

Q. And at the end of the day, aren't we talking about the

analysis and the prevention of known risks associated with this

operation? That's what we're trying to accomplish, from

beginning to end?

A. You are. You're trying -- if there is a -- something

that's recognizable, you're trying to respond to that. Yes.

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CALVIN BARNHILL - CROSS

Q. Now, the rig crew, in particular the Transocean drill

crew, is only going to be as good as management allows them to

be in terms of their ability to recognize and respond to known

risks. And by that, I mean they can only be as good as they

are trained. Correct?

A. I think that's part of it. I think training enters into

it. I think experience enters into it. So, you know,

obviously, there are certain things you can train for. There

are other things that experience teaches us that are notnecessary to train for. But I think you have to provide the

basics that somebody then can take that information and adapt

it as they need to.

Q. Okay. And in this particular case, you've testified you

reviewed the well control handbook, you've reviewed the actual

training that Transocean provided to the crew?

A. I have.

Q. In terms of what Transocean did to prepare the crew of the

Deepwater Horizon -- or any crew, for that matter, employed by

them to address the situation faced by the crew this night --

if I understand you correctly, you didn't go beyond the well

control handbook and the training they were provided on the

job. Correct?

A. What I looked at was basically how they were -- what well

control training they received. Basically, were they

certified? What was the foundation for the certification for

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that program, the various drills and the different things that

they received?

And, you know, I have to tell you, Mr. Sterbcow, in

looking at it, it looked to me that this was fundamentally a

basic well control situation. And I think these men had the

training that was necessary to understand the basic well

control situation and to react to it.

Q. Yet as we stand here today -- and you say this in your

report quite candidly -- we still don't have an explanationbecause, unfortunately, we can't talk to the men who were on

the drill floor --

A. Correct.

Q. -- as to how in the world they could have missed this the

way they did?

A. Absolutely. I think, you know, there are -- if you want

to say -- three basic 64 billion-dollar questions in this case.

Number one, why did they -- you know, why was the

negative test deemed a success?

Number two, why wasn't the -- you know, why wasn't

the operation stopped at around 9:00 and the test repeated?

And why wasn't the well shut in at 9:32 or 9:33, when

there was an anomaly?

We don't know the answers to those questions.

Q. All right. And you haven't undertaken or been asked to

undertake -- no criticism of you -- undertaken to try to find

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the answers to those questions, not by looking at what occurred

with respect to these gentlemen on this rig, but taking that

analysis off the rig and up Transocean's management chain. You

haven't looked at that?

A. I have not looked at that.

Q. Likewise, I don't think -- and correct me if I'm wrong --

you didn't review the competence of the Deepwater Horizon

marine crew, did you, versus the drill crew?

A. Did not. I did not look at the marine side.Q. That wouldn't be an area that you would typically involve

yourself?

A. Would not be.

Q. All right. Did you look at all of Transocean's policy and

procedure for communications between the drill crew and the

marine crew in certain situations?

A. Only as it related to the question of the communication as

it relates to the well and the functionality of, say, an

operation like an ESD or something like that -- or EDS. I'm

sorry, not ESD, an EDS.

Q. But you would agree -- and I think you mentioned earlier

that the bridge certainly needed -- the marine crew,

particularly those on duty, the DPOs on the bridge, need to

understand what's going on, particularly during a displacement

temporary abandonment procedure?

A. I don't know that the marine crew needs to understand -- I

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don't think you need to make well experts or well control

experts out of the marine crew. I think what they need to

understand is that at appropriate times there has to be good

communication between the two sides.

Just like I don't expect the drill crew to become

seafarers -- they're two different functions -- but I do expect

there to be good communication between the two.

Q. And the reason for that is that the marine crew should at

least know that the drill crew is entering into a phase of theMacondo well where they're going to be displacing, they're

going to be intentionally underbalancing, and there were risks

that are associated with those procedures?

A. You know, Mr. Sterbcow, I don't know that I ever thought

of it in that aspect. Again, I would expect the drill crew to

be good at what they did, and I would expect the marine crew to

be good at what they do.

I would expect -- if a situation arose where there

needed to be communication between the two to establish kind of

the rules of the road, if you will, at the time, I would have

expected that to occur.

Q. All right. Is that a specific issue that you looked at?

And that's a two-part question. Number one, the policy,

Transocean policy surrounding that communication; and two,

whether or not either crew followed the policy?

A. I did not.

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Q. Okay. Is it fair to conclude, though, that the drill

crew, the guys on the floor in the drill shack dealing with the

drilling end, are entitled to rely on the competence of the

marine crew in the event that that vessel faces a surface

blowout?

A. I think it's reasonable to expect both groups to be -- to

rely on the other. I also think that included in that is an

expectation that one group is not going to do something that

may be detrimental to the other group without confirming thatthat needs to be done or that there's communication between

those two.

Q. Right. And that goes back to the communication element?

A. It does.

Q. All right. If I understood what you said correctly, you

do not want the captain -- or for that matter, anybody on the

marine crew -- to just automatically EDS in the event of a well

control situation, because that could cause more problems than

it would solve, basically?

A. It could, yes.

Q. Did you see anywhere in any policy or procedural manual or

in any -- at least training that you looked at -- and

understanding you're concentrating on the drill side -- where

the marine crew was instructed or trained on what to do when a

surface blowout resulted in a complete inability to communicate

with the drill crew, like this one did?

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A. Again, I did not look at the training of the marine crew,

so I don't know what their training was.

Q. If you assume for me, for purposes of my question, that

there is no such policy; if God forbid, what happens this night

happens -- and let me back up and ask you.

Isn't it reasonable to expect that if you have a

surface blowout uncontrolled, like this one, the first place or

the most susceptible location on the rig to explosion and fire

is the drill floor?A. It would certainly be one of those, yes.

Q. Given that foreseeability, wouldn't you agree with me that

there should be some policy and procedure in place that guides

the marine crew, if this happens, on what they should and

should not do? And by "this," meaning we can't communicate

with the guys on the drill floor; we can't talk to the driller;

we're not sure whether he's tried to EDS or what he's done.

What do we do now?

Shouldn't there be some policy in place to deal with

that?

MR. HYMEL: Judge, we would like to object on the

ground that this is outside the scope of his report.

MR. STE

march 18, 2013 pm

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