converted? >> it is my opinion that it probably did not. there is one possible mechanism that might have allowed it to of.vert that i can think uppe that is that when, under the presumption that the obstruction was below the flow and circulation was established, the surge of pressure might have been adequate to give you that much differential. bp, in their report, said the they were doing further investigation into that possibility, and i would be very interested to see the results of that. >> just so i understand it, is it your opinion today that it is more likely than not that the equipment did not convert because the flow rate did not exceed 6 barrels per minute. >> the preponderant of evidence

would indicate that. -- would indicate that, yes. >> okay. what are the indications for the well and the cement job, if, in fact, the float equipment did not convert? >> the function of this type of float equipment, primarily, is to isolate the cement once it's been put in place to allow it to stay static while it's setting up, and preventing it from flowing back into the well due to the hydrostatic column and balance specs so let's look at this animation here of the cement job, which is what the cement job should look like at the end when the plugs have bumped. so what are you saying the application would be if these float valves were open and still had that to be? >> it would allow the cement

back into the casing. >> what would that mean for the cement job? >> that would present the opportunity for further contamination of cement and, by that, that would be the primary risk. >> would that be a concerted? >> it should be, yes. >> weather implications would be before the well if these float valves had not converted, besides implication for the cement job? >> there's debate as to whether or not float valves are a mechanical barrier. the issue is kind of academic, in that they do, to a certain extent, impede flow. and if they had not converted that element of protective barrier is not achieved.

>> so to the extent of these cells when closed might have prevented hydrocarbons from migrating up to the center of the casing, when they are not closer they are no longer a barrier? >> that's correct. >> so we have to implications that you have described, if these float valves are not converted. one is it could impact negatively the cement job. and two, it eliminates any argument that these cells are barriers to flow? >> that's true. >> now, you said that the you flow rate never exceeded the six barrels per minute necessary to convert the float valves at macondo, right? >> by the records, that's correct. >> have you seen evidence to suggest bp new at the time that they would have needed to achieve at least six barrels per minute of flow in order to convert that float equipment? >> yes, i have. >> what evidence have you seen? >> in the precementing portion of their well completion

procedure, it specifically states that the rate required to convert the valves is greater than for barrels a minute, by a factor of two. they said eight barrels. that's consistent with the common industry practice of making sure that you achieve adequate pressure and flow rates to function downhole tools. >> so i'm putting up on the screen a page from bp's april 152 plan. is this the drill plan you're talking about? >> yes, that's exactly the line i was talking about. >> i have highlighted bullet number 11, and it says right here that bp intended to use at least eight year old per minute of flow in order to convert the float equipment. correct? >> that's correct. >> is there any evidence that bp ever achieved even six barrels per minute of flow that might have convert the float

equipment? >> no, there's not. that i have seen. >> would have been prudent, in your mind, for the operator to insist that at least at some point during attempting to convert the float equipment, that the flow rate would have exceeded the six barrels per minute that you had identified early are? >> given the equipment that they ran in the well, that's actually a functional requirement. a more prudent approach would have been to have redesigned, we specified this piece of equipment to a lower shooting pressure, -- shooting pressure once the narrow fracture gradient had been identified. this equipment can be modified as i said such that it would have cheered at the source of flow rate that they ended up using. >> so there's an additional equipment that would have cheered at a much lower flow

rate and eight drills per minute? >> is the same equipment adjusted to a lower sheer pressure of? >> spent to have any sense as to why bp did not want the flow rate to reach six barrels per minute, much less eight drills per minute during the subs with cement job? >> yes. that is correctly routed to their desire to maintain equipment circulating bottom hole in the 14.5 pounds per gallon range. >> do you know what maximum flow rate bp had identified for the circulation prior to entering the cement job? >> i don't know what they felt a maximum might actually possibly be. i do know from the cement and opticem calculation runs, that they completed their design based on for barrels a minute. so i would have to infer from

that that was their belief that for barrels a minute was a maximum possible read. >> okay. if you look down further in the document, we have appear the line we just been discussing which talks about getting the flow rate from eight drills a minute, and the window down to to cement the production casing. what flow rate are identified down here with regard to actually setting the cement? >> well, as you can see there, it's three barrels a minute, or in tonight. >> and that those flow rates with the float equipment have converted? >> not as i understand the piece of equipment that was run, no. >> is it anyway in your mind to reconcile the fact that this document, is this line number 11 which is a barrels per minute of flow rate is needed to convert the float equipment, with these numbers down here saying that the circulation range should be kept below for barrels per minute during the cement job? >> no.

>> is that just a mistake of some sort? >> it strikes me as being a mistake, yes. >> now, if the crew or the individuals on the rig come in this case, bp, had any suspicion that he float valves had not converted, what action in your opinion should have been taken to either mitigate or remediate the situation? >> the standard practice of the floats have failed is that you apply a little bit of pressure here by a little bit, i mean maybe a few hundred pounds, to your mud column inside of the well, above that float. and then you lock that pressure in and you hold in place while

the cement has the opportunity to set. >> so what you're doing in that situation is you are accounting for the fact that the valves have not closed, so cement could come back up to the valve, so you're putting a little bit of pressure down in the system to counterbalance any flow back up to those float valves, correct? >> that's correct. you put enough pressure on to basically bump your plug in, your wiper plugs, make sure that they are seated on top of the float, and then hold that wiper plug in place until your cement is set. >> do you see any evidence that bp in the situation took that remedial step? >> no, they did not. >> we bp or others on the rig would be able to perform other operations while they were applying this downward pressure, bottom of a whole, told the cement in place? >> they would not be able to conduct any operations below the b.o.p. other rig operations in the rise or above the b.o.p., they could

have continued with. >> with the crew have been able to perform the casing hanger seal assembly test, or the positive-pressure test? >> i believe the answer to that is no. i have thought of one possible way to manipulate the choke and kill line, but i would have to look at more detail of the anger assembly itself in order to answer that question. but i think he had to do that is no. >> so in your opinion sitting here today you believe that the crew and bp would've had to delay those procedures to accommodate with having the float valves not be converted. that other probably is the float valves are no longer at their evil of any sort from below, is that correct? >> that's true.

>> this remedial measure you identified, pressuring down by the cement is kerning, would that solve the problem of an open float valves? >> that would've made no difference at all to the float valves itself as a barrier. what it is designed to do, he is to replace the function of the float valves, of isolating the cement from pressure while it's in the process of setting up. and that would have accomplish accomplished. >> are there any remedial steps that, your opinion, should have been taken in order to account for the fact that he float valves may have been opened so no longer a barrier to flow up the case in? >> if that had been identified as a failure, yes, then either the placement of a mechanical plug or simply more cement would have been appropriate spirit and

how long -- would have taken generally to put a mechanical bear down into the well of? >> i believe that they are round tripping time on this rig was about 18 hours each direction. it would seem to me that for setting a plug of this nature you might be able to do that a bit faster. but i'd say a minimum of 24 hours. >> and how about taking the other option is just adding more cement? >> that would have been at least as long also, in light of the fact that you would have to trip to bottom with a drill string to do that, and then place your cement. >> in your mind if there were any question as to whether the float valves converted, would have been prudent to take the remedial steps that you identified in order to ensure that there were no problems as a result of an unconverted float valves? >> i think that would depend actually on one's intentions for the next steps in the

abandonment. in light of the fact that their abandonment plan included leaving this wealth underbalanced, then i think it defined would have been prudent to have done something more with the issue, yes. >> you said earlier that your opinion, sitting here, that it is more likely than not that the float equipment did not convert. what other information would be helpful to you to determine whether that opinion is, in fact, correct or not? >> well, i don't think there's any information we can get at this point in time, and that the well was abandoned -- excuse me, the wealth was killed, and then plugged before there were any forensics done inside that well bore. from a purely engineering standpoint, it would have been

very, very interesting to me to have run back into that well, two td to investigate its actual physical configuration after the well was killed. that was not done. i have no reason -- no knowledge why it was not done. it would be in a certain sense a science project to have done that, but it might've also given us information to use in enhancing design for future completions. >> but as i understand, given what the people on the rig new, in particular the opehat day that the floats may not have converted. that in your mind there were certain remedial and other diagnostic steps that should have been taken? >> actually, this is one of those decisions, somewhat similar to the negative pressure test evaluation, where the

people felt that there was not a problem. they did their flow back test on the floats. they watched it for three minutes, which i think is a little bit shy. i got back and amount of fluid that was possibly appropriate for the amount of pressure they had on that well. but given the very low differential pressure between the cement in place and the mud inside the well, there's a lot of reason to question as to whether or not that was a valid test on that float. and, in fact, that's the conclusion that the bp investigative team came to, that their analysis they say specifically that we don't feel that was a conclusive test. however, the guys on the rig that day had their flow chart, their flow chart said check float. if float valves, pussy. they decided the floats were holding and they proceeded. >> i want to backup a little.

you mentioned a float check test. what is a flowchart can't? >> that is simply once you have bumped your -- bumpier plugs, you pressure out the system a little bit, the same popular and popular cement, how much to test you put on, a function of the design of the casing, and your completion equipment come is specified in your procedure. you hold that pressure for certain period of time to guarantee that your well is, in fact, patent. and then you release the pressure completely. you open the valves. unit that drill string catcher been pressuring to bleed back to a pit and you monitor for both the volume of the flow back, the time it takes to flow back, and whether or not the flow completely stops. that's standard procedure. it's called check float. it will be written check float that everybody knows you pressure up to whatever it said in the previous step, which will

be specified there, you let the pressure off, you record the volume, you watch it for xp to time. >> and you said that such a flow check was performed here, but you don't think it was suspicious to identify whether the float valves filled? >> i believe i suspect, just. >> and explain one more time why that is? >> one, the differential pressure in this case in design was so small that this question as to whether or not it really would youtube on you. you've got some viscosity aspects of that fluid. both the mind and the cement do take up a initial chill string, and to get that fluid moving takes a little bit of energy that whether or not the pressure differential between these two columns was adequate to do that is questionable. also simply watching for three minutes is a little bit low. almost any written plan will set

a minimum of watching for five minutes. it says three minutes in there. the accuracy of report writing in the field, of recording these sorts of things is such that they may have watched for more than three mins that they may not have. but the point is that they recorded the fact that this was a successful test after three minutes. according to the record that they presented in the halliburton cement completion form. both of those issues make the results somewhat questionable. >> so you agree with bp's conclusion that the flow check that was performed was inadequate to determine whether in fact the float valves had converted? and i will read from the bpb port. however, the investigation team concluded that with the 38-psi back pressure predicted in the halliburton april 18, 2010,

opticem program, the back pressure test conducted was not a reliable indicator that the float collar -- >> yes, i absolutely agree with that step what would your recommendation be in the future how one should conduct a flow check like this to insure that infect the float collar's had sealed? >> if one is designing such a no differential column, i cannot think of, just right now, a procedure, other than an extended float share, and/or possibly sibling maintaining pressure on that casing for a few hours until your cement had the opportunity to have an initial set. i don't think that would be required or advisable if you had to indication of a problem with your floats. if you would start a circulation of if you are taking your circulation to the design flow rate, without problem, and you

had an indication that you have float closure in terms of a positive check after that point in time. i wouldn't think that any other step would be required. however, indicates like this where you had a sequence of questionable events, and you have never obtained the design specifications for the proper functioning in that tool, then something was wrong and something else needs to be done. >> i'd like to move onto temporary abandonment phase ages, and i'm going to focus my questions on mr. bourgoyne and dr. smith. and i'd like to put up on the screen the april 20 ops note. there's been a lot of discussion about how the temperate abandonment procedures changed over the course of the last week with in bp.

the last manifestation of those procedures is in this april 20 ops note which was sent to the rig and other members of the team at 10:43 a.m. on the morning of april 20, less than 12 hours before the blowout. mr. bertone, you look through the steps. in your opinion, is this a great abandonment procedures an unusual one? >> yes, it is unusual. i guess what's particularly striking is the depth of the cement plug. it didn't have to be -- is not usually placed so deep. also, it is unusual to include the negative tests with the displacement, trying to combine those two. and then the well does not necessarily have to be under balance went abandoning. it doesn't have to be left under

balance while placing. >> we heard i think earlier on the first panel from mr. williams that at shell they never, during the temperate abandonment procedures, or do not going to temperate abandonment procedures leave the well underbalanced. here it was a devout. and you find a look at about what you meant by these procedures are a bit unusual given that the well was going to be so under balance of? >> you know, displacing the seawater above the well head and doing the negative tests, trying to -- >> let's put it this way. did the well need to be under vows at any point during these procedures be? no. only for the negative test, and that could've been, you know,

done in a controlled manner with the b.o.p.s already closed and anthen overbalanced reestablish. >> how would you have established, reestablish the overbalanced? >> by simply opening the b.o.p. pressure them back up or opening the b.o.p.s to put the riser back on the well. seen it could be placed in mud. it would have to be under balance at that point. you can also take the additional step of, before even doing the negative test, signaling heavy enough mud to provide the riser margin, to keep the well and overbalanced condition at all times spent explaining a little more about what you mean by that, utilizing heavier weight my to maintain overbalanced. >> the well was overbalanced when it was drilled, 14 pounds

per gallon that, but that 14 count per gallon but had to reach all the way back to the surface. that is, the riser had to be filled with 14 gallons per gallon that. you could achieve that same pressure with a heavier mud that only reaches back to the seafloor. so that essentially puts what we call a riser margin as a term of art. to provide an overbalanced, even when this riser is full of seawater. >> mr. lewis, do you see anything unusual about this particular temporary abandonment phase you do in your experienced? >> i think that the points that mr. -- mr. bourgoyne brought out there are the same things that i would have questioned. >> i want to ask that specifically some of the particular steps in your. the first of which is the fact

that these temporary abandonment procedures call for displacing 3300 feet of mud below the mud line with sea water. dr. smith, do you agree that that is a prudent procedure within the context of these temporary abandonment procedures? >> in the manner in which it was conducted in the fact that it's not prudent, the displacement of seawater in the annulus back up to the b.o.p. stack resulted in an under balance relative to the 14 pounds per gallon mud before the negative test ever started.

and so that's, that's the step that is particularly unusual. . . some other tools the seals off to a hydro-static and allows you then to believe pressure off the drill pipe to reduce pressure in at the well only after the blt is closed. >> is it safe to say that after removing the sea water,

performing a pressure test unnecessarily stresses the well before you can see if it can handle it? >> is not necessary in an absolute sense. some of that pressure reduction was offset by the fact that there was this heavier spacer that at that point would have been in the riser. , it's, it's not a desirable approach to doing the test to have this reduction on pressure inside the well before you close the annular preventer is the simplest explanation i can give. >> okay. and why is that? >> well, because you're, you're in a sense you're creating this pressure differential from outside the well to inside the well before you've confirmed

that the well will withstand that pressure differential and before you've closed the preventer so that you've got a rapid mean of controlling it if it doesn't contain that pressure. >> we've had some calculations here, and this is from a slide i put up yesterday, and you and i met since then, and you corrected some calculations. but my understanding now is that removing 3300 feet of mud from below the mud line and replacing it with sea water eliminates 926 psi of additional downward pressure on the bottom of the well. i believe in our conversations you said that that introduced an unnecessary amount of risk into the situation. what did you mean by that? >> well, what i said is it's not a absolutely required level of risk, and the point is we're,

we're going to at some point, we're going to remove hydrostatic pressure at the wellhead level, at the sea floor level when we remove the riser. and so whatever mechanisms we use to prepare the well for temporary abandonment, we know that we're going to remove the 14 pound per gallon mud and the hydrostatic it creates inside the well at the level of the wellhead when we move the rig off location and the riser's gone and that mud's no longer there. this is, this is a reduction in pressure below that depth inside the well that's not absolutely required as part of a procedure as has already been described by, by mr. bourgoyne. >> so let me get this straight. when you're going to move off

well, in any event, you're going to be removing the mud that's in the riser. so there's hydrostatic pressure in the riser, and that's going to be gone when you temporarily abandon the well. the question is whether and to what extent it makes sense or introduces additional risk to remove additional mud below the mud line, is that fair? >> that's right. >> and in this case removing that additional mud below the mud line, as you calculated it, removes an additional 926 psi of hydrostatic pressure exerting downward force on the cement at the bottom and the hydrocarbon pay zone, correct? >> right. >> does that have any implication, removing that additional pressure, for the cement job at the bottom? >> it means it's required to control a greater stress. there's a greater pressure differential acting from outside the well to the ideas the well than there otherwise would have been. >> was it mess to actually

remove in this temporary abandonment procedure that 3,000 feet of mud and replace it with sea water? >> no. i think that's already been stated yesterday and today both. >> and so was it necessary for bp to put that additional stress on the cement job at the bottom? >> no. >> now, my understanding is that the reason bp wanted to remove that sea water down to 3,000 feet was so that it can set the cement plug in sea water. that your understanding? >> that's my understanding, yes, sir. >> was it necessary to even if they wanted to set the cement plug in sea water, was it necessary for bp to remove all of -- even if -- i'll take that back. even if bp had wanted to set the cement plug down here at 3,000 feet, was it necessary to do so in sea water? >> no, sir. >> could a cement plug be set in mud? >> yes. >> now, let's imagine that bp

decided that it did not want to set cement plugs in mud because, perhaps, cement doesn't do as well in mud. were there other kind types of plugs that could have been used that would have done just fine in mud such as mechanical barriers or bridge plugs? >> they could have used a mechanical barrier, yes, sir. >> have you seen any indication in the documents you've looked at that bp considered the possibility of using a mechanical barrier or bridge plug rather than the surface cement plug that was used? >> no, sir. but i have not had access to their planning documents. >> mr. lewis, have you seen any indication that bp considered the possibility of using a bridge plug or mechanical plug? >> actually, there is one reference very early on in the initial documents in the predrilling instructions

indicating that a packer-type mechanism should be onboard for possible use in an abandonment, but beyond that, no. >> i'd like to interrupt for a second. commissioners, we had a -- in order to avoid lawyers just standing up all over the place and asking questions, i told the commissioner we'd work out a deal with all the lawyers that if there was anything we missed or thought we got wrong, they could e-mail me a question. what we've gotten is so far so good, and i want to make sure mr. grimsley wants to ask a question. we won't disclose publicly who it is, that's not porn. it is the only -- important. it's the only question we have, and i want to be sure. thank you. [inaudible]

>> now, the decision was made to set the cement plug down to 3,000 feet. was that required? could they have set the cement plug at a much higher level as part of this temporary abandonment procedure? >> yes. it would have been typical to set it closer to the sea floor. >> and even if they wanted to set the cement plug at 3,000 feet and set it in sea water, was there other ways to increase the hydrostatic pressure below the surface cement plug to account for the additional underbalance from the displacement above? >> yes. in concept the density of the fluid below the plug could have been increased in the way that mr. bourgoyne has described earlier, although the deeper the plug is set, the less practical that becomes. >> okay. but in this case are you saying that bp could have chosen to increase the weight of the mud that was actually down here below the cement plug? >> yes, sir. >> what would have been the

process by which bp would have had to have set that heavy weight cement or set that heavy weight mud? >> the most straightforward method would have probably have been to have run the drill string or the work string down to a depth just above the shoe track in order to circulate that heavy mud in place to fill that, that space in the well below that depth, below the 8367. >> and how long would it have taken to actually perform that procedure, to replace the lighter mud with this heavier weight mud? >> probably somewhere between one and two days based on what mr. lewis has said about the time it required for them to trip. and maybe a little less than that in that they were already tripping to 8300 feet. >> and, in fact, is it possible that bp could have circulated such heavier weight mud that there would have been no underbalance whatsoever seen at the bottom of the well?

>> i can't remember that i've done that calculation yet. we'd need to, we'd need to check that. >> okay. but certainly, well -- >> in any of your experience, have you ever seen a situation in which a cement plug was set at 3,000 feet below the mud line, put aside the sea water issue, but just a surface cement plug set 3,000 feet below the mud line? . bouryne? >> not as a top plug for temporary abandonment. >> dr. smith? >> i really don't have the recent direct knowledge to comment. >> mr. lewis?

>> i'm kind of halfway between these two previous answers. not as a top plug, i think, would be what i'd have to say. >> are well, have you ever seen one set so deep with sea water above it? any of you? >> no. >> no. >> now, mr. bourgoyne, one of the reasons i understand that bp chose to set, to displace this 3,000 feet of mud with sea water was because it wanted 3,000 feet to accommodate drill strength which it would hang off a lockdown sleeve in order to set that lockdown sleeve. is that your understanding? this. >> that's my understanding. >> and that's because they wanted 300 -- they wanted 100,000 pounds of weight which

was equivalent to 3,000 feet of drill strength. >> that's reasonable. >> okay. are there other ways besides hanging 3,000 feet of drill string off a lockdown sleeve to achieve 100,000 pounds of weight? >> yeah. you could run heavier tubulars or even casing. >> okay. could you also put weight on top? >> yeah. especially if you use casing on top, i mean, collars. >> are okay. and also one of the reasons, assuming they wanted to use the 3,000 feet of drill string, that they needed to set the surface cement plug so deep was because they wanted to set the lockdown sleeve last. is that your understanding? this. >> that's correct. >> was there any requirement that the lockdown sleeve be set last during this procedure? >> none that i'm aware of, no. >> okay. we've been told that the concern was that bp didn't want to harm the seal. there's a seal at the top of the

lockdown sleeve -- [inaudible] that bp did not want to harm that seal by virtue of having operations going up and down through that lockdown sleeve. does that sound reasonable to you? >> to try to preserve the lockdown sleeves by minimizing the number of trips through it? it's a reasonable thing to consider. i wouldn't be concerned with the operations that were planned, especially before the temporary abandonment. it's just a work string, after all. >> and aren't there other ways, sleeves for instance, that you can put in place that will actually protect the lockdown sleeve during further, during further operations? >> sure. >> is there any evidence you've seen that bp considered any of those possible ways to protect the lockdown sleeve? >> i vice president reviewed those particular -- haven't reviewed those particular planning records or things like that. i haven't had access to that.

>> mr. lewis, have you seen anything like that? >> actually, i think we have one technical clarification here. it's the polished ore that they were desiring to protect, and using the lockdown sleeve for that protective element, there are four protectors specifically designed for that type of purpose. i saw no evidence that they had considered those other options, and so, no. >> the final thing i want to ask about is the fact that, at least from our perspective, is that there was no barrier in place -- say that surface cement plug --

during the period of time many which the riser was being displaced. so that the only barrier was the cement job at the bottom which turns out to have been untested, and the b.o.p., do you agree with that? that was the state of affairs as a result of this temporary abandonment sequence? mr. bourgoyne? this. >> yes, i do. >> dr. smith? >> yes, sir. >> mr. lewis? >> yes, that's correct. >> okay. dr. smith, what is your view as to the advisability of having only one barrier, put aside that it was not, in fact, tested, but only one barrier in place besides an open b.o.p. during the displacement process? >> well, it's the minimum number of barriers that, that we would generally accept. and i think that's the fairest

thing to say. >> mr. lewis? >> it's putting all your eggs in one basket. >> what do you mean by that? >> i mean just what dr. smith just said, it's the minimum barrier. there's only one there. and you have purposely brought this well significantly underbalanced, and doing that against a single barrier that has been problematic in it creation and has never been really tested is dubious wisdom, in my point of view. >> is there any reason that there had to be during these temporary abandonment procedures only that barrier at the bottom? mr. bourgoyne? >> no. >> okay. what, what else could bp have done to insure that the cement at the bottom was not the only

barrier? >> well, they could have put the second cement plug in before removing the mud. >> would it have been, in your opinion, prudent to have done so? >> most definitely. >> dr. smith, do you have a view on that? >> i think there's multiple alternatives that would have achieved a second barrier that could have been considered -- there's just many different ways to conduct this procedure that you have different options about how you achieve the barriers and the controls that you want. and so increasing the mud density, setting the first plug in a higher density mud, in the mud to begin with, setting an extra cement plug or an extra

mechanical barrier before cutting the mud weight back to sea water, there's just lots of options. >> and all of those would have been, in your mind, prudent options? this. >> sure. but -- and there's complications and potentially risks associated with each one that would need to be considered. you're, you're doing a regular engineering design process of trying to get an optimum design where you're trying to balance multiple object i haves. -- objectives. >> but did bp employ any of those additional options that you just identified? >> no, sir. >> mr. lewis, do you have any additional opinions on that? >> i think it's been pretty clearly stated. >> i'd like to move on to the negative pressure test. actually, the one question that was handed to me -- and this is for mr. lewis on the float conversion -- you're aware that bp is currently doing testing or at least has indicated that it's

doing testing to determine whether the surge after circulation was reestablished at 3142 psi may have created a sufficient flow rate to convert the float equipment, are you aware of that? >> yes, i am aware of that. in fact, i referred to it when i said that in their report they indicated they were doing that, and i would be very interested in seeing their results. i'm curious as to whether they are physically testing equipment in a mock-up or if they are modeling that or just how they're going about that. i find that kind of an intriguing question. >> okay. and so you've given your preliminary opinion here today, but you'd be perfectly willing, obviously, to consider any test results from the surge testing that bp performing? >> the more science, the better. >> so the negative pressure test.

dr. smith, have you developed any opinions on the negative pressure test conducted at macondo? this. >> yes, sir. >> in your opinion, did the negative pressure test performed at macondo establish well integrity? >> no, sir. >> why not? >> because it was a test that showed there was not well integrity. >> and when you say it showed there was not well integrity, what data specifically showed there was not well integrity? >> when they opened the drill string, fluid would continue to flow back rather than stopping which would be indicative that there was a seal, and that when they then closed the drill string to stop that flow out from the drill string, pressure built back up indicating that there were fluiding leaking into the well, repressuring the system. >> in many your opinion, did the data that the men on the rig floor were seeing that evening indicate that the well was, in fact, flowing? >> well, the, the data that's in the sperry-sunday that records

does not reflect that was it did not record fluid going to the cementing unit. so the records that we have are the indications as in the bp report that the people who were on site said that fluids were flowing back to the cementing unit. >> okay. but given the fact that the pressure was building back up, is that an indication that the well was flowing? >> yes, sir. >> in your opinion was the negative pressure test conducted properly here? >> no, sir. >> are why -- why not? this. >> because they didn't begin with the conditions that they had stated they should begin with. >> and in your opinion is there any explanation for why there would be 0 psi on the kill line and 1400 psi on the kill pipe? this. >> yes, sir. there's two explanations, and the potential explanation's in the bp report. one is that someone unintentionally closed the valve on the outlet from the b.o.p. to

the kill line. i think that's very unlikely given that they were intending to monitor the kill line. the other is is that because the fluids in the well below the b.o.p. stack were not what was intended to be there. what was intended to be there was sea water, and that what was actually there was some mixture of sea water and this 16-pound-per-gallon spacer that, that those, that those fluids could get up into the kill line and potentially cause bridging or plugging in the kill line. so there's a -- and there's, in fact, in my opinion there's evidence of that during this period of time when they repressured the kill line from the top and pumped into it. there's, there's evidence that the kill line was acting like it was partially plugged and that that plugging or maybe excess gel strength in our language had to be broken for the, for the

kill line to take the fluid at the pressure it should have. in additioning, what's -- in addition, what's not in the bp report is that there's this strong evidence that before the negative test ever began that the 16-pound-per-gallon spacer was not, in fact, all displaced above the wellhead, that there was something on the order of 700 psi excess hydrostatic pressure measured on the drill pipe that had to be due to heavier fluid being below the wellhead or the b.o.p. stack in the annulus that was supposed to be filled with sea water. so that heavier fluid being present reduced the -- better way to say it would be it provided some barrier to pressure being felt on the kill line. and that was seen kind of throughout the beginnings of this test that when they opened the kill line, the pressure had

dropped on the -- when they opened the valve between the b.o.p. and the kill line so they could feel pressure in the well through the kill line, the pressure on the kill line dropped because the drill pipe pressure dropped. but they weren't equal. if, if test had been ready to conduct as planned, the pressures on the kill line and the drill pipe should have been equal always. they never achieved that. >> that's what i was going to ask. putting aside the potential effect of the spacer, should the pressures on the drill pipe and kill line have been equal throughout the test? >> yes, sir. in my opinion. and just from physics. >> is that because they're, basically, two straws going into the same vessel? >> two straws going into the same vessel that were supposed to have the same fluid in each straw. >> once the rig crew recognized that there was spacer that had leaked down below the annular preventer, what in your opinion would have been the prudent course of action for the crew to have -- the crew and well site

leaders to have taken? >> to have circulated that heavy spacer out, get the system back to being filled with sea water as was the original intent. >> was that done here? >> no, it was not. >> how long would it have taken, do you think, to have circulate ed, well, to have flushed out the system, essentially, of that spacer and to put the system back in a position where you could conduct the negative pressure test re-- reliably without the spacer? >> i haven't done the calculations, but my guess would be not more than a couple of hours. >> now, we talked about earlier you've testified previously about your analysis of the negative pressure test. >> yes, sir. >> and you've actually written a report on that as well? >> yes, sir. >> your testimony, at least, is publicly available, correct? >> that's right. >> okay. so i'm not going to go over that testimony again. if people want access to his

analysis of the negative pressure test, i would suggest they consult his testimony from the joint investigation hearings before the boem and coast guard. mr. bourgoyne, have you developed any opinions on the negative pressure test performed at macondo? >> yes, i have. >> do you agree with the opinions professor smith just gave? >> >> yes, i do. >> okay. do you have anything to add? >> no, i don't. >> so you agree this test was a failure and that it was not conducted properly and that it showed, in fact, that the well was flowing? >> it demonstrated the well could flow, that's correct. >> okay. mr. lewis, have you developed any opinions on the negative pressure test? this. >> yes. >> did the negative pressure test at macondo establish well integrity? >> no, it did not. >> did, in fact, the data obtained during the negative pressure test show that the well was flowing? >> showed that the well was capable of flowing, yes. >> in your opinion, was the negative pressure test conducted properly?

>> >> no, it was not. it was not conducted in compliance with written procedure although that procedure was very brief. >> okay. and then i want to talk just a little bit about the procedure. whose responsibility, in your experience, is it on a rig to design the negative pressure test procedure? >> you want me to answer that? >> why don't we start with you, mr. lewis. >> i would expect the town engineering team to outline the steps of that proceed you have. >> dr. smith, what is your view? >> that engineers that were responsible to the operating company would design that procedure. >> mr. bourgoyne, do you have an opinion? >> yes. it would be the engineers with the operating company, that's correct. >> so thes the operating company that's responsible, at least as you understand it, within the industry to develop the negative pressure test procedures for the crew on the rig. >> yes. and, of course, the, the rig crew has some responsibility to

report back, but, yeah, it was definitely the engineer working for the operator who designs it and is responsible for it. >> have you seen in your investigation in this matter any detailed procedures as to how to conduct or interpret the negative pressure test here at macondo? >> definitely i haven't seen anything on how to interpret it. some limited procedure on how to conduct it, i have seen that. >> okay. on the limited procedures on how to conduct it, i want to go back to the ops note from april 20th. >> okay. >> and it says right here run into hole, displace the sea water to above the wellhead with sea water in the kill line, close annular and do negative test. is that the limited procedure that you've been talking about? >> yeah, that's, that's it. >> so that's about it for a procedure? this. >> right. >> okay. dr. smith, have you seen any more detailed procedures that

was provided by the operator to the rig drew? >> identify -- crew? >> i've seen less, but this is the most detailed. >> mr. lewis, have you seen any? >> nothing more detailed, no. >> is this, in your opinion, dr. smith, a sufficiently detailed negative pressure test procedure to be giving to the rig crew? >> >> no, sir. >> will what additional type of detail would you expect to be included in this a procedure describing how to perform and interpret a negative pressure test? some. >> i would certainly have expected that there would have been a calculation of what pressure to expect to have trapped at the beginning of the test that's not present here. there is a pressure here, but it is not that pressure. it's a pressure that the rig crew can't measure. and i would have expected there to be some statement of what to do if test was not successful and, in general, my experience, my own practice there would have

been additional details about volumes to pump and steps that could be taken in monitoring more detailed criteria for whether the test was successful, the kinds of things that then the rig personnel might, might check, but the kind of calculations that, in general, the people on the rig are not expected to be able to do. ..

>> well, you know, the primary thing would be what you would expect a successful test to look like. perhaps how long to wait. also do those calculations like dr. smith was outlining the expected flea back volumes so the rig crew would evaluate if the test was going as planned. >> when you see bleed back volumes, we talked about this yesterday, once the crew has the pressure, there's a certain amount of pressure? >> that's right. >> before starting the negative pressure test, the crew wants to release any extra fluid up at the rig; right? >> the crew has to bleed off

that compressible volume to reduce the pressures, that's right. >> there's a way to calculate how much fluid one would expect to get back when you are bleeding off that residual pressure. >> you can estimate it. it can be accounted for. >> why would it be useful to know that information before conducting the negative pressure test? >> well, if you start to get back a significant within the measurement error, that indicates that there's additional fluid entering that is not accounted for. if it is sealed, there would only be compressibility in the well to bleed off, if you will. that volume would represent perhaps an in-flow into the

well. >> have you seen whether those calculations would done here at macondo prior to the test? >> i haven't seen any indications. there aren't any here on this document. >> mr. lewis, do you want anything to add what procedures should be included along with the description of the negative pressure test? >> no, i think it's been adequately covered. >> professor smith, i understand that as part of your investigation into the negative pressure test at macondo, you looked in to see whether there are, in fact, anything regulations or industry standards prior to the event governing how to perform a negative pressure test; correct? >> that's right. >> what did you in regard to any regulations? >> applying to the gulf waters,

there's no regulations, and i searched carefully. >> did you find a regulation that even priored the negative pressure test to be performed? >> not explicitly. >> is there some regulation they would have violated had they decided to forego the negative pressure test? >> yes, actually there is. there's a requirement in the code of federal regulations. if you don't mind, i'll just read it. >> please. >> it says before removing -- this relates to a temporary abandonment, or abandonment. it says before removing the marine riser, you must displace with sea water. you must maintain sufficient hydrostatic pressure or take precautions to compensate and maintain a safe well condition. logically, the negative test is a way to beforehand prove that the well will withstand that

reduction of pressure as a means to satisfy this requirement. >> so if one does not perform a negative pressure test or performs one and it -- and it's a failure, then the regulation you've just read would not be satisfied. >> that's my interpretation, yes, sir. >> did you also look to see whether there is any industry standard guidelines or procedures out there as to how to conduct and perform a negative pressure test? >> i did a course si search, yes, sir. >> what did you find? >> i did not find any practices that would be -- have some official weight. >> do you havethere were no regr industry standards? >> i think because this is a relatively rare procedure to

apply. this procedure is really important in deepwater wells where you are removing the riser, so you are removing the hydrostatic pressure that existed in the mud and the riser. it's not something that's common for land operations or shelf operations where we are working with a surface wellhead. >> just to get that straight, in deepwater when you are leaveing and temporarily abandoning a well, you are removing all of the mud in the riser when you pick up and leave; is that right? >> that's correct. >> so it's in no circumstances where you are most likely to severely underbalance the well in a the procedure? is that right? >> that's right. unless you've taken the kind of preemptive measures that we've discussed. >> there are regulations on deepwater drilling; right? >> yes, sir. >> do you know why they didn't account for this procedure? >> well, i think the regulation

that i read is the regulation that would require the operator to can be if they were going to remove the hydrostatic overbalance, to do something that prove the well was safe to do that. the only practical, responsibility approach to doing that would be to do a negative test. to remove that hydrostatic pressure in a control system as was done with the b.o.p. closed to verify the well will hold back that external pressure that you are going to impose on it. >> let's assume, hypothetically, that the men on the rig that night at 8 p.m. had concluded this is a failed negative pressure test. what steps would the crew and men on the rig then have needed

to take to diagnosis what the problem was and potentially remediate the situation? >> well, a logical first step would have been to circulate the sea water out and regain hydrostatic control. that would allow them to open the b.o.p. and work in a normal fashion. then the next step to see where was the leak so we can define a way to go back and correct that. and so it tends to be a very intense process that i haven't thought through those steps. and eventually, onceoff done the test to find where the problem is, then you have to design a correction to that problem. >> so let's imagine that here the rig crew and well side leaders had decided there might be a problem in the cement at the bottom. how long of a procedure would it

have been to remediate the cement failure at the bottom? roughly. >> something between 24 hours absolute minimum to trip in the hole and set one of these mechanical plugs, like a bridge plug near the bottom of a well to maybe several days if they were going to do a more thorough remedial cementing. >> is this consistent with the steps that would need to be taken, mr. lewis? >> yes, those are the basic steps that would be required. >> and that night, the choices with the negative pressure test to sign off on it, which we all have said we believe the men there thought or to undertake what could be a substantial and strengthy diagnostic and

remediation process; is that right? >> yes, sir. >> now in your experience, mr. bourgoyne, as a company managed chevron, when you had a seen, if you had seen the data like was seen that night during the negative pressure test, would you have called that back to shore? >> most definitely. you know, once -- probably in the process of getting the anomalous data made a call back. if i didn't understand what was happening, i'd seek counsel. seek help. and the engineer at shores task is to provide that. >> where there any policies in place at chevron that instructed it's well site leaders when to call back to shore when they might be seeing these anomalous situations?

>> i don't recall any policy. it was more of a -- or -- do you have confidence in your knowledge, wigging -- knowledge, i guess, the burden is on the company rep to recognize when something is anomalous. but there was definitely no policy or prohibition to it. i would say it's more of a cultural thing that varied from who you are working for as to whether you would call back with an inkling much a problem, versus nailing down that you really did have a problem. personalities are personality personalityies. sometimes if, you know, like if we take this case with the negative tests, you might have tried to do the test twice and even circulate sea water around before calling in to actually

say, yeah, i'm having a problem. or you might have for another different engineer called in much earlier to seek advice on perhaps there's another approach or something that i'm not seeing on a more informal level. >> mr. lewis, what is your experience with regard to whether to call back on to shore when anomalous data readings like this are encountered? >> i've not seen a written procedure in any of the companies that i've worked for as a well site leader that's so specific. i would echo and maybe even expand upon mr. bourgoyne's statements there about the relationship between the rig site personnel and the office engineering staff. i've worked for companies where

basically the well site leader was instructed to do absolutely nothing that wasn't already included in that well plan. and those were very, very complete well plans though with exactly has been described here, pressures, volumes, procedural steps. i've also worked in organizations where the well site leader was left a significant degree of personal discretion. as a well site leader, i learned early on that discretion is the better part of valor, however, if i didn't understand something, the best possible thing i could do for myself, and everyone on the rig, and for the benefit of the company that i was working for was ask for help. so there is a large amount of interpersonal relationship that goes into the willingness to go

pick up the phone. the old days the company man was god. he was supposed to know everything that went on all the time. we have evolved to an operational environment that's so complex and has technological elements in it that are beyond the ability of one man to be completely cognizant of. so it's not required for your well site leader to communicate with more people, more frequently, and possibility even at an earlier level in the evolution of events than has historically, traditionally been the case. >> well, even if there's not a specific policy in place, and i agree it would be odd, when you see weird negative pressure test readings, call. you want a culture when people are encouraged to call back to

shore when there's an odd reading they don't understand. how does one in a company create a culture whereby the instinct is in those situations to call back to shore? what has been your experience, mr. lewis, in that regard? >> that sort of culture would have to start with the mandate from the top. but it would be something that would have to be nutured by primarily the interface between your engineering management and your operation management in town. and the bp organization, they've actually got a separate group for engineering and a separate group for operation of the well. but they interface very closely. and that sort of communication would would need to start there. organizations that are smaller than that, you'll find the engineering and operations people are the same group. and it's actually somewhat

easier in those contexts to have these conversations. another thing that would engender that communication would be as was indicated might be the practice that another major company here earlier today, the environment of that field operational group, those drilling supervisors, as well site leaders is the new term. it's a bp term, by the way, that came to us courtesy bp. have them involved in the initial design and planning process. they may not have the technical skills to run an engineering program to calculate the loads on a spring of casing, but they definitely are the people who are going to be managing the installation of that casing, they are the people that are going to be confirming that they have the right equipment on the location. they should be involved in the beginning. if you have the people in the

room with the designing process, it's much easier to say charlie i need your help. i don't know charlie, should i call him? that sort of decision can play in here. it's that personal in some cases. that culture needs start at the top and be nutured without the process of drilling the well. >> what about your experience, mr. bourgoyne, calling people back to shore or involving other people in the discuss when the odd types of things are encountered? >> i guess i don't have a real good formal way to institute such a thing. i found and since working for chevron, i've worked as a supervisor, that it really is a matter of those in a supervisory position showing interest. and also fully exploring ideas

that are brought to them. i know that as a junior company man, if i approached or was included in some planning and i had an idea that perhaps didn't work or wouldn't work or was a brainstorming idea to explore why it wouldn't work. it was very educational. but it also led to this interpersonal relationship if you will, this feeling that, well, that's somebody that i can reply on for counsel. i guess also a deep feeling of responsibility is a big driver if you are that person who has to make the call. you have to know your limitations and, you know, even if there are repercussions for calling back, it's -- it must be done, if you will. that personally was my strongest

motivator if it was a tough ball to make. or something that i was concerned about bringing up and how, you know, exposing my ignorance, if you will in seeking advise for somebody who i thought might not appreciate that i'm learning or i'm confused and i need a hand. instituting a company-wide, i can see it would be a great challenge. it's actually pretty simple on a rig. there's two or three supervisory positions there. if those two or three people decide to make that environment, or create that type of environment, you know, it's a small -- very small group. so it can be either really good or really bad. i've worked on a lot of really good situations. never any really bad. but i could see the potential for this don't communicate

unless you absolutely have to obvious you have to be absolutely confidence in your position before you go out on a limb and actually offer an opinion or an idea even. >> i want to switch just and ask a couple of questions about well control and kick monitoring. i know that's an important issue, i know mr. bourgoyne, and dr. smith, both of you teach well control at lsu. mr. bourgoyne, how are people typically trained, drillers, rig crew, in how to monitor for kicks and conduct well control? >> they typically go to a course as three to five-day course. there's stimulations included. at lsu, we have a full scale well facility that we actually

do exercises on. so there are both classroom lexture -- lecture materials, and even stimulations. most of the stimulations that i've been involved with is what i would characterize a routine well control operations. that is most of the focus is on detecting a problem very early when it's much easier to correct, and there's much less risk involved if you connect -- correct it early and correcting it. there's not real high-stressed well control scenarios that are necessarily stimulated, but to demonstrate competency, and understanding of the procedures. >> what jumped out is when you say a three to five-day well control course. is that significant to be a driller on a rig? >> not to be a driller.

that course presupposed that that person has some on-the-job training, is familiar with rig operations, and worked their way up through the ranks to driller. there's quite a few positions before achieving driller. i don't recall the requirements on experience for one curriculum particular well cap. but it's on the order of years. it's not just a few weeks in that position. >> what type of certification requirement, is there, in -- if any, to be a driller? >> to be a driller, just the well control cards is the only one that i'm aware of. there maybe internal policies within companies. as far as some regulatory requirement to become a driller, i'm not aware of any. >> and the well control card, does that come from completion

of this well control course? >> yes, it does. and we've converted to a system where each operator adopts or is in charge of this well control training system if you will in the well cap has kind of become a standard, at least here in the gulf. >> now you had mentioned the well control courses you teach tend to focus on the typical situations during the life of the well, where there's drilling going on. that type of thing. there the emphasis is on detecting kicks early and dealing with them. >> well, in the life of well, you may never have a well control incident. so the well control incidents are relatively rare in operational terms. and by far, the most common or, you might call it they are not necessarily minor, but they are controllable. they are routine, if you will.

they are not frequent. and those can evolve into a blowout. but it has been focused on this early phase when reestablishing control is not near as -- nearly as panicked isn't the right word. but when mud is flowing out of the riser at jet engine velocities, it's considerably different than detecting a 20 barrel kick and having 45 minutes to hours before that type of event would ever occur. >> do you think it would make sense going forward to increase the training that individuals receive on how to deal with emergency situations? like what we've seen now with the macondo well? >> i definitely think an increase in training should be considered, particularly with a

scenario -- you know, a set of disaster scenarios, if you will. i think it would probably be much more effective if drills were regularly conducted along these lines on the rigs that were doing the operations with the crews, because rigs are very unique. it's very difficult to set up a stimulator to stimulate a specific rig, because they are custom-built things. and designed for different purposes. i would suggest that maybe a standard set of disaster drills, if you will, that would need to be conducted prior to beginning operations or immediately after beginning operations on a well, well-by-well basis if you will or perhaps on some other frequency determination. >> but if your understanding, current in the industry, you have not seen regularly drills performed on rigs or even in

classes to deal with these emergency type situations where somebody is faced with gas coming out of riser and whether to hit that button? >> you know, it's been -- it's talked about. it's covered kind of in the terms of the transocean model, manual, you know, so discussion, yes. actual put together stimulation that they have to take those and act those actions in sequence, and make very rapid decisions like whether to convert overboard or mud-gas separator, and the decision has to be made immediately to be successful, i've never seen any drills or exercises like that. >> one last thing on instrumentation, there's been a lot of discussion about whether the data that the driller or others on the rig is seeing is in this very modern age sufficient for those individuals to be able to actually identify

kicks in the well and to do so early enough to take action. do you have any views as to the nature of instrumentation and displays on rigs and in what way they might be improved? >> for routine operations, i guess for which they were designed, for instance, these routine kicks that i've described to you where the active system or the pit system is very controlled, there's not a lot of simultaneous operations, it was designed for the routine kicks, if you will. they are very adequate in my mind. and there's always the back up of if there's something suspicious, stop circulating and do a flow check. i think you would find there's lots of rig crews if they expect the well can flow, they will take that back up verification much quicker if there's anomalous readings.

in this particular case, they were pumping from one thing, if you will, they were taking sea water from one source and taking a return from the well back to another pit. with current displays and algorithms it's very difficult in real time to determine i put in one barrel. did i get one barrel out or 1.5 barrels out? i think the report that bp put together demonstrates it could have been much higher. i put in one barrel and got 40 barrels back at one point early in the progression. some system that can do that analysis, that was done in the report in real time would be a very advantageous and display it, yes, that would be an advantage. whether it's obtainable, there's a lot of logic that would have to be built into it. tracking all of those -- you have to keep track of whether

fluid is going on the rig among many different systems. then, of course, it would have to be vetted. but suggestion would be another set of eyes, another human brain doing the same analysis would be beneficial. and then it might even have another benefit in that, you know, i always do things better if i think somebody is watching over my shoulder. and will catch my mistakes, if you will. perhaps transmitting the data back to shore and being monitored by somebody else, they can talk to the rig and actually build a real time record of the operations much more detailed than is currently done would be a much more effective step. and that individual, that system, might even be an informal way to say, hey, i'm confused. is this a serious problem? especially if the communications

in real time isn't consistent. >> one last question, just on instrumentation and censors, there's been so discussion here about how at some point during the displacement of the riser, the spacer was actually sent overboard from the rig. at that point in time, when it was sent overboard, a flowout censor was bypassed. in your opinion, are the recommendations you can make as to whether and what extent it's a good idea to have censors that are bypassed during critical periods of the well? >> it's not a good idea to not measure flow rate out, not monitor flow rate out at any time. to be accurate with your question, transocean actually did have a censor in place. we just don't have a record of whether it was functional or not, or any indication from it.

the sparing sun was not in line, but there was a flow censor on the discharge. >> so commissioners, that, i'd like to open up the floor to any questions that you may have. : the question is, before this panel, what institute is responsible for making the decisions [unintelligible]

>> fred was not mike. >> the question was what entity would be responsible -- give me the wording again? >> my understanding of the question is, what, in your experience, having worked on these rig, who is the one responsible for signing off on test results such that the crew can then go on to the next phase of operations attack? >> the company man would be the one who "signed off on it," but there is no written policy, but i cannot conceive of signing off on the one without consulting

with -- as a matter of fact, the consent engineer's would be involved and that signing off. >> what about tonko rithe rig crew? >> they would definitely be advised and have the opportunity to evaluate it independently. i would think a rig crew would be interested, at least the person responsible for the rig. after all, transocean is responsible for the lives on board. borrow it down to one person it is the well site superivsor but i can't conceive not consulting with the rig crew and then of course getting the consent back from whoever, whoever was in charge of that well. >> professor smith?

>> sure. i think it is just crystal clear legally the operator has the responsibility. >> legally, and i understand that answer certainly but just in your experience who is the one who is generally signing off on these things? >> for this kind of thing, the culture that i worked in it was actually a companyoffice. >> how about you, mr. lewis? >> that is consistent with my experience. it's the operating company that's responsible for the design and execution of the well. the well site leader is the operating company's representative on location, quality control and confirmation is one much his

primary responsibilitis. the actual decision to go ahead on a test of any great significance would normally be discussed with the engineering staff in town. you would take your test results, either graphically or digitally. they would be transmitted to town. the engineer would look at them, go, yeah, i agree or the engineer would go, boy, that looks flaky, what do you think? but it's definitely on site the first call on that is the operator's representative. >> any questions from the commission? >> questions? co-chairman reilly. >> i have a related question on that. you've said that it makes sense to call back when you are uncertain or see information that you don't understand. is it always clear there is someone to call back to? i know that the, some of the

companies have, i've been in one in fact for shell, have rooms that, where people monitor full time each rig. i would suppose not all do. what percentage of them would have that? and if they did not have that, you would be getting someone at home presumably who would then do what? go on to his computer and look at the same data? how is that all done? >> well in my experience it's, it's usual one person that's assigned, it would be the person who primarily designed the well or somebody who assisted if that person's not available. there is always somebody on call, if you will. wasn't necessarily a room that you called into and it was 24 hours. if it was something of significance, particularly if it was significant to the, to the success of the well, or the safety of the well.

>> as company procedure is it federal law, regulation? >> oim not aware of any federal law or even written company procedure. i definitely didn't read a procedure when i was working as a company man that said that. it was just the way it was done there to call in and describe the problems you were having. usually had a well plan available. they were up-to-date on the operations. so it wasn't like there was a lot of graphical interface needed. if there would have been we would have faxed back reports. the engineer goes into the office. you know, the well site supervisor's responsible to make sure the well is secure so that those kind of prolonged discussions, whatever activities is going on is not to present an imminent threat but, if you're evaluating something, yes, that interaction

happens any time day or night. >> some companies make a lot of stop work capability and say that everybody has it. i guess i would be interested to know how often that is exercised and when it is, how much information is likely to be available to how many people? say if there were other who is might have detected the, or noticed the gauge that indicated a kick, is it likely there would have been possibly, or is that information confined to one person specifically typically? >> just about anybody involved with the rig operations that had, you know, an understanding of something that may have indicated a well control event. would have called back to the driller most likely. and informed him, because he is the one, he or she has the most information about current, that immediate,

that second, what is going on the rig. and that person also has the ability to react. if it is indeed a well control event, you want to act quickly and shut in the well to re-establish control. so i wouldn't consider a well control event, a stop work. almost doesn't fall into that category. its more like we're having a well control event. the driller is informed. that person evaluates whether it is a real kick event. most likely by doing a flow check. and if it is an event, then shutting down. how frequently a stop work happens, it never happened in my experience. seeped like it was never that formal. if somebody brought something to my attention that was of concern to them, it didn't necessarily have to be of concern to me but of concern to them, we would address it even if it required pausing operations.

>> one last quick one. the decision to use a diverter, would that decision be exercised by one person or would more than one person have power to do that or be consulted in that? >> you know, all the policies i'm familiar with that's one person because it has to be done quickly. >> that is the driller? >> that's the driller. >> okay, thank you. >> now --. ok. others can act if they see an event but the driller is the one who, it is focused on. >> i have a question that is similar to the ones bill just asked but in a different context and that is, responsibility for decision-making. i'm going to mention a few decisions that we talked about this morning. at what level of the organization would the driller on the rig make this decision, would someone back at home office notified of the situation make the

decision? or would it go higher up in the organizational structure? for instance, the decision to set the, the surface, the service lockdown at 3,000 feet, would that have been a, where would that have decision been made in the chain of command? >> there wouldn't have been a rig site decision. that would typically been a responsibility of someone in the engineering team to determine what the proper plugging method was for a temporary abandonment and it may or may not have been reviewed at the higher level of management within the operating company but presumably, the engineers responsible for the well would have laid out that plan. >> okay.

another, the shift from mud to saltwater which had the effect of reducing the pressure? >> same thing. >> same. the options to utilize after the negative pressure test failed? or to make the decision as to, first, that it did fail and second, what to do about it, where would they have been made? >> well, i think that relates to what we've been talking about, the environments that we worked in, that decision would have not been a decision that was solely made at the rig. it would have been a decision that would have always involved discussion with somebody who had been involved in designing the procedure and doing the, you know, doing the calculations for designing the procedure within the operating company. that it very well might have remained at the engineering level and not gone up to some supervisory level but

it would have been reviewed by an engineer. >> mr. lewis, those kind of systems in your experience. >> in my experience, that decision, particularly give the implications that it had, would have been one that had been reviewed jointly between the drilling superivsor, the well site leader, the design engineers and then the organizations i've been with in the last several years, that information of a failure of that magnitude would have been immediately taken up the chain to drilling manager level at the very lowest, if not above that. >> any other questions? gentlemen, this has been an extremely informative and helpful discussion as the panel that preceded you. i appreciate your candor and

the contribution that you've made to the public understanding of what happened in this tragic event. thank you very much. >> thank you. >> you're welcome. >> we will recess until 1:30. >> can i ask you all to please take your seats?

we are now going to turn to the government a partner in regulation. and begin with the deputy director of ocean energy management regulation and enforcement. an eight year veteran of the agency, from whom we are looking forward to a presentation. [captioning performed by national captioning institute] [captions copyright national cable satellite corp. 2010] >> i will now turn it over to our deputy counsel, sam sankar. >> i will ask you a few questions today. about the regulatory structure at the time of the macondo structure when i switch over to my feed. i want to talk about the new orleans office.

is that your understanding that was the office that had jurisdiction over the macondo well? >> yes, that's correct. >> and -- hang on one second here. here's the organizational chart for the gulf of mexico region here. and the regional supervisor field operations -- it's a little hard to read michael and then the new orleans district office if i'm right is down here under the deputy regional supervisor for district operations. so about -- do you have any idea about how many rigs of any kind that that office is called to regulate and supervise? >> the district office -- >> yeah, the district office in new orleans. >> yeah, i don't know the exact number off the top of my head. i believe that there's a number of rigs prior to the macondo was on the order of 30, 35%.

>> and about how many people work in that office? >> there's about two dozen people working in the district office. >> and of those how many are engineers? >> i believe tere's on the order of seven engineers and a dozen or so inspectors. >> are there different kinds of engineers in the office? >> there are. there's drilling engineer, production engineer. and some field engineers. >> when a permit comes in to drill a well like macondo, which is the particular kind of engineer who would review that permit? >> if it's an application for a rmit to drill for a well it would be by a drilling engineer. >> and do you have a sense about how many application ores permits to drill the new orleans office would field in the course of last year? >> it's a large number. i don't know the precise number. but again, the new orleans office does have on the order of 25 to 30% of all the permits that come in, in the gulf of

mexico. >> does that functionally mean that that's that drilling engineer in the new orleans office through whom that work is being channeled? >> it depends on the type of permit that comes in for the application of permit to drill and the applications were sidetracked, that would be correct. but there are other sorts of permits that come in that might be handled by some of the other engineers. >> mos of the drilling permits would be handled by that drilling engineer? >> that's correct. >> and about what is the budget of the salary for the -- for employees here in the new orleans district? >> the total salaries for that district office in the year 2010 is about $2.3 million. >> and about how much of that is engineer salaries? >> roughly half, i believe, a little less. >> okay. >> i'm sorry remind me of 2.3 million. >> yes >> just to give us a sense about

how much did that office spend on helicopter travel in the course of the year. >> about $3.5 million. >> so it's a -- a relatively small fraction of the cost of helicopter travel? i'm sorry, the cost of paying your enginrs is a relively small fraction compared to the cost of -- >> yes. the helicopter budget is more than half of the entire budget for the district office. >> now, i should tell the commission we spoke with two individuals who were more directly involved in the permitting of thmacondo well. they very graciously cooperated by providing written answers but given the stress of the situation, they would -- they preferred to submit written answers and mr. crookshank has agreed very graciously on his part to speak to specific permitting issues on the wells. i am going to putp the very

first permit for the macondo well, or the permits i should say. whoops. there we go. so this is what an application for a permit to drill actually looks like. you can see here it cost about $2,000. and it describes where you are. it doesn't say macondo anywhere on this but it is the first apd for the macondo well. i'm going to turn to one of the messages of this. the whole thing i'll show you is about 20, 28 pages with all the attachments. i'm going to skip ahead to one of the last pages in there which is an attachment which i hope will be a familiar chart to you. this is a fracture radiant chart, of course. have you ever seen these charts before, mr. crookshanks? >> if you want to take a moment the commissionnow my background. i'm trained as a mineral economist and have worked at the

department of interior for 25 years. i've been deputy director of the bureau since002. my job is largely been one on policy on management issues. so my familiarity on these sorts issues are from a management perspective as though from an engineer or someone who has worked in field operations. >> i apologize, mr. cruickshank. this is a radiant chart for macondo are you familiar at all with this particular chart? >> i'm aware of what it is. yes. >> you've heard some of the -- maybe you've heard some of the experts we've talked about describe thisoorressure radiant fracture chart here as a crucial piece of data about telling you how you should be drilling this well. when your drilling engineer looks at this kind of chart, what is he looking for on this chart, do you ow? >> my undstanding it's making sure that you're keeping the

sure the pressures in between the poor pressure and the fracture gradient. >> and the dash line here that represents the casing program and the mud program you want to keep that in between there. is it ever where the lines are not in the middle? >> not that i'm aware of. >> does the engineer actually check to see whether this is a particular narrow poor pressure gradient window at all? >> well, they would look at the data that comes in and they would be looking to make sure that the well design was going to stay within that interval that it needed to stay within. >> is there any reason they would say, look, this is a narrow poor pressure fraction gradient window and maybe some special requirements would apply to this well? >> i don't know. you would need to ask the engineers. >> i'm going to put up the schematic now, the well program schematic that was attached to the very same application for permission to drill. you'll see here that there is -- the well says it's going to be drilled to 20,000 feet but

there's no casing all the way down to 20,000 feet. instead, it terminates a little earlier than that. would you agree that this shows that it's an exploration well rather than a production well? >> yes. >> i'm also going to show you -- let me see if i can get it in here. on this well there's some indications about rupture disks and burst disks in here. is it your understanding that the inspector -- or i should say the engineer who would reviewed this would have considered the rupture disks or the burst disks in the course of his review? >> yes, he they look at the entire skematte jake and the entire well design. >> is there any regulation whether there shou be burst disks in the well. >> no >> so if the drilling engineer was looking at it he wouldn't have any basis whether it was okay or not okay?

>> he would have a basis if there was something in the well design that he felt was inappropriate he could raise the issue. >> so this is the original application for permission to drill submitted back in may of 2009. i'm going to skip ahead to another later application submitted some time later. it again shows a similar schematic you would agree, mr. cruickshank, an exploration type well shows the casings terminate before the end of the total depth of the well, would you agree? >> yes. >> would it surprise you to know that the internal bp design at this point included a full casing program that would have gone down to a production well? >> i would expect they had denite plansn how they wanted to drill out the well they would have submitted that with the permit.

>> i can show you -- i can show the commission what bp is -- i think i'll have to do this again. i'm sorry. this is a contemporary drawing from bp's internal documents from prior to this time frame showing a long string production casing and, in fact, showi that this was at least planned as a possible producer well. is there any reason you think that an operator would choose not to submit a full casing program with an apd at this point? >> my understanding when you have an exploration well -- until you confirmed whether or not you have a dry hole or a potentially commercial discovery you wouldn't be making a final decision about whether you would be putting in production casing or not. so you would wait until you were far enough along and to make that decision before you submit that additional information. >> you would permit it in stages then. only as much as you would need to have approved at that time? >> you would -- you would not as necessarily come in with the

design for the production casing beforeou knew whether it would be a well you would want to turn it into a producing well. >> nowof course, this also shows the now famous long string in place here. are there any regulations allowing or disallowing a long string production casing design? >> nothing specific. your well design needs to meet standards but it doesn't require you use a long string or a liner. >> are you familiar at all with some of the regulations contained in there. >> from a general perspective not an engineering one. >> some some of them covering cementing in particular. i'm going to scus a few of them with you and if you would like i could put them on the screen as necessary. i'm going to starts with one that speaks to the purpose of the cement in the well. so this regulation which is 30 cfr 250.420 says that cement has

to properly control formation pressures and fluids and has to prevent the direct or indirect release of fluids from any stratum through the well bore into offshore waters. is this something that a drilling engineer can determine whether these requirements will be m by lookinat an apd? >> i don't have training in engineering but they are supposed to be able to look at the design of the well and the cementing program and determine whether or not it's adequate to meet this test. >> has anyone to your knowledge ever violated this regulation or been cited for violating this regulation? >> not to my knowledge. but, you know, there have been incidents in the past related to cementing, and i would imagine there would have been some violations that may have gone with some of those incidents.

>> you're just not aware of any -- >> in terms of the front end of designing the cementing program, i'm not aware of any violations. >> now, moving ahead to another regulation 250.428, this is another regulation about cementing. and it says if you have indications -- if an operator has indications of an inadequate cement job, cement channeling or failure of equipment you should pressure-test the chasing shoe and run a pressure survey and use a combination of these techniques. are your aware now that the cement job at macondo failed? >> i've certainly heard some discussions of that, yes. >> and are you also aware there were no -- there were no loss returns at the macondo job or at least as we know right now there were no loss returns? >> okay. >> cement channeling, is that something that an operator can know ahead of time while pumping a cement job? >> i don't know. >> so would you agree it's hard for this -- this is a hard

regulation for them to implement at the time of the cementing b? >> right. these are thgs you wouldn't know until you're actually doing the cementing job. >> and even if you -- even if there are some indications it would be a complete satisfaction of the regulation to do -- to pressure-test the casing shoe? >> yes. >> so would a positive pressure test do a trick in pressure test in the case of a shoe. >> under our regulations, yes. under our regulations as they existed in april, i should say. >> i'm going to turn now to the final -- actually i'm going to show you one more regulation. i apologize.

this is a regulation that specifies you have to cement the space at least 500 feet above the casing shoe and about 500 feet above the uppermost hydrocarbon-bearing zone. would you agree this is an important regulation for the -- for the safety of the cement program of a well? >> yes. >> i'm going to turn now again to the apd. put two pages of it upside by side because, unfortunately, they are necessary. and i'm going to call out a small thing here. so this to our knowledge is the -- as we understand it, this is describing the cementing program at the macondo well. and this bottom area right here, which extends over to that one couple of words on the next page is the full description as we understand it of the cementing

program at the macondo well so it talks abouthe diameters of the casing and it talks about the rating of the casing and the size of the hole and the mud type of the hole and a whole number of things. having reviewed this, the only -- the only indication we can find of any discussions of cement is the volume of cement which is 150 cubic feet. i don't know if you've reviewed this document in detail, but i will represent to you that this is the only place that i've seen on this where it talks about cement. i won't ask you to agr. but my question is, 150 cubic feet of cement, if you do the math works out to roughly 26 barrels of cement in volume. do you have any idea whether that's a low amount of cement for cementing a production casing? >> i don't know. >> are you aware they actually pump 60 barrels of cement down the well? >> i was aware they used more than was in the application. >> and are you aware that even bp agreed that 60 barrels of cement was a very small amount

of cement to be pumping down that well at that point? >> i wasn't aware of that. >> this certainly sugges in the apd it says 150 that hopefully, you know, a drilling engineer might have flagged there was a low amount of cement in this well given the requirements of cementing a good cang? >> certainly the drilling engineer would have seen that number during his review. >> did they know whether bp was planning on using any centralizers at this well? >> i don't know what the drilling engineer knew about that at the time. >> are there any regulations that require information about centralizers or require their use? >> not at the time of these applications. there are now. >> are there any -- was there ything in the apd that you know of that discuss the flow rate of the cement? how fast it was going to be pumped down the well? >> again, i don't believe that was required at the time of this application. it is required under the regulations now. >> how about the type of cement?

is tre any required disclosures about the type of cement that would be used? >> no >> how about no indication whether they were going to use nitroagain foam cement? and were there any regulations -- and i apologize using the old acronym of speaking back at the time. were there any regulations that required laboratory testing of cement before its use in a well? >> no. >> are you aware that there was a 2007 study that identified cementing failures as one of the leading causes of blowouts? >> yes. >> was there any move to react to that by increasing the amount of cementing regulations? >> the reaction to that was they

at the time spoke to industry about the fact that a disproportionate number of loss ll control incidents were related to well control failures and discussed the need for some better standards of that. as a result, american petroleum institute formed a committee under its standard setting role to develop standards for cementing. some of our engineers took -- participated in that committee. it resulted in the publication recommended practice 65 part 2 in may of this year which we have now incorporated into our regulations as of last month. >> that wasn't in place, of course, at the time of the macondo incident, right? >> that's correct. >> so now i'm focusing on bp's application --ocusing too much on bp's application to modify it's temporary abandment procedures at the well. these are the procedures that we

discussed that changed quite frequently and then turned out in many ways to be crucial to the safety of the final well. and i apologize. i'm actually showing you the wrong page of this. here we go. this is the attachment to that first page that shows the particular procedure that we've been focusing on and the depth of the plug here it talks about setting a 300-foot plug. i talked about setting it quite deep as we've discussed. and it discusses the reasons why. it says it's for minimizing the chance for damaging the lds sealing area for future completion operations. mr. cruickshank, do you know what the lds sealing area refers to? >> i believe it's a lockdown mechanism. >> lockdown sleeve. so would it be fair to say that what bp was saying because of lockdown sleeve operations they wanted to set the plugs significantly lower tn the regulations would otherwise quire? >> yes.

>> what do you think prompted the engineer or what would have prompted an engineer to grant this departure? >> what the engineer would have looked at is whether they felt that under the description given of what they wanted to do, whether that would satisfactorily plug the well or not. this particular case, the engineer was relying on the negative pressure test that was going to be done as part of this procedure to determine whether or not that plug was going to do its job. and if it's not, then they would have revisited where that plug needed to be set. >> so he was relying on the plug? >> yes. part of the procedure as i understand it for putting on the surface plug was to do some tests of that plug. >> i don't mean to quarrel.

i believe the negati test was up here. the plug was afterwards in the procedure. would you agree to the negative test procedure appears to be and even this well monitoring program appears to be before the plug was set? .. >> i can't speak to the depth of knowledge on lockdown. >> i want to look at one more regulation now. is is a regulation about well

control. and in particular, there's a few phrases in here i'd like to focus on. can i get it -- there we go. again, the regulation here generally says what must i do to keep wells under control that are down here? i must take necessary precautions to keep wells, you must, for example, use the beth available and safest drilling technology to monitor and maintain the pressure for the well to control or kick. what does the best available and safest drilling? >> there's a regulation for best available and safest drilling. e technologythat's economically feasible. and that would protect the -- protect the environment. >> does that best available and safest technology vary dpending

on the depth of the water or the well that's bng drilled? >> it could. i mean i don't think our regulations necessarily specify what the best available and safest technology is all of the time. >> i want to actually close with just a few questions about the epic of your inspectors. it's worth noting to the commission that have interviewed the engineer who worked on the project, we found no indication that there was any bias, corruption, or undue nfluence on the people. these are people doing their job, trying to do it well. we found none of that at the level of employees that were doing this. do you believe there was lapses in anyone else beyond the two or three individuals that we spoke with in the new orleans district office? >> i have no reason to believe so. >> do you -- what impact as the

accusations of improper influence and bias on the part of your gulf of mexico region focus had on the morale of those folks down there? >> i think it's really had a negative effect. you know, there's been a lot of stories, a lot of public attention on that ossibility. and for the set of professional engineers and other staff that had taken their job very seriously for a long time, it's just a very, very frustrating and demoralizing picture to have painted publicly. >> with that, commissioners, i will ask you to direct your questions to mr. cruickshank. >> thank you. dr. cruickshank, as mr. bourgoyne has testified before the commission that she fully supported the expansion of offshore oil and leasing areas as president obama with the

agency that she had ssentially, they had adequate people and resources to cause herto support that. would you agree? >> i think at the time that was certainly what we believe, recognizing that if the program moved in the new areas, there would be an increase in staff to deal with operations in those new areas. >> do you think you hae adequate staff and resources to carry out your responsibilities now in the areas that you are presently responsible for? >> as a bureau with the department, we are seeking substantially more resources to beef up our inspection functions d our engineering functions and environmental science. we feel that we an o a more complete job, do a lot of things that we would have liked to do in a nonresource constrained world if we had more resources. the are a number of additional things that we would like to do. >> there's a concern in the

ndustry that although many of the industries will be able to coly with the new regulations, thahas been proposed and, in fact, are being implemented, that the agencyitself will have difficulty responding to the permits and making the judgments on the certification of the equipment and the rest in the a near term, and efficiently without delayin development further with the kind of de facto moratorium consequence in the gulf. you have no doubt heard some of those concerns. do you have any response to them? >> there is no de facto moratorium. we have moved resources around to try to address the workload issue that come with the new permitting requirement and we are focusing on resources on trying to design our processes to be able todeal with those. but they are new requirements. we are requiring new information, the process is different than it was a year

ago. and properly so. and i don't think we should expect to see processing return to exactly what it was a year ago. nevertheless, as -- the steps that we are taking to try to address the workload issues right now involve moving folks from other offices, which we can do for a while. but i think longer term, this is one the reasons we see a need for additional resources in the bureau so that we can have a me permanent fix to this. >> commissioners agree with you on that. perhaps we can have a interaction that could help establish your stance for the kind of resources that you do need. perhaps we could weigh in on that issue as well. commissioner garcia. >> thank you. dr. cruickshank, we don't have a lot of time. so i'll ask you to be as concise as you can, you can submit

information for the record if you feel that you need to supplement your answers. my understanding is that over the years, the agencies attempted to add a requirement for proactive risk management, but has not been successful. in fact, you've repeatly tried that. why is that? has industry supported those efforts? >> i'm not sure specifically what you are referring to. we do some risk basis for in our inspection program. there is some risk basis in the safety of environmental management syste rule that was put forward. beyond that, i'm not sure of anything specific. >> so there's been no attempt to enhance the safety regulations over the last several years? >> there's been a number of changes, or safety regulations over the years. >> okay. based on what you know now, there are anything that the agencies engineers and

inspectors could have done given the authority under the regulations to prevent or limit the blowout? >> i don't think that one can ever say you can prevent a blowout through these mechanisms. we will still waiting for the root cause anales to understand what happened here. certainly, i don't think there's a regulatory regime that can possibly design to eliminate the possibility of there being these sorts of incidents. >> okay. we've heard over the last day and a half about the unique challenges that deepwater drilling presents. do you think there should be a specialist ofice within the agency that oversees this drilling? >> well, we are taking a look at organizational issues as part of the organization of the bureau and considering all sorts of issues like that. we certainly won't say that our

staff that's overseeing the operions and the permit requests have the expertise-- >> but are you looking at some specific issue? >> that's part of what we are looking at, es. >> you are looking at that. okay. are you planning on developing specialist in areas like deepwater drilling? >> we're still consideri our options for under the reorganization about how we are going to structure. whether it's going to be around functional areas or do more cross training. these are issues that are under discussion. so at this point, i don't think we've reached a conclusion on exactly how we are going to structure the functions. >> let me ask you about an event that occurred a year ago. there was a blowout in australian waters. it lasted for over two months. was there very similar to the circumstances that we saw with macondo. was there any information transfer between regulators or within the industry as to the circumstances of that blowout?

>> there's been some between the regulators recognizing that the investigative report on that incident has not been released yet. so we don't have alof the information. but there has been some discussion between the safety regulators in the two countries. >> and are yo aware of any sharing of information within the industry? >> within the industry, not that i'm aware of. >> let me read a quote from the wall street journal and just get your reaction. this is from the may 7th, 2010 edition. and i'm quoting, steven alred, who as assistant secretary of the interior from 2006 to 2009 said the agency does conduct spot inspections of oil rigs for safety procedures, however, their roll is not to babysit the operators, he said. the agency' primary task during

inspections is to verify how much oil is being pumped, which is key to a duty, maximizing payment that the government gets from energy and oil producers. do you think quote, accurately rlected the political expectatis at the time prior to the blowout? >> i do not. certainly one the task of inspectors is to look at meters that measure production. but we consider that to be a secondary inspection. the primary inspections have to do with drilling rig production facilities, the safety inspections, those are the primary jobs of the inspectors when they go out in the field? >> why do you think he said that? >> i don't know. >> how did the regulatory approach of mms compare with other foreign regulators?

>> there's a variy of systems out there. but i think, you know, what we see and a lot of the other couries is they have a performance-based system of regulation where they have less in the way of prescriptive requirements and put more of the responsibility on the company to meet goals for having safe operations, rather than approving permits as we do. they get the submissions from the comanies and we'll review them, perhaps challenge them, and dece whether to accept or oect. but not necessarily formal approval process. >> mr. chairman? >> okay. other questions frompening remarks? >> i do. i have a brief statement. first of all, thank you for inviting me again. co-chairing reilly and graham

and other distinguished commissioners. as you know, this is my third appearance before the commission, although this is at a greater remove. i can barely see you from here. i'm delighted to be able to take this opportunity to continue our discussions both about the changes that we've made in our future plans for drilling on the nation's shelf. the regulation and enforcement share the same goal, which is to reform the way the offshore drilling is conducted and regulated in u.s. waters. as you know in late june the president and secretary salazar ask me to become the nation's director of offshore development. their direction was sweeping and clear, to review the agency from top to the bottom, and make the changes necessary to give the american people the confidence that drilling in our oceans will be conducted in a safe and environmentally responsible day.

since then, as you know, we've aggressively pursued reform agenda to raise the safety and accountability for my agency. these reforms are ongoing and will continue for some time. they are, i think, in many respects, familiar to the commission. let me walk through them very quickly. first we've launched an aggressive reorganization of the former mms. second, we've formed an investigations in review unit that steps up our internal investigations and external investigations in our efforts. third, clarifies what we expect to companies related to worst-case discharges, containment capabilities, and certifications of compliance, the most recent of which was issued yesterday. we have developed a policy to deal with real and apparent conflicts of interest. we've begun a full review which will no longer be used to

approve deepwater drilling projects. we've issued for the first time, guidance for what's called idol iron. requiring companies to set permanent plugs on approximately 3,000 nonproducing wells and dismanned -- dismantling approximately 750. we have developed rules related to casing, cementing, b.o.p. certifications, and other matters. we've developed and published the rule requiring oil and gas operators to develop for the first time their own safety and environmental management programs, the s.e.m.s. rule, both in the gulf of mexico and in the arctic. now we have pursued the changes while managing hundreds of loyal and committed public servants, many of whom have been in the agency for 20 years or more, through a crisis, the likes of which none of them had ever experienced before. and who it's fair to say have been deeply and profoundly shaken by the unrelenting and in

many ways, unfair criticism that they have received. now there are great challenges that face the country with respect to offshore oil and gas drilling. those challenges can't be minimized because they are substantial and they are difficult. let me summarize briefly several of the most significant challenges that i see for the development and regulation of oil and gas resources. issues that we confront every day and are the context for your work as well as for our reform agenda. first, to achieve the appropriate balance between ensuring that new safety environment standards are strictly adhered to my industry, and at the same time, expediting the prompt process of permits in deep and shallow water. this balance is critical and most be topmost in our minds as we impose and force regulations and make changes as we reform my agency. second, providing appropriate funding. we talked about this with dr. cruickshank.

funding and resources for the management of regulation of offshore energy development. it's clear, and i've seen statements that the agency for decades was starved for resources and was not able to review drilling operations, conduct inspections, and enforce standards adequately. even though the agency personnel tried very hard to do so. i've been asked by the president and the secretary to fix these problems. but that will, to put it starkly, require a substantial infusion of resources to accomplish. we have requested substantial resources from congress for the hiring of personnel to review drilling permits, to inspect rigs, monitor drilling activities, and to ensure compliance with environmental standards. there is a substantial technological gap between the industry and the people who oversee it, namely the people in my agency, that has to be addressed through new tools and training for government personnel. i'm deeply concerned without the resources that we requested,

justification for which could not be more compelling. the changes and reforms that we have pursued and will continue to pursue will not be realized. third, there is a grave need innovation and technological development with the safety, the blowout containment, and spill response. there's a tremendous opportunity here, and a desperate need for technological development offshore. i believe some, if not all of you, have gone on rigs and platforms. in many ways, they are engineering marvels. yet, the technological development that relates to safety has lagged behind the development of the rigs themselves. and so there's some questions that have come up that we need to address. what features should the next generation have in what types of censors and safety devices should be installed on the drilling rigs? what kind of electronic and metering should be required to

get realtime and important data. both to the companies that operate, and to the regulators that oversee them. how will versatile and containment equipment be designed and be built. now the department announced the creation of the institute, called the ocean center sail institute, that we hope will draw on government, industry, academia, and ngos to help address these and many other questions. fourth we need to optimize safety and environmental compliance regime for operational and offshore regulation. we will continue to think very hard about the safety and offshore regulatory regime. we have the prescriptive regulations, which is the system we currently have, and increasingly holding industry to performance standards that we develop.

those must be appropriate for the reality and scale of the united states as current offshore and oil and gas industry in our economy. we can't simply import foreign models into our current model. then too, the model that we adopt has to be consistent with the existing relationships between government and the private sector. finally, we must develop the strategy for offshore energy development in the arctic. as you know the resource potential there is substantial. but the arctic environment presents a broad range for challenges for oil and gas development. just to kick through them, they are whether conditions, the development of the necessary infrastructure. employs realistic still response resources and last but certainly not least, protecting sensitive arctic habitats and marine mammals. these are all important issues and we are considering all of them. final word, this commission is in a unique position to collect

and analyze information relating to these issues. and to draw upon a broad range of expertise and perspectives in your work. i know your work is coming to a close. but the challenges for industry and agency to develop practical and effective solutions will continue. therefore, as we do already, i look forward to working with the commission, i look forward to the report, i look forward to the recommendations, and i want to thank you the commission for its work. >> thank you, dr. bromwich. we really want to be helpful to you in the task that you have set. when you first appeared some four months ago before us in new orleans, i realized the question of the experience of the nuclear industry and the nuclear power operations that encouraged you to consider that as a way to supplement your regulatory effort. and raise the bar within industry by defining best practice and working closely with the regulators to bring up the game.

i also possibility taking some of the resource load off. have you had a chance to consider that? do you have an opinion on it? >> we have consider it. we will continue to consider it. i think your suggestions and your questions have stimulated thinking both within our agency, and i hope to some extent, within industry. i don't think it can be an immediate institute for the current system that we have now. is there the possibility and potential for the self-regulating mechanism that would enhance the regulatory system that we have and increase oversight? i think there is that possibility. i look forward to exploring it. i think we need to be realistic about differences that exist between the oil and gas and the nuclear industry on the others. and one is that oil and gas has been historically extremely competitive. my sense is the kind of information that would be handled in the oil and gas industry if one company inspected another or

participated in inspections of another, there would be issues about technical and proprietary information that companies maybe reluctant to share with one another. i think there are larger, far larger number of participates in the oil and gas and the shallow water drilling aspects of the industry than there are in the nuclear industry. so i think we have to look at those differences square in the face and try to figure out whether they are aspects that can be adapted to the oil and gas field. but i don't think -- i'm sure your not suggesting one can take one model and import it into a very different industry with a very different structure. >> thank you. senator graham. >> thank you very much, bill. my questions are going to largely follow the comments that you have just made, mr. bromwich. you stated that one of your priorities was appropriate funding to carry out your responsibilities.

in many areas in which private business is going to be inspected by government, there are fees or other means by which that inspection service is funded. if you take out a building permit, the funds that you pay for the permit end up going to finance the inspector who is supposed to be sure that the building is built to code and standards, safety, et cetera. why couldn't a system like that be utilized between the agency and the industry rather than relying on appropriated taxpayer funds to support the inspection function? >> that's a very good question, senator graham. my understanding was that was a significant element of what the administration was proposing to get us $100 million additional dollars in fiscal year 2011. there was a significant proposed

increase in inspects -- inspections fees. the reaction on capitol hill was mixed. there was substantial opposition from industry to raising the fees. that's not a surprising reaction. to the extent that we are banking on or hoping that an enhancement of fees will help to fund the needed augmentations, i think we need to see what the reaction is going to be. so far it has not been incredibly positive. >> there would be a potential alternative approach, and that is all of this drilling is done on public lands subject to lease arrangements. why couldn't you include in the lease the fee that would be sufficient to cover the cost of inspecting the activities that the leasee is going to undertake on you the tenant, on behalf of

the u.s. people's own land? >> that's an interesting suggestion. i don't know whether it's been previously explored or not. i would be intrigued, would be interested in pursuing it. i don't know whether it's ever been considered before, and if so, what the reasons were for not going forward with it. it's a way to go forward and get additional money from the industry that have used the public lands. >> another of your priorities is innovation, r&d, relative to offshore drilling. it seems to me it's a constant challenge for government to stay current much less ahead of entrepreneurial, aggressive, private sector energies. and that's -- we want entrepreneurial aggressive private sector entities to move the economy forward.

how would you see the new entity that you described giving government some greater ability to at least stay competitive in terms of it's ability to provide effective regulatory standards and enforcement standards in a rapidly changing technical environment? >> i think we don't have a fully developed proposal yet. i think sec tar salazar made the announcement because he wanted to get the reaction of the industry and ngos, but it is in recognition of a very significant definition that exists in the knowledge and industry and that guides them to deeper and deeper water and the technological know how and the development capacity that exists in the government. we are at a severe handicap and always have been as people drill in deeper and deeper water.

we're hopeful that one the things that may happen is we will create the institute and get the circulation of personnel. so we will get the benefits of people and industry who are involved in r&d programs who can share that information with the government, which will allow us to enhance the way we go about regulating offshore oil and gas. so the proposal, which is still very much in an outline form, is to try to develop that capacity in government so that we can stay more abreast of the industry than we have in the past. but i'm also concerned about something else which relates to the level of r&d which exists within industry. i went on a tour, recruitment tour a couple of weeks ago in the southwest. i dealt with the chairs of petroleum engineering schools in louisiana and texas. they expressed concern about the level of r&d in the private

sector into drilling and drilling safety. i think we're really talking about two different but important things. one is to make sure that drilling safety r&d goes on at an adequate level within the industry. but then also that that knowledge in r&d gets shared with the government so that the regulator is better equipped to do it's job. >> a couple of final questions, which were not on your list, one the things that we're probably going to be talking about is governmental restructuring. are there some changes that would match responsibility with skillsets more effectively? one of those that's been suggested currently the osha responsibility for worker safety is invested in the coast guard

for offshore rigs. it's my understanding the memorandum of the understanding the coast guard transferred that to mms. now is that continuing to be one of your responsibilities? >> yes, it is. >> what would be -- if the alternative were this should be placed in the hands of osha has onshore worker safety and comments to maybe why it should continue to stay in your hands? >> i am always concerned about proposal that further diffuse responsibility for one set of activities. in case, offshore drilling. and to put them in a larger number of hands. i think the coordination and collaboration problems when you go across cabinet agencies or cabinet departments tend to be far greater than they are within

the cabinet department. i would be concerned not only to have the rh and number of offshore and the coast guard and you add osha, you start to create the unmanageable environment. i think we are capable of enhancing our current capabilities. i don't think we should move components in out and willy-nilly. i know you are not suggesting that. i think we can do that job sufficient already, i've had meetings with the secretary assistant of osha and i look forward to more on what the effective regulatory on rigs and drilling. i think that's preferable to moving some of the inspections to osha or someone else. >> could you supplement your

comments with an analysis of what you think should be the criteria to evaluate the effectiveness of workers safety in an offshore environment and then why you think your agency based on it's actual performance has delivered at an acceptable level against those criteria? >> sure. we can do that. i want to remind you that i'm sure you know. we have within the last two months put out, i think, a landmark new rule in safety and environmental management system rule. and that's a rule that will be effective in october of '11, meaning we will begin doing inspections and reviewing to ensure compliance. that rule was in the works for a year before deepwater horizon. in recognition that a more holistic approach to workplace and drilling safety needed to be conducted. soy think our recognition that this is an issue, and that we can do better predates deepwater

horizon. and i think we will make that work. >> my final question relates to what we've been hearing last delay and a half and that is the consequences of having an industrial model which is built upon a lead company where much of the most important and frequently dangerous activity is actually then in the hands of a third or either fourth parties. we've had bp, transocean, haliburton sitting exactly where you are sitting in some cases laying the blame off on each other for a particular circumstances. how do you -- what do you see as the role of your agency in more effectively overseeing these multiple, multicorporate

relationships which constitute the actual team that goes out on to those rigs to execute to their responsibility? >> unfortunately, i haven't had a chance to listen to the evidence that you've had presented to you over the last day and a half. but certainly, if it does appear that the involvement of multiple companies seems to be a barrier to effective regulation, we will see what we can do to clarify what we -- what our expectations are with respect to each of the players who participate in a particular operation. i don't know whether that's an issue that's been focused on in the past. we obviously have an industrial model that we had no role in shaping, but we clearly have to effectively regulate that. i'll be looking with interest in what you conclude in the report, as well as what the other investigations conclude to determine whether we need to do things differently, given the number of players that are

involved in a particular project. >> thank you. >> commissioner. >> thank you. director bromwich, nice to see you again. >> i can barely see you. >> i can see you over there. if you can elaborate, you've been talking about the prescriptive regulatory and looking more at a safety case. this morning in the testimony, you've been looking at mms regulation, i realize they have changed. they weren't that prescriptive. they were very general, the industry because it is highly competitive and very productive doesn't have sort of, uniform standards either it appeared in each operate. with the expertise deep in the company. in the interest of moving towards more of a combination of the two, i'm just curious as to

whether since the macondo blowout with your dealings with industry, you've found a receptiveity of sharing best standards, best operations, and a more cooperative approach than certainly we've heard earlier today. >> i think deepwater horizon has not only been a wakeup call to my agency, but the industry as well. i certainly over the four months that i've been in the job had a lot of meetings with a lot of companies that tell me they've really taken to heart what happened with deepwater horizon. they are redoubling their efforts to improve their safety programs. i don't know whether over the long term there will be substantial changes in

enhancements to company's safety programs. i have been told by executives with companies who operate both in countries where there is more of a safety case regime that it is very risky to quickly move from one to the other. that, in fact, chaos would ensue if we flipped over to safety case model any quicker than a three to five year period. i think with that learning in mind, i think what we are going to try to do is to move towards more of a hybrid model over time. i think that our s.e.m.s. rule is a first and important step in that direction. and we'll have to evaluate whether there are other performance-based standards that we feel comfortable creating in order to build more of a hybrid system. i can't tell, frankly, whether

companies prefer the safety case system or the prescriptive regular -- regulations. i any if you ask the company representatives, i think it depends on what their own experience has been. and i think there are many differences between the country that is use the safety-case model than this one. about two years ago, i had the occasion to meet with my foreign counterparts at the international regulator forum in vancouver, i met from canada, uk, australia, and norway. it became sparkly clear to me, they face different and to my mind, less significant challenges than we do. it's far less competitive, there are many fewer participates, there are many fewer rigs and platforms that exist here. so i think we really are talking if not apples and oranges, we're talking about operations on a

completely different scale in those countries than from what we have here. now my very purpose in meeting with those regulators was to see what we can learn from them. this afternoon, i'm meeting with one of them again. we can learn, but the mind structure here and the historical way of doing business here is different from the way it's been conducted any place else. >> although many of the same countries that are operating here are also operating there, aren't they? >> yes, that's true. >> you would assume they would participated in both cases. they would be prepared to participate in the somewhat different system here. >> i can tell you, i won't name him, an executive from one of the major companies that had experience in the uk said he went through three to four year of chaos moving from one system to another. he didn't want to go through that again. those are the words of one

executive who made it fairly clear he didn't think transferring the experience in one place was that easy. >> uh-huh. thank you. on another point, you made the statement that you were looking much more carefully at the arctic and identifying four different areas that you were looking at. we've gotten in many comments into the commission on the challenges in the arctic. and particularly, the different gaps, response gaps, research gaps, gaps of equipment and the location of the equipment, et cetera, et cetera. can you just talk a little bit about what timeline that you are under to complete the reviews that you identified and over what period of time you will be making decisions relative to the arctic? >> it's going to be in the very near future. we've had meetings in the department of interior very recently and we have additional discussions that are going to be held in the very near future.

i think people understand that there's a desire for and a need for clarity. and we will try to provide that as quickly as we can. this is not a back burner issue. it's very much a front burner issue that's currently under discussion. >> one the issues that we've been looking at is the scale of the area wide leases, particularly in an area such as the arctic, the areas are so vast. are you contemplating narrowing the scale of the lease sales from area wide from more defined area with more analysis from the particular resources in those. i mean marine ecological resources in those areas? >> i have not yet been involved in discussions of that kind. we may well have them in the near future. so far in my four months, i have not been involved in those discussions. >> okay. thank you. >> other questions for director bromwich. we appreciate very much your appearing here.

wish you very well in your work and hope we can play an constructive and helpful role in your success. >> thank you. >> thanks to all of you. >> all right. we will take a break until 3:00. [inaudible conversations] [inaudible conversations] >> he has a long history with in

the oil industry, and from my point of view, given my experiences with the prince william sound exxon fell these experienced -- valdez experience, it has been fascinating for me to watch the evolution of this company which is the gold standard a lot of people's eyes for safety and environment, to see the kinds of initiatives that it has taken in the safety culture it has created. effective of observing. it's a pleasure to welcome you here, and we look forward to your presentation. >> thank you for the opportunity to be here today. america's only natural gas resources are the nation's economy and standard of living. it is essential that we ensure the safe production of these resources. this country is the global industry and will benefit from a

full understanding of the causes of the deepwater horizon incident. i'm confident that the commission's findings will enhance our goal to ensure all our nation's facilities are operated athe high standards of safety, so i am greatful for the chance to come before the commission to share in the integrity and risk management. many would say, especially now, that energy companies must make safety a top priority, but i believe that commitment to safety much run much deeper than simply bei a priority. a company's priorities can and do evolve over time depending on business contions and other factors. a commitment to safety, therefor should not be a priority, but a value, a value that shapes decision making all the time at every level. every company desires to have safe operations, but the desire

is to translate this into action. the answer is not found in writn rules, standards, and procedures. while they are important and necessary, they alone are not enough. the answer is ultimately found in a company's culture, the unwritten standards and norms that spe mind sets, attitudes, and behaviors. companies must develop a culture in which the value of safety is embedded in every level of the work force, reenforced, and upheld above all other considerations. i've been asked today to explain how exxon mobile approaches these systems in culture when it comes to safe operations and risk management. some day the evolution of exxon mobile safety culture back to the 1979 oil spill, and valdez was a low point in our history, a traumatic event with enormous

consequences for all involved, but it also served as a catalyst, a turning point prompting our management to reevalwait how -- reevaluate how we understand risk and safety. exxon mobile had been in business for more than 100 years, and we had always taken steps to maintain safety operations. we were proud of our safety record. believed as our safety ced stated that all accidents and injuries are preventable. like many companies, we worked to meet or exceed all standard, trained our employees, had met tricks that measured our success, but we did not have the comprehensive sismatic view of this aspect of our business that we have today. so in the early 1990s, exxon

mobile's management undertook what i considered to be a visionary approach, the goal to whollyeorganize the company, make safety of people, facilities, and the environment the center of everything we do. safety would come first, period. it was the beginning of a long journey for our company, and i should make it clear, this is a journey that we have not completed. we know we cannot rest or waiver from the goal o driving accidents and incidents to 0, and we're not there but we have made significant progress, and as we have learned from ts progress to be achieved, it had to come from within the company. we could not have government impose a safety culture on us or hire someone to do it for us. experts and consultants do provide a valuable service, but for an organization to change its culre, change must come from the inside out, not the outside in.

you cannot buy a culture of safetyff the shelf. you have to craft it yourself. we began. we began by creating the framework putting our safety commitment into action. today that framework is cald the operations integrity management system or oims for short. because oims is multifaceted, it's hard to describe briefly. here's the basics. oims i a rigorous set of ements designed to identify has -- hasards and risk, design, construction, and maintenance of facilities, emergency prepareness, management of change, assessment of performance, and reporting of accidents. we guide 80,000 employees as well as our third party

contractors around the world. over time, it has become embedded into every day wrork processes at all levels. through oims, exxon-mobile asures benchmarks and measures all aspects of our safety performance. it's structure and -- its structured are shared. one the greatest benefits is it enabled exxon-mobile a large organization operating across cultures to be of one mind when it comes to safety and risk management. i can visit a refinery, a lab, or a platform anywhere in the world and be on the same page as the local employees and contractors regarding safety practices and expectations. i want to stress that the contractors that we work with are embedded within our oims processes as well. we expect our contractors to be

knledgeable and con veer cant with our processes as with the employees. not every company has this expectation, but when everyone speaks the same language of safety, employees and contractors alike, everyone can work collaboratively and safely. that is why exxon-mobile measures its safety performance all the time down to every business level. we record not just our injuries, but we record our near misses, and our close calls. our goal is not just to analyze safety incidents after they happen, but identify risk and risky behaviors before they lead to a safety incident. the more elements of risk to be managed in an activity, the more frequently we test, measure, and analyze the safety approach in

that activity. more broadly, oims requires us to audit the health of the overall safety approach in all of our operating environments on a regular basis. importantly, these audits are performed not only by trained safety personnel, but by cross functional, cross regional teams drawn from all over our global organization. in this way, all employees are responsible for each other's safety. also, the knowledge employees gain by participating in these audits is taken home to their jobs and spread throughout the organization. yet, oims by itself is only one part of the equation. even the best safety systems are not fully effective unless they exist as a broader culture of safety withinhe people of the organization. while other energy companies use a lot of equipment, steel pipe to supeomputers, it is people

who bring this eipment to life, and people's behavior is heavily influenced by their culture. by instilling the value of safety for our employees, exxon-mobile strives to create a working enronment where safety is internalize, reenforced, and rewarded. the culture of safety starts with learship because leadership drives behavior and that drives culture. they set expectations, build structure, teaching others, and demonstrating stewardship. that is why the first element of oims is management, leadership, and accountability. exxon mobile managers are expected to lead the oims process by demonstrating a visible commitment to safety and operations integrity. in addition, safety leadership is a significant part of how a manager's overall performance is evaluated. as chairman and chief executive, i know that a commitment to

safety and operational integrity begins with me and the rest of the management team, but management alone should not and can want drive the -- cannot drive the safety culture. it must be embedded throughout the organization to flourish. therefore safety leadership at exxon-mobile comes not just from supervisors and managers, but from employees and contractors in channels formal and informal. our goal is not just to have employees comply with safety procedures. compliance can lead to complacency. we seek to go beyond compliance, to create a culture in which employeings not only meet the safety procedures, but they are challenging them so they can be improved where needed. i do not want anyone to think inside our outside our pride and

safety systems can provide safety. to get what we need in safety, continuous improvement is essential. in an industry like ours that operates 24/7 around the world, the need to manage risk never end. even the best framework is viewed as a work in pgress. developing a culture of safety therefore is not an event, but a journey. for exxon-mobile that began 20 years ago when weut our framework in place. on-embedded, we saw the culture changed and that improved performance. in turn, # we moved from implementing the system to improving it. that's when exxon-mobile's culture was really transformed. over the years i've seen people at all levels understand that our safety systems are put in place for them, that they wer about protecting them and their

co-worke and the public, and not about catching people doing the things wrong. part of that train formation is recognizing every employee's job involves some degree of risk management, even those who work in office settings. that is why oims extends even to administrative locations. when an organization reaches the point where everyone owns the system and believes in it, only then at that point, a culture of safety and operational integrity has been established that can be sustained. when it enters the hearts and minds of the people of the organization and becomes a very part of who we are. we often use the phrase of exxon-mobile nobody gets hurt to describe our safety objectives. some observers of our company question this. they say it can't be done. well, it can be done. weave operating units today that have gone years without a

injury. our challenges to sustain that performance where it's achieved and to replicate that performance across the organization. i have no doubt every single employee shares this goal. considering thatany of exxon-mobile's energy projects can span decades, achieving the goal of a self-sustaining energy culture means we have to be flexible and adaptable to changes in the operating environment. as a result, management of change is a key component of our oims system. our management of change processes are designed to ensure with any change in our business or operations, we recognize the change conditions, we actively identify the new changed risk, and we apply our risk safety and their consequences. risks are addressed, and the change is managed throug