cheeks counsel fred bartlit and from representatives from bp, transocean, and halliburton. with most election results final and the winners preparing to govern, use the c-span video library to see what they said on the campaign trail and during the 140 debates we covered. search, watch, and share any time. is washington your way. the chief counsel of the national commission on the gulf of mexico oil spill told investigators that halliburton knew its cement job of the macondo well was unstable, possible leading to the oil rig explosion last april. to come -- the commission releasing its preliminary findings with the final report due in january. this portion is a little less than four hours. 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 call the mud line. okay. 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 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't

understand is, people, people 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 getting into the well 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. . . 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 laternce 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] .. >> a couple of live events to tell you about tomorrow morning. the national commission investigating the gulf of mexico oil spill will include experts in the morning and federal regulators and executives in the afternoon. our coverage is on c-span2 beginning at 9:00 a.m. eastern. here on c-span, at 11:00 a.m. eastern, the future of tea party

political groups. the leader of the first tea party in florida will join us. every weekend on c-span3, experience american history tv starting saturday at 80 in eastern. here historic speeches from national leaders and eyewitness accounts from events that shaped our nation. visit historical sites and college campuses as professors and historians dole and to america's past. american history tv, all weekend, every weekend, on c- span3. >> most election results final, use the c-span video library to see what the winner said on the campaign trail and during the 140 debates that c-span covered. search, watch, and share. it is washington, your way.

>> you are watching monday's meeting of the bp deepwater horizon oil spill commission could preliminary findings say that there is no evidence that bp put profits over safety on the oil rig that exploded. our coverage of the commission's fifth kneading continues over the next several hours, including testimony from representatives of bp, trans ocean and halliburton. we return to the committee meeting.

>> i will turn this back over to you. >> thank you. >> i am having a minor glitch in the audio visual. do i have the right mouse, here? >> we will -- we will go on manual controls here.

what we have here is a list of issues. the final issue is one that is common in the industry. there is no direct indicator. what you will see is -- everything you are seeing is pressure. you're looking at your pressure gauges and when they do things, you are interpreting what is happening. the next thing you see is something called a lift

pressure. it takes additional force and you see that. for every barrel of cement you put in, you want to see a girl of mud come back to the top. that tells you that the cement is going down the well and not into the formation. if you are losing a lot of return, the cement might be going somewhere that you might want to. you have three indicators. let pressure, for return, and the plugs lending on time. after they pump, in the very early morning hours of the '20s,

halliburton said a report back to bp. it relied on some of these indicators. both clubs -- the estimated public pressure. these were indirect indicators of the cementing process. this suggested that a things might have gone well. these are indicate -- indirect indicators of something that is happening 3 miles away down a pipe of a small diameter. imagine your pipe is this long and trying to figure out what happened at the other end and all you have are the secondary indicators. not easy. and the industry knows this. there are tools in the industry that recognize these things. these indicators alone are imperfect. bad as whites bp cementing manuals say that when you are

trying -- that is why bp cementing manuals say that you have a couple of different options. you have temperature logs. and you have something called cement call on the back pressure. what is important is that left pressure will only give you a very course estimate to and it is unlikely to is provide a sufficiently accurate estimate. here, there were very similar. again, now we have a cement evaluation tool. the cement evaluation tool is called the cement bond lot. it is a series of different instruments.

it would make a different kind of sound. it is trying to see where the space is bonded to the casing. the cement bond tool has limitations. one of the key limitations was that it could not go past -- it can evaluate this top section, but it cannot evaluate the should track cement. this on evaluated section includes the should track. even if you had rhonda simmons evaluation, you would have not

seen at least one potential flow path up into the well. that is not to say that cement toll would not have been useful. you could about least scene where the top of the cement was. you could've gone indicators of how deep cement worked. the report issued concluded if the team had done a better risk assessments in light of all the conditions, it might have chosen futures mitigation options to address it. it is important to recognize that many operators have told us that they would not have run a cement evaluation block in this instance. those logs work best -- here, it would not have had that amount of time. it would have come back to get

the oil out of it. it would run a lot then. in the interim, they would have relied on extra plugs to help add additional safety. willie had gone to some of fart is a list of bullet points to of seen before but all the issues that the crew is dealing with at the time they run the cement job. those bullets once again, none of them are individually a huge problem. most of them are known in the industry and they're dealt with all the time. there are things that a prudent design team and a prudent would be keeping in their head upon doing the job. the lack of some of the safeguards would lead you to have to rely even more on the

negative pressure tests. before we get to the test, we want to talk about the questions that have been raised about. i want to go back to the animation of heavy cement and white cement. you can make heavy cement lighter by pumping nitrogen into it. it does not affect its chemical behavior. by pumping nitrogen into the cement, you could conduct with a full summit, almost looks like great shaving cream. it is lighter than the original cement. phone cement is useful for a lot of different purposes. howell -- a fall in the cement is useful for a lot of different purposes.

it is great if you have to reduce the pressure on your formation. it is a good fit for circulation problems were nothing else who work. as a result, it has done a lot of these jobs. halliburton says, if you use it, 79 jobs at 18,000 feet or deeper. halliburton recognizes that this is a technology that they believe is good in deep water. before you use it, everybody who we've talked to in the industry has said that for ahmadinejad testing is critical. -- that freedom-in job testing is critical. you take the blender and you felt it up with cement. -- and you feel it up with cement.

believe space on the top so that when you blend the cement and create the mixture, just like making a margarita, it is evenly blended air into the cement. it fills the entire sealed container and gives you a foamed cement that is the same density as the cement you're going to put down the well. dr. you create it, -- actor you create it, you can test it. you can pour it into a glass and let it stand for two hours and watch it. see what it does. you can also pour it into a plastic cylinder and let it cure for 48 hours. you can evaluate that as well. with either method, you are looking for density of variations. you were looking to see whether it is changing densities

overtime. a stable segment will stay just the same way over to allow worse. but if it is unstable, you'll get some segregation. when you look at the contents of the bottom, you will find that it is -- the bubbles have migrated up ports. -- upwards great if you do with the plastic, it is similar. geely ed -- gillette a turf for 48 hours and then you slice it up. before comparing the density at the top and the bottom. you are comparing the pieces to each other. you are comparing them against the design. the criteria for determining the weather -- we would to look at

the criteria and you can read them for yourself. excessive gas, visible signs of segregation, large variations in density. these are all objectives. there is no numerical criteria. there is no cut off. halliburton reported some results and after the incident, we looked back at those results. the lab results -- in that lab result, they show the results of the stability test. specific gravity. it plans on having a 14.5 cement and they got 15 at the top and fit in at the bottom. some have said that that is an unstable fall. others have said, that is pretty

good. we can talk about that this afternoon. we have to talk about the conditioning time. it is nothing more than mixing the cement. the longer you mix it, it starts setting up and developing some strength. mixing it for a long time and allowed can help that fallen become more stable. they mixed it for three hours. it is not conditioned. the mix it in the tank and send it down to the well. there is a long travel time down to the well. the cement is not conditioned before it is foamed. there were questions raised after the job. the investigative staff worked with chevron to run tests on a very similar materials provided by halliburton.

halliburton provided off-the- shelf ingredients identical to the ones used. we have the actual cements used. the vast majority went down with you greg. there is still a small amount of its that may be tested in the future. we years the exact recipe that halliburton eased. -- we used the exact recipe that halliburton used. none of the test that they ran were stable. most of the tests cannot produce similar to what halliburton got. but the fund stability tested not. during the test nine different ways, all the more unstable. will and back to halliburton and we talk to them. you will see it -- we went back to halliburton and we talked to them. that is the data from the april

12 test. when you look back at the original data, it seemed to have been tested on the 18th. why does that matter? it takes 48 hours to run the test in the lab. the cement dropped is pumped -- is finished pumped by one the morning. the pulte looks like it got started about 2:00 in the morning on the team. that test was not finished. we also know that to it was not given to bp before the job was run. we see the three-hour conditioning time. we're not sure whether it is stable. will looked at the data, we found another test. this one looks like it was run on april 13, after the lab test. it has the same test id number, the same target phone district

-- foam density. this one is clearly unstable. it has a different conditioning time. ad hoc the conditioning time of the later test. this one -- half of the air- conditioning time of the later test. we are sure that it was available to halliburton. then we look further back. back in february, halliburton ran a pilot test. a pilot test is not exactly the same the of the test they ran in april. it was done with a slightly different recipe. the overall design was very similar. in february, you get some very troubling stability results. clearly unstable. conditioning time difference.

this time, this one was reported to be peak in march, but it listed the wrong conditioning time. this one was reported to bp. it does not appear that anybody highlighted this information. it does not appear that anybody ndp recognize this information. there is also a fourth test. we went further back. no conditioning time. clear break out, clear that instability. it was never reported to bp. on the basis of the chevron and some of the evidence we have seen in the internal halliburton documents, he may have seen the letter about the staff wrote to the commission, our primary

concern was that the data strongly suggested that the cement was unstable and day -- that may have contributed to the. --. -- blow out t. the report says that you could have nitrogen break out. the bubbles could, louis. it could cause a host of problems. on stable -- unstable foams lead to an unstable structure.

what we have to now -- we have that on stable concerned, but we also have all of these indicators that were known at the time of the job. a lot of these things individually are common in the industry. taken together, it should been in the head of the design team at the time of the job. if nothing else, it should have led them to be very careful and very concerned about what they were going to do next. >> [inaudible] >> [inaudible] now we have heard quite a bit about cement and testing. what i would like to do now is reset the stage and bring you back to the deepwater horizon on

april 20. shortly after midnight, on the morning of april 20, the crew and some interest finished the job. at 5:45, at a halliburton e- mails back to shore and says the jobless well. at 7:30, bp concludes that the job done so well that they actually decide to send home the contractors that assessed the tool. at 9:49 p.m., it was the first explosion. it is critical to understand what happened in that 14 bling 5 hours. what is the crew doing after the cement job? they are moving to the next phase of the well, the temporary abandonment phase. it is basically just the

procedures that the well undertakes to get from the picture on the left to the picture that you see on the right. what many people may not realize is that the deepwater horizon does not actually produce the wealth. it does not extract hydrocarbons, oil and gas, from the well. it will cemented again, but not it up, leaving it for production or completion to come back at some later date. the process by which the deepwater horizon is called temporary abandonment. bring it from the picture on the left to the picture on the right. there are quite a few differences between those two pictures. you'll notice that this is gone. it has taken its riser with us. all of the heavyweight mud has gone along with the rig. the rig brings with it a blowout

preventer. is critically important that this well is going to be sitting there in the gulf of mexico without a blowout preventer that the crew in shorts that bagwell has integrity and is fully buttoned up -- in shores that the well has integrity. this is a 300 foot plot of cement. a 30-story building of cement. they will put in place before they temporarily abandoned the well. that segment? as a back up, it back up barrier just in case anything happens with the cement down at the bottom. if hydrocarbons leaked in, they will be stopped. notice, above that service is sea water. in this case, we will talk a little bit more about later, bp chose to run a very deep surface cement plug.

the deck here is 3,000 feet. -- the depth here is 3,000 feet below the mud line. heavyweights mud is about 6 pounds per gallon heavier than seawater. the decision to replace all that heavyweight mud would see water took a substantial amount of pressure from out of the wealth that was otherwise pushing down and helping to hold the hydrocarbons at bay. the lockdown a sleeve is represented here by these two black boxes. the obscure a tremendous amount of engineering technology. for present purposes, all we need to know is that lockdown mislead actually locks the casing in place. it blocks the to the wellhead. no casing -- how on earth is

that casing going to lift up? there are hundreds of thousands of pounds of casing. it has to do with the completion and production of the well. when a production rig comes back, at to produce this well, it is bringing up a very high hydrocarbons. they are also moving somewhat quickly. the heat and the movement can create left. at the left its great enough, this case in string can be lifted all. the sleaze purpose is to prevent that from happening. -- this leaves the purpose is to prevent that from happening. there's been a lot of talk about this lockdown the sleeve. and the fact that it was not said before the time of the blowout. there have been questions as to whether bp had -- should have

set it earlier in the procedures. if there is anything unusual about the lockdown asleep, it is that bp was going to set it at all during this phase. typically, locked down sleeves are not placed until the completion or production rate comes back to produce a while. bp made a decision here to set its at this stage. going forward, that is another story. keep in mind that it would not have been unusual at all for bp not to have said it at all before the deepwater horizon left.

the first step is to test the integrity of the well. you want to make sure there are no leaks in this well. 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. the seal assembly test basically tests the seal, which is right here between the casing and the well head. this animation obscures' substantial amount of very high- tech engineering. suffice it to say, there is that needs to be sealed. the crew needs to test. this is how they do it. they will isolate this right here and create a closed container. they do that by running 8 drawstring down with a --

running a and drill string down with a packer. the next thing they will do is close these variable rams. they are part of the bop. the clothes from the pipe and create a seal. -- they close around the pipe and to create a seal. you see these three lines. they are basically run from the bop back up. those pipes are used for a variety of different activities. back it up, please. one of which is the seal assembly pressure test. the crew will pump pressure down into this close to the

soul, close the valve at the top of the raid, and then watch for a period of time to make sure the pressure holds. if the pressure holds, you can be sure that this bill assemblies are doing well. there are holding pressure. out here, they ran a seal assembly test and it passed and nobody disputes that it was a good test. we will move on to the next test. the positive pressure test. the positive pressure test is testing something different. it is the integrity of the casing down in the well. again, what the crew does is pump pressure down into the well and see if it holds. but the pressure does not hold, it indicates that there is a leak. the way this setup the test is

to close a different set of rams. this way -- fred talked a little bit before about the it sure rams and how it is used in emergency to cut the pipe and shot in the well. it is not just an emergency measure. it is used for regular operations, this being one of them. the crew shots in the well, isolating the bottom from the top. the crowd will pump in a pressure for five minutes at two under 50 -- 250 psi's. the kroll then, and -- what if that holds for 30 minutes. if it does, that is a good positive test. it indicates that it could have could integrity down in the well.

the positive pressure test went well and nobody disputes that the positive pressure test indicated that the casing had integrity. the problem with both tests is that neither of them test the cement at the bottom. the positive pressure test, your pumping a lot of pressure in there, but there are too wide for plugs at the bottom. when you're pumping pressure into the well, your pumping against them. the cement is not releasing any of that pressure. there is only one test that was performed that actually tested the integrity of the cement at the bottom. that is the negative pressure test.

because the negative pressure test is the only one that has the integrity at the bottom, it is a critical test in the life of the well. it is the only one that test the cement, it is the last test actually performed. here is testimony from the the bp while team leader. what is a negative test designed to evaluate? it is designed to seek it the flood of equipment actually is holding, and also the case itself. is it accurate to say that this is the last evaluation test is performed on a while before the block is pulled and the rate is demobilized? that is correct. it is a very important test. this is testimony from the translation -- transocean

general manager. please tell the board how important or not important in- test is. it is very important. i want to set the stage for the negative pressure test. you've seen all those below points that we put up before. things that might cause concern in the minds of people about the integrity of the cement job. pia balcombe up with the negative pressure test. -- we have now come up with the negative pressure test. i would like to explain it just a little bit what a negative pressure test is. a negative pressure test is is the opposite of the positive pressure test. with the positive pressure test, you're pumping pressure in and seeing if the old. if anything links within -- inside the well to outside. with a negative pressure test, you remove pressure that is already in the well.

see if anything leaks from the outside in. the thing you are worried about leaking by the hydrocarbons. how do goal by removing pressure that is already in the wild? there is 18,000 feet of heavyweight mud. that is a substantial amount of pressure at the bottom of the well. that money alone is sufficient to hold the hydrocarbons at bay -- that month alone is sufficient to hold the hydrocarbons at bay. the next question you have to ask is how much of that money do we want to remove? -- mud. that is going to depend on your temporary abandonment plan. bp decided it would set its cement plug 3,000 feet deep and replace the mud in that 3,000

feet of sea water. that removes pressure from the well. hear, when starting the negative pressure test, you want to stimulate that situation. you want to remove the effects of that mud in the will you are taking out, plus what will be 5,000 feet of mud in the riser. here is what a basic-pressure test might look like. this is not what happens. i just want you to have a sense of how it might be done. a generic-through pressure test. the crew has won the drill pipe here on this side. this is what you are trying to simulate. they run the pipe down 3,000 feet below the mundelein. -- mud line.

the displaced the mud. you are taking one fluid and pushing it down to the drill pipe. when that floyd brown's the corner, it pushes whatever flyboys they're already out. uid the roundsloat the corner, it pushes whatever there already out. water and mud do not belong. you do not want them to mix. whenever you want to displacement of sea water, you will have the in between. at some point, they will displace the mud from three dozen feed to above -- three

dozenth -- 3,000 feet. but preventable create a seal, which isolates the spacer and arises from the well below. at this point, the crow has removed the effects of this 3,000 feet heavyweight mud. it then must stimulate the 5,000 feet of sea water that this wall is going to see at the time of temporary abandonment. you do that with a drill pipe. we have displaced mud would seawater through the drill pipe. the drill pipe itself now is in 8,000 foot column of water. it simulates or replicates the pressure gradient that the well will see once it has been temporarily abandoned.

i just want to point out these little bow ties. this one in green comet is open. when it is red, it is closed. the crew is almost ready to conduct the negative pressure test. the only problem right now is that there is some residual pressure leftover in the system from having displaced that seawater. the act of displacing the sea water and before you start your negative pressure test, you will need to bleed off that pressure. the goal is to bleed off the pressure before you get down to zero psi. \

the next thing to do is to open the valves on the drill pipe. it is just like opening up the valve on your bike tire. when you open it up, air comes out. in this case, it is fluid. they believe it down until they get the pressure to zero. people have a very good idea beforehand how much fluid to be bled off. they can do those calculations. in a good regular negative pressure test, they bleed off the fluid. the next up is simple, they just watch. they have taken all the pressure at of the system. if there is any float after this point, it means that something is going into the wall. hydrocarbons.

once that pressure is let down to zero, the only explanation for the coming back up is something is blowing into the well, that there is a leak, you do not have well integrity. that is what a good-pressure test would look like. criteria, no flow for a substantial period of time. no pressure buildup when that for a pipe is close. that drill pipe is communicating with the well. this is not what happened. the crew set up the test, then they got the point where they were going to bleed off that pressure. they glided down. -- a blood it down and could not get it to go all the way to zero.

the open to the drill pipe again to bleed it off and got it down to zero this time. they closed and it came back up to 1400. the opening up, and getting down to zero. close to in, pressure comes back up, 1400. three times they tried to lead it down and get rid of the pressure. three times it comes back down. at this point, they moved it to the kill line. the kill line is one of those pipes that goes up from the box. you can run a test on the killing, that is fine. the drill pipe and kill line are too strong sadr going into the exact same place. there should not be any difference whatsoever. it is fine to run the test on that. the open up the killed line and a little flow comes out. they then launched the fourth 30 minutes.

-- they then watch that for 30 minutes. bill looks like that test on the kill line was good. but they never reconcile the fact that there was still 1400 on the drill pipe. everyone who has looked back at this agrees that this was a failed-pressure test. these were some quotes from the bp report. abnormal pressure is absorbed during the negative pressure test were indicative of a failed or been conclusive test. however, the test was deemed successful. there was 1400 psi on the drill pipe, an indication of communication with the reservoir. what that means is that the well was flowing. hydrocarbons were leaking in.

for whatever reason, the crew decided it was a good-pressure test. the interesting question is not so much whether it was or was not a good-pressure test, the question is why these experienced man talked themselves into believing that this was a good test that could establish a well integrity? none of these men want to die. none of the men want to jeopardize their own safety. none of the men want to jeopardize the safety of the men and women work with state in and day out. why? we may never know the answer to that question. many of the individuals who made those decisions died in the explosion. others suffered severe medical injuries.

others have asserted their fifth amendment right not to testify. we may never know. we do have some information. we have snippets from witnesses who walked in and out of the rig during those three hours. we have the data itself. i would like to go over in more detail what that data looks like and what information we have that might explain why the red croup and will site leaders came to this decision. here is the set up. you have those three lines. you have the riser and the printer is label. the first thing that the crew is going to do after running the drill pipe in is to displace the

mud on of these three lines. that is not terribly significant for us except to note that some point, they are going to use the kill line during the procedure. at this point, they are setting up the test. they are going to displace mud would see water. -- would seawater. this is the first thing to note at this point. the spacer. the cure was unusual. -- spacer was unusual. bp wants to use some leftover materials. is significant volume of leftover materials. they were known as lost circulation materials. they are viscous fluids that you can actually put solid matter

into that you send down to the well when there has been a lost circulation. that material can patch many of the holes and the formation. bp has some of the stuff lying around and wanted to get rid of it. here is the quirk -- its bp does not send this down into the well, it has to dispose of this as hazardous waste back on shore. there is an exception to that requirement for water based drilling fluid. bp wants to send these materials down into the wild, circulate them back up to surface, where they can overboard them. there is no dispute that that was a decision that they made here. that is not a problem, but what is more problematic is nobody had used these combined materials before. the engineers said, it should be

ok, but everybody acknowledges that they have not use these materials before. the other thing to keep in mind about this is that is very heavy. 16.5 lbs per gallon. that is almost twice the density of seawater. the seawater is pushing it back up during the displacement. when you have a lighter fluid trying to push a much heavier fluid, the concern is that heavier fluid will drop down into the lighter fluid. keep at spacer in mind. the crew gets -- at that point, the proceeds this residual pressure leftover in the well.

they go to plead its down. they open up the drill pipe. they do something unusual. they stopped at 1250. we are not entirely sure why they did that. the kill lion, which also has a pressure gauge, was there at 1250. the crew may have wanted to see if the drill pipe and kill line would equilibrate. they should be the same pressure. 12500 and one should be in 1250 on the other. at this point, they open up the kill line just to see if the pressures are equal. the pressure on the kill line goes down to 645. the pressure on the drill pipe goes up to 1400. it does not make sense given that these should be communicating with the same measure.

the crew then tries to bleed down the pressure on the drill pipe. the fluid is coming out. they bleed down the pressure and they cannot get it below 250. they cannot get it to blow up to 60. this indicates that there is a leak somewhere in the well. it does not say where or what it is, but there is a leak. the crew shots back to the drill pipe and the pressure goes back up again. they notice that if level -- the fluid level has been dropping. somebody walks over, put the flashlight down in to see if the fluid level has dropped.

what they realize is that the printer is leaking. it was not closed quite enough. i list the crew has not solved one possible reason as to why there might be a leak. they go to try to test again. the crew of leads off the drill pipe and this time it goes all -- goes down to zero. water is flowing. didn't close the drill pipe to watch what happens. the pressure jumps up again. this is starting not to make sense. there is slow coming up from the wild. what did they do?

they decide we will try to bleed off the pressure on the drill pipe through the kill line per it did get a pressure down to zero. they shot it in again. the drill pipe pressure goes back up to 1400. at this point, there was a discussion. according to certain witnesses, some of this is in dispute, the transocean -- croute explained why they were getting the 1400 in the drill pipe. they attributed it to something called the bladder a fact. -- a fact. a well site's leaders said about it.

the mud in the riser would push and transmits pressure downhole, which would be seen on the drill pipe. what we know now is that everybody who has looked at this agrees, the bladder fact does not exist. to the extent that it does not -- that it might exist, it would not explain the data that the crew was in and night. it would not explain why the pressure would keep coming back up. after these discussions, one of dpp leaders said, let's move the test to the kill line.

the reason given was that when they submitted its application setting forth a temporary abandonment procedures, it indicated that it would run a negative pressure test on the kill line. one of the leaders said, let's run it to the killing. so they did. they opened it up and they get a little bit of flow, which then stops. like i said before, everything then looked good. but they never reconcile the fact that there was that 1400 still on the drill pipe. the enduring mystery here is why on earth was there 1400 on the

drill pipe and zero on the kill line? how can those two things possibly be reconciled? there are a number of possibilities that people have cited. one is a spacer. we all know that there was a leak in the printer and that spacer clicked down below. some of that could have gone into the kill line. the purpose of that is to actually clock materials. there is a possibility that clawed back to . ogged that kill line. there is no good explanation for that difference. if you cannot explain the 1400, it is not a good-pressure test. why would these men not have

realized that this is a bad negative pressure test? just to show you here, 1400 -- this is what it should have looked like in a perfect world. why would these men not have realized that this was a bad negative pressure test? nobody really in the industry or in government had set forth any procedures governing what the test is, how to conducted or how to interpret it. the mms had no regulations governing procedures for conducting or interpreting a negative pressure test. the regulations requiring one of all. the crew that night, had they not conducted a negative pressure test, would of been violating the regulations. bp, while they require a

negative pressure test, does not have any such procedures, nor does it train in particular procedures. it could be different on every single red, depending on what the team agrees to. transocean, they require a negative pressure test in these situations. they, too, have no set procedures and no training for their people. at least prior to this event. it appears to us that at no point in time during the three hours that anyone on that floor called back to shore. to say, we're getting weird readings. there is a problem here can you help us out? it doesn't appear that anybody from bp did that. it does not appear that anyone from transocean did that.

that is a concern that we raised for the commission. the parties have wanted us to assess blame on this. who is responsible? he signed off on the negative pressure test? bp has said that it was transocean response ability. -- responsibility. transocean has said that it is the responsibility of bp. that is not our job. we are not trying to assess blame or fault or liability. the only plan we want to make is that those men had convinced themselves and agreed that this was a good-pressure test. there is no indication to any of us that anybody spoke up and said, there are problems. we should not go ahead. it is it o'clock at night and a

crew -- is 8:00 and a crew is going to move on to the rest of the temporary abandonment procedure. once the crew green light to the negative pressure test, the next up was to displace the riser entirely. the deep water horizon is going to be leaving. it will be taking its riser and it needs to get rid of that heavyweight mud. the next step would then have then to set the surface cement plug, that 300-foot 30-story building cement plug. once that was done, bp would .hen set the lockdown sleeve

you will see that there is all this drill pipe hanging beneath it when it is being set. it needs 100,000 pounds of weight to be sacked. the way that bp chose to achieve that waite was to hang in 3,000 feet of drill pipe. because bp want to set it last, that is why it be needed to set the surface cement plug so deep. they needed that 3,000 feet of space to accommodate the weight. finally, the crew would pull up the riser and blowout preventer and go on to the next job. at this point, i would like to make a few comments about the particular temporary abandonment

procedure that bp chose and the sequence that they chose from getting to point a to point b period -- b. i will talk about two points here. we have talked a little bit about it already, but it is the removal of that 3,000 feet of heavyweight mud. that mud is exerting a force down on the bottom of the well. it is helping out the cement job. it does not have enough force to hold the hydrocarbons and they want you pulled up and there is no heavyweight mud in the riser. but it helps. the more seawater you've removed, the more stress you are placing on the cement job. the decision to displaced that much mud with seawater was a

decision to stress the cement dropped perhaps more than was necessary. it is a decision that puts a real premium on the test of the cement job, the-to pressure test. it eliminates >> there has been uniform testimony setting the plug 3,000 feet deep was not only unusual but unheard of. here is some testimony you can look at. this second problem with these procedures, or something that introduced additional risks, is that bp chose to displace the mud from the riser before setting that cement plug. setting that cement plug.