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>> and that the national commission on the deepwater horizon oil spill continues with its fifth series of meetings, looking into last april's gulf of mexico oil rig explosion. it is a day to of this public hearing. today where it expecting remarks or regulators and scholars and experts on well drilling and operations. later this afternoon, time is set aside for public comment. we plan to bring that to you live also. during the explosion on april 20, in 11 people died, about 200 million gallons of crude oil spilled into the gulf of mexico. this is live coverage on c-span2.

[inaudible conversations] [inaudible conversations] [inaudible conversations] >> good morning, everybody, and welcome to day two of this, the fifth many of the national commission on the bp deepwater horizon oil spill and offshore drilling. i'm hereby calling this meeting to order. my name is chris smith and 90 designated federal official for this commission. i'm also the deputy assistant secretary at the united states department of energy. i will be guiding us through a busy day of panel today. before we proceed i would like

to familiarize everybody with a safety procedures. in case of emergency or fire, you will see the exits to my left, to your right. please proceed out to the left that up the escalators come and go be a security personnel that will escort you out to the street. so that's the procedure in case of emergency. we would also like to ask everybody to turn your blackberries, cell phones to vibrate or silent. the president astonished this bipartisan commission to examine the root causes of the bp deepwater oil disaster, and provide recommendations on how we can prevent future accidents offshore and mitigate their impact, should they occur. this committee is conducting its work, which has a high standard for and transparency. and as such today's hearing will be held here in this public forum and broadcast live via video feed. beforehand, -- beforehand of the

event over i would like to provide a quick summary of today's agenda. this morning we'll be hearing from a panel of experts on oil well drilling and operations, featuring panelists from by you petrophysics, shell energy resources, seldovia marine services and louisiana state university. we will break for lunch at 12:30, and at 1:00 we will reconvene with two panels on regulations featuring panelists from the pure of osha management regulation and enforcement, followed by a panel on industry safer -- safety culture featuring palis from the shell oil company and from exxon mobil. starting at 4:00 we'll be hearing wrapup comments from the commission's chief counsel, mr. fred bartlit. and a senior science engineering advisor, richard sears. following closing remarks are to co-chairs, there will be public comments made from 5:00 to 5:30.

in addition, any member of the public who is pushing to make a public comment to this commission may do so in writing via the committee's website, which is www.oilspillcommission.gov. again, that is www.oilspillcommission.gov. and at this point i would like to end the floor over to our to go chairman, co-chairman, senator bob graham and the honorable william reilly. >> thank you, chris. mr. chairman. >> good morning. presentations and examinations yesterday uncovered a suite of bad decisions. failed cement tests, premature removal of blood under balancing the well, a negative pressure test that failed but was judged as a success. apparent inattention, distraction, or misreading of a

key indicator that gas was rising toward the rig. our investigator team did not ascribe motive to any those decisions, and reported that they found no evidence that those flawed decisions were made to save money. they didn't rule out cost, just said they were prepared to attribute mercenary motives to man who made, who cannot speak for themselves, because they are not alive. but the story they told is ghastly. one bad call after another. whatever else we learned and saw yesterday is emphatically not the culture of safety on that rig. i referred to a culture of complacency yesterday, and speaking for myself, all three companies we heard from displayed it. and to me, the fact that each company is responsible for one

or more each courageously bad decisions, we are closing in on answer to the question i posed at the outset of yesterday's hearing, and that is, whether the horizon macondo disaster was a unique event, the result of some special challenges, and particular circumstances, or indicates something larger, a systemic problem in the oil and gas industry. bp, halliburton, and transocean are major respected companies operating throughout the gulf. and the evidence is that they are indeed of top to bottom reform. we are aware of what appeared to be a rushed to completion of the macondo well, and one must ask, where the drive came from that made people determined that they couldn't wait for sound cement, or for the right centralizers.

we know as safety culture must be led from the top, and permeate company. the commission is looking beyond the rig, and not just to yesterday in what happened on april 20, but to the months and years that preceded it. bp has been notoriously challenged on matters of process and safety. other companies may not be so challenged. and today we will hear from to whose reputation for safety and environmental protection are exemplary. they will tell us, i believe, that safety and efficiency reinforce one another, and that their safety cultures have contributed to their profitability. both companies and their safety and risk management systems have received extensive examination by the commission staff in meetings i have attended.

they are very impressive. nevertheless, their rigs have been shut down in the gulf this summer, just like those other companies because of the performance to which they had not been implicated, the performance of bp transocean and halliburton. this has led us and the commission to learn from the nuclear industry, which has an institute that promotes best practices, reinforces government regulation, and police is the laggards. so if yesterday we heard from the laggards, if yesterday we looked back, today we hope to learn from the leaders, and to look forward. and to look at companies which have learned from their own crises and disasters, and rose

to become standard barriers. thank you. >> thank you, mr. reilly. as co-chairman reilly has just said, today we will be focusing on the future, not the past. at the future is always influenced by our past experiences, and so will we be. yesterday, we had a very detailed description of the well drilling operation, as well as the details of intercompany decisions and how those decisions played out and contributed to the ultimate disaster. there was in the news reports of yesterday's hearing, a statement that i think was stated in too broad a term.

the statement was that there was no evidence that they were conscious decisions made to trade off safety for profit. i agree with that statement as it relates to those things that occurred on the oil well read itself. those men whose lives were going to be in the safety risk equation, there is serving no evidence that they degraded their own mortality. i think the larger question is the one that co-chairman reilly has just focused on, and that is the reality is there were a series of almost inexplicable failures in the hours leading up to the disaster. they were a series of actions which are difficult to explain in this environment, to just select one, the fact that there

were three different temporary abandonment plans adopted in the week before final execution of the plan is illustrative of the fact that the lack of consistent planning for safety. the problem here is that there was a culture that did not promote safety, and that culture failed. leaders did not take serious risks, risks serious enough. did not identify risks that proved to be fatal. today, we will be looking at the same issues as yesterday, but from a different perspective, including the perspective of somebody, those within the industry with the best reputations for an effective safety culture. i hope that in the course of

this, that we might have some new perspectives on what happened at macondo, what were the motivations that led to various decisions to be made. i might say one specific issue that i'm going to be interested in, is why was the date april 20 so, such a committed date? and there were multiple reasons why it would have seemed prudent to have delayed the final actions until various safety measures, some of which were within a few hours of completi completion, could have been available for consideration as to the wisdom of moving forward to the next step. that is just one of the questions which i hope we will get some additional intelligence

upon today. with that, we will turn to the first component of our program today, which is panel to comment experts on oil well drilling and operations. and for this presentation, mr. e. c. thomas, consulting petrophysicist and owner of bayou petrophysics. mr. thomas. also, mr. steve lewis of advanced drilling technology implementation engineer, seldovia marine services. mr. cichon rogers smith, associate professor, department of petroleum engineer at lsu,

and darryl bourgoyne director of louisiana director louisiana state university petroleum engineering research and technology transfer laboratory. mr. thomas? >> yes, sir. >> do you have an opening statement? >> commission, if i could for a moment. >> panel members here this morning, we also have charlie williams of the shell company, who will be answering questions today. is to give you a sense of what the format will be, this morning we're going to hear from five different deepwater and non-deepwater drilling experts in two separate panels. on various subjects relating to

well designed and deepwater drilling issues, generally, as well as macondo and the blowout. we will be splitting the panels into too. one in the first more recession which includes the individuals, commissioner graham has just introduced. and we will then have a second panel and a second morning session. while each of the expert is focused on a particular topic, we will be asking them to comment on other topics of various points during the presentation. and unlike yesterday, we expect the commissioners, if you have questions of any of these experts, to please go ahead and ask those questions. just to orient the commission, the topics for discussion today for the first morning session will be deepwater geology and formation issues at macondo. mr. thomas will be speaking principally to that issue. well design, generally, not specifically at macondo. mr. williams i believe will be

speaking to that issue. and then finally, drilling operations and implementation of well design. not only generally, but at macondo, mr. lewis will be speaking to the issue. in the second morning session, just to give you a preview, we will have a discussion, once again, with mr. lewis, on pre-cementing issues that you saw some of yesterday. we'll also be speaking with some other experts on the negative pressure test, temporary abandonment procedures. and, finally, we will be speaking with one of the experts on kit detection and response, both generally and at the macondo well. >> i will begin the process by asking the question of the experts that we have. we can switch over to my presentation here. again, we have dr. e.c. thomas, consulting petrophysicist.

yesterday to experience in the field. charlie williams, chief scientist for well engineering and production technology for shell, and steve lewis, four years of field experience in drilling operations in areas places that i want to start by talking a little bit about deepwater and what makes deepwater different, special, with mr. thomas. mr. thomas, what do you do for a living? >> i may consulting petrophysicist. >> and can you tell us all little bit about your experience in the oil industry? >> i worked as a research physicist, then management of that department, then i went to new orleans to be a field engineer and then i served as the leader of those sections, went ahead office training and taught petrophysics in both beginning, intermediate and

advanced sessions. and then went to head office to be a technical advisor to the vice president of technology. >> is your experience including deepwater experienced? >> yes, it does. >> i'm going to put up against the slide that we should yesterday, orienting people to what deepwater might actually mean. so do you agree generally with this picture of where the boundary of deepwater would be in the gulf? i'm not asking you to be sure about every specific, but is that the accepted generally accepted boundary line? >> it is generally accepted at 1000 feet of water. >> wended industries are moving to drill wells in deepwater? >> in the 1980s. >> we heard some suggestion in the media and elsewhere that one of the reasons that industry went to deepwater is because of concerns raised by environmentalist in shallow water. is that too in your the?

>> of saluting not. >> why did the industry go to deepwater? >> to put it simply, that's where the oil was. unique geological opportunities there. >> speaking of those unique geological opportunities, i'm wondering if there's anything that comes a tent with his opportunities, any challenges you face in deepwater? >> absolutely. the good thing is that we have high velocity and high permeability, but that carries with it then rocks that are weaker, and that we end up with a much narrower margin between the pore pressure gradient and the fracture gradient of those rocks. >> so am i right though that the narrow pore pressure in fracture gradient that you're talking about is some of the same, the same fracture that makes it so attractive? >> it certainly provides the

ability to have high reservoir energy, and, therefore, high flow rates from the wells. >> can you give me a sense, in order of magnitude level, of the different production from a deepwater well to a well inside that line? >> roughly is in the order of magnitude, say, from 2000 barrels a day, to 20,000 barrels a day. >> i'm going to move to a slide about the gradient at macondo. have you reviewed this chart or anything about the pore pressure at macondo? >> yes, i have. >> when you start drilling a well like macondo, do you know ahead of time with the pore pressure and fracture gradient will look like? >> we can only estimate it. >> so the numbers then change over the course of drilling the wells? >> yes, they do. >> how does that affect your

operations at the wells? >> we continually have to monitor all the signs that give us the clues as to well, we're going to be exceedingly fracture gradient, or not, being over pressured. and we have to stay within that window. >> and how there was the window in numerical terms at macondo? >> by the time they were at their final point, there was about 1.8 or 1.7 pounds per gallon muddy equivalent. >> and that's the difference between the pore pressure and the fracture gradient, am i correct? >> that's correct. >> i don't have -- many people who don't have a sense of whether that is a small number. is that a small number to you? >> it is a small number to make. >> what's the rule of some for what you would like to have? >> will come in general we would like it to be as large as mother nature can make it, but if we

can, we are happy to have at least two pounds per gallon separating the two. >> so what is having a 1.8 pounds per gallon differential mean to you in terms of the complexity of the situation you were dealing with? >> basically, they were getting very close to not being able to drill any further at all. >> we discussed an e-mail yesterday from mr. bobby bowden act at bp what he talked about a lot of these explaining the partners at the well, the addition to call total depth early and it was this it was this wanted as a drilling a hate any further would unnecessarily jeopardized the well bore. what does that mean to you? >> in this case i think he was referring to the fact that they had planned to make this well a producer, therefore, if they wanted to go any further, to their stated td, then they would have to set a lineup that if

they set a headliner at this stage, then they would not have been able to have had the well bore size to make the pursuit they wish to have. >> another issue we talked about yesterday was lost returns. on april 3, at this well. are lost returns an indication of a narrow pore pressure and fracture gradient? >> it is one, yes. >> and how did they respond to the loss return problem here at macondo? >> as you can see, when we say lost returns, we are talking about that reservoir is taking mud, and to offset that, we inject materials that try to plug that up. and not only do they use regular

lost circulation materials, but they use some very advanced polymer materials to try to plug it. >> and is that a typical approach or appropriate approach? >> sure. yes, it is. >> does it get you back to the original state before you had a fracture or a loss return? >> generally, no. once you have parted the greens, then it makes it easier to do it the second time. >> so would it be fair to say then that something like a band-aid, you doing this but your never going to be quite where you were before? >> yes, that's a good analogy. >> but nevertheless, having that fix in place, is that sufficient to allow you to continue to drill? >> yes, it is. >> do you have an opinion on whether the well was actually stable after they finished drilling a total depth, at least in your review of the materials? >> in my opinion, it was table.

they had managed to stay within that window. at td, they had a stable well for four days. and made several trips in between to remove debris from the well come and they did that without any incident. >> so when you say the well was stable at this point, does it mean that they have solved their problem and that from then on they would've been okay? >> well, they have solved that problem of getting down, but they could never ignore the fact that they are and a geological environment that had a very narrow pore pressure fracture gradient window. >> and does that mean, for example, i think about their process including cementing and running casings, those are issues they would have to -- >> they would be paramount. >> and how does having a narrow pore pressure fracture gradient window a fact that cement job? >> they would have to pay

particular attention that they were not exceed the fracture gradient due to the weight of the cement. >> and is that why they chose come in your view, to use lighter foam cement in this job? >> i believe that's so. spent and you heard me describe yesterday that cement job based on e-mails and reports of bp, a complex cement job, and a complex well bore. have you evaluated in your professional experience wells that were as complicated as macondo? >> yes, i have. >> where they drilled safely? >> yes, they were. >> and what is it that made macondo complicated that was similar to those of the wells? >> just repeat myself, it is really the very narrow margin between pore pressure and fracture gradient, and the very high deliverability of these blocks. so it's a unique geological environment really spent and on the other wells were describing

that were drilled safely, that were drilled safely, they were able to in there'll, they were able to negotiate these narrow pore pressure and fracture gradient concerns? >> yes. if you pay attention to the drilling you can certainly do that. >> if people want to go to the gulf of mexico to get more oil, where do they have to go? >> they're going to have to go to deepwater. >> is that because of the podunk issue that you described earlier that they produce more? >> that's just about the only unfilled acreage that is left. >> is inevitable when you go to deepwater you will have to face these narrow pore pressure and fracture gradient concerned. >> yes is, because of the geological environment that has put the rocks in that particular location. >> given that environment, does that necessarily drive you to more complicated well design wells? >> yes, it does. >> thank you, mr. thomas. i want to turn out to mr. charlie williams from shell. let me first ask charlie, what do you do for a living for sean?

>> on the chief scientist for well engineering and production technology, and i'm a technical consultant and technical advise her and advise on different major projects, and also do special technical projects and i also advise. >> at shell, do you guys also a similar view about the relative productivity at deepwater wells versus shelf wells? >> yes. >> do you consider deepwater to be a more challenging drilling environment than shallow water? >> in general. i mean, you can have challenging wells in either environment, but in general, you know, there's a unique challenges in deepwater. >> would you agree with mr. thomas' view that narrow pore pressure and fracture gradient is one of the challenges of? >> that's correct. >> what are some of the other challenges deepwater proposes? >> there's many, but certainly one aspect is simply because it's in deepwater. so you have currents, you have

water depth, you have conditions you have to design for big so you can do up with these dynamically positioned anchors or rigs, and it's a challenge to have the technology to do all of that correctly. it's a challenge because you have this long riser. you need to i think you need to deepwater. anand in most wells businesses d that we talk about that is so important to have in the well and maintained correctly, now exist not only in the well but in the riser. so managing, you know, but in the riser and managing that total system, total circulated system is different simply because you have 10,000 feet, or 2000 feet of riser to contend with. and then, of course, you have your blowout preventers on the ocean floor, quite a depth down. they have to do all of the work on those remotely with rovs. you have to, you know, if you want to do maintenance or

repairs, you have to pull those back out of the water over a considerable distance in the water depth. there are many challenges like that that aren't of course based on a shallow water or on short. >> and doesn't show therefore use different size teams ago to deepwater? >> yes. >> how many people typically professionals working to deepwater will? >> so typically you have a three drilling engineers. by the lead going into, to drilling engineers. you have the people that are going to be operationally on the rig, so usually six operations staff that are involved in planning the wells also. and you have any order of six to 10 subsurface people. so that would be better physical people, reservoir engineers, geophysicist, geologist and all the people that look at what the prospect looks like and actually help determine the location of where you're going to do. then you will be part-time people, technical people to come

in as well. >> in a typical team with the operating staff, you know, would be as much as 20 answered at least 15. >> and how long does it take this kind of a team to put together a plan to drill a deepwater will? >> it depends on what you're doing an exploration well where you have to do, you don't know as much about the environment and you have to determine those things in advance versus a development well where you already know a lot about the geology. but to answer the question, it's anywhere from eight months to as much as, you know, i hear, depending on the complexity. >> during the course of that time is the norm of the design would change? >> yes. >> and how does shell usually or how is your best practice the process of change those designs during the course of the process

of? >> is a defined collaborative process. as i mentioned the team is large, and so we bring in all these technical groups, including the operational people that will be involved in drilling the well. and they work, start out on what's the location of the wilner going to drill and start looking at all the complexities and challenges that we have to deal with in various designs that they really hold that design over this period we talked about come and see if you could change the position of the well, or you could change other aspects of the design, and would it be more optimum and could be better meet the challenges. and that involves over that whole period of time, and then at different stages in their we had even bigger reviews. and we will have a review, you know, recently i was we involved in a review. we brought in the entire contract rig crew, and they also looked at the well design. and so we looked for the maximum collaborative cooperative

environment. at the end of that process when we had chosen the design, then it's approved, and then it becomes the design that was used to execute the well. >> so you do involve the rig crew then at least sometimes in the design process? >> correct. >> how about the well site leaders? >> correct. >> and when you make changes, i assume there are some kind of changes that don't require this kind of process? >> yes. justice dr. thomas mentioned, as you're executing the well there are certain things you don't know exactly, for instance, the good predicting pore pressure but it may be different as you drill. and so as these things occur, you know, there are certain operational things that you do, like might change the mud weight two-tenths of a pound, go up or down, and there are certain routine operational changes. those made by the shell drill site leader, makes those kinds of operational changes that if

we make a change to the design basis of the, what we call the prognosis, that goes through the same approval process as a proven the original pron. agosta the same kind of consultation, back with the people in the office that did the original approval. and that people in our we note operating centers are also consulted when changes are made. and any particular, if it's changes that involve changing the head, so i guess we go back into these approvals the same way you approved the original design. >> would change the procedures for temperate abandonment process fall on one side or the other of the spectrum of major and minor? >> well, it would be particularly read doing those kinds of changes because it involves establishing barriers and one of our key design philosophies is maintaining the barriers and will. that includes the various they going to the temporary

abandonment. >> i want to put up a slide here that i think you gave me. and move the discussion over a little bit to to the trapped annuals issue i described yesterday. do we have the laser pointer somewhere? you can always count on her chief scientist to have a laser pointer. [laughter] it's a little dim but i think it will work for purposes of illustrating. the well we have, the well drawn we had which was very simple by drawing, doesn't show a trap and is in a deepwater drilling? >> that whitespace that is is above the cement and between the two cross-sections of white. >> so it's that white section in there, and this is the inside of

the well bore come and then the space outside between inside casing and the next for the outside casing, is that right? >> yes. >> thank you. so it's the space writer, correct? and here we are illustrated this is the well head, here is the mud line, so this would be the ocean floor here, and this is the formation into which we are drilling. >> and the important feature is it is sealed at the bottom and sealed at the top. >> so we discussed a little bit yesterday the prospect of heeding this space up, and can you describe briefly what makes that space heat up when you're producing a deepwater well like this? >> yes. the temperature in the zone you are producing, there's a temperature gradient that increases with depth like the pressure gradient. so that the heat in his own you're producing the temperature is hard. when you put the well of production, it's bringing up this hot production relatively high production.

and then the heat is transferred from that hot production into all of these two dealers that are on the outside of the well. and so it heats up this space along with everything else. >> so any get well because of whether it is in deep water, can have been annular pressure build up issued? >> correct. and what's unique to deepwater is your ability to control that pressure because of the seal that is in the well had housing. >> we talked a little yesterday, you may have seen about some of the methods for controlling this annular pressure build up. our burst discs one of those methods of? >> correct. >> and what do they actually do functionally? >> the first disc, they took a whole in the casing. and in that the service desk and the thickness and shape of that disc is designed to failed passionate fellow at a certain pressure and to relieve the pressure to the next outer

string. >> so it would be a whole functioning, in this casing has? >> yes. >> are there any drawbacks of using that kind of approach to managing any pressure build a? >> you know, there's advantages and disadvantages to all of the techniques. one of the complications with using first disc is that you are limited pressure in the casing is then limited to the burst discs. so can you have a higher pressure in that casing, then you know you delimited by the burst disc, not by the design rating in the casing which was higher than the burst disc. >> and why might you want to have a higher pressure in that casing? >> you know, if you have certain kinds of problems on the well where you wanted to circulate out, for instance, pressure that gotten in there and you want to circulate that out and re- kill the annuals or refill the annulus with the control fluid,

you could be limited by what pressure the burst disc. >> so burst discs are one pressure -- methods. are there other methods of the with it as well? >> the other techniques involve a limiting amount of heat that is transferred. to one of the very common ones is to insulated two beings so the two being that goes inside this final casing would be insulated. and that would allow the heat to travel with the production and limit the heat transfer to this annulus and thus the pressure build up. another possibility is putting an insulating fluids into that limit the heat transfer, and also you can put in different kinds of fluids and materials that have more compressibility than a liquid. >> in this space you should put in a compressible material? >> correct. >> going to a different issue, i wanted to talk about the choice

between using long strings and liars in deep well. you often have to make that choice between using a line and a long string? >> yes, it's accommodation. we use both long strings, fighters and tie back. the choice is, like all the other design choices you make on the well, it depends upon many factors, but in particular it depends on the uniqueness and the unique characteristics of the particular well that you're designing for. and some of the considerations are things like how long it would take you to run a long string versus a liner, compared to the condition of the well at the bottom of the hole, and whether certain things occurred on the bottom hole condition. you know, whether you have high confidence that you can get a long string run all the way to the bottom of the whole, because you know, you have to install the this on the top of a long string and you want that specs

are have to get all the way down to the bottom of the hole. >> you want to anger to be in the right place. and sometimes you want to be able to roll take -- rotate the price because of your decide that it's difficult to rotate a long string. string. to be easier to rotate a liner. >> what is that? >> it really turkey lies is the cement and certain cases can make this a bit more because it essentially a version of mixing down home. >> so that sounds like it's an issue about cementing. are there other issues about cementing a long string versus cementing a line of? >> the other key thing you look at in making this choice, and other geometry consideration because you surge that the cement down, you know, through whatever you're running the whole. if you run the long string or if you run the line it will go to your drill string and you lie when you circulate it. and just the size and spaces affects the pressures that you circulate out.

so you do look at that. but back to your question about the cement, if you have concerns that you might lose returned or partially lose returned string for cement job, the thing about a liner is that you can reestablish your barrier by putting a mechanical seen device or multiple mechanical sealing device on top of the letter. or squeeze will because we cementing which would be forcing cement down from the top of the liner. and this, the procedure is sometimes, in my opinion, more effective than perforating holes in the pipe which would be your other alternative. even though it is done both ways. >> would you saving in general it's a situation where you have a tough cementing situation to the formation is easy to cement a line in than a long string? >> if you're concerned that you will lose returned or might lose returned when you're cementing,

or running the liner, in my view, more straightforward on reestablishing the barriers. >> speaking of barriers i want to ask you about the barriers that use during temporary abandonment phase is of a well. in your view, when you temporary advantage and welcome what kind of barriers can you leave in place? what should you leave in place? >> well, typically in wells, typically in wells in deepwater, you know, our procedure would be to have a plug near the bottom. and when we say a plug, we normally set a mechanical plug with cement. and we would put that close to the bottom of the well, in particular we might want to put that if we have a liner top, put that above the liner top. and then we would put another one that's at an intermediate depth, and they would always have one at the service. one of the intermediate depth

would also have a mechanical device plus cement. the one at the surface would have a resin type plug. and also cement again. so it normally, you know, in our temperate abandonment feature, and for america procedures have 3.6 sometimes it may be as many as five logs depending on what you want to isolate. >> you have as many as five logs? >> a more typical with three. >> you spoke briefly, i want to inform the commissioners on this about the mechanical plug and the other partner can you explain the difference between those? >> i think people have seen in the diagrams, about running a packer or bridge plug. i think it is been referred to. these are not quite exactly the same, but for practical purposes it will be similar to what is called a bridge plug. so it would be a device that has slips on that bite into the casing and hold it in place, and then has a metallic mandrel

inside it, and it allows you to the cement below it and then you can close, there's an internal valve and you can put cement above it. >> doesn't rely on cement to achieve a barrier? >> no. you actually effectively have to, because you have a mechanical barrier also pressure seal in addition to the cement. >> doesn't make it easier to use the cement plug as well? >> yeah, it gives you a positive placement of your plug because you can put your top cement on top of this device, this mechanical device. so where it is placed, you know, you know exactly where it is placed in exactly the dimensions of it spent can you please mechanical plugs using mod? >> yes. >> can you placed cement box in my? >> yes. >> do have a few where the cement plugs can be set in synthetic oil based logs? >> yes. >> is as good as putting them in sea water? >> you know, you have to worry about, you have to be concerned

about spaces. it's done routinely in both. >> so to explain that, how do you in your view used a cement plug safely and since i -- synthetic oil based logs? >> you would want to have a space or between cement and the sense that it oil based mud to avoid the mixing. but it's routinely done on primary cementing and similarly, you can routinely do it when you place these plugs. common operation that successful. >> what's the advantage of leaving the mud in the well bore as a temporary? >> well, when your temporary abandoning the well obviously it's never out of balance during this entire september and abandonment procedures. so you have, you leave that to wait much in there, all of these operations you do, the well is under control just by virtue of to kill weight mud in there?

>> we've heard a lot, and i want to sort of move back to a given point that relates, you heard a lot yesterday, maybe did a lot yesterday about negative test procedures. do you consider a negative test procedures to be an important test to the well? >> i do. >> do you do it on every well before you had the temperate abandonment? >> no. >> no. what kind of wells do not do it on? >> well, you know, our common practice on a typical deepwater well where we drilled this single well with a floater, we do the temporary, you know, we do this temporary abandonment, and then we leave the kill weight mud in the well and the plugs in the well. we come back for the completion and drill out these plugs. and we do all of our displays and testing at that point in time. we test the plugs, but doing things like under ballast testing, we do later in the completion face. so we do it full of the kill

weight mud specs are you are leaving the well overbalanced in the temperate abandoning face, greg? >> correct. that's our design choice. >> if you are primary cement job fails in the kind of situation, what's the effect of having a primary cement job figure? >> if it happened or you're a temperate abandonment, the kill weight mud would keep the well under control. >> thanks, mr. williams. i'm going to move on now to mr. lewis and asking a few questions. mr. williams was kind of to come to us from shell to explain some tactical areas in which he is highly experienced, but he has not reviewed the details of the macondo well design of the macondo process. mr. lewis, by contrast was asked to look at precisely some of those issues. mr. lewis, what materials relevant to the macondo well design have you reviewed? >> i have reviewed the complete

sequence of drilling plans that were developed internally for this well, starting with the flange in 2009, before the marianas moved off of the well, continuing through the final plans for the temporary abandonment and the internal operations notes that were sent back and forth between the rig, and the office in town for those modifications. i've also reviewed the habitations or permit to go, for the applications for modifications that was abated to the mms. and i have reviewed the bp incident reports, specifically with emphasis on their review of the casing design for the original well plan.

i did that because that is the best access to the design, basis of design information that i can find. i've also reviewed the daily drilling reports, but primarily in the ddr review, concentrated on the last months of the well, with special emphasis on the last two weeks. >> based on your view, do you feel familiar with the process of the design of macondo well? >> i'm very familiar with the documentation of that design. i have some insight into the process, because the organization that mr. williams here described is similar to many that i have functioned in, and the basic philosophy of design as a circular process where one comes up with an initial design, the value which

the application of that design on the overall objectives of the well, are consistent to the industry. so yes, i would say i have an understanding. >> and looking specifically at the design choices that they made, is it fair to say, would you agree with charlie wiliams i should say, that there are lots of in pressure built like a? >> yes, there are. >> and were burst disc one of the methods? >> yes. the dp design of this well includes worst disk. >> in your view what impact do burst discs have on the function of the well overall? >> as mr. williams indicated, the first discs essentially be rate the pressure capacity of that string of casing. and if nothing goes wrong, that's not a problem. but if you find yourself in a scenario where you have an unexpected or suspected even

ingress of pressure into that angelos, actually either annulus that piece of casing is exposed to, you then have to rethink all of your actions at the lower pressure rating at the burst disc as opposed to pressure rating of that string of casing. operationally, the burst discs aren't a problem, if nothing goes wrong. >> so good burst discs have an impact on the way that you contain wells if something does go wrong? >> absolutely. >> are you going with the of protective casing any deepwater well such as this been? i believe i protective casing you're referring to what i call an intermediate casing, but yes, i understand that concept. and that basically is, that by design, your last string of casing before your production casing would be a long string going from just above your

production zone all the way back to your wellhead without liners hung in that string. >> what's the value of that protective casing? >> it gives you a more continuous pressure rating through that interval, and it eliminates the possibilities of failures at locations such as liner hangers. >> was there any education in your view that bp used a protective casing at macondo? >> no, and this design there was not what we would call a protective casing in that definition. >> you also heard, you heard mr. williams described his practice of leaving wells overbalance when you temporary abandoned mine. having reviewed the progress of the macondo well, was bp planning to leave the well overbalanced? >> no, they were not. >> is there any downside to

using the kill weight mud approach to overbalance a well as was described? >> there's a operational downside, no. there is a requirement for time and materials to accomplish that. >> is there any upside to leading a well underbalanced? >> in my mind, there's an extreme upside, in that you have the basic laws of physics then controlling that well for you as opposed to a mechanical. you are either statically overbalanced and you never bring the well underbalanced that it cannot float. >> i asked if there any advantage of leaving the well under ballast that am i correct passionate. [inaudible] >> no. none whatsoever. >> you also heard mr. williams described a number of plugs, mechanical and cement plugs he would typically use in a well, a deepwater well. how many plugs get bp -- bp used

to use before it abandoned the wealth? >> the design called for four. >> could have used more cement plugs in this will? >> yes, they could have. >> was that any operational downside to adding mechanical plugs or cement plugs in this will? >> the only operational downside becomes once again, time and materials. and then time and materials required to remove those floats when one returns to complete the well. >> i want to move over to talk all of it about well design. when you in your practice first design a will, how much detail do you put into the original initial well design? >> it's my thing that a well design needs to include as much detail as is technically as possible. the first thing one needs to define is what the well is going to accomplish. that tell you what the basic

well should look like or whether it's an expression well or at production well. and in each element of that wealth needs to go through a complete design cycle, going into the next element with complete design cycle that goes back and checks the application of that design, both on the previous abortion and the future portion of the well. so what should be, into my experience, a pretty complete engineering process. >> when you place some unplanned events in the case of a well, how does that affect your design? >> that implies the necessity to go back and completely we evaluate the design, both the portion of the well that is already been completed and what you had in mind for contingencies for compensating for those unplanned events. but you should go through that same design cycle of looking from top to bottom, and looking at the entire lifecycle of the well, and considering the

implications of those decisions. >> are you suggesting if you haven't unplanned event and you have to do with a contingency, you are partially redesigned the well from scratch it's because you're redesigning the well from that point forward, but back checking against the previous design to make sure that those two are compatible. >> is having an unplanned event like lost returns for example, impose any, make any changes to the way you think the rig crew should be operating as well in the field of? >> and unplanned event should reinforce the level of vigilance on the rig, and hopefully move people into thinking, looking ahead, thinking about what the next steps in the procedure are going to be. and making sure that they have the right equipment and the right personnel lined up to accomplish those steps. and making sure that they have the right equipment and the

right personnel lined up to accomplish those steps. nosteps. and making sure that they have the right equipment and the right personnel lined up to accomplish those steps. no, rather than focusing you on solving that the media problem, should also broaden your scope of vision to looking towards the future of that well. u. . >> and see if from the other aspects of their interest in the well you have done anything that would compromise their efforts. >> and how about operationally or logistically?

>> operational logistics is half, at least, of drilling oil, and by that i mean you have to have the right equipment and the right people there at the right time to do the job. unplanned events imply an immediate need to reevaluate your entire logistic and material supply structure. >> so stepping back to look at macondo now, in your view having reviewed the initial design of the macondo well, was it adequately detailed? >> the initial design was adequately detailed for an exploration well. >> and how about the later design you saw as they evolved? >> i felt that they were deficient in detail, especially in light of the fact that by that point it had become fairly apart that this well was -- apparent that this well was going to be completed as a production well. >> and if you had additional detail, what would that have helped to do?

>> it would have helped, i believe, focus both the field and the office staff on the difficult and almost marginal nature of what they were attempting to accomplish here, brought in a heightened level of vigilance, allowed for proper timing to mobilize equipment and materials and possibly allowed further discussion of options. >> and that further discussion you're talking about, you heard mr. williams describe the process of involving the well site leaders and the rig crew in those design discussions. is that your view of how things should be done? >> absolutely. it's my feeling that the people executing that plan should understand the basis of design that it came from and be able to

suggest and input modifications if from their perspective and experience they're appropriate. >> and, again, in your view the subsequent design that bp did for this well, they include the kind of detail that would have allowed people in the field to think about those assumptions. >> this i do not believe they did. >> you heard yesterday from some of the explanations that i gave that bp didn't run a number of additional centralizers at one point because they believed or at least they didn't or believed they didn't have the right kind of centralizers available. having reviewed the process of the design at this point, was there enough time after bp chose to use the tapered long string to get enough centralizers of the proper kind? this >> if they had properly managed their materials acquisition process, yes, they had time to do that. >> so is it fair to say based on your comments about the value of design that the lack of centralizers could have been the result of an inadequate design process? >> at least the result of

inadequate communication about that design process, yes. >> you also heard me talk about the modeling of the cement design that was done and the decision not to rerun that model in the very last few days. is there any reason, in your view, not to rerun that model in the last few days before cementing the well? >> actually, in my view it's exactly the opposite. there's very many reasons to redo that design. >> now, in the last phase of the macondo well they were worried about the loss returns and the pressures in the bottom of the well, is that correct? >> that's absolutely true. >> in terms of well design, what are the different ways that you can keel with those -- deal with those kinds of bottom hole pressures? this. >> there are basically three elements that you can manipulate to adjust bottom hole pressure, and those are the weight of your fluids, the density of your fluids, the speed with which you

pump those fluids which controls the frictional pressure that that's producing and then you can adjust the geometry of the well bore through your design. >> so did you see evidence that bp was thinking,ing at least, about some of those things when they dealt with the bottom hole pressures that they had at macondo? >> actually, there's evidence that they thought about all those things. >> is it -- adjusting one of those things can influence the other things? this. >> definitely. it will have influence on the other aspects. >> and what happens, your review of the redesign process, is it proper to evaluate all those things at the same time? >> yes, absolutely. it's critical. this is an interdependent system. it's a machine, and if you change one cog in that machine, you have to consider whether or not it meshes with the others. >> and are there implications in the changing those cogs for the eventual value of the cement job at the bottom of the well?

this. >> yes, there are. >> you described, i think, an iterative design process here. i'm wondering if you think that design process also applies to the procedures that are used to build the well. >> they should, yes. >> and in particular, how about temporary abandonment procedures? >> those definitely should be designed to the same degree of rigor. >> the, some of the slides that sean showed the commission yesterday discussed through different temporary abandonment procedures that were used at macondo, and those three changes, i think, were all made within a week or so of the blowout. in your view, is that a lot of changes to be making in the final week? >> that's an unusual number of changes to make that close to the execution, a portion of a well that is, a, that critical and, b, been known to be a requirement for quite some time. >> so is there anything that would have prevented them from establishing the temporary abandonment procedures earlier

in the life of the well? >> no, there's not. >> do you think it would have helped if they had thought about it earlier? >> it would have allowed people to give the matter more thought in a less time-sensitive environment, and i think that would have been beneficial. >> and more generally, what are some of the other things that you consider essential at the end of a well activity to make sure that the process goes smoothly? >> well, a well is, is actually a pressure vessel. the design function is to control and contain the fluids that we are attempting to extract, and in the process especially of a temporary abandonment, but in every aspect of the well's construction process containment is paramount.

at the end of a well operation, there is, there are many things that need to be done in order to move forward, and there's also a natural human tendency to look towards the future operation and a tendency to lose focus on what we've just accomplished. it seems to me that at the end of a well it's even more important to maintain that vigilance and focus. >> have you ever worked on a well where you felt the vigilance or focus tapered off at the end of a well process? >> absolutely. >> is that just the way it works sometimes? >> it's the way it works sometimes, it's also an extremely variable thing. it can occur in any organization

that i've been associated with on the basis of the flow of both bad individual well operation and the other wells that the organization is dealing with at the same time. >> but i take it from your earlier comments that you would prefer a higher level of vigilance or at least a maintained high level of vigilance during those end-of-well procedures. >> yes, i would. >> what do you have to do with an organization to make sure you have that vigilance? >> you have to have, obviously, the resources in terms of manpower available. you need those same resources when you're designing a well, but you have to have the commitment to maintaining the mental focus on, on what you're doing. you have to have the commitment to paying attention to the present time as opposed to

worrying too much about the future. >> is there, in your view, sometimes a tendency for engineers to move on, think about the next job near the end of a well? >> yes, there is. it's a natural thing. >> mr. lewis, do you consider yourself an expert in if deepwater drilling? >> not really an expert in deepwater drilling. an expert in drilling generally, yes. >> have you drilled wells in deepwater? this. >> yes, i have. >> and have you followed at least the professional interest, the industry's move in the deepwater in the gulf of mexico and other -- >> yes, i have. >> what's your view of the industry's ability to deal with the risks and challenges presented by deepwater? this. >> i'm confident that the industry can meet those risks. >> and do you believe that the industry has done everything it can to meet those risks? >> no, i don't. i feel that the industry has done a very credible job, in

fact, a somewhat amazing job of being able to move into that environment and correctly, safely drill and complete a well. where i feel we have been remiss is in our development of the capability to respond to failures in that environment in a timely and safe manner. i also think that we have as an industry failed to cooperate internally in the development and adoption of appropriate best practice. there's, this is a very, very competitive industry, and more so than anything that i know of. of course, it's the one i know. [laughter] but the willingness to exchange

technical information is limited in that that technical information is a tool to use in our ultimate goal of, basically, making a profit for the owners. the need for that exchange of information, however, increases with the technical difficulty of our operations. the willingness as a group to define and adhere to best practices will require a acceptance across the industry spectrum of what is an acceptable level of risk. we've had one example described today of what i consider a very conservative but very appropriate abandonment procedure -- >> and that's the procedure mr. williams --

>> mr. williams' discussion there of multiple barriers and, more importantly, never leaving the well underbalanced. i have worked in areas where regulatorily you cannot leave a well underbalanced. >> what are some of those areas? >> well, alaska, for instance. state regulations require it. and in norway where i have abandoned wells, you're required to leave wells overbalanced there also. it's not required in our environment in the gulf of mexico by either practice, generally-accepted practice or regulation. so it's going to take, to my mind, an evolution of the industry to recognize and uniformly accept that the bar has to be raised here. we have to work to a higher standard of protection in this environment. >> if those things are done, do you think deepwater drills can be drilled safely? >> yes, i do. >> thank you, very much, mr. lewis. with that, i'll ask the commission to proceed with any questions it has for this panel.

>> chairman lowy? >> dr. thomas, are there, are there reservoirs with such concentrations, great concentrations of high pressure oil and gas that they just cannot be controlled when you tap into them? >> not to my knowledge. >> so any pressure situation can be managed successfully to ec tract hydro-- extract hydrocarbons? >> i'm not prepared to say any, but -- >> you've not seen any? >> not seen evidence of any. >> so there's no such thing as a well situation that, or a geological situation that poses too large a problem to even attempt to drill? this. >> not from a standpoint of pressure so far, but i can

imagine cases where there might be very narrow margins between poor pressure and fractured radiant such that they could not be drilled, but you would stop before you get there. >> and you would, you would be able to go some distance before you got there. you would not encounter that gradient problem initially right at the mud line, say, or at the formation, beginning of the formation? >> that is correct. >> do you, would you say anything about the formation of this well and the characteristics that it has and how it might compare to non-deepwater environments? we had a spill, a very long-lasting one, in mexico, and that was in something like 140, 50 feet of water some time ago.

is it your information that relatively shallow wells with formations relatively near the surface, also, can present just as many problems to manage as the deep ones? >> i have not reviewed that particular well, so i don't know the environment that they were drilling in. there are always possible geological complications that if one doesn't pay attention to, then all sorts of things can happen. but i think in the environment that we are in deep water, the geological environment while somewhat hostile yet at the same time is very uniform. >> do you have any observations

or impressions about alaska and the challenges that are presented there? that's relatively hallow water -- shallow water and relatively high formations and low pressure. is that, are there issues there that you think with respect to drilling are particularly difficult or challenging? >> i'm not an expert in alaska, sir. i do know that they have drilled wells successfully there without any incident. so i wouldn't expect there to be any problem, but i would have to defer to someone who's actually worked that environment. i have not. >> when you train people in industry, do you -- >> [inaudible] >> pardon me? >> i'm sorry to interrupt that we do have someone on the panel who has extensive experience in alaska, and without leaving your question, you might want to direct it to mr. lewis. >> fair enough. >> fair enough, right.

>> operationally below the portfolio o.p. -- b.o.p., alaskan drilling is not unusually hazardous. in fact, in many areas of the state it's fairly straightforward. the remote environment does imply some constraints. those can be managed through proper program planning and proper development of response technology. but on a subsurface basis, no, we were not in the areas that i have drilled which is actually extensive, i've drilled all over the state both onshore and offshore. it's not particularly tough country. >> i want to come back to an issue, i won't ask you, mr. williams, what you think about alaskan drilling. i think i know.

[laughter] when you, dr. thomas, when you train people in industry, when you train them to drill wells, do you, do you highlight or establish routine responses or protocols for certain kinds of experiences that they might encounter? do you teach them, for example, about how to recognize a kick in the system just to cite one example? and i wonder if there are others. >> i'm afraid i'm going to have to defer simply because i train in petro physics, i do not train -- >> in operations. >> -- people in drilling. so if someone else would like to answer that, i think they'd be more qualified than i would. >> okay. no further questions. >> are there other questions? >> yes.

>> [inaudible] >> thank you to the panel for providing additional insight for us this morning. i sincerely appreciate it. i found it very useful in the putting into perspective some of the things we heard yesterday, so thank you very much. i direct this question to mr. lewis, but if others on the panel wish to address it, that would be fine. yesterday we heard many things that raised questions that were not directly answered, but of all of them the two mysteries that were described i'd like to put before you and ask you if you have opinions about them. the first mystery was why in the world bp changed its temporary abandonment plan three times in the last week and what implications that had for safety. and secondly, why the experienced trilling crew and all of the others -- drilling crew and all of the others who were on this rig did not see the pattern of anomalies one after

another after another after another to get to that heightened sense of concern that they should have had? i know it's easy in retrospect, but mr. bartlit laid out a dozen things that should have put people on high alert, the final the negative pressure test which, obviously, failed but was declared positive. in retrospect, one has to sort of ask for both of these mysteries were they being driven by a sense of we're in a hurry, we have to finish this job, let's get on with it clouding one's ability to adequately assess the risk and put a premium on safety? i mean, that's one plausible answer, perhaps there are others. and i would just ask you from your many years of experience, mr. lewis, on rigs and doing drilling, why else then a sense of let's get this job over with would drive people to change the

plan at the last minute given how important that plan was to the safety of this temporary abandonment and why else would the rig crew ignore all of these anomalies that should have put them on high alert? >> we were going to do this. i can speak both generically to the drilling command and control structure, and i can speak to a certain extent to bp in that i have worked for bp both as a well site leader and a drilling engineer. i am around bp continuously on the north slope of alaska. they dominate what goes on in

the industry there. and i have read a number of internal communications from both field level to fairly senior management from the last year inside the bp structure with respect to the macondo well. and i've been there and done this in terms of designing, drilling and finishing a well. your question as to the changes of the abandonment plan over time, the only explanation i have for that is that it's a detail of the plan that was not necessarily known to be required when they first started the well. this was an exploration well with a possible production

completion. my suspicion is that -- well, it's not my suspicion, it's my belief that that detail was left unattended to probably due to the lack of availability of mental resources, engineering time. until it became apparent that it was going to happen, and then there was what i would have to describe as scrambling to catch up on that design. that opinion is based largely on the documents that i see and the fact that there was no, no real detail of abandonment in the initial plans. and then the -- thank you. thank you very much.

the final plans and the operations note while the engineering may have been adequate in those, the operational detail, to my mind, was totally deficient. what was sent to the rig did not include a procedure. it was simply accomplish these major steps however you feel like you want to. that's, that's totally inadequate in this environment. the only thing i can attribute that to is lack of engineering resources and lack of command and control of the process. process control breakdown. the question of why the people in the field did not twig to this e wednesday of questionable events -- sequence of questionable events and raise flags is much more difficult to address in that many of those individuals were killed in the incident. and then other individuals whose

positions one would think would require that cognitive process have not been available for answering those questions. i know that there was pressure on this group of people to get done and move on. i have seen internal bp communication at senior management level inquiring as to whether or not the well was going to be done in time, whether or not the rig would be released in time. and by in time in this case they had commitments to wells' regulatory commitments that were required to maintain, in one case, a viable lease that

required well work. the rig was needed on those wells to protect the assets of that other piece. the -- whether or not that concern at senior management level was verbally communicated down to the people in the field i cannot say, but pressure to move, to make progress is actually inherent in the business, and it takes a spaded conscious management presence to counter that. as i mentioned, we're very competitive. trillioner -- drillers drill against each other. we want to be the fastest, best

driller there is. and our natural tendency is to want to be making progress. to that end, sometimes we focus too narrowly on the immediate step, and we don't step back and look. the complexity of these wells and this new -- i say new, in the last 20 years -- involvement of the design team and the field team together provides a check and balance against that tendency. as was said, none of these guys made the conscious decision that, okay, i'm going to do this because it's faster, but it's not as safe. i don't believe they did that. but the overall impetus to make progress and to, in some cases of design and execution, choose

a route that was quicker, that involved fewer steps, that part of it does come from management. so i can't tell you why they continued step after step after step to miss the point, to not go into high alert, to not go shutter down. we don't know what's going on here, we've got to get this figured out. i can't tell you that. but i can tell you that there is continuous pressure to move forward, to make progress. to get'er done. >> mr. lewis, i appreciate your candor and, i guess, for those of us who have never worked on a rig, we can only imagine all of the complexities of these things that are happening all at the same time as well as the pressure to get it done. what i am curious about and particularly because our commission's mission is to really think about what we can recommend that will change the

balance between the pressure to get it done and the pressure to do it right and be safe is i'm trying to think through what it is that could be required either of the industry by way of best practices, as you've described, or by government in terms of regulation that would up the ante on the safety equivalent si. you mentioned that in alaska and in norway you're required to leave wells overbalanced. obviously, that must be a regulation that doesn't apply in the gulf of mexico. do you think that would be helpful, that kind of thing. not necessarily just the overbalance, but that kind of additional requirement by government to put additional pressure on the industry to be able to assure the safety when these wells get closed down? this. >> i think there's a balancing point. i think that some of the mms regulations, i'm sorry, i'm

still stuck in the old terminology here. i'm not even sure i know the new acronym for the agency. [laughter] their regulations, i feel, are inadequately specific both in definition of the intent of some of them, but more importantly, in their continuous use of qualifications where they say or as the operator in their best judgment decides. an example is maximum anticipated surface pressure. it says you have to bring us a casing design and show us what the maximum anticipated surface pressure is, and then it never says anything about how you calculate the maximum anticipated surface pressure.

and there are an innumerable array of assumptions that you can use in that calculation which will drive that number from either total reservoir pressure or total formation fracture pressure to zero depending on how you want to play with the input. now, the regulation says that the mms will review your data and see if it's appropriate. the reality is that they have neither the staff, nor the tools, nor the financing to do that. if we're going to talk about increasing regulation, we need to talk first about increased financing and increased staffing and increased technical competence of the people who are charged with enforcing those regulations. i think that a very important part of today will be this afternoon when we hear from two of the major companies with respect to their safety cultures, and it might be interesting to ask those people how they feel about melding that

with a regulatory environment that together induces best practices. >> thank you. >> i was just going to add the comment on that. you know, i agree that, you know, we have to have a regulatory environment that has some requirements, obviously, some specific requirements. i think it also needs to be performance-based because, you know, i think that, you know, to deliver the kind of safety performance and industry performance that we want it has to be this integration of safety culture and, you know, and the specifics of safety. you have to have a safety culture of performance, and just like mr. lewis' discussion about drilling fast, you know, certainly, you know, one of the key things is optimally, you know, drilling. but as we, you know, all know if, you know, if you try and drill too fast, you end up having hole problems and lost returns and actually, you know,

it's not only effecting the safety, it actually then ultimately effect your efficiency. so i think it was mentioned earlier, i think chairman reilly mentioned it, you know, this, you know, good performance also is good safety and good safety culture. so i think it has to be a combination of those two things. >> mr. bosch. >> yes. mr. lewis, you indicated that one reason for the changing plans for the temporary abandonment within the last week might have been as a result of the lack of previous attention to converting this well, making sure this well was available for production well. when in the process of drilling this well was it determined that this would be left as a production well. >> well, that final decision would not have been made, would not have been finalized until

they had evaluated the logging data that was run after they td'd the well. however, i believe that there was a fair degree of confidence in their geophysical interpretation that it would be completed. the drilling of that section of the well would have given you your preliminary confirmation of that in that we are now essentially logging while drilling to a certain extent. however, the point of this is that the amount of time available from that decision point which was ten days, two weeks from the failure is totally inadequate to obtain the

materials necessary to achieve this abandonment, totally inadequate to achieve the materials to complete the well with. you're talking lead times here of months to sick or eight months -- six or eight months to a year for some of these items if you have not designed for them before that point in time, not only are you going to be rushed with the design, you're going to be running in circles trying to find stuff to do it. i may have lost the thrust of your question there. have i adequately covered that for you? i think you responded it was not until maybe two weeks prior to the incident that the determination, the information was available to make the determination that this would be a production well. and i think i got that from your your -- what youal said

there was one thing that was thrown into this design at the last minute, and that's the use of this excess loss circulation material as a spacer. that decision was a last minute change and was driven by a attempt to simplify a disposal issue that would have been considered a hazardous waste and required shoreside transportation and disposal if it had not been used in the manner that it was used.

>> was there, was there material suitable for use as a spacer that is a type of more readily available in use spacer on the rig? >> there most likely was. i would expect there to have been. normally, what you would have used is simply a vis cosfied fluid, possibly weighted. a standard procedure is to use a spacer that's about halfway between the fluid you're displacing and the other fluid in terms of density. your waiting materials, your vis cosfiers and your weight fluid all should have been available on the rig, yes. >> great, thank you. >> we're now going to take a ten-minute break. we'll reconvene at 10:48.

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[inaudible conversations] >> day two of this hearing looking into the bp macondo oil well explosion and spill underway today on this tuesday. commission is taking a short break right now, about 15 minutes. they've been hearing from industry experts and scholars who are offering insights on the accident. a little later today we'll hear from michael bromwich. he is the head of the agency that regulates the industry. starting things off today, the co-chairs, former senator bob graham and former epa chief william reilly offered these remarks. we'll show them to you right now during this break. >> good morning. >> presentations and examinations yesterday uncovered a sweep of bad decisions.

failed cement tests, premature removal of muds underbalancingeb the well, the negative pressure test that failed but was judgedt a success.c apparent inattention,on, distraction or misreading of a key indicator that gas wasr rising toward the rig.r our investigator team did not ascribe mote i have to any ofn those decisions -- motive to any of those decisions and reported that those flawed decisions werl made to save money.ey they didn't rule out cost, just said they weren't prepared tor attribute mercenary or motives to men who made -- who cannotnot speak for themselves because they are not alive.no but the story they told isth ghastly.e one bad call after another. whatever else we learned and saw yesterday is emphatically not aw culture of safety on that rig.

i referred to a culture ofe complacency yesterday, and speaking for myself all three companieses we heard from displayed it and to he the fact that one or more company made bad decisions, we're closing in this on the answer to the question of whether the horizonh macondo disaster was a unique event, the result of somef special challenges and particular circumstances or indicates something larger, a systemic problem in the oil and gas industry. bp, halliburton and transocean are major respected companies operating throughout the gulf,op and can the evidence is that they are -- and the evidence is that they are in need of t top-to-bottom reform. we are aware of what appeared tr

be a rush to completion at the macondo well, and one must ask where the drive came from that a made people determine that theye couldn't wait for sound cement or for the right centralizers.. we know a safety culture must be led from the top and permeate a company. the commission is looking beyond the i rig and not just to yesterday and what happened on april 20th, but to the months o andn years that preceded it. bp has been notoriously challenged on matters ofriou process, safety. other companies may not be so challenged, and today we will hear from two whose reputations for safety and environmental protection are exemplary. they will tell us, i believe,

that safety and efficiency reinforce one another, and that their safety cultures have contributed to their profitability. both companies and their safety and risk management systems hav received extensive examinationan by the commission staff in meetings i have attended. they are very impressive. nevertheless, their rigs have been shut down in the gulf this summer just like those of other companies.mpan because of the performance to which they had not been implicated. this has led the commission to learn from the nuclear industry which has an institute that promotes best practices, reinforces government regulatioc and polices the laggards. so if yesterday we heard from the laggards, if yesterday we

looked back, today we hope to learn from the leaders and to look forward. and tolo look at companies whico have learned from their own crises and disasters and rose to become standard bearers. thank you. >> many thank you, mr. reilly. as co-chairman reilly has just said, today we are going to be focusing on the future, not the past. but the future is always influenced by our past experiences and so will we be. yesterday we had a very detailee description of the well-drilling operation as well as the details of intercompany decisions and how those decisions played out and contributed to the ultimatep

disaster. there was a in the news reports of yesterday's hearing a statement that i think was stated in too broad a term. the statement was that there was no evidence that there were conscious decisions made toev trade off safety for profit. i agree with that statement asr it relates to those ting things that occurred on the oil welle rig itself.el those men whose lives were goin to be in the safety risk equation. there's certainly no evidence that they degraded their own mortality. i think the larger question is the one that co-chairman reilly has just focused on, and that is the reality is there were a series of almost inexplicable

failures in the hours leading up to the disaster. there were a series of actions which are difficult to explain in this environment. to just select one, the fact that there were three different temporary abandonment plans adopted in the week before the final execution of the plan is illustrative of the fact that,e of the lack of consistent planning for safety.pl the problem here is that there was a culture that did not promote safety, and that cultur failed. leaders did not take seriousle risks seriously enough, did not identify risks that proved to be fatal. today we will be looking at the same issues as yesterday buta from a different perspective

including the perspective of some of the, those within the industry with the best reputations for an effective safety culture. i hope that in the course of this we might have some new perspectives on what happened at macondo, what, what were the motivations that led to various decisions to be made.s de i might say one specific issue that i'm going to be interested in is why was the date, april 20th, so, such a committed date? there were multiple reasons why it would have seemed prudent to have delayed the final actions until various safety measures -a some of which were within a few hours of completion -- could

have been available formple consideration as to the wisdomn of moving forward with the next step. that is just one of the questions which i hope we'll ges some additional intelligence upon today. [inaudible conversations] >> opening statements from the co-chairs of president obama's commission looking into the oil pill in the gulf of mexico. -- spill in the gulf of mexico. commission members taking their first break of today's session. this should last just a couple more minutes. we are expecting more from the panel you heard from earlier today. after lunch at about 12:30, there'll be discussions on regulation of offshore drilling and setting safety standards for the drilling industry. and at about 5:00 the public will be invited to offer comment for about half an hour. while we wait for the hearing to

reconvene, we'll quickly turn to a congressional transition event that happened earlier today. an event that happened on capitol hill. more than 90 soon-to-be members of the house are arriving here in washington this weekend for freshman orientation, and head of them is the gop transition team getting members of the gop ready to begin the new term next year. a short time ago the 21 members of the team held a photo op for the media on capitol hill. it's led by congressman greg walden. >> all right, there we go, there we go. we're ready to go. okay. first of all, i want to thank all of you for coming in today. as you can see, we have a terrific transition team. we met last night for a couple of hours, we'll meet most of today. our goal is to look at how we can make the u.s. house of representatives more open, more transparent, more accessible to the american people, the public, the press and us in terms of how to improve legislative policy.

how we can get to job number one which is creating jobs, and how we can get after reducing deficit spending. it is really important that we get the input from all of our members and a broad cross-section of our conference. we'll also be reaching out to other members of the other party, and we'll be reaching out to the staff around here to find out from them how we can run this place more efficiently to cut costs. as the old small business owner in me, i'm going to look for every savings and so is our team, how we can make this a more efficient institution and how we can reduce our costs, improve our operations, make them more transparent and accountable. it's essential. we've got the people's business to do, and the people have the right to watch that business being done. so we, we've got a lot of work ahead of us. we had a good session last night, and we're going to break down into work groups in this a few minutes and really begin to trillion down. next week when the entire republican conference is here, they'll have an opportunity to weigh in and give us their

input, and there'll be further work group sessions so that they have quality time to give us our advice. as you know, we've got well over 80 members that will be new to our conference coming here. a lot of them bring a lot of energy, intelligence and experience that we want to incorporate into how we rewrite the rules of the house and the rules of the republican conference. with that, let me stop. i think we've got time for a couple of questions. >> mr. walden? >> [inaudible] how important is it for the republican leadership presenting their ideas -- [inaudible] >> it's essential to listen to all the members. remember, we all stood for election. we were all out in the same atmospherics and environment. but i'll tell you what, we have some dynamic young leaders that are coming in to our conference, and you bet we're listening to them because they're bringing the message that we heard from americans, and a lot of what we heard from americans is already reflected in the our pledge that we intend to uphold and keep

faithfully. >> first impressions from some of the new members how the meeting is going, do you feel like your voice is being heard? [inaudible] >> sure. this is an important opportunity for us as members of this new class to be at the table moving forward as to what this congress looks like and, of course, transparency and accountability as being number one focus right now -- [inaudible] >> minority outreach for the republican party. >> i think it's important for us to realize that the best outreach for minorities is to look at the overall conscious of america and realize that we all go together. the water's rising, all ships have a better view of the future, so for me it's always been about -- [inaudible] encompasses all groups with no exclusions and to the extent we continue to do that, we will lead america in where we're going. >> i know in 1994 there was a transition team, mr. nussle -- [inaudible]

what were some of the things that you could learn from -- [inaudible] they've told you didn't do it that way -- [inaudible] >> you know, i think a couple of things that are important. to sweat the small stuff. at the end of the day, the small stuff matters. it matters to how this institution operates, it matters to how the public sees this institution, it's very important to get deep into the weeds, make sure you get it right. i think the other thing that's very important, the message that came from jim, was do unto others the way you'd want to be treated. treat others the way you want to be treated. and i think that's really important to restoring some confidence in this institution to make it the best deliberative legislative body on the planet is by allowing everybody to participate regardless of your party in a, in a constructive way where we can harness their energy and ideas too, keeping our principles and pledge, of course, but certainly making sure they have the opportunity to be full participants. they came here with brains, they

shouldn't be parked at the door just because they have a different party label. too often the decisions around here have been made at the highest levels excluding the rank and file members of both parties. we need everybody pulling together to try and solve these huge problems our country faces. we've got to figure out a jobs strategy that works to get americans back to work in the private sector. we're all going to have to work together to reduce the reckless spending that's gone on around here, and i think we can find good participation. i met yesterday with the head of the transition for the democrats, brian baird was in to see me, he's got some great ideas about reform. he was a real leader in the 72-hour effort we tried to get done in the last -- well, in this congress. so we're going to be reaching out. >> [inaudible] how it came about, how you -- [inaudible] >> you know, i'd probably defer that to the leader, mr. boehner. but i can tell you that, let's

face it, you've got 80 incoming freshman members. they're bringing a lot of energy, enthusiasm and ability to our conference. we want them at the leadership table, and they will be represented effectively and forcefully by whomever they choose. >> thank you! >> thank you. >> thank you, everyone. >> you can learn more about the transition team at our web site, c-span.org. we'll go back live, now, for more from the public hearing of the deepwater horizon oil spill. >> in the gulf of mexico. so we're going to be asking these panelists questions on a variety of summits, but -- subjects, but each of them has been prepared to focus on one. so i'd like to start with mr. lewis and talk a little bit about float equipment. you'll recall that yesterday during the presentation fred discussed the troubles that the

crew had at the macondo well actually converting the float equipment. and as you'll recall, the float equipment are, basically, two what are otherwise one-way valves that have what's called an autofill tube in them. and that autofill tube allows mud to go through the tube when the casing, when the valves is actually running into the hole. but once the casing is actually landed at bottom, you want to convert these valves to a one-way valve. the way to do that as we showed yesterday is to drop a ball into the tube, pressure up, then at some point when the pressure gets high enough, the tube should come through, and these valves convert to one-way valves. so that's just to reorient you to understand what float valves and float conversion is. is that about accurate, mr. lewis? my description of the float equipment and the float valve?

this. >> it's a good start. >> all right. [laughter] what to you, what does it mean to say float valve conversion? >> bloat valve conversion is what you just described there, of converting from autofill which simply means that the valve is held open to its function as a one-way check valve. >> how is an autofill float valve converted? >> this particular design is simply a differential pressure across that tube which causes some pins -- you can show them if you want to that assembly that is unsheared. the larger portion there has shear pins in it that will break at a given stress that's applied by the pressure. how you adjust the shear pressure for those is either by adjusting the number or the

strength of the pins or changing the size of the orifices at the bottom. so it's an adjustable tool, but you have to make that decision in advance, of course, of putting it together in your assembly. >> so once the float equipment is is actually at the bottom and you're to the point that you want to convert the float equipment, this ball -- which has been seated up here while running the casing -- drops down, and then you apply pressure to that ball. when the pressure gets great enough, it will actually convert the equipment. >> actually, what you apply is a differential pressure across the ball. that differential pressure is created by floats that are above the ball. until you have flow through those ports, there is no differential pressure. >> how much differential pressure was necessary to convert the float valves used at macondo? >> this particular tool by the

manufacturers, this is a weatherford tool. by their data tables provided in the graphical presentation, it would have taken between 5-700 citizen psi to -- 5-700 psi to convert this valve. the equation they provide is a fluid dynamics friction lost through nozzle-type calculation, and i did those numbers with the mud weight in the hole at the time and calculated right at 600 psi. >> now, looking at this float equipment, when you drop the ball, it plugs up this hole at the bottom. but there are these two additional holes at the side through which mud can flow, right? how does one obtain 600 psi of

pressure when you have these two holes on the side through which mud can flow? >> well, as i said, you have to pump mud through those holes at least six gallons a minute, if not possibly more to guarantee that you have sheared the pins and, thereby, converted the valve. >> so is the flow rate more important than the pressure that's actually being exerted by the pump? >> the flow rate is the only thing that's important. the pressure at the surface is actually irrelevant. the mechanism that activates it, as i said, is differential pressure. the tool, in fact, is described and designated a flow-activated full open. >> so just to make clear, what flow rate would you have expected would have been necessary at macondo to convert these float valves from two-way valves to one-way valve? >> the minimum of six barrels a minute.

>> did at any point in time the flow rate at macondo exceed six barrels per minute? >> subsequent to running the casing, no. >> so at some point when the crew was trying to convert the float equipment we saw yesterday that they pressured up to 3 be 142 -- 3142 psi. remember that? >> yes, that's correct. they did. >> and at that point they reestablished. >> that's correct. ..

>> did the flow rate ever exceed at any point in time after the attempted conversion six barrels per minute? >> no, it did not. >> mr. lewis, do you have an opinion sitting here today as to whether the float equipment at the macondo well converted? >> it's my opinion that it probably did not. there is one possible mechanism that might have allowed it to convert that i can think of. that is that when, under the presumption that the abstraction was below the float after was cleared in circulation was

established, the search of pressure might have been adequate to get you that much differential. bp in the report said they were doing further investigation into that possibility, and i would be very interested to see the results of that. >> but just so i understand, is it your opinion today that it's more likely than not that he float equipment did not convert, the flow rate never exceeded six barrels per minute at macondo? >> i would say the preponderance would indicate that yet unfair and yes. >> okay. -- 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 >> 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 operator, that 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 paicularly unusual. . .

>> in the annulus and allows you, then, to bleed pressure off the drill pipe to reduce the pressure in the well only after the b.o.p. is closed. >> so is it fair to say that performing the negative pressure test after having removed 3,000 feet of sea water unnecessarily stresses the well before you've even tested whether the well can handle it? >> well, it's, it's not necessary in an absolute sense, and some of that pressure reduction was offset by the fact that there was this heavier spacer that the intention was

and at that point it would have been in the riser, but it's, 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? mr. bourgoyne? >> 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 bee