hoover is alleged to have said the worst thing about capitalism is the capitalist. and so, you know, again, as servants of the american people, republicans in the majority in the house have a responsibility to the country to not only keep an eye on the obama administration, we also have to make sure that the private sector plays by the rules. and i can assure you that we'll do that in the energy committee, and speaker boehner in a conference call earlier has, has assured the incoming chairman of the new, of the committees that we're going to take a look in every committee in overseeing the obama administration and also the jurisdictional private sectors that each committee's responsible for. >> host: last question from juliana gruenwald. >> host: mr. barton, if you're

unsuccessful in your bid to become chairman, i'm assuming you'll stay on the committee, and would you seek a subcommittee chairmanship, and if so, which one? [laughter] >> guest: well, that's a very rhetorical question. i fully am fully engaged in being successful and convincing the republican conference and the leadership to, to give me the privilege to be the full committee chairman. so i'm going to focus my efforts on being full committee chairman, and i'm, i'm very confident that i'll be successful in that effort. so i'm really not going to speculate on what happens if that's not successful because i think it will be successful. >> host: and finally, congressman barton, how would a chairmanship, your chairmanship differ from that of, perhaps, fred upton? >> guest: well, that's a very speculative question. fred and i are very good

friends. we sit side by side for a number of years. he and his family are lovely people, just delightful people. i think the differences between congressman upton and myself, you know, i am a, obviously, consistent conservative across the board. fred is, tends to be somewhat more moderate. so you'd have a little bit of a philosophical difference perhaps. and i've also been chairman for one term, and i think i'd be able to hit the ground running. fred has served as subcommittee chairman on a number of the subcommittees, so he certainly has leadership at the subcommittee level, but, you know, the american people have given us a two-year lease to be

in the majority in the congress, and i think that we should put our best team on the field for the next two years. and, you know, i think that while fred's very competent and very well qualified, my experience is at a little bit higher level than his, and i would be much more able immediately to run the committee in an effective fashion. >> host: and just to make it known, we have invited congressman fred upton to appear on this program as well. ranking republican on the energy and commerce committee and potential chairman joe barton, thank you as always for being on "the communicators." we'll look forward to watching the process play out. juliana gruenwald of tech daily dose, the editor national journal, thank you as well. >> ahead on c-span2, newsmakers

talks with michael bromwich. >> this week on newsmakers, our topic is the future of offshore drilling, and the man in charge, michael bromwich. thank you for being with us. appreciate it. >> thank you, my pleasure. >> host: two reporters to help us with questioning, nila and jennifer. jennifer, you have the first question. go ahead. >> directer, you took office, obviously, after the deepwater horizon disaster, and it's been more than six months. a lot of people are still wondering what exactly happened in the hours and weeks leading up to the explosion in april. a key piece of evidence in that, in the ongoing investigations into what happened, the blowout preventer that was unearthed from the well site is now sitting in a nasa facility in louisiana where it awaits a

battery of tests. but there's been some disagreement between the joint investigation that your agency and the coast guard are leading and the chemical safety board over access. what does that dispute do to the timeline and the chances that we'll get answers about the bop and the well soon, and what are you doing about it? >> guest: well, i'm hoping it doesn't effect the timeline. we did face some delays at the beginning of the process that put us a little bit behind schedule, and some of those delays required us to request an extension of the time when our final report is going to be issued. it was originally scheduled for the end of january, and because of delays in the b.o.p. testing, we've had to ask for an extension until the latter part of march. i'm hoping that the requests by the csb that we are trying to deal with responsibly will not lengthen the timeline, but as you may know, they've, they are

making a bit of a fuss about it, and they've threaten today go to court about it. we're actually discussing issues with them this afternoon and hope to be able to resolve it. it's unfortunate. i find some of the things they've done both aggressive and somewhat puzzling since they've acknowledged in the past some doubt about whether they have any jurisdiction to conduct such an investigation. it's taken a lot of cooperation, coordination, discussions to get to where we are right now with the b.o.p. testing, and so the csb's request which, again, we've been trying to accommodate recently, have been a disturbance and a distraction over the last week or so. so i'm hopeful we can resolve it quickly, but it would be very unfortunate if this caused an additional delay. >> host: and let me jump in at that point because viewers who are watching this wondering b.o.p., csb, the blowout

preventer, those are words that the american people have heard. if there is a delay and no resolution, what does it mean to the american people that are waiting to find out what exactly happened? this. >> guest: it means that the most extensive and comprehensive investigation of what happened, what caused the deepwater horizon to have the explosions and to sink, that the final answers will not be known as early as they might otherwise be. i never heard of a b.o.p. until a few months ago, i think that's true for many of us. i've now fallen into the bad habit of using abbreviations for longer words. b.o.p.s are blowout preventers, csb is the chemical safety board which has a clear set of missions and tasks for various kinds of investigations. as i suggested before, it is far from clear as to whether they have a strong claim to make to do an invest here. -- investigation here. in fact, they acknowledged in correspondence with the department a number of months ago that they weren't sure that they had jurisdiction to do this

investigation. so that's one of the reasons i find it surprising and somewhat disappointing that they're being so aggressive about pushing their positions and risking a delay in the completion of the most comprehensive investigation that we have going right now. >> host: well, we also know that this week there's been an election that's going to bring about a vastly-changed congress come january. and i want today ask you about some legislation -- wanted to ask you about some legislation that's pending to regulate offshore drilling and give you the adequate resources that you need to hire more inspectors and tighten up regulation of offshore drilling. if that legislation does not pass, what does that mean for your agency? what does that mean for oversight of offshore drilling and the plans that you have? >> guest: well, it's too early to say, obviously, but it would mean if legislation doesn't pass that we will lack the, what they call the organic statutory foundation for the functions

that we carry out. right now our agency is supported as a legal matter only by secretarial order rather than statute. and that's a place where we don't want to be. but more importantly, i think that's sort of an arcane legal issue. what's important to us is that we have the resources that we need to carry out our mission and to do our job. i think what everyone has agreed on in the wake of deepwater horizon and the reviews of our agency that have been ongoing is that our agency has never had the adequate resources to do its job. there is an agreement between pro-drilling and anti-drilling forces, there is agreement between democrats and republicans. and the president's budget for 2011, as you probably know, contained a request for 100 million additional dollars for us in order to build up the number of inspectors that we have, to build up the number of engineers that we have and to add various other kinds of both

equipment and manpower to do all the important tasks that we have. i am very hopeful that even with what's happened in the election this past week and even with the emphasis on deficit reduction and budget cutting that that kind of consensus on the need for us to have the additional resources will survive, and we will continue to have that pushed through the congress. because the fact is that even for those people who are pro-industry and pro-drilling, what i've heard in the past is they want us to have the resources in part so we can process their permits in an expeditious way. if we don't have the resources to be able to do that, then people who want us to be granting permits are going to be disappointed as well as lots of other people being disappointed. so it's a lose/lose if we don't get the resources. it's a win/win if we do. >> host: on the permitting issue since you brought up this issue, what is the status of the low

water and the -- shallow water and the deepwater permitting process right now? how many permits have you received since secretary salazar lifted the moratorium. >> guest: it's a small number, fewer than a half dozen that have been filed. now, all of the applications have to comply with the new requirements that have been established over the last couple of months, and that will inevitably be a more time-consuming process than it has been in the past. we know there's a lot of interest in getting these permit applications processed, but we obviously have a job to do in making sure that these new applications comply with the new rules and regulations. so we are going to process them as expeditiously as we can, but we need to insure that they are fully compliant. >> host: could you expand upon that a little? what is it in the new regulations that you have that, as you said, makes process more time consuming either on your end and, you know, the people who are reviewing the permits or

the work that the oil companies have to do to prepare the permits. >> guest: well, the oil and gas companies do have to do additional work, and i met with one of of the representatives from one of the major companies, and i asked how long did it take. they confirmed that it is additional work and even though they saw the foreshadowing of these new rules way back in may when the secretary filed his 30-day report to the president recommending various kinds of safety and reforms in the area of compliance that even though they've been doing some of the work since then, they are still not completely done. so there is a significant amount of additional work that the companies must do. i think they're very much expediting that process and doing that work. but there are also additional steps that we have to take. we have to insure that certifications that they're now required to provide are in good order. we have to confirm and review their cementing and casing proposals that we didn't

previously require of the companies and, therefore, we doesn't have to review -- didn't have to review ourselves. now, we're doing the best that we possibly can with the resources that we have in connection with processing shallow water drilling operations. we actually bulked up the resources that we were devoting to reviewing and processing those applications. we transferred some manpower from some of our smaller regions in alaska and the pacific, but more importantly we transferred internally within our gulf of mexico region approximately 20 additional people. so that we now have a more robust staff of people who are reviewing permit applications than we ever have before but still there's a lot of work to be done, and it's very hard to predict how long the process is going to take. >> host: regarding those shallow water permits, it seemed like in early october there was a flurry of approvals, the number got to about 12 or 13 new wells approved, but it stayed fairly

flat. as of friday there were, i believe, 20 applications that had been kicked back or were no longer pending. what is the holdup? is there some change since the interim safety rules came out that is causing some of these delays? >> guest: no, i don't think so. i think it's more that, as you say, a number of these applications are being kicked back because they didn't contain all the information that's required. so there's actually a very small number of applications that are truly pending. i think the number is three or four. so if we get incomplete applications, we don't have any choice but to kick them back to the companies. so the only, the only applications that are currently on our plate, as i say, are three or four which is not a large number. now, what i was told several days ago by our staff in the gulf is they thought that it would not be long before at least a small number of additional applications would be refiled, the information would be complete and that we'd be able to proceed to prompt review

and approval of those permits. but it's back and forth process. we, obviously, if information is missing, we can't say, yes, we approve this. so we have to send it back for additional information to be added. so it's the back and forth that's really taking a lot of time. >> host: one of the things we were hearing when people were discussing delays in the shallow water permits, and this was even before the moratorium was lifted was that the holdup seemed to be around the worst-case scenarios they had to plan for, and i was wondering if that scuttlebutt was true, that really there's a greater demand for precision and perhaps better planning on the worst-case scenario? this is that where some of the holdup is? >> guest: and just to be clear, worst-case scenario looks at what happens if there's a blowout of a well. what is -- how many hundreds or thousands or hundreds of thousands of barrels of oil may be spilled in the case of a so-called worst-case discharge.

and this was a relatively, it was a concept that had been in our processes before but because of deepwater horizon we sharpened it and imposed additional requirements on the companies. and the truth is that i think there was some legitimate confusion on the part of the companies in terms of what we wanted and because we were applying worst-case discharge in a slightly different way than we have historically. there was some lack of certainty even among our own people. so we solved that in a responsible way. we had a series of discussions with shallow water drillers and tried to clarify what we meant and what we were looking for. we did that both through a series of telephonic discussions, a series of in the-person meetings -- in-person meetings and a series of frequently asked questions that we put out to the industry to try to clarify some of the uncertainty and ambiguities that

existed. so we've learned a lot, i think the companies have learned a lot, i think the companies have a much better idea now of what we're looking for and what will pass muster. and i think we're all hopeful that they do understand it, that the applications that we're going to be getting from this point forward, in fact, contain all the right numbers and all the right analysis and we'll be able to move pretty swiftly to approve those that are qualified. >> host: the worst-case discharge requirement was one of the requirements being noted in the note to lessees, imposing rules on emergency basis. >> guest: right. >> host: there's, obviously, been some pushback from industry to that process and, as you know, a couple weeks ago a federal judge in louisiana essentially kicked back one of those notices to lessees saying that it really should have been proceeded by a public comment period and a public notice. what does that do to your ability as directer of the bureau to impose new regulations very quickly without having to go through the lengthy process,

and what are your options? this are your hands tied? >> guest: well, the truth is it does create complications. it was, it's one decision by one judge. it's based on one ntl, and the impact of that decision, in fact, is not great because we have moved forward and incorporated most of the requirements that were in that ntl and, again, that stands for notice to lessees, boo our recent -- into our recent final rule. and so we haven't lost very much of anything in that process. but the larger concern is that we have a limited number of tools in our tool box. limited number of things we can do to enhance safety and to make sure that offshore drilling, exploration, production takes place in a safe and environmentally-responsible way. to go through an entire formal rulemaking process can take many, many months if not years. and given that we're operating in a very dynamic environment as

regulators, we're going to be learning new things about what caused deepwater horizon, and can we want to be able to act on those insights in a responsible way, in this a way that the public -- in a way that the public expects us to act. it's unfortunate that there is now something of a cloud over the ways in which we can use one of the tools in our tool box. now, we're going to move forward, we're going to, obviously, be careful about the way we use notice lessees, but we're not in the face of one adverse court decision going to stop using them. because we need to. we can't afford, frankly, to go through the entire notice and rulemaking process for every little change, tweak or enhancement of safety regulations. that would be a mistake. >> host: so if you're at home listening to this conversation, you might be thinking to yourself, could it happen again? given what you've just talked about, shallow water permits and this understanding that industry has had to come to, that you've had to come to at your agency,

what's the percentage that the bp oil spill could happen again? >> guest: i can't put a percentage on it, but i think what we've all learned is is the percentage is not zero. and i think for 40 years, the last significant spill we've had in this country was 1969 in san santa -- santa barbara. and i think that because there had not been any events of that kind since then, people grew overly confident, regulators and companies grew complacent, and they didn't admit to themselves or to each other that it could happen. that, that, now, has utterly changed. we know that it can happen, it has happened with devastating impact to human life and potentially to the environment. and so that's what drives us to look to ways in which we can in a common sense, nonstifling way raise the bar in terms of the standards that are imposed on the industry so that we can drive down the risk that this

will happen again and drive it down to the point where we can feel comfortable and confident that it can proceed in a relatively race -- risk-free way, and i emphasize relatively. >> host: is it the nature of what you're doing that it's always going to be 50/50, there's a 50% chance this could happen? >> guest: i don't think there are any -- keep in mind, there have been, in my understanding, over 4,000 holes dug in the gulf just in deep water, okay? this there was one blowout. now, those are not 50/50 odds. those are low odds. but what i think people did not recognize is that even though it might only happen once, it could have enormous consequences. and can that's why we are all legitimately concerned about driving down the risk that it can happen again. is it possible it can happen again? absolutely. when you have unknown reservoirs, you have exploratory

drilling, you have advanced technologies and more than anything else you have human beings involved, there is a chance that something could go bad. now, i think what we'll learn and i think we're already learning to some extent is that what happened with deepwater horizon was, unfortunately, a perfect storm of both mechanical and human error. so the risk of that perfect storm happening again is not great, but it exists. and so we need to do everything we possibly can to diminish the chances that it will happen again. >> host: go back to our reporters. >> host: just a follow up on that. there's a lot of criticism, you know, after the deepwater horizon both in the media and now in commissions and investigations about the way various government agencies responded to the crisis. criticisms about relying too much on bp, criticisms about not really knowing who's in charge about information being withheld and so on. given all of that and, obviously, the fact that you're still assimilating this and you

are not the only entity responsible for spill response, what -- how would things be different if there were a spill? how would the response on the government side look compared to what happened after april 20th? >> guest: well, i think a lot was learned during the response. a fairly complex but well-functioning coordinating mechanism was set up that involved department of the interior, that involved the coast guard, that involved bp, the company that was most centrally involved. and so by all accounts things were not coherent and not terribly well organized on day one. but that changed, and that changed fairly dramatically as time went along so that you had all entities functioning together, working together and putting their minds and their muscles together to develop a coordinated effort. i think that one of the things we need to be very mindful of is

trying to capture that learning and make sure that both the mistakes that were made and the good things that were done are memorialized and preserved so that if, god forbid, we had another spill tomorrow, we could reassemble this coordination mechanism, and we could move forward. now, we're in a very different position today than we were on april 20th in the sense that industry and the government were unprepared for a deepwater blowout. they didn't have containment equipment, they didn't have the resources, they didn't have the know how, they didn't have the technical knowledge. that technical knowledge now exists to a very significant degree both in the private sector -- not just in bp, but in other companies as well -- but it also exists in the government. and the equipment deficit is being addressed through, among other things, an agreement among the majors to put together a very ambitious what they call a marine well containment corporation to develop subsea equipment that would be capable

of being applied to another deepwater spill. so we are in a different place than we were before. we do have the mechanisms that exist that didn't exist before. my greater concern is not that, god forbid, something happened in a month when those mechanisms and the know how are still more or less in one place, but how we keep those ready to go if it were to happen a year from now or three years from now -- >> host: five years. >> guest: and five years from now. i think you're ready immediately after a crisis to respond to another similar crisis. what i worry about is the muscles aren't toned up anymore to do that kind of response, and so five years down the road you're not in as good a place as you would be now. >> host: or there's a crisis you haven't thought of yet. >> guest: correct. >> host: just to follow up on that, there was -- the private sector prepared for a spill in alaska, and there continues to be, now, great interest in

drilling in the arctic ocean, and i wanted to, i guess, find out what, what is going on on the side of government to make sure that drilling is safe in the, in the arctic because of how complicated we've seen, you know, the -- how complicated it is to clean up after a spill there. i mean, i guess the valdese was much farther south, and this is where there's going to be a lot of ice and so on and, you know, these seem to be big concerns amongst environmental groups, amongst indigenous groups there. and i ask that in the vein of the disaster that you don't prepare for yet, the thing that you haven't, that imagination hasn't reached yet. so, you know, what can one do with the arctic, and what are the challenges that are present there? and, you know, are you confident

that the oil companies can meet them? >> guest: those are are real concerns. there are a different set of issues in the arctic than there are in the gulf, and i spent a lot of time meeting with representatives of native groups, representatives of environmental organizations who have expressed those concerns to us. we've also met with the oil companies that want to operate there and have made major efforts to show ha they're doing everything -- that they're doing everything possible to make drilling as safe and environmentally responsible as possible. the main concern that we have, and you alluded to this in your question, is how do you deal with a potential spill in the arctic? because it is so different. when i held just a series of public forums all over the country to gather information relevant to whether secretary salazar was going to lift the deepwater moratorium, we held one in alaska. and the focus there was oil spill response. and it focused even more specifically on what are the special challenges that exist

when you have far less infrastructure than you do in the gulf, when you don't have the kind of coast guard presence in the arctic as you do in the gulf, when you have the enormous challenges posed by broken ice and total ice. so even though it's not deepwater and so, and the geology is different and the nature of the drilling would be different, the fundamental questions that we are still grappling with is have we been given adequate answers on spill response, and if not, what additional steps need to be taken in order to satisfy ourselves that drilling in the arctic can take place within a tolerable risk. and so we're still, we're still wrestling with those questions right now, but we haven't reached any decisions. >> host: couple minutes left here. go ahead. >> guest: given that uncertainty about the arctic, what is your

expectation that we could see wells drilled? shell's been planning to drill a couple years now. obviously, that's on hold. do you expect to see something in the next few years? >> guest: we're going to be making some decisions that will bear on that in the relatively near future, so i don't have an announcement to make today, but we know we need to resolve this issue because, because nobody likes uncertainty. and so we need to provide an answer so people understand which direction they're going to be permitted to go. we understand that, and we'll try to make decisions in a timely way. >> host: probably time for one last question. go ahead. >> guest: and i wanted to ask you about staffing up for throughout the system, and i wanted to find out what is, what's happening with your efforts to increase staff especially in the gulf. i know that you went down to do a recruitment tour, and can i was wondering how that went and whether, you know, people -- whether you can get people into the public sector these days.

>> guest: it was actually phenomenally successful, and i'm thinking of changing jobs to become a full-time recruiter. we went to five engineering schools in louisiana and texas last week, lsu, university of texas, university of louisiana lafayette, texas a&m, university of houston. and in response to our, my appearance there we got well in excess of 100 applications for both engineering positions and inspector positions. we had a job announcement more generally that was open for only two weeks, and we had in excess of 400 applications for a total of 30 inspector positions, 30 petroleum engineer positions and between 15 and 20 summer internship positions. so to say that the response has exceeded our expectations would be a vast understatement, so -- >> we'll leave this program at this point to go to the national commission on the bp deepwater horizon oil spill hearing holding their fifth series of

meetings, and their continuing their investigation into last april's gulf of mexico. ..

>> legal and knowledge of offshore operations. they include frances by nikki, the present of the natural resources defense council. doctor donald bosch, president of the university of maryland center for environmental science. terry garcia, executive vice president of the national geographic society. dr. cherry murray, dean of the harvard school of engineering and applied sciences. and fran ulmer, chancellor of the university of alaska at anchorage. this commission is conducting its work in compliance with the federal advisory committee act, which sets a high standard for openness and transparency. and as such terms are being broadcast via live video feed and are being held here in this public forum. before i hand this over to our two distinct co-chairs, i'd like to write a quick summary of today's agenda. this morning we'll be hearing a presentation by the commission's

chief counsel, fred bartlit. mr. bartlit will lead a discussion on the ongoing investigation on the causes of the accident and will present some preliminary findings for the commissioners to consider and deliberate today, and any future public sessions. we will break for lunch at 12:30 and reconvene at 1:30 for elegant session with beatty, transocean and halliburton. it would not be a public comment period today but do we want to borrow afternoon at 5 p.m., any member of the public who wishes to submit written comments to the commission may do so by the website which is www.oilspillcommission.gov. that again is www.oil spill commission dot got. at this point i will hand it over to our two -- two cochairman. >> thank you very much, mr. smith. we appreciate the service that you have provided throughout our hearings. i asked the commission, we have

been charged by the present with helping the american people understand the root causes of the largest oil spill in american history. a disaster that claimed the lives of 11 workers on the deepwater horizon rig. we have held four public meetings thus far, and numerous site visits. >> we've heard from the people of the gulf, learned about regulation of offshore drilling, examined the important issues of response and gulf restoration, and had her first occasion to deliberate on key findings. today, it we turn to an important piece of the puzzle. our chief counsel, mr. fred bartlit, will give an overview of what he and his team have learned to date about what happened on the rig. i believe this will be the clearest presentation the american people were received to date on what led to this tragedy. fred bartlit is the right man

for this job. he is widely respected, a tenacious lawyer, enormous credibility, thanks to his unquestioned reputation as a straight shooter. his experience with the this issue is very deep. he led influential investigation of the last major disaster on an offshore rig, the piper alpha explosion in 1988 in the north sea. the commission that investigated the columbia shuttle disaster made a very important point. complex systems failed in complex ways. there is a natural tendency to focus on one crucial position or misstep as the cause of the disaster. but as they observed, doing so gives a dangerously incomplete picture of what actually happened. we will learn for the next two days that many ways in which this complex system failed. we are not looking for

scapegoats, but we do believe we have an obligation to uncover all relevant facts. only by understanding what happened can we extract the important lessons from the deepwater horizon disaster. there is much that we know now. there are still areas of uncertainty and disagreement. these meetings will go a long way to bear in mind where we stand. i want to personally thank him and on behalf of commission, mr. bartlit and his dedicated team for the work so far. i would also like to thank our witnesses today for their cooperation with the commission. i would now turn the gavel over to co-chair, mr. bill o'reilly. >> thank you, bob. good morning. the disaster in the gulf undermined public faith in the energy industry, in government

regulators, and even our ability as a nation to respond to crises. as a commission, it is our hope that a thorough and rigorous accounting, combined with constructive suggestions for reform, can help restore public trust. our prior meetings have confirmed that investigations -- that investments in oversight, safety, and response capabilities failed to keep pace with the rapid move in to deep water. it appears in at least some quarters but this is a real joy culture exhibited in attention and a false sense of security. over these next two days we will be looking in detail at what happened on the rig. our investigative staff has uncovered a wealth of specific information that greatly enhances our understanding of the factors that led to the blowout. one question i think we all have

and have had from the beginning is, to what extent this was just a unique set of circumstances unlikely to be repeated, or was it indicative of something larger? in other disasters, we find recurring theme's of missed warning signals, information silos, and complacency. we out prejudging our finest no one can dispute that industry and government together have an obligation to ensure that such a set of conditions offshore must be subject to a safety culture that is protective of lives, livelihoods, and the environment. extracting energy resources to fuel our cars, heat our homes, our industry, and light our buildings, can be dangerous. our reliance as a nation on

fossil fuels will continue for some time. in the boulder new oil and gas discoveries lie, not on land, but under the water. the risk taken by the men and women working in energy exploration benefit all americans. we owe it to those who manage and accept those risks to ensure that their working environment is as safe as possible. over the next two days, we will learn from fred bartlit, sean grimsley and others, about what went wrong on the deepwater horizon. this detailed account of what led to the loss of 11 lives, the largest oil spill in american history, will guide our thinking as we move to final deliberations on findings and recommendations. so today, we are fulfilling the first of the fundamental task, and most fundamental task that the president gave to us in the

executive order establishing this commission. and that is, determined the cause, find out what happened. i will be most interested in the lessons we may learn today that help inform the commission's recommendations for the future for how we create policies, prevent something like this from ever happening again. i want to remind all of you here that the information that you will be exposed to today that was gathered by our investigative team was achieved without the power to subpoena witnesses or evidence. i compliment the companies whose cooperation made this possible. i can't limit the fred bartlit whose reputation earned the kind of trust and cooperation that this displays. and to those two senators who blocked this commission from receiving subpoena power, let me just say, i hope that you are presently -- pleasantly surprised of what we have

learned, and not disappointed. with that i will turn to our chief counsel, fred bartlit. >> thank you, bill. i want to start by setting the stage. what we are going to accomplish today and how we are going to go about it. but first, it's very easy when you're enmeshed in these technical engineering, scientific details against a background of huge financial exposure, it's easy to forget why we are here. we are here because the 11 men died. and i've asked, prior to today, and i'm going to ask today for all of us, we're all lawyers, most of us, to put aside our natural desire to be advocates. and keep in mind these brave,

hard-working men that died on the rig that day. and keep in mind that we will honor them if we can get to the root cause without a lot of bickering and self-serving statements. 100 years from now we want the world to say, they changed the safety regime in the gulf of mexico offshore drilling. so, what i'd like to do is start by having a few moments of silence, where we each reflect on these men that are gone now. and we each promise to their families that we will honor them by getting to the root cause of being sure this never happens again. now, what are we going to accomplish? be very careful to the presidential mandate which is, examine the facts and

circumstances surrounding the root cause of the blowout. we are not assigning blame. we are not making any legal judgments as to liability. we are not considering negligence or gross negligence, or any legal issues at all. we are trying to walk a fine line between looking at root cause and not getting into the legal issues. it's a hard thing to do, and maybe we will axially step across the line, but our goal is to look at clause -- cause, not liability. we will first explain to the public what happened 18,360 feet down at the bottom of the macondo well. because nobody wants to hear one person talk for three hours, any one person doesn't want to talk to three us. we will split it up that i'll be taking part of it. my partner, sean, would be taking part of it. sand will be taking part of it. it's just a matter of human interest, it's interesting that these two young men clerked

together for the legendary united states of supreme court justice sandra day o'connor. and they were picked back as young men to be the best and brightest, and working on this commission, they have shown that she was smart at picking them. then this afternoon we will have witnesses from transocean, halliburton and bp up here. and we will ask questions. this is not a cross-examination. it's not a trial. we will be trying to find out what the areas of differences are and was the areas of agreement or. because it will save us a lot of time in writing of our report if we could put aside issues, whether disagreement, and we can let the commission know what the areas of disagreement are that they might need to focus on. and we might then have to suggest other ways perhaps in resolving some of these issues. then we will inform everyone at the end of the morning our

tentative views on root cause. and together, the parties have these tentative conclusions, they are tentative. we want to be sure we get it right. they will be invited to comment on any of our tentative conclusions, and everybody will get a copy. and end any of them or any parties want to file written collaborations on these issues within five days, we invite that. that more information we can get, the better. tomorrow there will be some panels of technical experts on deepwater drilling, macondo, some regulators, and i know we're privilege of the ceos of shell and exxon. everywhere we went in the industry, people said to us in formally, fred, exxon, is the gold standard of safety and mr. tillerson is going to come here and tell us how he achieved that position.

i want to thank everybody for their cooperation here. as bill absorbed, we don't have subpoena power. that means that to a certain extent bp, halliburton, transocean had to put aside the normal tendency of a trial lawyer to stonewall everything until the last, you have to go to court, and cooperate with us. and i want to thank for bp, john hickey, there council. i want to thank rachel clingman for transocean, and don godwin for halliburton. they have given us an unprecedented degree of cooperation in situations where their clients had serious issues to face, a very unusual sacrifice they made. and we couldn't get where we are without them. i want to thank two other agencies, cisco corporation volunteer to send us one of their top litigators, paul

ortiz, who worked with us on our commission, gratis. cisco is paying the cost of it. and i want to thank trial graphics. we don't have any money to on this commission to get going to see today what is probably a half million dollars of graphics, that basically were done for free by megan and bill. and i've worked, 50 years as a trial lawyer, i worked with the best graphics teams in america. they blew me away. they have been up all night. they are not getting paid. making use of has a masters degree in engineering, and bill is one the top of graphics artist in america. so, their team was led by a real engineer, and the work product was done by one of the best graphics people, and we thank you guys very much. finally, the presentation you will see today has been vetted

as thoroughly as possible. we showed the presentation to some of the top deepwater drilling experts in major oil companies not involved in this litigation, to be sure we got it right. to be sure that our observations are consistent with custom and practice of the deepwater drilling business. we also showed this presentation last week to transocean, halliburton and cisco. told her there council, we don't believe in surprises. people ought to have a chance to know what's going to happen, a chance to prepare, and a chance to respond. and throughout this thing, our purpose has been to be totally transparent. this is what we are thinking. if we're wrong, tell us. there's no pride of authorship. we must get right. and we must get right to honor the men that died that night, and to a degree that surprised me, the parties and counsel have

kept in mind that purpose. and often, i believe sublimated what might be the normal reaction of trial lawyers to investigations like this, and i thank you guys again. it's not only the parties that have cooperated. the entire offshore drilling industry has cooperated. as you'll see, we had cooperation from chevron, exxon, shell, from dril-quip, from parties that make this equipment, schlemmer j., everybody has pitched in. they been willing to meet with us. they have leveled with us and cooperate. i particularly want to thank bp for the report they did. so people in the newspaper said was self-serving, we agree with about 90% of it. there's a lot of extremely vital work that was done to the cost bp a lot of money. we don't agree with everything. but it's a contribution to this hearing, and we thank you for doing it.

the last thing i want to say is, as we met with all the parties in the last week, as the people here will know, some within will be smiling, every time we had a meeting, people said, fred, you're not getting it right, you're treated as harshly, you're being too nice to somebody else. everybody said that. during the meeting. there were sometimes some harsh words because everybody was told in advance, so i told my guys, and i say to you guys, we must be doing something right because everybody hates me. okay, now we will start. i will begin the run through. and when we get to the same issues, sam sankar will take over. when we get to the negative test and the temperate abandonment issues, train eight will take over. so let's go. now, we'll first talk about the

rig itself. we are also money with it, but everybody's on the same page so they know where it was and what was unique about it. we will then talk about what it's like to drill offshore wells, generally that and then the macondo timeline, then will come to the senate issues. some recent questions raised about cement, the temperate abandonment issues, kit detection, kicked means we is the term hydrocarbons that hydrocarbons are gas and oil. of course, you will see gas expand rapidly as it comes to the surface. if gas comes to the surface, it gets on the rig, that's bad. when gas gets in the well, and the rise, that's called a kick. as we go through these terms, a lot of us have never heard before, i will be sure to explain to them. and we will talk about the blowout itself. okay, here's the gulf of mexico, his houston, his temper, here's new orleans, here's the macondo

will. the gulf last year. the gulf last year, there were $170 billion worth of oil and gas produced. most people aren't aware if there is a very dense network of wells, pipelines, subsea manifolds, a whole community of helicopters, offshore vessels, a huge industry here. generally speaking, deepwater, we're talking but here begins about 1000 the, water deaths of 10,000 the. the water depth here was 5000 feet, a mile down. then they went down 13,000 feet into the formation underneath the seabed, what we call the mud line. now here's the deepwater horizon. isn't the mississippi canyon

that it's actually canyon that was formed as the mississippi river came out eons ago. here's the 5000 feet of water. here's the rig. here's the famous b.o.p., the blowout preventer. and now we go down to seabed and other 13,000 feet, what we will be talking about, this is where the pay sands are. this is where oil and gas is. and the oil business they can't pay because that's where the payoff for drilling the well is. so down here 18,360 feet aren't hydrocarbons they were drilling for that has been established for by seismic work, work of geologists and the like. what happened occurred right down here. bottom of the well. this cemented you see here, and you'll see enough cement today you'll be sick of it, but this

thing that down here is where the leak occurred, and we'll be spending, we'll have big blowups and animation showing what happens down there. you'll hear a lot of names. we all know bp, transocean was the owner and operator of the rig. they have a lot of rigs all over the world. halliburton, among other things, does cementing. m-i swaco is an schlumberger company that handles the drilling mud. you will learn more about what drilling that is and what the purpose of it is. schlumberger was on the well the day of the explosion to do certain logging, and that, we will discuss that. and halliburton unit called sperry sun capture data, the data that was on the rig and that night, went down with the rig, but halliburton had a sperry sun unit that was sent

shoreside. they caught the town, or houston, or shoreside. certain data which was saved and there are some certain data about that. oceaneering, the work down there at the bottom is done by these robots, oceaneering did it. dril-quip made wellhead casing hanger's. you will see pictures of dril-quip equipment. they been very cooperative. and top engineers and they've helped us interpret what happened with that equipment. and, finally, the famous centralizers you've heard about were made by weatherford. now, in 50 years of trying cases i've learned what people hear names, they learn track of them, they can't keep track of where they are and that kind of thing. so what we've done is this. we have a chart of the onshore, sometimes you see people called out and down passionate in town. on the onshore chart, the people, transocean and

halliburton. and then we have who was on the rig that night, bp well site leader's, the transocean team operating the rig, halliburton personnel. to make it easier to keep track, we put around the room these big charged with all these names on it again as far as i'm concerned it's okay if you get confused what's going on to walk up and take a look at this. it's important that everybody understands what's going on. at the breaks you can walk up and look at it and get a feel for it. we won't talk about all these people today, but we have done this so that everybody can follow the names and follow what's going on. of course, as we go through this will also explain who the players are and who they work for. all right, now we will learn a little bit about this rig, generally. this is the deepwater horizon

rig. it's a drilling rig. a lot of people don't know there's production rigs that stay on station for longtime and have a lot of dry gas separate and things on board, pipeline shoreside. this was a drilling rig that was going to drill down to passionate originally was going to go down to 20,000 feet. they ended up going down to 18,360. it's easier to understand the rig when you do in this sort of a cartoon fashion. high as a 40 soar building, giant derricks on-topic and and a 400 tons or more. almost as long as a football field in two ways. helicopter pad. pipes stored. now we're getting to where the action happened. okay, this is the drill floor. here is the road repaired this

is where the well is drilled, and when you hear the mud came up, the gas came up, and the explosion started, that's where it is. the true shack with the drillers are is pretty close. and you will see pictures from the inside of the drill shack of the people sitting there, like the captain of a 747. they've got all of the controls and they sit in chairs. they work long shifts, 12 hour shifts monitoring all this information. this is the mud longer shaft, which is halliburton. you hear about the diverted which can under some circumstances divert oil and gas over board there's a made it doesn't end up on the rig. and that my guest separator byte, if you have gas, natural gas, at the mud you can separate it here, get rid of them that gas up your and put the mud in the mud pits. now, a lot of people look at

this and they think that this is the deck and then there's not much else. this is one of the lower decks, the moon pool is this business that's been run a long time and are turned years ago somebody look down there at night and saw a reflection of the moon coming up and it's been called the moon pool ever since. the mud pits are important because with a drilling mud is regulated and stored in the mud pits, it is taken from the mud pits, it is moved around in the mud pits and that sort of thing. we will hear a lot more about drilling mud in a moment. this rig is more complicated than it initially looks. the first place, it's not anchored. there are some rigs in the world that are anchored by tension leaks. some by cables. this rig is a ship, it floats. it's not anchored.

it gets positioning signals from a satellite that receives the positioning signals and then there are computers on board that operate these big thrusters underneath. and these thrusters keep the deepwater horizon over the well. this is the rise of echoes down through the moon pool. when you're on it you are not really conscious you are on a ship that is a big thing and it is heavy, but the technology is amazing because this thing is not towed around and can actually sail away and go to the next location. it has a captain just like any ship has. and, of course, that's one of the reason the coast guard has been involved in the district you get an idea, it's kept on station by these thrusters. we tend to put the death appear. now we are going down the riser to the seabed. this is a mile down.

when you're down there it is black dark, can't see anything. it's 32 degrees. we've had to artificially illuminate it here. the b.o.p. -- this is the seabed. sometimes called the mud line. this is the b.o.p., a blowout preventer, which is, you hear more about come is a stack of towels to shut down the well in emergencies but also used for different tasks and functions during the drilling of the well. it's not just an emergency device. the blowout preventer sits on the well had come and then the drilling -- it goes down here through the sands through the formation. so we're already down a mile and we're going down another 13,000 feet, another two and a half miles or so. casing string.

now we will go down. now, down at 18,360 feet, the temperature rsis 265 degrees fahrenheit. the pressures are size 14,000 psi. when you get all the way down there, to pull up the drilling equipment takes 18 hours. so if you want to do something down to come it takes 18 hours to put the drill string. putdowns new tools, go down for many, many hours and do the work, another 18 hours up, and, of course, then back down again. so when you do work down there, it takes a lot of time. it won't surprise you to learn that the out of pocket all in costs, for someone like bp, a running one of these rigs is about a million and a half dollars a day.

and, of course, if you're taking four or five days running drill strings up and down to do work, that's a cause. now, i'm going to say something now and i will say it again at the end. to date we have not seen a single instance where a human being made a conscious decision to favor dollars over safety. i will talk more about that later, but it's important to keep that in your mind as ago. there's been a lot said about it. this is one of the most important issues. we have not found a situation where we can say, that man had a choice between safety and dollars, and he put his money on dollars. we haven't seen a. and if anybody has anything like that, we, of course, welcome it. okay, here's the pace and again. this is where the action was and you hear a lot about what happens down here. now going to talk about drilling

offshore wells, because there are a lot of unique technologies and truly brilliant engineering and called in the endeavors. there's the b.o.p. we will talk about it and explain some of these functions, so when we get down towards the end, it's 50 feet high. there's a six-foot man, weighs about 400 tons, costs about $25 million. the b.o.p. travels with the rig. this is the rising b.o.p. -- a rising b.o.p.. horizon b.o.p. as we stay, the house i can open

and close on the drill pipe. you hear about the annual preventers. we will see them operate in a moment. these are the control pods you read about in the papers. up i grant and close on the pie. the blind shear ram is the last resort in shutting down the well in an emergency. the blind shear ram as you will see actually slices through the pipe. these rams weigh maybe, a blind shear ram may wait 1400 pounds. very hardened steel, and we will show how they operate now. and okay, the pullout prevented sets out the well head on the sea bottom. the drill string comes down to it. drill pipe.

now we will show you, first show you how the annual preventers operates, you will hear a lot about it. hydraulic pressure comes up year. when it comes up, this black deal here is like a giant 18 wheeler truck tire made out of the heart is robert you've ever seen in your life. it's almost as hard as the plastic, and when you want to close the annual preventers, you pressure of these deals, these arms go up and it squeezes this giant hard rubber tire into the annual us. you hear more about the annual is, and keeps any hydrocarbon pressure, anything from coming up outside the drill by. it does not close the drill by. it closes the area around the drill by. okay, let's look at the bible or the pipe ram.

-- variable boer ram. the variable more ram begins to close off the annual's and fits tightly around the close by then closes all. is what we'll call the annual is there. and here's the blind shear ram. this is the last resort when you true grit, it cuts through the drill pipe and a hydrocarbon, oil or gas or anything can come up the drill by. and you will hear, the drilling, the driller sits there in his chair, a big red button behind him, he can push that big red button, and that energizes the blind shear ram and and about 40 seconds later it's got to the drill pipe and the well a shut down in that regard. now, although you've heard a lot about the b.o.p., you may be surprised to know that we're not

going to talk much about the b.o.p. and the reason for that is this. the government has retained a norwegian engineering company to analyze the b.o.p., and it's a two or 3 million-dollar contract and they'll analyze this thing from soup to nuts. it's not done yet. some hoped it would be done by now, but it is not. and for us to speculate on what happened with the b.o.p., was it energized, did it work? if it didn't work, why? all these issues that it would be very premature for us to speculate when some reasonable period of time we will know hopefully what happen. so we will not talk about the b.o.p. said but because it is not productive. we will be talking about when it's to be triggered and who is supposed to do what. but we will not be talking about any failure mode in the b.o.p. today.

now, what a lot of people don'te think that there's these pools of oil and gas down there and you drill down and you stick a straw in a you suck it up. it's nothing like that at all. down here these pay zones are pores in rock. and it's pretty hard rock. it's like a hard sandstone that you can stand on, and the rock is full of pores and the pores of oil and gas in them so there is extreme high pressure, you will see. so as you are drilling down here, you are drilling down to get to the pay zones so that you can, here comes the drill, as you get into the pores here, you can start getting on and gas out. stop it. this is very important.

the brown color here is drilling mud. drilling mud is maybe 14 half pounds per gallon. you will see that the weight can change. drilling mud is used to take the cuttings from the drill bit and get them off the bottom as much comes to the top, he goes over a screen, the mud goes through and the cutting stays so you don't get the bottom of the well just full of all of these cuttings. the drilling mud also served to keep the fluid, the gas and oil, under pressure in the reservoirs at bay. because the drilling mud is designed so that the weight of the drilling mud counterbalances the pressure of the fluid. the red arrows will always be the weight of the drilling mud. the green, the pressure of the fluid. so when you come down to one of these layers of hydrocarbons, oil and gas, the drilling mud,

people continually monitor these pressures and they keep the drilling mud and await such that it is have enough to keep the green on it and gas under pressure from geg bore. and one of the key issues we will be talking about again and again is the tension between keeping the drill mud at exactly the right weight, getting it too heavy and, or getting it to life. if it's too light, the green on gas comes into the well. if it's too heavy and actually fracture the side of the well. it gets heavier than what's called a fracture radius and we will see that. but it's important understand that pay sands, the pay area we are drilling for is raw, actual rock with pores in it that contain this fluid under pressure. okay, now we're talking generically about drilling a deepwater drilling. here's the drill bit.

here's the previous casing. here's the pressure in the formation. at this height it might be sea water pressure. we are going down. the cuttings are going a. the brown is the drilling mud. the pressure of the mud has to overbalance the pressure in the formation. so the weight, the heavier the mud is, the easier it is to keep the hydrocarbons from getting into the well. you do not want obviously to get oil and gas in the well at the wrong time. while you are drilling come it would be really bad to get oil and gas in the well. if it does get in the well, it is what is called a kick and it can be sent to the top because if the pressure starts coming in here, it will change everything all the way up to the talk -- top, and they will say, pressure has changed, there is a kick. so what we do is we continually

increase the mud weight as the pressure gets bigger. pressure is here, gets bigger, mud weight gets bigger, mud weight is bigger. and there's a mud engineer at the surface. here it was someone called him i swaco which was a schlumberger sub. the mud engineers continually change the weight of the mud as they go down and get information on the formation. okay. now this is important. you will see, you will notice when you look at these pictures of the well, it's like a telescope. keeps getting smaller and smaller as we go down. the reason for that is that, as you get down here and the pressure is higher, if that might pressure keeps getting higher and higher and higher, the blood pressure which is needed, the mud which is needed down here, to counteract the

pressure could be so high up here that it cracked the formation. so as you get deeper and the mud weight gets heavier and heavier, periodically you run a casing. casing is just a circular piece of steel that comes down, and after you run the casing, which is here, then you run cement down the center. the senate goes to the bottom of the well, turns the corner and goes up the side. so the casing is thoroughly cemented in. and you'll see, every time you see a picture of a welcome you will see these from the top on down. you see casing cement, casing senate, casing cement. and as you'll see in a minute, this isn't the bottom of the well. you have to keep doing this. so they will have to drill this out when they did this casing cement. when it's at the service it doesn't take so long. when you're setting casings at the bottom it could take 18 hours to bring up the drill

pipe, put on a casing, bring up the casing tool, but the drill pipe back down. it could take a couple of days to do some of these things. now, this is key. here's the pressure. remember that the hydrocarbons are in the rock that there under very high pressure. as you go deeper, the pressure gets higher and higher and higher. this is the fractured radio. the fractured rating is the amount of pressure that will take to put a hole in the formation. if you put a hole in the formation or crack it, bad things can happen. you can lose some of your drilling mud. you can losing it. they don't want to break the formation of the vote of the. and as they drill down here, you will see their continually changing the mud weight to stay

in between the green line and the blue line. that is one of the secrets of deepwater drilling. keep the red night in between these two lines as you go down, continually fine-tuning it up on the surface. the mud engineer is doing this, changing the mud, mixing the mud so it's exactly the right weight so it keeps out the green pressure and doesn't break through the blue formation. that's one of the keys. here's a place where it is coming very close. to the poor pressure. and when you get to a place where you are challenging these two, that's when you put in another casing. up comes the drill string. down comes the casing. down comes the cement. and it always turns the corner

and goes up. now there's something i want to explain right now. this is hard for a lot of people to grasp right away. this area here is called the annulus. this is out the center of the casing, and this is called the annulus. it looks pretty big, but we brought this out here, and train it will take this around and show people, but the annuals is a very small. this is the casing in the center. this is the formation, and we have to pump cement as you'll see into this small area. at the bottom, this might be 1000 feet of cement. that's as high as 100 story building. it is an art, to be sure that all of this is the was cement, all the way around. there's no gaps. the gaps are called channels

that we will talk about that later. but this is pretty much to scale. and we look at these it looks like it is a big wide thing. it is not easy to get cement all the way a round here at the small little annulus over the height of a 100 story building. shawn will just take this up and down the aisle so everybody can see it. the commissioners are of course aware of this. we're shown the commissioners at length. okay. now we are going to talk a little more about drilling a deepwater well. the big out here, coming down through the moon pool. these are called tool joints.

it's interesting that when you first start at the surface drilling a well, the formation is not as hard as it is. it's not as rocky as it is. so when you start drilling down, you can just check out, maybe 36 inches, you can just check out the formation with water. you simply send water through the drill pipe and jet it out. as a matter of interest you don't have to drill it all the way down. and, of course, you have to vent the water out through here. said the casing -- set the casing. of we go. now, we've heard the term riser.

an important term. before you come at the very top, you don't need any drilling mud to balance the pressure because the pressures aren't that great. but later on you need some tube to go around the actual drilling pipe, the drill pipe. to contain the mud. so you can imagine the drill pipe is like this and then there's a big riser ground is that goes 5000 feet up to the rig. and you will hear, if hydrocarbons get in the riser, that is bad. because that's above the deal be. it means somehow they have gotten the past the blowout preventer, there in the riser and as we'll see once they get in the riser they will come up very fast and they are very dangerous.

stop it, please. remember, i told you that in all these interim steps as you go down, you cement around, then you have to drill out the cement you just lay. you want to keep the cement in the annulus, but you need to drill that out to continue drilling down through the formation. always pleasing member, when you look at the annulus here, this is half-inch to an end. it's a very small space. we have to distort this in order to make our point, but as john showed you, the annulus is very small and there's some skill involved in a mild amount of predictability in getting the cement and the annulus all around the well. but you have to get the cement in the annulus, as we will see.

wellhead. now we have cemented in another casing. now we are lowering this 400 done b.o.p. to put on top of the wellhead. when you imagine somebody lowering from a mile up, a 400-ton piece of equipment, putting it in place like that, you imagine the engine and count that is involved in this deepwater drilling.

and then of coarse the drill string -- once the b.o.p. is on, if it is operating properly you can shut off, close the annulus other pointed out. you can actually cut through the drill string, completely shut the well down. doesn't go this fast. i got tired of watching a go at the right speed. here's the riser. and once we get down a certain depth, the drill string is in the center of the riser, and the mud circulates on the outside of, down the center of the drill

pipe and then comes up on the riser on the outside. circulation of the mud is very important that you will see more about it, but the mud will come down through here, they will drill at the bottom, the cuttings and the muggle. him it will be cleaned and it will go back and and they will continue circulating. i will make a point that is very important, and we will make it again and again, but this is a closed system. and you out to get as much mud up at the top as you put into the well. in other words, you put it in and it circulates that if you begin losing mud, it means to get a problem down there. that is called lost returned. and lost returns can be important. in other words, the mud is returned to the surface to if you're not getting up as much as you should be you better stop and check it out. and their work lost returns here. -- there were lost returns here. here's the macondo timeline. we have talked about the rig

generally. we have talked about the signs of drilling offshore, and using how generally cement issue. you have seen how the casing is late and that sort of thing. now we will talk about the timeline of macondo. originally, macondo was being drilled by a different transocean rig called the marianas. it was about 9000 feet, and hurricane ivan came along, marianas was damaged and they had to take it off and bring in deepwater horizon. deepwater horizon drilling began february. here they had a kid. we all now know what he take his. hydrocarbons somewhere down there and there's an indication that pressure shows you that there is cascading and. what they had to do here is, they kick caused a certain piece of equipment get stuck in the pipe. so what they did is they are able to, believe it or not, they can come down and they can just

go off at an angle and keep drilling. so they can change the angle of the drilling, moved over, avoid the problem and start doing again. that is called a bypass. believe it or not, even after they bypass the well is very straight. this is one of the most vertical drills -- wells people have seen. that means it was straight up and down, not at an angle or anything like that. and on april 3, they get severe lost returned. will now learn what lost returns are. this again is very important. this is 17 days before the blowout. now, we are back to where we started a little bit. we can now see the whole well. remember, i told you the problems at the bottom. here's the cement work at the bottom. the formation that they were

trying to produce oil and gas from was here, and this is the annulus. it's not big. it's tiny. and that the cement here has to isolate the hydrocarbons zone your it's called zonal isolation. and if the -- if the cement here does not isolate the hydrocarbons in here, they can get in the well and come up to the surface. so the cement job, called the the primary cement job at the bottom, the cement job has to keep the hydrocarbons in those pores. cemented off from the well bore so they don't come up the well. there were difficult drilling conditions here. now, we've talked to everybody we can find about the gulf of mexico. and many say -- you a frequent encounter difficult drilling conditions.

sansei not this difficult, there are different points of view. what we are going to do now is to show you, back up one, please come at the time of the key cement job, what was known about the situation in that well. so we're going to go through a number of things that were known. they started the cement job and i think the evening or the afternoon of april 19, the day before the blowout. they finished a little after midnight on the day of the blowout. when they started, at the time they started the cement job, what did they know? number one, difficult drilling conditions. none of these -- this is the actual macondo pressure gradient. and as you can see, as we go down, every time you get the mud over into one of these areas, you put a casing in, might gets

closer here. you put a casing in. you keep going down. this is why you get the typical kind of a telescope looking deal. and you can see your the mud is getting very close to the pressure from time and time again. so this is the fracture gradients at macondo. air having somewhat of a hard time keeping the mud in between where it had to be. now, the things i'm showing you, this is not at all abnormal. each one of the things i'm showing you is a very's degrees of frequency, but that's what these guys do. they are good at keeping the mud weight ought to be and doing these things. so don't assume when we say that there was a narrow fracture gradient, oh, my god, that's terrible. people trail that all the time and they're supposed to drill it, and it works, okay?

now, transocean driller, mr. burgess, difficult well. wouldn't say worse than others, it was difficult. . . >> cement placement is critical. and i'm going to say some things, and some of these things need to be said twice. placing cement when you're up three-and-a-half miles above from here to the iwo jima memorial or something like that is not an easy thing to do.

you can't see the cement down there at all. you have to sense by secondary measures like pressures, and sam will explain more, where the cement is. you want to be sure, obviously, the cement is placed high enough to block off the zone but not so high that it causes a problem closing up the annulus and causing a heating problem which sam will talk about. so people knew when they were doing this, halliburton and bp, that they had a challenge in getting a good cement job because of the, this narrow fractured radiant. again, people look at things, say, oh, my god, that's terrible. it's not terrible. it happens, and people deal with it all the time because of the engineering talent that they have. now, now, we've heard a lot about the long string. the press has said again and again and many experts have said

that nobody in their right mind would use a long string. here's the difference. this is the well design they did use. you'll notice that there's a long string all the way from the bottom all the way up here into the wellhead. that's called a long string. here is another choice which is a liner. the liner would only go to here and would be tied back here. some have said that the long string design does not have a barrier here, this little annulus is open so that a leak could go up here into the wellhead, it doesn't have enough barriers. i will show you the proof -- i think all of us now believe including bp and transocean -- that the leak did not come up the annulus. the leak came up the center through what's called the shoe. so that the long string has

implications, as sam will explain it has implications for cement placement, it has implications for whether the cement can get contaminated. but as we see it now and i'll say this as often as we can, we are ready to listen to anybody from any source that knows something we don't know. but talking to the designers of the equipment, looking at photographs of this equipment which i will show you, our view is that the leak did not come up this annulus, but came right up the center, right up here through -- into the riser. it's important you know the differences between these two, and sam will explain the implications that the well design has for cement jobs. okay. we now know there's difficult drilling conditions. we also know they had lost returns. what's a lost return?

you're drilling, here's our drilling mud, circulating around up and down, taking away all the cuttings. and if mud, if drilling mud pressure gets too high, it can go into the formation. you're now losing drilling mud. if you're at at the surface now, you're putting down more mud than is coming up. you want to get full returns. you want to have as much mud coming down, coming up as is coming down. and this means if you, if you lose returns, one thing that can happen is you crack the formation, and the mud is going into the formation. if mud can go into the formation, then if you cement the job, cement could go in the formation too. this was something like a 60-barrel cement job, and it was a relatively low-volume cement job. and you have to keep in mind that if you can lose mud into

the formation, you can lose cement in the formation. there were pretty serious lost returns here as they got down near the bottom. now, originally they were going to drill this well down to about 20,000 feet. they drilled it only to 18,360 feet. and why was that? because when they got down there, they faced a tough decision. they were getting lost returns into the formation. this is a bp employee that says drilling -- they were going to drill to 20, they're at 18,000. 2,000 feet short. drilling any further would jeopardize the well bore. having a 14.15 -- this is the pressure exposed and taking

losses in a nearby reservoir, that means that this is higher pressure, this is lower, so it's actually circulating from one reservoir to another, had forced our hand. we had run out of drilling margin. at this point it became a well integrity and safety issue. total depth was called at 18,360. so they saw conditions caused probably by the formation which caused them to stop short of where they'd planned to go. now, i know i keep saying this, people look at this as, oh, gosh, well integrity and safety. they stopped because they were interested in this well integrity and safety. they didn't go as deep as they could have gone, and they might have reached more hydrocarbons because they wanted to stop so they didn't create safety problems. so you have to be aware of two things. you have to be aware that surprises in the reservoir can cause you to make changes, surprises like that can effect what happens later.

you have to keep in the back of your mind. but it's good, not bad, to stop here for safety reasons. so bp near as we can tell in talking to our experts, you know, they did the right thing here. now, this next point is a complicated point, but it's important. that's converting the float equipment. let's put that up. now, you're going to hear the term shoe track. that's another one of these oil business terms. my wife's family's in the oil business, and they talk about the oil business west texas, shoe track's an all-business term. let's look at it. here's the bottom of the well.

the roemer shoe at the bottom that leads the long string down, and here's something called the float valve's up in here. and let's focus in on the float valves at the top. it's in the float collar. the shoe track, everything's being down here. it's the height of a 19-story building. so when you, when you put the long string down these float collars, these valves, one-way valves, -- >> pull on this. [laughter] oh, it's the wrong one. [laughter]

it's nice to have sandra day o'connor clerks to correct you when you screw it up. [laughter] so thanks, sean. so as we -- this is a valve that has to be open when it's going down. it has to be open when it's going down because if it was closed, you tried to push it down against all that mud in there, you'd create high pressure and maybe fracture the formation. i'm always glad to see a guy nodding that actually knows this. [laughter] i'm getting it right. so you want to have this open while the long string is is going down. so they've got a pretty ingenius way of doing it, they have it open, and they put -- this tube

is in here, as you can see, that the valve is now open. it holds it open. now, when you get to the bottom and the shoe's in place, you want to close this valve because now it's down in place, and you want to be sure that hydrocarbon things can't come back up through it. so how do you take this at the bottom and convert it? pretty ingenius, pretty simple and pretty ingenius. what they do is they drop this little ball down in the center, goes to the bottom, and we'll see these two little holes here. so the mud is coming out of the holes, but the holes are smaller than the origin deal was. -- original deal was. so that you increase the mud flow and increase the mud flow,

and pretty soon the pressure is such on the ball this falls all the way to the bottom, the valve is converted, t closed. so 18,360 feet down you turned a two-way valve into a one-way valve. now, the problem is that these things are supposed to convert at about 750 psi. we'll run through this again up here just so we get it. he's the valve -- here's the valve before it's converted, pressure can come here, pressure can come here. it's a two-way valve. now we'll run it. ball falls, ball sticks because there's a collar here. then you pressure it, and it goes all the way down to the bottom in the shoe track, 190 feet down. ends up in the roemer shoe. we'll talk more about the roemer

shoe later. now, just to give you an idea, roemer shoe, float collar, 190 feet, here's the pay zone. we've now got the valve the right way. this may seem like a small issue, but normally these things convert pretty readily at about 750 psi. didn't work out this way. they had to try nine separate times to get this float collar to convert. now, again, i have to keep warning you don't put too much import on any one event. we're now building up to all of the different events that were known in the minds of the men on the rig that night when they got ready to pour the cement job. and there were some anomalies, as we've seen. not anomalies that are never encountered, not anomalies that

were necessarily anybody's fault, but there were anomalies that people would be aware of. so now let's talk about the problems in converting the normal float valve conversion. very simple. roemer shoe comes down to the bottom of the well, this is 190 feet. circulate it. 750 psi. float collar converts, valve's closed, you're set. what happened heresome -- what happened here? roemer shoe comes down shoe track. remember, they want to get this out of there. they put it down, first attempt. 1800, doesn't work. supposed to come to 750. second attempt, 1900, doesn't

work. third attempt, 2,000 psi, doesn't work. fourth attempt, 2,000 psi, doesn't work. fifth attempt, 2,000, doesn't work. sixth, doesn't work. seventh, 2250, doesn't work. eight, 2500, doesn't convert, still stuck there. ninth, 2750. finally at 3,000 it converts, maybe. maybe. we don't really know if that ever converted or not because it's now cemented in down there, and there's a lot of different things that could have happened here. for example, what could have happened is that the ball was forced out of the tube on the

ninth attempt, but the tube stayed there, so it's still a two-way valve, and hydrocarbons or anything can go back up the well. we don't know if that happened. these are the best judgments of possibilities, and nobody will ever know what really happened. secondly, can we go back to number two? >> [inaudible] >> oh, okay. third, as sam will explain, it's possible in a long string well that you can get debris -- mud that's been scraped off the walls on that long trip down some 13,000 feet, on that long trip down it's possible that you can get debris in the bottom of the roemer shoe. it's possible that when they are pushing and pushing and pushing here that this was jammed with debris. some debris went out, the pressure dropped, and they

thought that the float collar converted, but it didn't. it was still wide open both ways. now, secondarily here, it's not altogether certain that a failure to convert is a huge problem. because most people in the industry do not consider the float collar as a barrier. you'll see the term barriers. the cement is a barrier. certain seals are barriers. some people will say this is a barrier, some won't. when you look at this valve, even if it converts under the kind of pressures we're dealing with, it would not be impossible to get leaks around it. clearly, though, if it's wide open, it's easier to get leaks. one could, some say -- i've learned the way newspapers report things these days -- some say that this whole thing is such that under the kind of pressures that were established when the reservoir, hydrocarbons got in the well this whole thing

could come apart. so what do we know? we know there was an anomaly. we know they normally convert at 750, it took nine tries and was over 3,000, and we don't know if it ever converted. and the people up on the rig know this. we're not saying good or bad or up or down, we're just trying to list the events that were in the men's minds during that night as we come closer and closer to pouring the cement job, and we'll see that the cement job is important because the way, the way the rig was handled on the evening of the blowout beginning 8:00 at night meant that the cement job was the only barrier, the only barrier preventing hydrocarbons from getting into the well. so as we're getting ready to do the cement job, it's worthwhile looking at what people knew.

okay? now, we've had a problem converting a float equipment. now we see that after it's converted we see another anomaly. we see pressure lower than was expected. low circulating pressure. this is the pressure. it was expected to be about 570, it was only 340. now, this may mean something, or it may mean nothing. was this ever resolved? it was not. the pressure of the mud circulating was, you know, almost a little less than half of -- little more than half of what it was supposed to be. so what did the rig, what did the crew do when after they'd just had this problem with the conversion of the float valve these pressures showed up wrong? not what was expected? this here's what they did. here's what they did.

the company man -- that's bp -- again, this is oil industry lore. the bp man on the rig, the well sight leaders are always called the company man. that's always a bp guy. so bp was uncomfortable with the circulating pressure being so low. spoke with mr. gagly yang know, that's the halliburton cement engineer on the rig that night. and what'd they do? did they ever resolve the situation? here's what happens next. i don't believe it ever got resolved. they felt the gauge was wrong. and they decided the rig's standpoint pressure game was incorrect -- gauge was incorrect. maybe it was incorrect, maybe it wasn't. and you can debate about what was done to decide if it was

incorrect, did they simply say we think it's incorrect, did they test it? that's for further inquiry. but we know they had a problem converting the float valve, and after that the pressure was low, and apparently -- and i stand ready to be corrected -- apparently, they assumed the gauge was wrong, and that was the end of it. now, would this make a difference? we're not saying that it did. we're listing things that happened and describing how the people on the rig reacted to it that night. no bottoms-up circulation. here's bottoms-up circulation before you pour cement, they circulate the mud coming down the center. here's the indicator of the mud that was at the bottom. bottoms-up marker goes all the way to the top circulating, circulating, supposedly hope fully cleaning this out down here. before you add cement, you wait

for the bottoms-up marker to get to the surface. that is the normal way of proceeding. and there's reasons for doing it. the reasons are -- now the cement's added. sam will explain this when we get to the cement job. why do you do bottoms-up? well, the mud is conditioned. remember, you're changing the mud weight as we go, so when you circulate the whole thing and make sure you get uniform mud throughout the well. secondly, it circulates the cuttings, gets any cuttings out of here, out of the shoe. we now know what the shoe is, it allows the crew to look at the mud that comes up from the bottom to see if there's any hydrocarbons in it. this is normal. bp did not do bottoms-up before the cement job here.

they had a reason for doing it. they didn't just decide to hurry up, and here's what they did, and here's what their reason was. here's what bp did. here's the bottoms-up marker. remember over here you waited until you got to the top. bp sent the cement down when the bottoms-up was only there. so when they did bottoms-up, they'd done about, i don't know, maybe a fourth of the circulations normally done. they had a reason for doing it. remember, we'd had these formation problems down here. they'd had lost circulation. they didn't want to disturb the formation any more, those are valid reasons for not doing full bottoms-up. when you don't do full bottoms-up, there can be consequences. we're not saying there are, but there can be consequences in that the shoe track cuttings might not have been cleared out, and maybe the hydrocarbons weren't tested before cementing. but, again, no one of these

things is the be all and end all. we see things happening, and we see people having good reasons for it. one of the things that we'll talk about -- and we've discussed this with the commission -- is that it's important maybe not to put behind you events in the past and then start from scratch each time you do something new. maybe there has to be a way where people keep in mind the other things they have been experiencing as they went down here when they make their final decisions. and i'm not saying because we'll never know for the reasons you've heard, we're not saying that people did forget all this. we're not saying they didn't either. but the fact is there were a lot of events, and it sort of looks like once another hurdle was over, some people might have said, well, that's solved, and sort of started from scratch and maybe there has to be a way to keep track of everything that's gone before. at any rate, bp didn't just say we want to save time. bp said we lost circulation, if

we do full bottoms-up, we might have more problems with the reservoir down there, and we can always once we get this up to the wellhead, we can always circulate it to the surface and check it and look at the cuttings and look at things. we don't know if that was done, presumably it was, but that's something i don't know as i stand here today. okay? mr. guide is the shoreside, shoreside well team leader. if you're drilling a well in the gulf and you go to houston and you go to bp or shell or any of these companies and you go in the their offices, there'll be a room almost as big as the end of this room that's dedicated to the macondo well. and the shoreside engineers and personnel will be in that room. and the data from the well will go to that room, and can the

shoreside people who are -- and the shoreside people who can look at the data and communicate with the well are frequently asked questions about the well. so all the information is gathered, and that's why we have some of it today. now, mr. guide said he asked why didn't they do complete bottoms up. the biggest risk with this cement job was losing circulation. that was the number one risk, losing circulation. remember, we explained if mud or cement gets into the formation, you're getting less at the top than you put in, and you're losing circulation. so mr. guide said we decided to get circulation established, and we could always do full bottoms-up later once the cement was in place. that's why they made the decision. now, this is something that a lot of people are not aware of. we explained that during the final hours of the well the

cement job at the bottom was the sole barrier, the only barrier in the well between the hydrocarbons and the rig. that's because to do what they did, as sean grimsley will explain, they had to have the b.o.p. open. there were no other mechanical barriers in place. so the cement job was it. now, what's interesting is it is known in the industry that these cement jobs are, from time to time, not perfect. it's not an awful thing. nobody has screwed up. it's not an easy thing, as we explained, to fill a thousand feet of narrow annulus with cement. so sometimes it, you have spaces in the annulus. and you have to, you have to remediate or fix a cement job. so let's look at this. here's a cement job, and you can

see this is that skinny little annulus that sean grimsley showed you, and for one or another reason the annulus doesn't have cement in it here, and it should. believe it or not, these engineers have developed ways of being down there 18,000 feet and fixing that. here's what they do, it's called squeezing. the term squeezing is important because there's a critical e-mail that uses that term. here's the situation. if the casing isn't centered in a well, and as you'll see it's pretty hard to center sometimes, then maybe when you put the cement in around here, it doesn't get in here and leaves mud. cement keeps hydrocarbons out of the well, mud can't keep hay do war bonnes -- hydrocarbons out of the well under those conditions. so you know there's a problem here, and you decide you want to

replace that cement down there 18,360 feet, replace that mud there with cement. how in the world do you do that? well, here's what you do. send down this equipment, first comes a packer. a bridge plug. you're going to squeeze in here, this is the area. you set this down so there's pressure that's blocked off here. you still want to get cement in here. how are you going to do that? you set a packer here, so it's blocked off here, blocked off here, and you want to get cement here. they put down a, basically, a perforation gun. for those who have been in the military, these are like the shape charges they use to penetrate tank armor. they're very powerful bullets, in if effect. in effect. and they send an electrical charge through and actually put a hole in the casing. and then they send cement down,

pull up the tool 18,000 feet, and they put in cement. can't go here, can't go here. it's stuck, so it fills up, fills up, fills up, fills up. and when it's full, it starts to squeeze through these holes into the formation. and suddenly they've repaired this -- it's going to take 2-5 days to do this -- but they've repaired the missing cement in the annulus from the top. and, of course, this wasn't -- this is done with some frequency, and it'd been done twice before on this very well. so we know that in october they'd done a squeeze job, february cement squeeze and march 6th, squeeze. so what do we know now?

we take stock. we know that the cement at the bottom in the last hours was the only barrier. we know that sometimes these barriers are somewhat defective when they first go down. it's not a big deal, it happens. and there are books written this thick on how to fix these jobs. we know there are ways to fix these jobs. so the issue you want to think about, the possible, potential vulnerability of the very critical cement job, the potential -- we're not saying it was vulnerable, but the potential vulnerability was known. because it was down there, it's the only barrier. these jobs, sometimes these jobs have to be fixed and be remediated. this particular cement job was never remediated for reasons that sam sankar will explain. but the importance is you know that the cement jobs are, from time to time, not perfect.

and there's nothing wrong with that. it happens, it's routine and they've developed all kinds of ways of fixing it. now, there's something called cement modeling. bp has a program called optimizing cement, and it's a proprietary software program bp owns that is used to figure out what's going on down there. design centralizer placement, evaluate job results, predict pressures, that kind of thing. and it turns out that the well team leader, john guide, shoreside didn't put any faith in the bp model, thought it was wrong a lot. now, i imagine there'll be a dispute emerging about whether it's right or wrong. the only question is what was known that night. and we're not saying that it was right or wrong and can that that

caused any problems. we're just saying that we're running these, as sam explains, they were running these cement models, these software models, and the bp man in charge didn't think they were worth much. okay. at this point we've been setting the stage for all the things that have been known in the industry generally and things known on this rig. now we're going to turn to this particular cement job, and sam sankar is our cement guy on our team. he's been involved in this from the beginning. he went down with chevron when they did the tests, and it's nice to hear somebody else's voice. [laughter] so sam will take over and talk about the rest of the cement issues. >> so what we see here now is is that the crew on the rig is facing a number of known issues

at the time that they're doing their cement job. the one we should focus on right now is the serious lost returns in the zone to be cemented. having serious loss returns, again, is not in the and of itself a tremendous problem. but it complicates the cementing. when you're cementing a job where you know you're going to have lost return or you have a threat of lost returns down in the formation, you have to be careful. so bp designed a cement job for this process that was somewhat complicated. i'm going to show it to you a couple of times. first time i'm just going to show it to you in three dimensions, and we're going to go through the various fluids that bp pumped down the pell. well. now, the first fluid, what happens is is you send these fluids down the well. you have to send them in sequence. the mud is is oil based and the cement is water based. the two don't get along. so you have to send things between them to keep them

separate. you'll see an orange material and a purple material. i'll explain what those were for. these things went down in sequence, separated by separating fluids and by mechanical plugs, and at the end of the job you had cement in the shoe track between the location of the float valve and the roemer shoe, and you also have cement all the way up here in the annulus covering your pay zone. so we've been emphasizing a lot the importance of isolating the pay zone. you may be wondering how do you actually get the oil out after you do all this work to isolate the pay zone. i'm going to give you a little preview of something that sean's going to explain a little more as well. when you come back to the well after you've finished drilling and cementing it, you produce it by doing something very similar to what you did when you squeezed it. you go back down to the bottom, you have that cement in the

annular space, and you send another tool down -- another perforating gun much like the one used in the squeeze job -- except now you're doing it in the pay zone. now this yellow area here is full of hydrocarbons, and you've got your cement currently isolating them from the annular space. to get them out, you send the perforating gun down, you poke holes in the casing and the cement. so now what you have is holes in the steel casing and in the cement that allow the oil to flow into the well. but that's later when you're getting the oil out of the well. for now we're first trying to get a good cement job that will allow us to isolate hydrocarbons. so now i'm going to go back and explain again the cement job that bp used at the bottom of the well. and when i say bp here, i mean

bp in conjunction with halliburton. halliburton was the cementing contractor for this job, and bp and halliburton worked together to perform the process. so again, what we see here now in schematic view is the float valve, the roemer shoe, the volume in the shoe track and also, again, the skinny annular space that fred has shown you. remember, again, when we're doing this that we're talking about the annular space that sean had showed you when he walked around. it's the small, narrow area in there between the casing and the formation itself. so to begin the job, as always, you're circulating mud. the mud's going down through the float valve. the first thing that comes down, again, is that base oil. the purple here is showing the base oil. base oil is a lightweight oil that they decided to use on this well in order to lighten the weight of the mercurials in the annular space. i'm going to show you a little

more what that is. the orange material, again s a spacer. it's a material that's compatible with the mud and the cement and helps keep them separate. you're going to see a plug land out very shortly there. that plug right there mechanically separates the cement from the mud. now, you see some dark gray material and then some lighter gray materials. the dark gray material is the cement that they were pumping down there. you've heard a lot about nitrogen foam cement recently, this is cement that hasn't yet had nitrogen added to it. the whiter cement is the cement that does have the nitrogen in it. so now we have a slug of unfoamed cement followed by lighter cement followed again by the heavier cement. now, what's important to note here is the first material that goes down the well is the first that comes up the annulus as well. so now what we have here is a stripe of the spacer and a

stripe of the base oil. as these materials come up into the annular space, they're exerting pressure backwards. on the way down the well, gravity was helping you. on the way up, here, it takes pressure to lift the cement up. and that pressure is something you feel in the formation. and remember that, again, they're very worried about lost returns at this point. loss returns are caused by, among other things, overpressuring the formation. so a lot of this cement job was designed to reduce the pressure on the formation. final position of the cement job is you have a top wiper plug in place, a bomb wiper plug in -- bottom wiper plug in place. the shoe track should be full of unfoamed cement and the annular space should be filled with lighter foamed cement, primarily with a layer of unfoamed cement at the top.

now, that slide may have struck you as a little bit complicated. n., you're right. this was a comply -- in fact, you're right. this was a complicated cement job. the number of fluids being placed down the well and the threat of lost returns led everybody to understand it was a complicated cement job. there's e-mails showing that bp recognized that this was an important job, that it was not going to be an easy one, and in bp's report issued after the incident, it is repeatedly recognized that cement placement was critical, that there was a complex design and that the cement crew and the cementing engineers and the design team were focused primarily on achieving an acceptable equivalent circulating density during cement placement to present lost returns. equivalent circulating density is a fancy phrase for pressure on the formation. they were trying to make sure that pressure on the formation didn't get too high.

this was, as bp has acknowledged in its report, this was a challenge. another way of reducing the pressure on the formation is to pump the cement more slowly. if you pump it very fast, it takes more pressure. experience with that, in order to make a liquid flow through a pipe faster, you need to increase the pressure on it. so the design team chose a low cement flow rate. again, this is showing that same animation again, only we're going to emphasize flow rate now. again, the faster you pump, the more pressure you use. and so the cementing design here in order to avoid problems with overpressuring the formation, use the low cement flow rate. now, a high cement flow rate is helpful generally when you're cementing because, among other things, it helps clean the formation and scour out any remaining gelled-up mud or debris from the annular space. again, a fast jet of water will

clean something better than a slow jet of water, and that's why high flow rate in the cementing is helpful. here, however, they recognized that that would be preferable, but because of that circulating density concern, because of the concern about overpressuring the formation the team chose a lower rate. and, again, as fred has been saying, these were decisions that weren't made consciously. as the report acknowledges, i'm sorry, as the cementing design acknowledged they had consciously chosen a reduced rate of cementing in order to avoid, again -- there's that phrase, ecd. ecd means pressure, in order to lower the pressure on the formation. again, now, we have another issue that in and of itself is not a problem, and it's not uncommon. but it's something that the crew needed to be keeping in their mind as they were thinking about the long-term quality of the cement job and what they could expect out of it.

another factor, low cement volume. again, driven by the very same concern about pressuring -- about overpleasuring the for-- overpressuring the formation. again, what we've been explaining is that if you, if you overpressure this formation, you risk losing the cement into the formation, losing cement into the formation, and the cement doesn't do what you want to. it doesn't isolate the hydrocarbon zone. so one way, again, to reduce the pressure is to reduce the top of cement. keep the cement lower in the annular zone than it would have otherwise been. bp had two reasons for reducing the height of the cement it put in the annular space. one reason was about trapped annular pressure. as this animation shows, if you

close off all of the area in the annular space over here, you can increase the pressure on this, on this casing. and that's because the oil in the bottom of the well is quite hot. fred explained it can be up to 260 degrees. when you take hot oil and run it up the inside of this production casing, it's going to make the things around it very hot. in particular, it'll make this space in here, this annular space in between the two casing strings, it'll tend to make it expand. and when it expands, it creates pressure. that pressure can be very problematic. if it goes too high, it can collapse the inner casing string. that's a disaster for the well. so if that pressure in the annular space gets too high, you collapse the casing, and you've lost your well. again, a disaster that you want to avoid. so that's one reason bp was -- one thing bp was concerned about, and they did two things

to address the concern. first, they put burst discs into the outer strings so that if that pressure goat too high, the burst discs would allow it to escape rather than collapsing the casing strings. but they gave themselves another way out as well. they said, we're going to not cement the casing all the way up into the next liner. that will leave us an open space here that'll give any pressure a second way of getting out. now you have an alternate path for that annular pressure to be, to escape. so there was the pressure escaping. the end result of this is is a lower top of cement. as fred described, this is a low-volume cement job, about 60 barrels of cement. that decision was driven in part by the annular pressure concerns and in part by the concern about

overpressuring the formation. again, the higher the cement goes in this annular zone, the more pressure it exerts on the formation, and the more likely you're going to have lost returns. so in the end bp chose to run the annular cement about 800 feet above the pay zone. now, mms regulations only require 500 feet, but bp's internal guidance documents required a thousand feet. it is okay to deviate from those, from those guidance documents under certain situations, and here the team said we want to reduce the pressure on the formation, we are consciously going to make a choice. fred previewed this issue for you again. the concerns about long string versus liner that have been explained in the press have gone

against the barriers to annular space. that's the first difference between long strings and liners. again, as fred showed you, there's a seal up here on a long string. there's similarly a seal down here on the liner called the liner top packer. that goes to whether or not the hydrocarbons could come up inside this annular space. but there are other reasons that a long string versus liner decision becomes important. one is, again, the cement circulating pressure. in a long string, you have to push the cement a little harder to get it to come up the annulus. because it's a skinnier space than with a liner. you can see there's a much bigger open space for the mud returns to come back up to your riser in a liner. so that's one reason why a long string can require more pressure to cement than a liner. all other things being equal.

there's -- as you see over here, when the liner comes down, these returns are coming up again. the wider space here, not the skinnier space that they're using in a long string. another reason as well, differing risk of contamination. now, we've been showing these wiper plugs largely in schematic view. i'm going to show you more closely what they do. the point for now is to recognize that as they come down, they take some mud with them. that long 3-mile tube even after you've sent wiper plugs and spacer down there is going to have mud on it. and as i've said, the mud and cement don't get along. but there's going to be some contamination, and everybody knows this. the contamination, all things being equal, can be more with a long string. with a liner, you're running the plugs down less distance.

>> here's the plug in more detail. what i was talking about before was if you have these wiper plugs scraping the mud down the sides, they will leave that mud in the shoe track. fred showed you a slide in which mud in the shoe track, cuttings in the shoe track could cause problems with having, having -- with converting the float valve. and here what we see is mud in the shoe track brought there by the wiper plugs as they come down. fourth difference between liners and long string is the cementing approach. on the long string, you need to leave that little annular space open to allow for pressure to's escape. to escape. so, again, you don't want to run your cement as high as you might otherwise.

on the liner, by contrast, you can eliminate the annular space entirely. you can run the cement all the way up to that seal, and the result is that you have a completely sealed system here and more cement. the point here, again, is that more cement is good. you're running your cement down a long pipe in an uncertain area. the more cement you put down there, the more cushion you have to make sure the job goes well. bp recognized that liners and long strings had different consequences for cementing and engaged in a debate in april in conjunction with halliburton deciding how to do things. the original design called for a long string way back before they actually started drilling the well, but the engineering personnel changed their minds when they looked at the ecd issue, and they said, let's use a liner instead. it reduces -- second reduce the

pressure on the formation as we cement this well. finally, after looking at the halliburton models again in conjunction with an internal bp cementing expert, the team decided that the long string could, in fact, be cemented. now, the long string has some value over the long-term life of the well. so there were reasons why they wanted to use a long string that weren't directly related to these initial cementing concerns. again, using the long string itself not a huge problem, just requires more attention to the way that you do the other operations. so now we're going to talk a little bit about the famous centralizers that you may have heard about. fred will show you what these look like. so we're going to go back and

show you an animation about what the actual centralizers do. the actual centralizers used at this well were about 4 feet high, so the ones we have here are just little models. the point here is is that you have that skinny annular space. i'll hold it, you wiggle it. and if you don't have the pipe right in the middle, you can cause problems. among other things -- >> you can see you want cement all the way around it. and if it gets down here, it may be harder for cement to get in here. so you want to keep this right in the center. and, remember, this is a thousand feet or so. so you want to be, you want to do everything you can do to keep it centralized. >> and one way you can do that is with a centralizer. a centralizer, that's a model. we have a real one sitting up here for a smaller diameter well. nothing more than this. it does exactly like what it looks like it'll do, it helps

hold that pipe smack in the middle of the hole that you've got. >> and as you can all see, even with this little artificial centralizer, it keeps it in the center. all the way around, it doesn't get up against the side. i'll just walk around like grimsley did so everybody in the back can see. these will be up here, by the way. if you want to look at them during the break, people are welcome to look up. you want to keep it in the center, obviously. >> so now i'm going to show you on this animation what the value of a centralizer is. if you don't have your pipe centralized -- we're going to use the one on the right as an example of a noncentrallized pipe and the one on the left as a centralized pipe. we're going to start running the mud now. first, show you again what you've seen. this is in planned view what the effect of a centralized pipe looks like. if you're running the mud, the

mud's fine, it's going everywhere. but the cement, you want it to come up on both sides of the well. you can see on the one on the left, the cement is flowing evenly on both sides of the pipe. the one on the right there's some mud left behind. the mud's taking the preferential flow or the cement's taking the ease ier path up and leafing some -- easier path up and leaving some mud behind. that's called a channel. that's an area where it's easier for gas and oil to come in. you want to avoid it. so bp's original design called for more centralizers than they eventually used. but there was a problem, there weren't enough of the kinds of centralizers they preferred. they're called centralizer subs. so what's a centralizer sub? show you on the next slide. there's a picture on the left of a centralizer sub versus a centralizer with a stop collar. the ones on the left are screwed

into the pipe joints as they go down. that means they're very securely on there, they're not going to move around. whereas the ones on the right which are more like this slip over the pipe and require some stop collars to hold them in place. when you have those stop collars, you have additional material on the outside of your casing as it's going down. now, bp when they talked to halliburton and they were talking about the long string and the liner, halliburton personnel jesse gagrilano ran the model and said, look, we think you're going to have a fair number of centralizers on there -- 21, to be exact -- to reduce the risk of channeling in this well. based on a computer simulation. so jesse gagliano tells the bp engineers in the their office -- he works in the same office -- i think there's a potential problem here. there's a potential for flow due to the six centralizers. all right? so what happens as a result of that?

bp says, we only have those six centralizer subs. what are we going to do? a bp engineer in greg walls sends an e-mail to the design team and says we need to honor that model. we need to honor the model to be consistent with our previous decisions to go to the long string. the long string design p was going to require that they have more centralizers. david, david civiles here who's -- sims who's one of the senior engineering managers there -- was in the office, talks to greg, and they agree they're going to need more centralizers on this job. so the end result is that greg says i gave brett the go ahead, and he means the go ahead to send more centralizers out to the rig -- >> time for our break, but it would be better for sam to finish this issue, if that's already. >> we agreed.

so greg says we've lined up a weatherford hand to install those centralizers, and we're putting them on a helicopter to get the centralizers and the weatherford hand out to the rig. so they're there, the 15 plus the six will give them the 21 that they need. but there's a last minute decision not to use the additional 15 centralizers. john guide, again, a senior engineer on the project, says i just found out that the stop collars aren't part of the centralizers. he's talking, now, about separate stop collars top and bottom. he says now i have a total of 45 pieces, those 15 centralizers and two stop collars each that are going to be external casings, and i'm worried about them. it's going to be ten hours to install them, plus we're adding 45 pieces. the concern here is that having those exterrible centralizers -- external centralizers can either

hack up the casing in the wellhead which makes it very difficult to finish the well, or they can come off and not do their jobs. his subordinate, brett, says in thinking about this, who cares, it's done, end of story. we'll probably be fine, and we'll get a good cement job. i would rather have to squeeze than get stuck above the wellhead. this is why fred explained to you what squeezing is. this e-mail's important because it shows that the team recognizes that squeezing is a possibility. and as they've increased the possibility of having to squeeze by choosing to use less centralizers. what's interesting is that since the event the bp report has concluded that, in fact, the centralizers sent out to the rig were the right kind of centralizers. the stop collars would have been part of the original centralizers, and they wouldn't have had too many pieces to be sliding around on there. in addition, we've learned that

the weatherford person who was on the rig who knew exactly what to do with the equipment wasn't actually consulted by the team on the rig. so it may be that they had the right centralizers. now, in our interviews with the bp engineers -- let's go back to the previous slide for a second -- what we found is that some of them actually believe that despite what the bp report says, they did have the wrong centralizers on the rig. we don't know at this point whether they had the right ones or the wrong ones. the point for us to convey to you is that there's no clarity, even now, on whether the additional centralizers should have been used on the rig. the next point is that when bp decided to run with only six centralizers, they didn't go back to halliburton and say, can you rerub the opt to send -- rerun the opt to send model? we want to see what the effect is going to be. they instead went with their engineering judgment, and they proceeded with the well. and i think we'll stop there for

now and take our break. >> i have just about 11:00. let's reconvene at 11:15. [inaudible conversations] .. [inaudible conversations] [inaudible conversations]

[inaudible conversations] [inaudible conversations] [inaudible conversations]

[inaudible conversations] [inaudible conversations] [inaudible conversations] >> live coverage of the national commission on the deepwater horizon oil spill, and offshore drilling. looking into the investigation of the explosion of the macondo oil well. 11 people died during that explosion. this is the first of two days of hearing as commission mbs continue their probe into the incident. the first break of the day.

this should last about another 15 minutes, at 11:15 or so they will reconvene. there will be a break in a coverage at noon eastern for a brief pro forma session of the u.s. senate. expected to last just a couple of minutes and then we will return right after that. lunch break is at 12:30. at that time we do plan to open our phone lines to get your thoughts on the investigation. a short break and we'll come back to this when the commission reconvenes.smit and tell been opening statements from the commission co-chairs bob grant and william reilly from earlier today.ked th c >> we have been charged by theye president with helping the american people understand theot ioot causes of the largest oil p spill in american history.to a disaster that claimed the lives of 11 workers of theork deepwater horizon rig. we have held four public meetings thus far, and numerous site visits. >> we've heard from the people of the gulf, learned about

regulation of offshore drilling, examined the important issues of lesponse and gulf restorationu and had our first occasion to er deliberate on key findings. today we turn to an important piece of the puzzle. our chief counsel, mr. fred n rtlit, will give an overview a of what he and his team have abt learned to date about what happened on the rig. i believe this will be thehe clearest presentation of the american people have received to date on what led to this tragedy. fred bartlit is the right man m for this job. he is widely respected, adely tenacious lawyer, enormousous credibility thanks is unquestioned reputation as a straight shooter.ight shoer. is experience with this issue is very deep. he led the influentialed ienti investigational of the last majd disaster on an offshore rig, thh piper alpha explosion in 1988 i8

the north sea. the commission that investigated the columbia shuttle disaster made a veryis important point.. complex systems fail in complex. ways. there is a natural tendency tott focus on one crucial decision, or on the step as the cause of disaster. saster but as they observed, doing sod, gives a dangerously incomplete o picture of what happens. happene. we will learn for the next two days that many ways in which this complex system failed. we are not looking for scapegoats, but we do believe we have an obligation to uncover all relevant facts. only by understanding what happened can we extract the important lessons from the deepwater horizon disaster. there is much that we know now. there are still areas of uncertainty and disagreement. these meetings will go a long

way to bear in mind where we stand. i want to personally thank him and on behalf of commission, mr. bartlit and his dedicated team for the work so far. i would also like to thank our witnesses today for their cooperation with the commission. i would now turn the gavel over to co-chair, mr. bill o'reilly. >> thank you, bob. good morning. the disaster in the gulf undermined public faith in the energy industry, in government regulators, and even our ability as a nation to respond to crises. as a commission, it is our hope that a thorough and rigorous accounting, combined with constructive suggestions for reform, can help restore public trust. our prior meetings have confirmed that investigations -- that investments in oversight,

safety, and response capabilities failed to keep pace with the rapid move in to deep water. it appears in at least some quarters but this is a real joy culture exhibited in attention and a false sense of security. over these next two days we will be looking in detail at what happened on the rig. our investigative staff has uncovered a wealth of specific information that greatly enhances our understanding of the factors that led to the blowout. one question i think we all have and have had from the beginning is, to what extent this was just a unique set of circumstances unlikely to be repeated, or was it indicative of something larger? in other disasters, we find recurring theme's of missed warning signals, information silos, and complacency.

we out prejudging our finest no one can dispute that industry and government together have an obligation to ensure that such a set of conditions offshore must be subject to a safety culture that is protective of lives, livelihoods, and the environment. extracting energy resources to fuel our cars, heat our homes, our industry, and light our buildings, can be dangerous. our reliance as a nation on fossil fuels will continue for some time. in the boulder new oil and gas discoveries lie, not on land, but under the water. the risk taken by the men and women working in energy exploration benefit all americans. we owe it to those who manage and accept those risks to ensure that their working environment is as safe as possible.

over the next two days, we will learn from fred bartlit, sean grimsley and others, about what went wrong on the deepwater horizon. this detailed account of what led to the loss of 11 lives, the largest oil spill in american history, will guide our thinking as we move to final deliberations on findings and recommendations. so today, we are fulfilling the first of the fundamental task, and most fundamental task that the president gave to us in the executive order establishing this commission. and that is, determined the cause, find out what happened. i will be most interested in the lessons we may learn today that help inform the commission's recommendations for the future for how we create policies, prevent something like this from ever happening again. i want to remind all of you here that the information that you

will be exposed to today that was gathered by our investigative team was achieved without the power to subpoena witnesses or evidence. i compliment the companies whose cooperation made this possible. i can't limit the fred bartlit whose reputation earned the kind of trust and cooperation that this displays. and to those two senators who blocked this commission from receiving subpoena power, let me just say, i hope that you are presently -- pleasantly surprised of what we senator bob graham off an open remarks at this two-day gathering of the national commission on deepwater oil spill and offshore drilling. as we look into the find investigation on explosion of the macondo oil well. we have been bringing you live coverage of this for them. committee members taking a break right now.

while we have a few minutes we will go back to late last month where the commission co-chairs were guests on "washington journal."host: >> on your screen that can to co-chairs of the presence national oil commission, senator bob graham, former senator ofssn florida, democrat. reilly.iam fo for epa administrator for the bush administration from 1989-93. h of you. thank you for being here. i want to begin, if i could, with where you both are, where your commission is in this process of putting out your report. it is due out in january. the president is asking for it. you have finished your public hearings. mr. reilly, please talk about where you are in the process. guest: we are about halfway through. our report is due january 11. we then will have two months to communicate it. we have completed hearings in new orleans and in washington.

we have had an extensive list of presenters, public officials, and our organization group leaders and others. a number of people from the region -- i think we have been careful to include the people most affected by the spill. next month, november 8, we'll have a full presentation of the details of what actually happened on the rig, the decisions that were made and the consequences for the technology, for the breakdown. then we will go to serious writing, and we will have recommendations no later than early december for the president. we will meet with the president late in november and let it all rollout in january. host: you will let him know privately sort of what you're -- guest: we will meet with the president to let him know some of the directions we are going, some of the recommendations, and i'm sure that the white house will be public about some of

those. host: senator graham joins us from miami this morning. what happens after you put the report out in january? you will have a couple of months to communicate that report. how are you and mr. riley -- mr. reilly and the rest of this report count? how will you make sure that your reforms and suggestions get passed congress and the administration? guest: the first that is the findings that support the recommendations, and do they make sense. are they persuasive to important decision makers, starting with the president. then congress, other members of the administration will be involved in implementing. number two is we will have an extensive set of activities with the american people. we have a number of presentations to university

audiences and other groups that have had a special interest in this issue. one of the things that we have not really talked about is what several other conditions, including the 9/11 commission and now the weapons of mass destruction commission have done, and that is set up some capacity to continue to influence public opinion on the topic after you go out of official business, which for us will be two months after january 11. that will be another way which a group can continue to press the importance of and the relevance of the recommendations that they are making. host: we are talking with former senator bob graham, talking to us from miami this morning, the co-chair of the national oil spill commission, along with william reilly, the epa administrator from the first bush administration. senator graham, you said it will

be the quality of your report that you think will make a difference. mr. reilly, do we need to name names, then? guest: we need to be specific, a truly to the proximate cause, of who did what. for that we would certainly name company names. beyond that, no, i would expect that we would be more policy- oriented than the justice department may be in its lead oregon -- it's later o investigations. host: there will be a lot of legislative father and a report, you said. senator gramm, can you give us an idea of where it -- senator graham, can you give us an idea of where that will be? guest: congress -- last summer

it did not pass the senate. when the congress reconvenes, this will be among their higher priorities. some of the issues are going to relate back to the last big oil spill, which was exxon valdez. after that, congress passed legislation that was very much focused on the specific circumstances of exxon valdez, an accident that occurred by a tanker that went aground, spilled hundreds of thousands of gallons of oil into a small bay in alaska. much of the current legislation oil spill is based on that scenario. we had quite a different situation occur on april 20. we had not an oil spill by a tanker, but rather a rupture of

a drilling rig, which is operating almost a mile below the surface of the water, where there were very few contained in capabilities on site, and there was an immediate scramble to try to hold the damage down i think much of our report and recommendations will be focused on how to be able to respond to an incident without being unduly specific as to what the details of that will be, because i am confident that unfortunately there will unfortunately be another oil-related accident, but it will be neither like exxon valdez or like the april 20 bp spell. host: mr. reilly, when it comes specifically to the management service, what will it be?

guest: with respect to the adequacy of the regulatory process, the training, the performance capability of inspectors, i think we can infer that we will have strong recommendations with the reform of that enterprise. secretary salazar has already undertaken some of that, and we expect some of the things that he has said to us, that there will be proposals for better training. it is extraordinary that on-the- job training have been on most or all of what the inspectors have ever had, with the most sophisticated technology of cementing and centralize servers and all sorts of things that the inspectors have acknowledged in interviews that they have not been trained to understand. we will have a lot to say about that. host: critics of this commission process are saying that these conditions do not have any impact, and looking ahead to the midterm elections, after the

midterm elections, people are saying republicans, people in your party, if they take control of the house, they're not likely to pass any of the reform suggestions that you all put out. guest: after the exxon valdez, oil pollution reforms were passed. recommendations. >> we return now live to coverage of the oil spill public hearing taking place today here in washington. >> do i have the right notes year? -- here? all right. we will go on manual controls

here. there's one last little point that we want to talk about here. and again, what we have here is a list of issues at the time of the cement job. the final issue is one that is, an industry that everybody knows about. it's that there is no direct indicators. cementing success. next slide, please. what you see here is again that same image of the senate being pumped down the well, and there's a couple of indicators that we are going to see. stop it there. and what you will see is the first thing, everything you're saying from the top of the rate is basically pressure. you're looking at your pressure gauges and when they do think you are interpreting what is happening at the bottom as well. one of the first things you can interpret happening, when the plug-ins it takes the pressure to burst it and it goes through. you continue on the next thing

you see, something called lift pressure. lift pressure again is the pressure you see from the same it coming up in the annular space again, the senate is coming down, grabbed is helping it. when it turns the corner it starts going up into the annual's and takes additional force and you see that at the rate. what you can see at the rig is lift pressure. the other thing you see during this is something called full return. as freddie described, every barrel of seen it you put in you want to see a barrel of mud come back at the top of the rig. that tells you that the senate is going down the well and not in the formation. if you're losing return it's an indication president may be going somewhere you don't want to. you have three indirect cementing indicator. lift pressure, full returns him and the plugs landing on target if the plugs land on time, again that suggests the cement arrived down at the bottom of the well, probably without a whole lot of

problems. now, after they pumped the job in the macondo, very early morning hours of the 20th, halliburton said a report back to bp. and it relied on some of these indicators that said the cement job was pumped as planned. it said both plugs had pumped. full return seemed throughout entire job, and estimated 100-psi of lift pressure. so these are good in direct indicators of the cementing process. suggested that they might have gone well. the problem is these are indirect indicators of something that is happening three miles away down a pipe of the small diameter. imagine your three miles long pipe this long will be pumping 30 barrels of cement and try to forget what is happening at the other end and all you've got is these secondary indicators. it's not easy. the industry knows this. there are tools in the industry that recognize these things. next slide, please. but these indicators alone are

in perfect. that's why bp's own cementing manuals say that we are trying to determine zonal isolation you have a couple different options. three options listed in the many of the cement evaluation laws which i'll talk a insect. temperature log, which we're not going to discuss. were not at issue in this incident. and you have something called back pressure. cement column back pressure is a fancy word for lift pressure. what's important is that it says lift pressure will only give you a very worst estimate and were cement and mud weight is very similar, it is unlikely to provide sufficiently accurate estimates. here the mud weight and submit weight are, in fact, very, very similar. so again, now we have, stop there, a cement if i wish into. see many violation tool is often called the cement bond log and the president exactly a series of different estimates sit down

the well and so that looks almost -- lower down in the well. with a number of centers is pulled back up the well and it looks at the cement and tries to get a sense of how it works. the best way to describe what it does, take a bill and you rate with a hammer and it makes a certain sound. but if you took that same bill and coded it in cement, concrete, you whack it again it would make a different kind of sent. think of a cent a night the -- that is a function what it is doing. checking to see how well the cement annular space bonded to the casing and also secondarily to the formation outside. so the cement bonded to even then has some limitations. and one of the key limitations that macondo was they couldn't go past this float collar. so we can evaluate the top section up here, but it cannot evaluate the shoe track. what's important to note is this unevaluated section here includes pay zones and it

includes the shoe track. so even if you had run see many violation tool, you wouldn't have seen at least one potential flow path up into the well. that's not to say the cement bond log and go would have been useful. you have at least seen where the top of the cement was. you could have gotten gross indicator of how well the cement job had worked. and on the next slide we will see that bp's report issued after the incident concludes that if the team had done a better risk assessment of the cement job, in light of all the conditions that existed, it might have chosen for the mitigation option to address those. and this may have included running a cement evaluation of law. what's important recognize is that many operators have told us that they would not have run a cement if i wish and log in this instance. those logs work best at 48 hours to cure. here when it had that amount of time.

many people would have saved the cement if i wish and log for the production phase. it would come back, before preferring the well preferring the well to get the oil out of it, run the login to get a sense of the cement that in the interim they would have relied on extra heavy mud in the well bore, or extra plugs in the well bore to help add additional safety to keep the hydrocarbons from coming out of the well. so now i'm going to move on to some questions about cement. what we've gotten to so far is a list of bullet points that you have seen before. about all the issues that the crew is dealing with at the time that they've run the cement job. those bullet points again, none of them are individually a huge problem. most of them are known in the industry. they are dealt with all the time in the industry. but there are things that a prudent design team and a prudent cementer would be keeping in their head at the time there during the cement job. the lack of some of the

safeguards that they might have would lead you to have to rely even more on the negative pressure test which sean will describe after i'm done. before get to the negative pressure test i want to talk about the questions that been raised about the cement that was pumped down the macondo well. to do this first i want to go back to the foam cement. that's the slide where should you, you the admission of heavy cement and weissman and then heavy cement back. you can make heavy cement lighter by pumping nitrogen into. nitrogen is entered. doesn't affect chemical behavior. so by pumping nitrogen at 1000-psi into this but you can end up with a foam cement. almost looks like gray shaving cream is a gem. that is lighter than the original cement. foam cement is 14 and a half pounds per gallon. now, foam cement issues for a lot of purpose. and halliburton one of the

leading providers of foam cement, and he says, foam cement can be mixed and very lightweight, great if you want to reduce the pressure on information, and this is especially is a good fix for extreme lost circulation problems were nothing else has worked. and as a result it has done a lot of these jobs. how burton says you foam cement in over 1000 jobs including 279 jobs at 15,000 feet or deeper, and 79 jobs at 18,000 feet or deeper. halliburton recognized this is a technology they believe is good in deep water. but it's important before you foam cement to test it. everybody we've talked in the industry says pre-johnson and testing with a foam cement or any other kind of seen it is critical. i want to show you how you test foam cement in the laboratory. in the rig it is generated in a different way. in the laboratory you use a blender. take the blender, and you fill it up with cement.

you leave ahead space at the top of gas so that when you blend the cement, it creates the phone to mixture, just like making a margarita, the foamy mixture now that it is evenly blended air into the cement. it fills the entire field container and gives you a foam cement that is the same density as the cement you're going to put down the well. you've got a model. after you created the foam cement, in the lab, you can test it in one of two ways. you can port in a class, graduated cylinder, and let stand about two hours and just watch it. see what it does. you can also pour into a plastic cylinder and let it cure for 40 hours in a hot water bath, and you can evaluate that as well. but with either method the point is this thing. you are looking for density

variations that you're looking to see whether the foam cement which was a rigid all one density is changing densities over time. so a stable foam cement will stay just the same way over two hours in the glass cylinder. if it is unstable things can happen. one of the things that can happen is you'll get some segregation. when you go back a look at the top density and the bottom of density, you will find the top flight and the bottom heavy. that can be a sign of instability. if you get with the plastic tube method, it's similar. you take it, let it cure for 48 hours, and then you slice it up. one, two, three, four. you cut it any number of different pieces. the point is again you're comparing the density from the top in the bottom. . .

>> visual signs and large variations in density. you'll notice these are all somewhat suntive. there's no -- subjective. there's no clear cutoff. so hall purrton just before -- halliburton just before the job reported some results, and after the incident we look back at those results, and you can see that the lab results old april 12, 2010, when they were sent to bp, and in that lap result they show -- lab result they show the results of the tests. sg means specific gravity, it's a way of measuring density, and they planned on having a 14.5 per gallon cement, and they got

15 at the top, 15 at the bottom. some have said that's an unstable foam, others have said that's pretty good. half a pound for variation is not terrible in the laboratory. we can talk about that this afternoon. what's also important to note is the conditioning time. conditioning is nothing more than mixing the cement before you test it in the lab. the longer you mix it, after some time it starts setting up and developing strength, so mixing it for a long time in the lab can help that foam, perhaps, become more stable. so they mixed it for three hours. it's important to note here as well that on the rig t not conditioned before -- it's not conditioned before it's foamed. you mix it in the tanks, you immediately foam it, and it's sent down the well. now, there's a long travel time down the well, but but again, oe rig the cement isn't conditioned before it's foamed. so there were questions raised about this cement after the job by bp, among others, and so the investigative staff worked with chevron to actually run tests on

very similar materials provided by halliburton. what halliburton provided to us was off-the-shelf ingredients identical to the ones used in macondo. we didn't have the actual cement, the vast majority went down with the rig. there's still a small amount of it, one and a half gallons, that's held under an evidence preservation order that may be tested in the near future. but we used the exact same recipe and we used off the shelf versions of the same material. the chevron lab which is acknowledged to have some of the best cement experts that we could find said none of the tests they ran on the foam were stable. most of the tests they ran on other qualities of the cement came out pretty similar to what halliburton got, but the foam stability test did not. running the test nine different ways, all of them were unstable. we went back to halliburton, and we talked to them about this. now, you'll see one data here,

and that's the data from the april 12th test that i displayed earlier. when we look back at the original data in the lab, we noticed it seemed to have been tested on the 18th. why does that matter? it takes 48 hours to run the test in halliburton's lab. remember, the cement job is pumped -- finished pumping by 3 in the morning on -- 1 in the morning on the 20th. the test looks like it got started at about 2 in the morning on the 8th. so -- 18th. we also know, we're quite sure that it wasn't given to bp before the job was run. we see, again, the three-hour conditioning time. we're not sure whether it's stable. we see that 15-pound-per-gallon density. so when we looked at the data again, then we found another test in april. this one looks like it was run on april 13th, soon after the lab test requests went in. has the same test id number, the

same target foam density, but this one is much more dense at the top and more dense at the bottom than the test that was reported. this one, our experts tell us, is clearly unstable. also interesting is it has a different conditioning time. half the conditioning time of the later test. this one, clearly, was never given to bp before the job, and even though we are sure it was available to halliburton before the job was pumped. so then we looked further back. back in february halliburton ran a pilot test. now, a pilot test is not exactly the same as the test that they ran in april. it was done in a slightly different recipe and may have been done on slightly different materials. the overall design was very, very similar. and in february on february 17th, you get some very troubling foam stability results. again, clearly unstable.

conditioning time, again, different. and this time this one was reported to bp in march, but it listed the wrong conditioning time. it listed zero as the conditioning time even hoe the lab sheets show -- though the lab sheets show or at least suggest that it was two hours of conditioning time. regular lab sheets sent to the bp engineers. it doesn't appear anybody highlighted this information, it doesn't appear anybody at bp recognized the significance of this information. there's also a fourth test. we looked even further back, february 13th, the worst yet. no conditioning time yields high density clear foam breakout, clear instability. available before the job to halliburton, yes? ever reported to the bp? no. on the basis of the chevron tests and some of the evidence we've seen in the internal halliburton documents, you may have seen the letter that the investigative staff wrote to the commission to explain our concern about some of these

things. our primary concern based on the chevron test was that the data strongly suggested the foam cement used at macondo was unstable and that that may have contributed to the blowout. the interesting question, of course, is what does it mean to pump unstable foam cement down a well, and the truth is nobody really knows with any precision. everybody agrees you shouldn't be using the cement, and bp's report says, you know, the bubbles could come loose, you could have nitrogen migration, this could cause a host of problems. there are textbooks saying that -- or academic articles, i should say, saying good foam stability is required to maintain the initial foam structure until setting. unstable foams lead to a poor structure that's highly interconnected. it's sponge like. you don't want to have spongelike cement if you're trying to isolate hydrocarbons and it emphasizes the

performance of having successful foam stability tests before you run a job. so what we have now, we have that unstable foam concern, but we also have all of these indicators that were known at the time of the job. and, again, i'm going to say this yet another time, a lot of these things individually are common in the industry. taken together they're something that should have been in the head of the design team, cementing team at the time it was cementing the job, and if nothing else, should have led them to be very careful and very concerned about what they were going to do next which was test the job. >> okay. so do we have -- [inaudible] >> i should introduce sean -- >> so we've heard quite a bit about -- is the mic on? this now we've heard quite a bit about cement and foam cement and cement testing. what i'd like to do now is reset

the stage and bring you back to the deepwater horizon on april 20th. shortly after midnight on the morning of april 20th, the rig crew and cementers finished the cement job. at 5:45 a.m. a halliburton cementer on the rig e-mails back to shore and says the cement job went well. at 7:30 a.m.bp concludes the cement job went so well that they actually decide to send home the contractors they had brought out to the rig to perform the cement evaluation tool. fourteen and a half hours later at roughly 9:49 p.m. is the first explosion on the rig. so it's critical to understand what happened in that 14 and a half hours. so what is the crew doing on the rig after the cement job? they're moving to the next phase of the well. the temporary abandonment phase. the temporary abandonment phase

is, basically, just the procedures that the well undertakes or the rig undertakes to get from the picture of the well on the left to the picture you see on the right. what i think many people may not realize is that the deepwater horizon does not actually produce the well. it does not extract hydrocarbons, oil and gas from the well. it drills the well. then, ultimately, will cement it in, button it up to leave it for a production or completion rig to come back at some later date. the process by which the deepwater horizon buttons up that well is called temporary abandonment, bringing it from the picture on the left, the picture on the right. and you'll see, obviously, there are quite a few differences between those two pictures. fist you'll notice the -- first you'll notice the rig is gone. the rig has taken its riser with us. all the mud, the heavy weight mud that's in the riser is gone along with the rig, and also the rig brings with it its blowout

preventer. so you see here there is no blowout preventer. so it's critically important that this well is going to be sitting there in the gulf of mexico without a blowout preventer that the rig crew insures that that well has integrity and is fully buttoned up. now, some of the other difference you'll see are a cement plug. and this is, basically, a 300-foot plug of cement. a 30-story building of cement. that the rig crew will put in place before they actually temporarily abandon the well, and that cement plug acts as a backup, a back-up barrier just in case anything happens with this cement down at the bottom. if hydrocarbons begin to leak in, they will be stopped by that surface cement plug. but notice above that surface cement plug it's sea water. and in this case we'll talk a little bit more about it later. bp chose to run a very deep

surface cement plug. the depth here is 3,000 feet below the mud line, and rather than keep heavy mud in that space, bp chose to fill it with sea water. heavy weight mud is about 6 pounds per gallon heavier than sea water, so the decision to replace all of that heavy weight mud there with sea water took a substantial amount of pressure from out of the well that was otherwise pushing down and helping to hold the hydrocarbons at bay. the last point i want to make on this slide is the lockdown sleeve. the lockdown sleeve is represented here by these two black boxes which obscure the dril-quip people are here, obscure a tremendous amount of engineering technology. so i'm not trying to change you short here. but for present purposes all we need to know is that lockdown sleeve actually locks the long string casing in place. it locks it to the wellhead so

at no point, then, will the casing actually lift up. now, you may ask yourself how on earth is that casing going to lift up? there's hundreds of thousands of pounds, millions of pounds, perhaps, of casing. well, it has to do with the completion and production of the well. when a production rig actually comes back to produce this well, it's bringing up very hot hydrocarbons up this production string. and they're also moving somewhat quickly. the heat and the movement can actually create lift, and if lift gets great enough. believe it or not, this casing string can actually be lifted up. so the lockdown sleeve's purpose is to prevent that from happening during the completion or production phase. now, one thing i'd like to -- one myth i'd like to deal with, there's been a lot of talk in the media about this lockdown sleeve. and the fact that it was not set before the time of the blowout.

and there have been questions as to whether bp should have set this lockdown sleeve earlier in the procedures. i will tell you if there is anything unusual about the lockdown sleeve here, it is that bp was going to set it at all during this phase of the well. typically, lockdown sleeves are not actually placed until the completion or production rig comes back to produce the well. bp, for whatever reason, made a decision here to set the lockdown sleeve at this stage. now, going forward whether it may or may not make sense that this should be an additional safety measure when drilling rigs are out there drilling these wells, that's another story. but just keep in mind it would not have been unusual at all for bp not to have set a lockdown sleeve at all before the deepwater horizon left. so again, temporary abandonment, getting the well from what you see on the left at the end of the cement job to what you see

on the right which is when the rig is going to move away. so the first step in the temporary abandonment sequence is to test the integrity of the well. as you might imagine, you want to make sure there are no leaks in this well when the deepwater horizon picks up and moves away. so there are a variety of tests that the crew will undertake to make sure that the well has integrity. the first is called the seal assembly test. the seal assembly test, basically, tests the seal which is right here between the casing and the wellhead. and, again, this animation obscures a substantial amount of very high-tech engineering, but suffice it to say there is a space there that needs to be sealed. so the crew needs to test the casing hangar seal assembly, and this is how they do it. first, they're going to isolate this space right here and create a closed container. they do that by running a drill

string down with a packer. this packer right here seals off the top of the well from the bottom. the next thing they will do is is close these variable, variable bore rams. these variable bore rams, as fred discussed earlier, are part of the b.o.p.. they actually close around the pipe and create a seal, so at this point you have created what should be a closed pressure vessel. the rig then pumps down pressure through one of these three lines, and you've seen these three lines. we haven't talked much about them, but they're basically pipes that run from the w.o.p. back -- b.o.p. back up to the rig. and can those pipes allow the rig crew to send fluids down into the well and bring fluids back up without having to rely solely on the drill pipe or the riser. so those pipes are used for a variety of different activities -- back it up, please -- one of which is the seal assembly pressure test. so the crew will pump pressure

down into this closed vessel, close the valve at the top of the rig and then watch for some period of time to make sure that the pressure holds. if pressure holds, you can be sure -- or at least have a very good idea -- that those seal assemblies are doing well and holding pressure. and out here on the macondo they ran a seal assembly test, and it passed, and nobody disputes that it was a good test. so we'll move on to the next test. which is, the positive pressure test. the positive pressure test is testing something different. what the positive pressure test is testing actually the integrity of the casing down in the well. and, again, what the crew does is pumps pressure -- stop it right there -- pumps pressure down into the well and see if that pressure holds. if pressure doesn't hold, it indicates that there's a leak.

and the way the crew sets up the test is to close, now, a different set of rams. this time the blind shear rams. so fred talked a little bit before about the blind shear ram and how it's used in an emergency to cut the pipe and shut in the well. but it is not just an emergency measure. it's actually used like many other parts of the b.o.p. for regular operations, this being one of them. so the crew shuts in the well isolating the bottom from the top and pumps in pressure. the crew will pump in pressure for five minutes at 250 psi to watch if it holds. if it holds, then for 30 minutes the crew will pump in -- or the crew will then pump in 2500 psi of pressure and watch if it holds for 30 minutes. if it does, that's a good positive pressure test, and it indicates that you have good integrity at least within the casing string down in the well.

the crew at macondo performed a positive pressure test here. it went well, and nobody disputes that the positive pressure test here indicated that the casing had integrity. the problem, though, with both the positive pressure test and the casing hangar seal assembly test is is that neither of them tested the is cement at the bottom. you see, the positive pressure test you're pumping a lot of pressure in here, but there are these two wiper plugs at the bottom, and they're actually on a ledge. so when you're pumping pressure into the well, you're pumping against those wiper plugs. so the cement is not really seeing any of that pressure. there's only one test that was performed at macondo that actually tested the integrity of the cement at the bottom. that's the negative pressure test.

now, because the negative pressure test is the only one that tests the integrity of the cement at the bottom, it is a critical test in the life of the well. not only is it the only one that tests cement, but it is the last test actually performed. so here's testimony from john guide who was bp's well team leader for the macondo well. what is a negative test designed to evaluate? answer, it's also designed to see if float equipment and the cement, actually the cement inside the casing is holding and also the casing itself. question: is it accurate to say that this is the last evaluative test that is performed on a well before the b.o.p. is pulled and the rig is demobilized? that is correct. so it's a very important test. next slide.

this is testimony from don winslow, transocean general manager for the gulf of mexico. please tell the board how important or not important a negative test is. answer: it's very important. so i want to set the stage for the negative pressure test. you've seen all those bullet points that we put up before, the situation at the time of the cement job, things that might cause concern in the minds of people about the integrity of the cement job. and we've now come up to the negative pressure test which all acknowledge is really the only test performed on the cement job that day. so i'd like to explain just a little bit, basically, what a negative pressure test is. a negative pressure test is, in many ways, just the opposite of the positive pressure test. with the positive pressure test, you're pumping pressure in and seeing if it holds, if anything leaks from inside the well to outside. with the negative pressure test, what you do is you remove

pressure that is already in the well and see if anything leaks from the outside in. and the thing you're worried about leaking from the outside in are the hydrocarbons down here. so the question is, how do you go about removing pressure that's already in the well? well, recall that there's 18,000 feet of heavy weight mud. that exerts a substantial amount of pressure down on the bottom of the well and, in fact, before the cement job that mud alone was sufficient to hold the hydrocarbons at bay. so what you're going to want to do is remove the effect of the downward pressure of some of that mud. and then watch what happens to the well. the next question you've got to ask is how much of that mud do we want to remove or the effect of which do we want to remove, and that's going to fend on your temporary abandonment plan. here recall bp decided it would

set its cement plug 3,000 feet deep and replace the mud in that 3,000 feet with sea water. that removes pressure from the well. so here when starting the negative pressure test you want to simulate that situation, so you want to remove the e peck of that 3,000 -- effect of that 3,000 feet of mud in the well you're taking out, plus ultimately what will be 5,000 feet of mud in the riser that you're taking out. so here is what a basic negative pressure test might look like. this is not what happened at macondo, i just want to give you a sense of how it might be done what can the cry -- what the criteria for success are and then talk about what actually happened that night. so let's walk through just a generic negative pressure test. so the crew has run the drill pipe, and here on the side what it's supposed to look like in temporary abandonment. so the crew runs a drill pipe down to 3,000 feet below the mud line or sea floor. it then does what's called

displace the mud above that 3,000-foot depth. stop it. displacing, all that means is you are taking one fluid, pushing it down through the drill pipe. when that fluid rounds the corner, it then pushes whatever fluid was there already out. that is what's called displacement. so here you are displacing mud, heavy weight mud with sea water. the ore thing to -- other thick thick -- thing to note here is is the interface you see. right there it's kind of an orangish/purplish, it's spacer. water and mud don't get along, so whenever you're going to displace mud with sea water, you're going to have this spacer in between. so keep rolling. so at some point the crew will get, will displace the mud from 3,000 feet down below the mud

line to above the annular preventer or the blowout preventer and then will shut another one of these rams, in this case the annular preventer, around the drill pipe. that annular preventer will create a seal which isolates the mud and spacer in the riser from the well below. so at this point the crew many this negative pressure -- in this negative pressure test has removed the effect of this 3,000 feet of heavy weight mud. but et then must simulate, also, the 5,000 feet of sea water that this well is going to see at the time of temporary abandonment. and how that is done is with the drill pipe. recall, we have displaced mud with sea water through the drill pipe. so the drill pipe itself now is an 8,000 column -- 8,000-foot column of water that simulates or replicates the pressure gradient that the well will see once it has been temporarily

abandoned. my, up other i -- now, up here i just want to point out these little bow ties? those are valves. this one right here when it's green, it's open, when it's red, it's closed. red closed, green open. so the crew at this point is almost ready to conduct the negative pressure test. the only problem right now is that there is some residual pressure left over in the system from having actually displaced that sea water. the act of displacing that sea water, you get some pressure that gets trapped in the system, and before you start your negative pressure test, you need to bleed off that pressure. and the goal is to bleed off pressure to where you get it down to 0 psi. so the next thing the crew does

is opens up that valve on the drill pipe at the top of the rig and bleeds off pressure. and when i say bleed off pressure, it's just like opening up a valve on your bike tire. you open it up, air comes out. in this case, it's fluid. you open it up, fluid comes out. so they bleed it down million they get the pressure to zero. and people will have a very good idea beforehand how much fluid should be bled off before they will reach zero. they can do those calculations. and if it turns out they're seeing a lot more fluid come back than they anticipate, that could be a problem. but in a good regular negative pressure test, they bleed off the fluid. and the next step is simple, they just watch. because what the crew has now done is taken all of the pressure out of the system. if there is any flow after this point in time, it means something is flowing into the well from down below. hydrocarbons. the other thing the crew can do

is shut in the valve at the top and see if pressure builds up because, again, once that pressure is bled down to zero, the only explanation for it coming back up is is that something is flowing into the well, that there's a leak, and you do not have well integrity. so that is what a good negative pressure test would look like. criteria no flow for a substantial period of time when that drill pipe is open, no pressure buildup when that drill pipe is is closed. because, remember, that drill pipe is communicating with the well. it's basically just a tube. this is not what happened at macondo. at macondo, the crew set up the tests, and then they got to the point where they were going to bleed off that pressure. they bled it down. on the drill pipe. couldn't get it, actually, to go all the way to zero, so they closed the drill pipe back in, and the pressure came up.

to 1400 psi. they opened the drill pipe again to bleed it off, got it down to zero this time. they close in the drill pipe, comes back up to 1400 psi. they open it up, bleed it off, get it down to zero, close it in, pressure comes back up to 1400 ps si. so three times they try and bleed it down and get rid of the pressure, and three times it comes back up. so at this point they move it to the kill line off the drill pipe. the kill line's one of those pipes that goes up from the w.o.p. we talked about before. and you can run a test on a kill line, that's fine. the drill pipe and kill line are two straws going into the exact same place. they should be seeing the exact same pressure. there shouldn't be any difference whatsoever between them, so it's fine to run the test on that -- >> we'll leave our live coverage of the investigation of the gulf coast oil spill for a brief pro

forma session of the senate. at the conclusion we'll return to the oil spill hearing. and now live coverage of the u.s. senate. the presiding officer: the senate will come to order. the clerk will read a communication to the senate. the clerk: washington, d.c., november 8, 2010. to the senate: under the provisions of rule 1, paragraph 3, of the standing rules of the senate, i hereby appoint the honorable sheldon whitehouse, a senator from the state of rhode island, to perform the duties of the chair. signed, daniel k. inouye, president pro tempore. the presiding officer: under the previous order, the senate stands in recess until 9. 30 a.m. wednesday, november 10,