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tv   U.S. Senate  CSPAN  November 9, 2010 12:00pm-5:00pm EST

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>> well, you know, the primary thing would be what you would expect a successful test to look like. perhaps how long to wait. also do those calculations like dr. smith was outlining the
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expected flea back volumes so the rig crew would evaluate if the test was going as planned. >> when you see bleed back volumes, we talked about this yesterday, once the crew has the pressure, there's a certain amount of pressure? >> that's right. >> before starting the negative pressure test, the crew wants to release any extra fluid up at the rig; right? >> the crew has to bleed off that compressible volume to reduce the pressures, that's right. >> there's a way to calculate how much fluid one would expect to get back when you are bleeding off that residual pressure. >> you can estimate it. it can be accounted for. >> why would it be useful to
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know that information before conducting the negative pressure test? >> well, if you start to get back a significant within the measurement error, that indicates that there's additional fluid entering that is not accounted for. if it is sealed, there would only be compressibility in the well to bleed off, if you will. that volume would represent perhaps an in-flow into the well. >> have you seen whether those calculations would done here at macondo prior to the test? >> i haven't seen any indications. there aren't any here on this document. >> mr. lewis, do you want anything to add what procedures should be included along with the description of the negative pressure test? >> no, i think it's been adequately covered.
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>> professor smith, i understand that as part of your investigation into the negative pressure test at macondo, you looked in to see whether there are, in fact, anything regulations or industry standards prior to the event governing how to perform a negative pressure test; correct? >> that's right. >> what did you in regard to any regulations? >> applying to the gulf waters, there's no regulations, and i searched carefully. >> did you find a regulation that even priored the negative pressure test to be performed? >> not explicitly. >> is there some regulation they would have violated had they decided to forego the negative pressure test? >> yes, actually there is. there's a requirement in the code of federal regulations.
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if you don't mind, i'll just read it. >> please. >> it says before removing -- this relates to a temporary abandonment, or abandonment. it says before removing the marine riser, you must displace with sea water. you must maintain sufficient hydrostatic pressure or take precautions to compensate and maintain a safe well condition. logically, the negative test is a way to beforehand prove that the well will withstand that reduction of pressure as a means to satisfy this requirement. >> so if one does not perform a negative pressure test or performs one and it -- and it's a failure, then the regulation you've just read would not be satisfied. >> that's my interpretation, yes, sir. >> did you also look to see whether there is any industry standard guidelines or procedures out there as to how
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to conduct and perform a negative pressure test? >> i did a course si search, yes, sir. >> what did you find? >> i did not find any practices that would be -- have some official weight. >> do you have any sense why there were no regulations or industry standards? >> i think because this is a relatively rare procedure to apply. this procedure is really important in deepwater wells where you are removing the riser, so you are removing the hydrostatic pressure that existed in the mud and the riser. it's not something that's common for land operations or shelf operations where we are working with a surface wellhead. >> just to get that straight, in deepwater when you are leaveing and temporarily abandoning a
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well, you are removing all of the mud in the riser when you pick up and leave; is that right? >> that's correct. >> so it's in no circumstances where you are most likely to severely underbalance the well in a the procedure? is that right? >> that's right. unless you've taken the kind of preemptive measures that we've discussed. >> there are regulations on deepwater drilling; right? >> yes, sir. >> do you know why they didn't account for this procedure? >> well, i think the regulation that i read is the regulation that would require the operator to can be if they were going to remove the hydrostatic overbalance, to do something that prove the well was safe to do that. the only practical,
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responsibility approach to doing that would be to do a negative test. to remove that hydrostatic pressure in a control system as was done with the b.o.p. closed to verify the well will hold back that external pressure that you are going to impose on it. >> let's assume, hypothetically, that the men on the rig that night at 8 p.m. had concluded this is a failed negative pressure test. what steps would the crew and men on the rig then have needed to take to diagnosis what the problem was and potentially remediate the situation? >> well, a logical first step would have been to circulate the sea water out and regain hydrostatic control. that would allow them to open the b.o.p. and work in a normal fashion. then the next step to see where was the leak so we can define a
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way to go back and correct that. and so it tends to be a very intense process that i haven't thought through those steps. and eventually, onceoff done the test to find where the problem is, then you have to design a correction to that problem. >> so let's imagine that here the rig crew and well side leaders had decided there might be a problem in the cement at the bottom. how long of a procedure would it have been to remediate the cement failure at the bottom? roughly. >> something between 24 hours absolute minimum to trip in the hole and set one of these mechanical plugs, like a bridge plug near the bottom of a well
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to maybe several days if they were going to do a more thorough remedial cementing. >> is this consistent with the steps that would need to be taken, mr. lewis? >> yes, those are the basic steps that would be required. >> and that night, the choices with the negative pressure test to sign off on it, which we all have said we believe the men there thought or to undertake what could be a substantial and strengthy diagnostic and remediation process; is that right? >> yes, sir. >> now in your experience, mr. bourgoyne, as a company managed chevron, when you had a seen, if you had seen the data like was seen that night during the negative pressure test, would you have called that back to shore? >> most definitely.
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you know, once -- probably in the process of getting the anomalous data made a call back. if i didn't understand what was happening, i'd seek counsel. seek help. and the engineer at shores task is to provide that. >> where there any policies in place at chevron that instructed it's well site leaders when to call back to shore when they might be seeing these anomalous situations? >> i don't recall any policy. it was more of a -- or -- do you have confidence in your knowledge, wigging -- knowledge, i guess, the burden is on the company rep to recognize when something is anomalous. but there was definitely no
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policy or prohibition to it. i would say it's more of a cultural thing that varied from who you are working for as to whether you would call back with an inkling much a problem, versus nailing down that you really did have a problem. personalities are personality personalityies. sometimes if, you know, like if we take this case with the negative tests, you might have tried to do the test twice and even circulate sea water around before calling in to actually say, yeah, i'm having a problem. or you might have for another different engineer called in much earlier to seek advice on perhaps there's another approach or something that i'm not seeing on a more informal level. >> mr. lewis, what is your experience with regard to whether to call back on to shore
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when anomalous data readings like this are encountered? >> i've not seen a written procedure in any of the companies that i've worked for as a well site leader that's so specific. i would echo and maybe even expand upon mr. bourgoyne's statements there about the relationship between the rig site personnel and the office engineering staff. i've worked for companies where basically the well site leader was instructed to do absolutely nothing that wasn't already included in that well plan. and those were very, very complete well plans though with exactly has been described here, pressures, volumes, procedural steps. i've also worked in organizations where the well site leader was left a
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significant degree of personal discretion. as a well site leader, i learned early on that discretion is the better part of valor, however, if i didn't understand something, the best possible thing i could do for myself, and everyone on the rig, and for the benefit of the company that i was working for was ask for help. so there is a large amount of interpersonal relationship that goes into the willingness to go pick up the phone. the old days the company man was god. he was supposed to know everything that went on all the time. we have evolved to an operational environment that's so complex and has technological elements in it that are beyond the ability of one man to be completely cognizant of.
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so it's not required for your well site leader to communicate with more people, more frequently, and possibility even at an earlier level in the evolution of events than has historically, traditionally been the case. >> well, even if there's not a specific policy in place, and i agree it would be odd, when you see weird negative pressure test readings, call. you want a culture when people are encouraged to call back to shore when there's an odd reading they don't understand. how does one in a company create a culture whereby the instinct is in those situations to call back to shore? what has been your experience, mr. lewis, in that regard? >> that sort of culture would have to start with the mandate from the top. but it would be something that would have to be nutured by
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primarily the interface between your engineering management and your operation management in town. and the bp organization, they've actually got a separate group for engineering and a separate group for operation of the well. but they interface very closely. and that sort of communication would would need to start there. organizations that are smaller than that, you'll find the engineering and operations people are the same group. and it's actually somewhat easier in those contexts to have these conversations. another thing that would engender that communication would be as was indicated might be the practice that another major company here earlier today, the environment of that field operational group, those drilling supervisors, as well site leaders is the new term. it's a bp term, by the way, that
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came to us courtesy bp. have them involved in the initial design and planning process. they may not have the technical skills to run an engineering program to calculate the loads on a spring of casing, but they definitely are the people who are going to be managing the installation of that casing, they are the people that are going to be confirming that they have the right equipment on the location. they should be involved in the beginning. if you have the people in the room with the designing process, it's much easier to say charlie i need your help. i don't know charlie, should i call him? that sort of decision can play in here. it's that personal in some cases. that culture needs start at the top and be nutured without the process of drilling the well.
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>> what about your experience, mr. bourgoyne, calling people back to shore or involving other people in the discuss when the odd types of things are encountered? >> i guess i don't have a real good formal way to institute such a thing. i found and since working for chevron, i've worked as a supervisor, that it really is a matter of those in a supervisory position showing interest. and also fully exploring ideas that are brought to them. i know that as a junior company man, if i approached or was included in some planning and i had an idea that perhaps didn't work or wouldn't work or was a brainstorming idea to explore why it wouldn't work. it was very educational. but it also led to this
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interpersonal relationship if you will, this feeling that, well, that's somebody that i can reply on for counsel. i guess also a deep feeling of responsibility is a big driver if you are that person who has to make the call. you have to know your limitations and, you know, even if there are repercussions for calling back, it's -- it must be done, if you will. that personally was my strongest motivator if it was a tough ball to make. or something that i was concerned about bringing up and how, you know, exposing my ignorance, if you will in seeking advise for somebody who i thought might not appreciate that i'm learning or i'm confused and i need a hand. instituting a company-wide, i
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can see it would be a great challenge. it's actually pretty simple on a rig. there's two or three supervisory positions there. if those two or three people decide to make that environment, or create that type of environment, you know, it's a small -- very small group. so it can be either really good or really bad. i've worked on a lot of really good situations. never any really bad. but i could see the potential for this don't communicate unless you absolutely have to obvious you have to be absolutely confidence in your position before you go out on a limb and actually offer an opinion or an idea even. >> i want to switch just and ask a couple of questions about well control and kick monitoring. i know that's an important
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issue, i know mr. bourgoyne, and dr. smith, both of you teach well control at lsu. mr. bourgoyne, how are people typically trained, drillers, rig crew, in how to monitor for kicks and conduct well control? >> they typically go to a course as three to five-day course. there's stimulations included. at lsu, we have a full scale well facility that we actually do exercises on. so there are both classroom lexture -- lecture materials, and even stimulations. most of the stimulations that i've been involved with is what i would characterize a routine well control operations. that is most of the focus is on detecting a problem very early
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when it's much easier to correct, and there's much less risk involved if you connect -- correct it early and correcting it. there's not real high-stressed well control scenarios that are necessarily stimulated, but to demonstrate competency, and understanding of the procedures. >> what jumped out is when you say a three to five-day well control course. is that significant to be a driller on a rig? >> not to be a driller. that course presupposed that that person has some on-the-job training, is familiar with rig operations, and worked their way up through the ranks to driller. there's quite a few positions before achieving driller. i don't recall the requirements on experience for one curriculum
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particular well cap. but it's on the order of years. it's not just a few weeks in that position. >> what type of certification requirement, is there, in -- if any, to be a driller? >> to be a driller, just the well control cards is the only one that i'm aware of. there maybe internal policies within companies. as far as some regulatory requirement to become a driller, i'm not aware of any. >> and the well control card, does that come from completion of this well control course? >> yes, it does. and we've converted to a system where each operator adopts or is in charge of this well control training system if you will in the well cap has kind of become a standard, at least here in the gulf. >> now you had mentioned the
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well control courses you teach tend to focus on the typical situations during the life of the well, where there's drilling going on. that type of thing. there the emphasis is on detecting kicks early and dealing with them. >> well, in the life of well, you may never have a well control incident. so the well control incidents are relatively rare in operational terms. and by far, the most common or, you might call it they are not necessarily minor, but they are controllable. they are routine, if you will. they are not frequent. and those can evolve into a blowout. but it has been focused on this early phase when reestablishing control is not near as -- nearly as panicked isn't the right word. but when mud is flowing out of
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the riser at jet engine velocities, it's considerably different than detecting a 20 barrel kick and having 45 minutes to hours before that type of event would ever occur. >> do you think it would make sense going forward to increase the training that individuals receive on how to deal with emergency situations? like what we've seen now with the macondo well? >> i definitely think an increase in training should be considered, particularly with a scenario -- you know, a set of disaster scenarios, if you will. i think it would probably be much more effective if drills were regularly conducted along these lines on the rigs that were doing the operations with the crews, because rigs are very unique. it's very difficult to set up a stimulator to stimulate a
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specific rig, because they are custom-built things. and designed for different purposes. i would suggest that maybe a standard set of disaster drills, if you will, that would need to be conducted prior to beginning operations or immediately after beginning operations on a well, well-by-well basis if you will or perhaps on some other frequency determination. >> but if your understanding, current in the industry, you have not seen regularly drills performed on rigs or even in classes to deal with these emergency type situations where somebody is faced with gas coming out of riser and whether to hit that button? >> you know, it's been -- it's talked about. it's covered kind of in the terms of the transocean model, manual, you know, so discussion, yes. actual put together stimulation that they have to take those and
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act those actions in sequence, and make very rapid decisions like whether to convert overboard or mud-gas separator, and the decision has to be made immediately to be successful, i've never seen any drills or exercises like that. >> one last thing on instrumentation, there's been a lot of discussion about whether the data that the driller or others on the rig is seeing is in this very modern age sufficient for those individuals to be able to actually identify kicks in the well and to do so early enough to take action. do you have any views as to the nature of instrumentation and displays on rigs and in what way they might be improved? >> for routine operations, i guess for which they were designed, for instance, these routine kicks that i've described to you where the active system or the pit system
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is very controlled, there's not a lot of simultaneous operations, it was designed for the routine kicks, if you will. they are very adequate in my mind. and there's always the back up of if there's something suspicious, stop circulating and do a flow check. i think you would find there's lots of rig crews if they expect the well can flow, they will take that back up verification much quicker if there's anomalous readings. in this particular case, they were pumping from one thing, if you will, they were taking sea water from one source and taking a return from the well back to another pit. with current displays and algorithms it's very difficult in real time to determine i put in one barrel. did i get one barrel out or 1.5
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barrels out? i think the report that bp put together demonstrates it could have been much higher. i put in one barrel and got 40 barrels back at one point early in the progression. some system that can do that analysis, that was done in the report in real time would be a very advantageous and display it, yes, that would be an advantage. whether it's obtainable, there's a lot of logic that would have to be built into it. tracking all of those -- you have to keep track of whether fluid is going on the rig among many different systems. then, of course, it would have to be vetted. but suggestion would be another set of eyes, another human brain doing the same analysis would be beneficial. and then it might even have another benefit in that, you know, i always do things better if i think somebody is watching over my shoulder.
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and will catch my mistakes, if you will. perhaps transmitting the data back to shore and being monitored by somebody else, they can talk to the rig and actually build a real time record of the operations much more detailed than is currently done would be a much more effective step. and that individual, that system, might even be an informal way to say, hey, i'm confused. is this a serious problem? especially if the communications in real time isn't consistent. >> one last question, just on instrumentation and censors, there's been so discussion here about how at some point during the displacement of the riser, the spacer was actually sent overboard from the rig. at that point in time, when it was sent overboard, a flowout censor was bypassed.
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in your opinion, are the recommendations you can make as to whether and what extent it's a good idea to have censors that are bypassed during critical periods of the well? >> it's not a good idea to not measure flow rate out, not monitor flow rate out at any time. to be accurate with your question, transocean actually did have a censor in place. we just don't have a record of whether it was functional or not, or any indication from it. the sparing sun was not in line, but there was a flow censor on the discharge. >> so commissioners, that, i'd like to open up the floor to any questions that you may have. :
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question is repeated. it wasn't miked. >> so the question was what entity would be responsible for, the wording again? >> i'll do it -- >> okay. my understanding of the question is, what in your experience having worked on
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these rigs, who or what entity in your experience having worked on these rigs is the one responsible for signing off on test results such that the crew can then go onto the next phase of operations? >> i would say in my experience the company man would be the one who quote, unquote, signed off on it but, there's no written policy but i can't conceive of signing off on one without consulting with, as a matter of fact, the drilling engineer expecting me to consult with back to the office. so the operator drilling to the engineer's consent would be involved in that signing off. >> what about the rig crew? >> the rig crew would definitely be advised and have an opportunity to evaluate it independently. i would think that a rig
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crew would be interested, at least a tool pusher, the person responsible for the rig. after all transocean's responsible for that vessel and the lives on board but as far as that, you know, if you want to borrow it down to one person it is the well site superivsor but i can't conceive not consulting with the rig crew and then of course getting the consent back from whoever, whoever was in charge of that well. >> professor smith? >> sure. i think it is just crystal clear legally the operator has the responsibility. >> legally, and i understand that answer certainly but just in your experience who is the one who is generally signing off on these things? >> for this kind of thing, the culture that i worked in it was actually a company that bp has absorbed, the
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company man would have had the first step and for almost any pressure test of the any welcome point would have, would have called in and discussed that with the einiger in the office. >> how about you, mr. lewis? >> that is consistent with my experience. it's the operating company that's responsible for the design and execution of the well. the well site leader is the operating company's representative on location, quality control and confirmation is one much his primary responsibilitis. the actual decision to go ahead on a test of any great significance would normally be discussed with the engineering staff in town. you would take your test results, either graphically or digitally. they would be transmitted to town. the engineer would look at them, go, yeah, i agree or the engineer would go, boy,
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that looks flaky, what do you think? but it's definitely on site the first call on that is the operator's representative. >> any questions from the commission? >> questions? co-chairman reilly. >> i have a related question on that. you've said that it makes sense to call back when you are uncertain or see information that you don't understand. is it always clear there is someone to call back to? i know that the, some of the companies have, i've been in one in fact for shell, have rooms that, where people monitor full time each rig. i would suppose not all do. what percentage of them would have that? and if they did not have that, you would be getting someone at home presumably who would then do what? go on to his computer and look at the same data?
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how is that all done? >> well in my experience it's, it's usual one person that's assigned, it would be the person who primarily designed the well or somebody who assisted if that person's not available. there is always somebody on call, if you will. wasn't necessarily a room that you called into and it was 24 hours. if it was something of significance, particularly if it was significant to the, to the success of the well, or the safety of the well. >> as company procedure is it federal law, regulation? >> oim not aware of any federal law or even written company procedure. i definitely didn't read a procedure when i was working as a company man that said that. it was just the way it was done there to call in and describe the problems you were having. usually had a well plan
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available. they were up-to-date on the operations. so it wasn't like there was a lot of graphical interface needed. if there would have been we would have faxed back reports. the engineer goes into the office. you know, the well site supervisor's responsible to make sure the well is secure so that those kind of prolonged discussions, whatever activities is going on is not to present an imminent threat but, if you're evaluating something, yes, that interaction happens any time day or night. >> some companies make a lot of stop work capability and say that everybody has it. i guess i would be interested to know how often that is exercised and when it is, how much information is likely to be available to how many people? say if there were other who is might have detected the, or noticed the gauge that
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indicated a kick, is it likely there would have been possibly, or is that information confined to one person specifically typically? >> just about anybody involved with the rig operations that had, you know, an understanding of something that may have indicated a well control event. would have called back to the driller most likely. and informed him, because he is the one, he or she has the most information about current, that immediate, that second, what is going on the rig. and that person also has the ability to react. if it is indeed a well control event, you want to act quickly and shut in the well to re-establish control. so i wouldn't consider a well control event, a stop work. almost doesn't fall into that category. its more like we're having a
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well control event. the driller is informed. that person evaluates whether it is a real kick event. most likely by doing a flow check. and if it is an event, then shutting down. how frequently a stop work happens, it never happened in my experience. seeped like it was never that formal. if somebody brought something to my attention that was of concern to them, it didn't necessarily have to be of concern to me but of concern to them, we would address it even if it required pausing operations. >> one last quick one. the decision to use a diverter, would that decision be exercised by one person or would more than one person have power to do that or be consulted in that? >> you know, all the policies i'm familiar with that's one person because it has to be done quickly. >> that is the driller? >> that's the driller. >> okay, thank you. >> now --. ok.
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others can act if they see an event but the driller is the one who, it is focused on. >> i have a question that is similar to the ones bill just asked but in a different context and that is, responsibility for decision-making. i'm going to mention a few decisions that we talked about this morning. at what level of the organization would the driller on the rig make this decision, would someone back at home office notified of the situation make the decision? or would it go higher up in the organizational structure? for instance, the decision to set the, the surface, the service lockdown at 3,000 feet, would that have been a, where would that have decision been made in the chain of command?
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>> there wouldn't have been a rig site decision. that would typically been a responsibility of someone in the engineering team to determine what the proper plugging method was for a temporary abandonment and it may or may not have been reviewed at the higher level of management within the operating company but presumably, the engineers responsible for the well would have laid out that plan. >> okay. another, the shift from mud to saltwater which had the effect of reducing the pressure? >> same thing. >> same. the options to utilize after the negative pressure test failed? or to make the decision as to, first, that it did fail and second, what to do about it, where would they have
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been made? >> well, i think that relates to what we've been talking about, the environments that we worked in, that decision would have not been a decision that was solely made at the rig. it would have been a decision that would have always involved discussion with somebody who had been involved in designing the procedure and doing the, you know, doing the calculations for designing the procedure within the operating company. that it very well might have remained at the engineering level and not gone up to some supervisory level but it would have been reviewed by an engineer. >> mr. lewis, those kind of systems in your experience. >> in my experience, that decision, particularly give the implications that it had, would have been one that had been reviewed jointly between the drilling superivsor, the well site leader, the design engineers
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and then the organizations i've been with in the last several years, that information of a failure of that magnitude would have been immediately taken up the chain to drilling manager level at the very lowest, if not above that. >> any other questions? gentlemen, this has been an extremely informative and helpful discussion as the panel that preceded you. i appreciate your candor and the contribution that you've made to the public understanding of what happened in this tragic event. thank you very much. >> thank you. >> you're welcome. >> we will recess until 1:30.
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[inaudible conversations] i. [inaudible conversations] [inaudible conversations] [inaudible conversations]
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[inaudible conversations] >> our coverage of the president's commission looking into the oil spill in the gulf of mexico, taking their lunch break at this point of today's session. they are scheduled to return at 1:30 eastern. at that time testimony will return to regulation of offshore drilling. that will be followed by a panel on setting safety standards for the drilling industry. then at about 5:00, there will be a period for public comment. that should last about half an hour. and that will wrap up the day. while we wait for this hearing to reconvene, go back to the beginning of the session today and hear from the first panel where a number of representatives from the oil industry looked at oil well and drilling operations.
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>> give you a sense of what the format will be, thisou morning we're going to hear from five different deepwater and nondeepwater drilling experts in two separate panels. on various subjects relating to well design and deepwater drilling issues generally, as well as macondo and the blowout. we will be splitting the panels into two. one in the first morning session which includes thef individuals, commissioner gram has just introduced.ha and then we will have a second panel in the seconden morning session. while each of the experts ish focused on a particular topic, we will be asking them to comment on other topics at various points during the presentation. unlike yesterday, we expecto the commissioners, if you have questions, of any of these experts to please go ahead and ask those questions. just to orient the commission, the topics for discussion today, for the
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first morning session will be, deepwater geology and formation issues at macondo. mr. thomas willn be speaking principally to that issue.y well design, generally, not specifically at macondo. mr. williams i believe will be speaking to that and then finally drilling operations and implementation of well design.g not only generally but atd macondo.on mr. lewis will be speaking to that issue. in the second morning session just to give you a preview, we will have ae discussion once again with mr. lewis on precementing issues that you saw some of in the presentations yesterday. we will also be speaking with some other experts on the negative pressure test and temporary abandonment procedures. and finally we will be speaking with one of the experts on kick detection and response, both generally and at the macondo well.
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>> if it please the commissioners, i'll begin the process by asking some questions of the experts that we have. we can switch over to my c slide presentation here. again we have drm dr. thomas. consulting petro sissyist. he 32 years experience in the field. charlie williams, production technology for shell andef steve lewis with 40 years of field experience in drilling operations in various places. i want to start by talking a little bit deepwater and whata makes deepwater different and special with mr. thomas. mr. thomas what do you do for a living?wh >> i'm a consulting petrophysicist. >> can you tell us a little bit about your experience in the oil industry. i have worked as a research petrophysicist.a then, management of that department. then i went to new orleans
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to be a field engineer and. then i served as the leader of those sections. went to head office training and taught petro physics at both beginning and intermediate and advanced and then went to the head office to be a technical advisor to the vice president of technology. >> is your experience include deepwater experience?>> >> yes, it >> i'm going to put up againd a slide that we showeda yesterday, orienting people to what deepwater mightri actually mean. so agree generally with this picture where the boundary of deepwater would be in the gulf? i'm not asking you to be sure about every specific but is that the generally accepted boundary line? >> the generally accepted boundary is 1,000 feet ofar water. >> when did industry start
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moving to drill well into deepwater?nd >> in the 1980s. >> and we've heard some suggestions in the media and elsewhere one of the reasons that industry went to deepwater is because oft concerns raised by environmentalists in shallow water. is that true in your view?r >> absolutely >> why then did industry go to deepwater. >> to put it simply, that's where the oil was. unique geological opportunities there. >> and, speaking of those unique geological opportunities, i'm wondering if there is anything that comes attendant with those opportunities? are there any challengeshi that you face in deepwater? >> absolutely. the, the good thing is that we have high permeability but that carries with it rocks that are weaker andth that we end up with a much narrower margin between the
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poor pressure gradient and fracture gradient of thoseur rocks. >> so am i right though, the narrow pour pressure and fracture gradient you're talking about is some of thead same factor that makes it so attractive?i >> it certainly provides the, the ability to have high reservoir energy and therefore, high flow rates from the wells. >> can you give me a sense on order of magnitude level of the difference in production from a deepwaterv well to a well inside that line, a well in the shelf? >> roughly an order from 2000h barrels a day to 20,000 barrels a day. >> i'm going to move and show a slide about the actual core pressure and fracture gradient at macondo. have you reviewed this chart or anything about the corehi pressure and fracture
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gradient in macondo? >> yes, i have. >> when you start drilling a well like macondo do you toepr know what the pore pressure and fracture gradient will look like?o >> we can only estimate it. >> do the numbers change over the coursef of drilling a well? >> yes they do. >> how does that affect yourou operations at the well? >> we continually have to monitor all the signs that give us the clues as to well, well we are going to be exceeding the fracture gradient or not being overpressured.e and we have to stay within that window. >> and how narrow was the window in knew nair call terms at macondo? >> well, by the time they were at their final point, it was about 1.8 or 1.7 pound per gallon mud equivalent. >> and that's a difference between the pore pressuren and fracture gradient, am i correct?e >> that's correct. >> and i don't have a sense,
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maybe many people here don't have a sense whether that is actually a small number. is 1.8 a small number to you? >> it's a small number tot me. >> what is the rule of thumba for what you would like to have? >> well in general we'd like it to be as large as mother nature can make it but if we can, we're happy to have at least 2 pounds per gallon separating the two.le >> so, what is having a 1.8 pound per gallon differential mean to you in terms of the complexity of the situation they were dealing with?ty >> basically they were were? getting close to not beingtt able to drill any further att all. >> we discussed in an e-mail yesterday from mr. bobbybb bodek at bp where he talked about a lo t of things. he explained to some of thers partners at the well to call total depth early. drilling any further would unnecessarily jeopardize the well bore.
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what does that mean to you?s >> in this case i think he was referring to the fact that they had planned to make this well a producer. therefore if they wanted to drill any further to their stated td, then they would have to set a liner. if they set a liner at thisn stage, then they would notn have been able to have had the well bore size to makere the producer that they wished to have.e >> another issue we talked about yesterday was with rock returns on april at this well. are loss returns an indication of a narrow pore pressure and fracture gradient? >> it is one, yes. >> and how do they respond to theo loss return problem here at macondo? the animation in the background simply to illustrate the point here because we like it so much. >> as you can see that, when
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we say loss returns we're talking about that the reservoir is taking mud and, to offset that, we inject materials that try to plug that up, and not only do they use regular loss circulation materials butst they use very advanced poll limber materials to polymerr materials to try to plug it. >> is that typical approach or appropriate approach to deal with lost returns?p >> sure, yes it >> does it get you back to the original state before you had a fracture or the lost returns to begin with?re >> generally no. once you have parted the grains, then it makes itr easier to do it the second time. >> so, would it be fair to say then that this is something like a bandaid? you're doing this but you're never going toto be quite where you were before?-a >> yes. t that is a good analogy. >> but nevertheless, having
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that fix in place is that sufficient to, allow you tofi continue drilling? >> yes, it is. >> do you have an opinion on whether the well was actually stable after they finished drilling to total depth based on your reviewli of the materials? >> in my opinion it was stable. they had managed to stay within that window. they, at td they had ah stable well for four days. they logged and made several wiper trips in between tod remove debris from the well. and they did that without any incident.wi >> so when you say the well was stable at this point, does it mean that they hadle solved their problems and that from then on they wouldt have been okay? >> well, they had solved that problem of getting downy? but they could never ignore the fact that they were in ab geological environment thaty had a very narrow pore pressure fracture gradient window. >>es and does that mean, for
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example, i'm thinking about later process including cementing and running casingsin those are issues they would have to consider duringhe those processes am i correct. absolutely. they would be paramount. >> how does having a narrow pore pressure fracture gradient window affect the cement job? >> they would have to pay particular attention they would not exceed the fracture gradient due to thee weight of the cement.f >> is that why they chose in your view to use lighter foam cement at this job? >> i believe that's >> and you heard me describe yesterday the cement job based on e-mails and report from bp as a complex cement job and a complex well bore. have you evaluated in yourmp professional experience wells that were as complicated as macondo? >> yes, i have.e >> were they drilled safely?co >> yes, they were.e >> and what is it that made macondo complicated that was similar to those other wells? >> just to repeat myself, it
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is really the very narrow margin between pore pressure and fracture gradient and the very high deliverability of these rocks. so it's a unique geological environment really. >> on the other wells that you were describing that wasnt drilled safely, that were drilled safely they were able to narrow, they were able to negotiate those narrow pore pressure and fracture gradient concerns. >> yes, if you pay attention to the drilling you can certainly do that. >> if people want to go toy the gulf of mexico to get more oil, where do they havean to go these days? >> they're going to have toe go to deepwater. >> and is that because of the productivity issues that you described earlier at the deepwater wells produce more?un >> well, that is just about thee only undrilled acreage that's left. >> is it inevitable when you go to deepwater that you'rea going to have to face thesen narrow pore pressure andr fracture gradient concerns? >> yes it is because the geological environment that
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has put the rocks in thatha particular location. >> and, given that environment, does that necessarily drive you to more complicated well designs as well?ce >> yes, it does. >> thank you, mr. thomas. i want to turn now to mr. charlie williams from shell. let me first ask you, charlie, what you do for aom living for shell? >> i'm a chief scientist for well enter gooing and production technology and i'm a technical consultantnt and technical advisor and advise on different major projects. o also do special technical projects and i also advise on the r&d program. >> at shell do you guys also have a similar view about the relative productivity of deepwater wells versus shelft wells?ty >> yes. >> and do you consider deepwater to be a more challenging drilling environment than shallow water? >> in general, i mean, you can have challenging in either environment. but, in general there's, unique challenges to
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deepwater. >> would you agree with mr. thomas's view that, that narrow pore pressure and fracture gradient is one of the challenges.ra >> that's correct. . . >> that's correct. >> what are some of the other challenges deepwater proposes? >> there's many, but certainly one aspect is simply because it's in deepwater. so you have currents, you have water depth, you have conditions you have to design for big so you can do up with these dynamically positioned anchors or rigs, and it's a challenge to have the technology to do all of that correctly. it's a challenge because you have this long riser. you need t i t yod t >> when most wells, the mud system that we talk about that's so important to have in the well and maintain, it exists not only in the well, but in the riser. managing mud in the riser and the total circulating system is different.
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simply because you have 10,000 feet or 2,000 feet of riser to contend with. then you have the blowout preventers on the ocean floor quite a depth down. you have to do all of the work remotely with r. o.d.s, if you want to do maintenance or repairs, you have to pull it out of the water in considerable distance. there's many challenges like that that aren't faced in shallow water or on shore. >> did they use different size in the deepwater than it does in shallow water? >> yes. >> how many professionals work? >> typically you'll have the three drilling engineers, a lead engineer, and the people that are operationally on the rig. there's usually six operation staff they are involved in planning the wells also. then you'll have on the order of six to ten subsurface people.
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that's be petrophysical, petrophysicist, geologist, and look at what the prospects and help determine the location of where you are going to drill. there will be part time people, technical people that come in as well. >> for full-time employs, what range of people is shell employing? >> i'd say the typical team with the operating staff would be as much as 20 and certainly at least 15. >> how long does it take the team to put together the plan? >> again, depends if you are an exploration well where you don't know as much as about the environment and you have to determine those things in advance. versus the well that you know the geology.
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anywhere from eight months to as much of a year, depending on the complexity. >> during the course of the time, is it normal is the design would change? >> yes. >> how does shell usually or your best practice with the process for changing those designs during the course of that process? >> well, it's -- you know, it's defined collaborative process. as i mentioned, you know, the team is large. and so we bring in all of these technical groups, including the operational people are going to be involved in drilling the well. they work, you know, start out on what's the location of the well we're going to drill. start looking at all of the complexities and challenges that we have to deal with in doing various designs. they hone the design over the period that we talked about, and see if you could change the position of the well or other aspects, would it be more optimum and meet the challenges? that evolves over the whole period of time.
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then in different stages in there, we have even bigger reviews, and we'll have a review, recently, you know, i was involved in the review. we brought in the entire rig crew, the entire contract rig crew. they also looked at the well design. and so we looked, you know, looked for the maximum, collaborative, cooperative environment. at the end of that process, when we have chosen the design, then it's approved. and then it, you know, becomes the, you know, the design prog that's used to execute the well. >> you do involve the rig crew then, at least sometimes, in the well design process. >> correct. >> how about the well side leaders? >> correct. >> when you make changes, there are some kind of change that is are minor that don't require the process? >> yes, just as dr. thomas mentioned, as you are executing the well, there's certain things you don't know exactly. for instance, you've got a good ways of predicting pore
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pressure, but it maybe different as you drill. as these things occur, there's certain operational things that you do. you might change the mud weight, two tenths of a pound up or down. there's certain routine operational changes. those are made by the shell drill site leader. makes the kind of changes. if we make the design changes of what we call the prognosis, that goes through the same origin gnat -- original process as approving the original, and the people in the office and the people in the remote operating centers are also consulted when changes are made. and in particular, if it's changes that involve changing the permit. so we, you know, go back and do the approvals the same way we approve the original design. >> would change in the procedures for a temporary abandonment process fall on one side or the other on that
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spectrum of major to minor in >> well, it would be particularly reviewing those kinds of changes. because it involves establishing barriers. and one of our key design philosophies is maintaining, you know, barriers in the well. that includes the barriers that go into temporary abandonment. >> i want to put up a slide here that i think you gave me. and move the discussion over a little bit to the trapped annulus issue that i described yesterday. do we have the laser pointer somewhere? you can always count on your chief scientist to have a laser pointer. [laughter] >> now, it's a little dim. but i think it'll work for the purposes of illustrating, mr. williams, the well that we have -- the well drown that we have
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here which is a very simplified drawing. does it show a dropped annulus in a deepwater well? >> yes, it does. it's the white space that's, you know, above the cement and between the two cross sections of the pipe. >> i'm going to point at it. this is the inside of the wellbore. then there's the outside and the inside casing and the next. is that right? >> yes. >> thank you. maybe a little bit more effective. this phase right in here. >> correct. >> here we are illustrating, this is the wellhead, here's the mud line, this is the ocean floor and this is the formation into which we are drilling. >> and the important feature is, you know, it's sealed at the bottom and, you know, sealed at the top. >> so we discuss a little bit yesterday, the prospect of heating this space up. and can you describe just briefly what makes that space heat up when you are producing a deepwater well? >> yes, the temperature in the
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zone that you are produceing, there's a temperature gradient, like the depth gradient, the heat in the zone is higher than the shallower than the well. when you put the well into production, it's bringing up the hot production, the relatively hot production, and the heat is transferring into all of the tubulars that are on the outside of the well. so it heats up this space, you know, along with everything else. >> so any deep well, regardless of whether it's in deepwater can potentially have a build up issue? >> correct. what's unique to deepwater is your ability to control that pressure because of the seal that's in the wellhead housing. >> we talked a little yesterday, you may have seen, about some of the methods for controlling this annular pressure build up in deepwater. are burst discs one of those
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methods? >> correct. >> what do they do functionally? >> the burst disc, they drill a hole in the tube in the casing and into that, they insert this disc. and the thickness and shape of that disc is designed to fail at a certain pressure and relieve that pressure into the, you know, next outer string. >> it would be functionally in that casing here. >> yes. >> are there any draw backs to using that kind of approach as to managing annular pressure build up? >> there's advantages and disadvantages to all of the techniques. one the complications with using burst discs is that you are limited limited -- the pressure in that casing is limited to the burst disc. if you needed to have a higher pressure, then you would be limited by the burst disc, not by the design rating and casing, which is designed by the burst
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disc. >> why might you want to have higher pressure in that casing? >> you know, if you had certain kinds of problems on the well where you wanted to circulate out, for instance, pressure that had gotten in there. and you wanted to circulate that out and rekill the annulus, or refill the annulus with control fluid, you could be limited by what pressure the burst disc are for. >> burst disc is one method. are there other methods of dealing with it as well? >> yes, the other techniques involve limiting the amount of heat that's transferred. the very common one is to use insulated tubing. so the tubing that goes inside the final casing would be insulated. that would allow the heat to travel with the production and limit the heat transfer into this annulus. thus the pressure build up. another, you know, possibilities are putting in insulating fluids in there that limit the heat transfer, and also you can put
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in different kinds of fluids and material that is have more compressibility than the liquid. >> in this space here, you put in the compressible material. >> correct. >> you could put in a compressible material. going to a different issue, i wonder if you could talk a little bit about the choice between using long springs and liners. do you often have to make that choice between using a line or a long string? >> yes, it's a common decision. we use long strings and liners in tiebacks. you know, the choice is like all of the other design choices that you make on the well. it depends upon, you know, many factors, but in particular, it depends on the uniqueness and the unique characteristics of the particular well that you are designing for. and some of the considerations are things like, you know, how long it would take you to run, you know, along string versus a liner compared to the condition of the well at the bottom of the hole.
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there's certain time dependent things that occur on the bottom hole condition. whether you are high confidence that you could get a long string, you know, run all the way to the bottom of the hole. you know, you have to install this hanger on top of the long string. >> manage this is a long string, you got to get it all the way down president >> -- all the way down. >> correct. the hanger, you want to rotate the pipes because of the cement design. it's difficult to rotate a long string. it's easier with a liner. >> what does rotating do? >> it really tour buy loses the cement. it's a version of mixing down hole. >> that sounds like an issue about cementing. are there other issues versus cementing a long string versus a
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liner? >> well, another thing is a geometry consideration, you are going to circulate the cement down through whatever you run in the hole. if you run the long string or liner, it's going to go through the drill string and liner when you circulate it. just the sizes and spaces, you know, affected the pressures that you circulate out. you know, you do look at that. back to your question about the cement, you know, if you have concerns that you might lose returns or partially lose returns during your cement job, the thing about a liner is that it's -- you can reestablish your barrier by putting a mechanical sealing devices, or multiple devices on top of a liner, or squeeze, what we call squeeze cementing, which would be forcing the cement down from the top of the liner. this procedure is sometimes in my opinion more effective than, you know, perforating holes in
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the pipe. even though it's done both ways. >> would you say in general, you have a tough cementing situation, it's easier to cement a liner in than a long string? >> if you are concerned that you will lose returns or might lose returns when you are cementing, running the liner is, in my view, more straightforward on reestablishing the barriers. >> speaking of barriers, i want to ask you a little bit about the barriers that you can use in temporary abandonment phase of the well. in your view, when you temporary abandon a well, what kind of barriers can you leave in place? what should you leave in place? >> well, what we -- you know, in typically in wells, -- typically in wells in deepwater, you know, our procedure would be to have, you know, a plug near the billion. -- bottom. when we say a plug, we normally
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set a mechanical plug with cement. and we would put that close to the bottom of the well. in particular, we might want to put that -- if we have a liner top, we might want to put that above the liner top. we put another one at an intermediate depth. then we always have one the surface. the one at the intermediate depth would also have a mechanical device plus the cement, the one at the surface would have a drillable, resin-type plug. so it would normally have in our temporary abandonment procedures have three plugs. sometimes it may be as many as five plugs, depending on what you want to isolate. >> you'll have as many as five. >> sometimes. but more typical, it would be the three. >> and you spoke briefly, i want to inform the commissioners on this, about mechanical plugs and cement plugs. can you explain briefly the difference between those? >> i think the people have seen in the diagrams about, you know, running a pack or a bridge plug.
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i think it's been referred to. these are not quite exactly the same. for practical purposes, it would be similar to what's called a bridge plug. it would be a device that has slips on it to bite into the casing and hold it in place. then it has a metallic drill inside it and allows you to put cement below it. then you can close, there's an internal valve, you can put cement above it. >> does it rely on cement to achieve the barrier? >> no, you have two. because of the the mechanical barrier also in addition to the cement. >> does it make it easier to use the cement plug as well? >> well, yeah, gives you a positive placement of your plug. you can put your top cement on top of this device, you know, this mechanical device. so where it's placed is, you know, -- you know exactly where it's placed and exactly the dimensions of it. >> can you place mechanical
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plugs in mud? >> yes. >> can you place cement plugs in mud? >> yes. >> and do you have a view as to whether cement plugs can be placed in synthetic oil-based mud? >> yes, definitely. >> as good as putting them in sea water? >> yes. you know, you have to worry about -- you have to be concerned about spacers and all. but it's done, you know, it's done routinely in both. >> so to explain that, how do you in your view, use cement plugs safely in synthetic oil-based muds? >> well, you know, you'd want to have a spacer between the cement and the synthetic oil-based mud to avoid the mixing. you know, it's routinely done on primary cementing. similarly, you can routinely do it when you place the plugs. it's a common operation that's successful. >> what's the advantage of leaveing the mud and the wellbore as a temporary abandonment phase?
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>> well, when you are temporary abandon the well, obviously, it's never underbalanced during this, you know, the entire set of temporary abandonment procedure. you leave the kill-weight mud in there, all of the operations that you do. the well is under control just by virtual of the kill-weight mud in there. >> now we've heard a lot. i want to sort of move back to a different point that relates to this. you heard a lot yesterday about negative test procedures. do you consider the negative test procedure to be an important task of the well? >> i do. >> do you do it on every well before you have the temporary abandonment? >> no. >> no? what kind of well do you not do it on? >> well, what we -- you know, our common practice on a typical, you know, deepwater well where, you know, we've drilled the single well with the floater, is to do -- we do the temporary -- you know, we do this temporary abandonment. then we leave the kill-weight mud in the well and the plugs in
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the well. we come back for the completion and drill out these plugs, you know, then we do all of our displacement and testing at that point in time. you know, we test the plugs. but, you know, doing things like the underbalanced testing, we'd do later in the completion phase. so we'd leave it, you know, full of kill-weight and tested muds. >> you are leaveing the mud overbalanced at of temporary abandonment phase? >> correct. that's our design choice. >> if your primary cement job fails, that's the affect of having a primary cement job failure? >> if that's happened during your temporary abandonment, the kill-weight mud would keep the well under control. >> thanks, mr. williams. i'm going to move on to mr. lewis and ask him a few questions. mr. williams was kind enough to come to us from shell to explain some areas, technical areas in which he's highly experienced. he has not reviewed the details of the macondo well design of
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the macondo process. mr. lewis has been obtained to look at precisely some of those issues. mr. lewis, what materials is relevant to the macondo well design and daily operations have you reviewed? >> i've reviewed the complete sequence of drilling plans that were developed internally for the well, starting with the plans in 2009 before the marianas moved off of the well. continuing through the final plans for the temporary abandonment and the internal operations notes that were sent back and forth between the rig and the office in town for those modifications to land. i've also reviewed the applications for permit to drill and the applications for modifications that were submitted to the mms.
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and i have reviewed the bp incident reports specifically with emphasis on their review of the casing design for the original well plan. i did that because that is the best access to the designed basis of design information that i can find. i've also reviewed the daily drilling reports. but primarily in the ddr review, concentrated on the last month of the well with special emphasis on the last two weeks. >> based on your review, do you feel familiar with the process of the design of the macondo well? >> i'm very familiar with the documentation of that design. i have some insight into the process, because the
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organization that mr. williams here describes as similar to many that i've functioned in, and the basic philosophy of design as an iterative circular process, where one comes up with an initial design, evaluates the implications of the design on the overall objectives of the well are consistent. yes, i would say i have an understanding of the process. >> looking specifically at the design choices that they made, is it fair to say would you agree with charlie williams, i should say, that there are lots of means of controlling annular pressure build up? >> yes, there are. >> was burst disc one the methods that they used to control annular pressure build up for the macondo? >> yes, the bp design includes burst discs. >> in your view, what impact did the burst discs have on the overall function of the well?
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>> as mr. williams indicated, the burst disc derate the pressure capacity of that string of casing. if nothing goes wrong, that's not a problem. but if you find yourself in a scenario where you have an unexpected or suspected even ingress of pressure into that annulus, i'd actually -- either annulus if that piece of casing is exposed to, you then have to rethink all of your actions at the lower pressure rating of the burst disc as opposed to the pressure rating of that string of casing. operationally, the burst discs aren't a problem if nothing goes wrong. >> so could burst discs have an impact on the way that you contain the well if something goes wrong. >> absolutely. >> are you familiar with the concept of a protect casing in the deepwater well? >> i believe that by protective
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casing, you are referring to what i call an intermediate casing. yes, i understand that concept and that basically is that by design your last string of casing before your production casing would be a long string going from just above your production zone all the way back to your wellhead without liners hung in that string. >> what's the value of that productive casing? >> it gives you a more continuous pressure rating through that interval. and it eliminates the possibilities of failures at locations such as liner hangers. >> was there any indication in your review that bp used a protective casing at macondo? >> no, in this design there's not. what we would call a protective casing under that definition. >> you also heard -- you heard mr. williams describe his
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practice of leaveing well overbalanced when you are temporary abandoning them. having reviewed the progress of the macondo well, was bp planning to leave the well overbalanced at the time? >> no, they were not. >> is there any downside to using the kill-weight mud approach to overbalance the well as mr. williams described? >> the only -- there's no operational downside, no. there is a requirement for time and materials to accomplish that. >> is there any upside to leaveing the well underbalanced? >> in my mind, there's an extreme upside. in that you have the basic laws of physics then controlling that well for you as opposed to a mechanical device that we have built. you are hydrostatically overbalanced, you never bring the well underbalanced. >> i asked if there any advantage to leaveing the well
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underbalanced? >> no, none whatsoever. >> you also heard mr. williams describe the number of plugs and mechanical and cement plugs that we would typically use in a well -- a deepwater well. how many plugs did bp use or plan to use before abandoning the well? >> the design called for one. >> could they have used mechanical plugs? >> yes, they would. >> could they have used more cement plugs? >> yes, they could have. >> was there any operational downside to adding mechanical or cement plugs? >> the only operational downside becomes once again, time and materials, and the time and materials required to remove those plugs when one returns to complete the well. >> i want to move over to talk a little bit about well design. when you, in your practice, first design a well, how much detail do you put into the original initial well design?
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>> it's my feeling that a well design needs to include as much detail as is technically possible. the first thing one needs to define is what the well is going to accomplish. that tells you what the basic well should look like, whether it's an exploration well or production well. and then each element of that well needs to go through a complete design cycle, rolling into the next element with a complete design cycle that goes back and checks the implications of that design both on the previous portion and the future portion of the well. so it should be, and to my experience is pretty complete, engineering process. >> when you face an unplanned event in the course of drilling the well, how does that affect your design? >> well, it implies the necessity to go back and completely re-evaluate the design. both the portion of the well that's already been completed,
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and what you had in mind for con tin tin -- contingencies, but you could go through the same design cycle of looking from top to bottom and looking at the entire life cycle of the well and considering the implications of those decisions. >> so are you suggesting that if you have an unplanned event and you have to deal with the con contingency, you are redesigning the well? >> you are redesigning the well from that point forward, but back checking to make sure those two are compatible. :ple, impose any, make any changes to the way you think the rig crew should be operating as well in the field of? >> and unplanned event should reinforce the level of vigilance on the rig, and hopefully move
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people into thinking, looking ahead, thinking about what the next steps in the procedure are going to be. and making sure that they have the right equipment and the right personnel lined up to accomplish those steps. and making sure that they have the ri so an unplanned event rather than focusing you on solving that immediate problem should also broaden your scope of vision to looking towards the future of that well. >> when you were talking about the initial design and the responses to unplanned events and the nature of the design re-review that you do at that point, what in your view are the benefits of this extended design review and re-evaluation process? >> well, the immediate benefit is to guarantee the continued
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operational efficiency of the well. you also have the opportunity at that point to bring in everyone else's eyes and see if -- from the other aspects of their interest in the well you've done anything that would compromise their efforts. >> and how about operationally or logistically? >> operational logistics is half at least of drilling the well and by that i mean, you have to have the right equipment and the right people there at the right time to do the job. unplanned events imply an immediate need to reevaluate your entire logistic and material supply structure. >> so stepping back to look at macondo now, in your view having reviewed the initial design of the macondo well, was it adequately detailed. >> the initial design was quadly detailed for an exploration well.
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and i felt that they were deficient in detail. especially in light of the fact that i at that point had become fairly apparent that this well was going to be completed as a production well. >> and if you had additional detail, what would that -- what would that have helped to do? it would have helped, i believe, focus on the field on the difficult and almost marginal nature of what they were attempting to accomplish. brought in a heightened level of vigilance to mobilize equipment and materials. and possibly allowed further discussion of options.
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>> and that further discussion you're talking about, you heard mr. williams describe in the process of involving the well site leaders and the rig crew in those design discussions, is that your view of how things should be done? >> absolutely. it's my feeling that the people executing that plan should understand the basis of design that it came from. and be able to suggest an input modifications if they are remote. -- appropriate. >> in your view the subsequent designs of the bp did for the well would that allow the detail for people in the field to think about those assumptions. >> i don't believe they did. >> you heard yesterday from some of the discussions -- some of the explanations that i gave that bp didn't run a number of additional centralizers at one point because they believed there were -- they didn't or believed they didn't have the right kind of centralizers available. having reviewed the process of the design at this point, was there enough time after bp chose to use the tapered long string
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to get enough centralizers of the proper time? >> if they had properly managed their materials acquisition process, yes, they had time to do that. >> is it fair to say based on your comments about the value of design that the lack of centralizers could have been the result of an inadequate design process? >> at least the result of inadequate communication about that design process, yes. >> you also heard me talk about the modeling of the cement design that was done and the decision not to rerun that model in the very last few days. is there any reason in your view not to rerun the model in the last few days before cementing the well? >> actually in my view it's exactly the opposite. there's very many reasons to redo that design. >> now, in the last phase of the macondo well they were worried about the loss returns and the pressures of the bottom of the
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well; is that correct? >> that's absolutely true. >> in terms of well design, what are the different ways that you can deal with those kinds of bottom hole pressures? >> there are basically three elements that you can manipulate to adjust bottom hole pressure and those are the weight of your fluid, the speed with which you pump those fluids which controls the frictional pressure that that is producing and then you can adjust the geometry of the well bore through your design. >> so did you see evidence that bp was at least thinking about some of these things when they dealt with the bottom hole pressures in macondo. >> actually be there's evidence that they thought about all of those things >> adjusting one of those things can influence the other things? >> definitely. it will have direct influence. >> and what happens -- your view of the design process is it proper to reevaluate all the
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same things at the same time when you change one of those variables? >> yes, absolutely. it's critical. this is an interdependent system. it's a machine and if you change one cog in that machine, you have to consider whether or not whether it meshes. >> and changing the cog of the cement job at the bottom of the well? >> yes, sir, there are. >> you described, i think, a design process here. i'm wondering if you think -- the design process also applies to the procedures that are used to build the well? >> they should, yes. >> and in particular, how about temporary banning the procedures? >> those definitely should be designed in the same degree of rigor. >> some of the slides that shaun showed the commission yesterday discussed at three different temporary abandonment procedures that were used at macondo. and those three changes, i think, were all made within a week or so of the blowout. in your view is that a lot of changes to be making in the
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final week? >> that's an unusual number of changes to make that close to the execution of a portion of a well that is, a, that critical and, b, been known to be a requirement for quite some time. >> so is there anything that would have prevented them from establishing the temporary abandonment of the procedures in the well. >> no, sir, there's not. >> do you think it would have helped if they thought about it earlier? >> it would have allowed people to give the matter more thought in a less time-sensitive environment and i think that would have been beneficial. >> and more generally, what are some of the other things that you consider essential at the end of a well activity to make sure that the process goes smoothly? >> well, a well is actually a pressure vessel. the design function is to control and contain the fluids
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that we are attempting to extract. and in the process especially of a temporary abandonment but in every aspect of the well construction process containment is paramount. at the end of a well operation there is -- there are many things that need to be done in order to move forward. and there's also a natural human tendency to look towards the future operation and a tendency to lose focus on what we've just accomplished. it seems to me that at the end of a well it's even more
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important to maintain that vigilance and focus. >> have you ever worked on a well where you felt the vigilance or focus tapered off at the end of a well process? >> absolutely. >> is that just the way it works sometimes? >> it's the way it works sometimes. it's also an extremely variable thing. it can occur in any organization. that i've been associated with. on the basis of the flow of both that individual well operation and the other wells that the organization is dealing with at the same time. >> but i take it from your earlier comments that you would prefer a higher level of vigilance or a high maintained vigilance at the end of those procedures. >> yes, i was. >> and what do you have to have'd to do to have that level of vin lance at the end of procedures? >> you have to have, obviously,
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the resources in terms of manpower available. you need those same resources when you're designing a well, but you have to have the commitment to maintaining the mental focus on what you're doing. you have to have the commitment of paying attention to the present time as opposed to worrying too much about the future. >> is there in your review sometimes a tendency of engineers to move on and think about the next job near the end of a well. >> yes, there is. that's a natural thing. >> mr. lewis, do you consider yourself an expert in deep water drilling. >> this recorded testimony from earlier today. we'll go back live now to the grand hyatt hotel here in washington where we're returning to live coverage of the gulf of mexico oil drilling and to hear testimony of regulation of offshore drilling and there will be a panel on setting safety
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standards to the drilling industry. there will be a period set aside for public comment and that should wrap up the day. this is live coverage on c-span2. this panel just getting underway. >> i will now turn it over to our deputy counsel, sam sankar. >> good afternoon, mr. crookshank. i'm going to ask you a qufez about the regulatory structure at the time of the macondo structure when i switch over to my feed. i want to talk about the new orleans office. is that your understanding that was the office that had jurisdiction over the macondo well? >> yes, that's correct. >> and -- hang on one second here. here's the organizational chart
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for the gulf of mexico region here. and the regional supervisor field operations -- it's a little hard to read michael and then the new orleans district office if i'm right is down here under the deputy regional supervisor for district operations. so about -- do you have any idea about how many rigs of any kind that that office is called to regulate and supervise? >> the district office -- >> yeah, the district office in new orleans. >> yeah, i don't know the exact number off the top of my head. i believe that there's a number of rigs prior to the macondo was on the order of 30, 35%. >> and about how many people work in that office? >> there's about two dozen people working in the district office. >> and of those how many are engineers? >> i believe there's on the order of seven engineers and a dozen or so inspectors. >> are there different kinds of engineers in the office? >> there are.
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there's drilling engineer, production engineer. and some field engineers. >> when a permit comes in to drill a well like macondo, which is the particular kind of engineer who would review that permit? >> if it's an application for a permit to drill for a well it would be by a drilling engineer. >> and do you have a sense about how many application ores permits to drill the new orleans office would field in the course of last year? >> it's a large number. i don't know the precise number. but again, the new orleans office does have on the order of 25 to 30% of all the permits that come in, in the gulf of mexico. >> does that functionally mean that that's that drilling engineer in the new orleans office through whom that work is being channeled? >> it depends on the type of permit that comes in for the application of permit to drill and the applications were sidetracked, that would be correct. but there are other sorts of permits that come in that might
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be handled by some of the other engineers. >> most of the drilling permits would be handled by that drilling engineer? >> that's correct. >> and about what is the budget of the salary for the -- for employees here in the new orleans district? >> the total salaries for that district office in the year 2010 is about $2.3 million. >> and about how much of that is engineer salaries? >> roughly half, i believe, a little less. >> okay. >> i'm sorry remind me of 2.3 million. >> yes >> just to give us a sense about how much did that office spend on helicopter travel in the course of the year. >> about $3.5 million. >> so it's a -- a relatively small fraction of the cost of helicopter travel? i'm sorry, the cost of paying your engineers is a relatively small fraction compared to the cost of -- >> yes.
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the helicopter budget is more than half of the entire budget for the district office. >> now, i should tell the commission we spoke with two individuals who were more directly involved in the permitting of the macondo well. they very graciously cooperated by providing written answers but given the stress of the situation, they would -- they preferred to submit written answers and mr. crookshank has agreed very graciously on his part to speak to specific permitting issues on the wells. i am going to put up the very first permit for the macondo well, or the permits i should say. whoops. there we go. so this is what an application for a permit to drill actually looks like. you can see here it cost about $2,000. and it describes where you are.
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it doesn't say macondo anywhere on this but it is the first apd for the macondo well. i'm going to turn to one of the messages of this. the whole thing i'll show you is about 20, 28 pages with all the attachments. i'm going to skip ahead to one of the last pages in there which is an attachment which i hope will be a familiar chart to you. this is a fracture radiant chart, of course.r seen these c before, mr. crookshanks? >> if you want to take a moment the commission know my background. i'm trained as a mineral economist and have worked at the department of interior for 25 years. i've been deputy director of the bureau since 2002. my job is largely been one on policy on management issues. so my familiarity on these sorts issues are from a management perspective as though from an
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engineer or someone who has worked in field operations. >> i apologize, mr. cruickshank. this is a radiant chart for macondo are you familiar at all with this particular chart? >> i'm aware of what it is. yes. >> you've heard some of the -- maybe you've heard some of the experts we've talked about describe this poor pressure radiant fracture chart here as a crucial piece of data about telling you how you should be drilling this well. when your drilling engineer looks at this kind of chart, what is he looking for on this chart, do you know? >> my understanding it's making sure that you're keeping the sure the pressures in between the poor pressure and the fracture gradient. >> and the dash line here that represents the casing program and the mud program you want to keep that in between there. is it ever where the lines are not in the middle? >> not that i'm aware of. >> does the engineer actually
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check to see whether this is a particular narrow poor pressure gradient window at all? >> well, they would look at the data that comes in and they would be looking to make sure that the well design was going to stay within that interval that it needed to stay within. >> is there any reason they would say, look, this is a narrow poor pressure fraction gradient window and maybe some special requirements would apply to this well? >> i don't know. you would need to ask the engineers. >> i'm going to put up the schematic now, the well program schematic that was attached to the very same application for permission to drill. you'll see here that there is -- the well says it's going to be drilled to 20,000 feet but there's no casing all the way down to 20,000 feet. instead, it terminates a little earlier than that. would you agree that this shows that it's an exploration well rather than a production well? >> yes. >> i'm also going to show you --
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let me see if i can get it in here. on this well there's some indications about rupture disks and burst disks in here. is it your understanding that the inspector -- or i should say the engineer who would reviewed this would have considered the rupture disks or the burst disks in the course of his review? >> yes, he they look at the entire skematte jake and the entire well design. >> is there any regulation whether there should be burst disks in the well. >> no >> so if the drilling engineer was looking at it he wouldn't have any basis whether it was okay or not okay? >> he would have a basis if there was something in the well design that he felt was inappropriate he could raise the issue. >> so this is the original application for permission to drill submitted back in may of 2009. i'm going to skip ahead to
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another later application submitted some time later. it again shows a similar schematic you would agree, mr. cruickshank, an exploration type well shows the casings terminate before the end of the total depth of the well, would you agree? >> yes. >> would it surprise you to know that the internal bp design at this point included a full casing program that would have gone down to a production well? >> i would expect they had definite plans on how they wanted to drill out the well they would have submitted that with the permit. >> i can show you -- i can show the commission what bp is -- i think i'll have to do this again. i'm sorry. this is a contemporary drawing from bp's internal documents from prior to this time frame showing a long string production
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casing and, in fact, showing that this was at least planned as a possible producer well. is there any reason you think that an operator would choose not to submit a full casing program with an apd at this point? >> my understanding when you have an exploration well -- until you confirmed whether or not you have a dry hole or a potentially commercial discovery you wouldn't be making a final decision about whether you would be putting in production casing or not. so you would wait until you were far enough along and to make that decision before you submit that additional information. >> you would permit it in stages then. only as much as you would need to have approved at that time? >> you would -- you would not as necessarily come in with the design for the production casing before you knew whether it would be a well you would want to turn it into a producing well. >> now, of course, this also shows the now famous long string in place here. are there any regulations allowing or disallowing a long string production casing design? >> nothing specific. your well design needs to meet
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standards but it doesn't require you use a long string or a liner. >> are you familiar at all with some of the regulations contained in there. >> from a general perspective not an engineering one. >> some some of them covering cementing in particular. i'm going to discuss a few of them with you and if you would like i could put them on the screen as necessary. i'm going to starts with one that speaks to the purpose of the cement in the well. so this regulation which is 30 cfr 250.420 says that cement has to properly control formation pressures and fluids and has to prevent the direct or indirect release of fluids from any stratum through the well bore into offshore waters. is this something that a drilling engineer can determine whether these requirements will be met by looking at an apd?
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>> i don't have training in engineering but they are supposed to be able to look at the design of the well and the cementing program and determine whether or not it's adequate to meet this test. >> has anyone to your knowledge ever violated this regulation or been cited for violating this regulation? >> not to my knowledge. but, you know, there have been incidents in the past related to cementing, and i would imagine there would have been some violations that may have gone with some of those incidents. >> you're just not aware of any -- >> in terms of the front end of designing the cementing program, i'm not aware of any violations. >> now, moving ahead to another regulation 250.428, this is another regulation about cementing. and it says if you have indications -- if an operator
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has indications of an inadequate cement job, cement channeling or failure of equipment you should pressure-test the chasing shoe and run a pressure survey and use a combination of these techniques. are your aware now that the cement job at macondo failed? >> i've certainly heard some discussions of that, yes. >> and are you also aware there were no -- there were no loss returns at the macondo job or at least as we know right now there were no loss returns? >> okay. >> cement channeling, is that something that an operator can know ahead of time while pumping a cement job? >> i don't know. >> so would you agree it's hard for this -- this is a hard regulation for them to implement at the time of the cementing job? >> right. these are things you wouldn't know until you're actually doing the cementing job. >> and even if you -- even if
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there are some indications it would be a complete satisfaction of the regulation to do -- to pressure-test the casing shoe? >> yes. >> so would a positive pressure test do a trick in a pressure test in the case of a shoe. >> under our regulations, yes. under our regulations as they existed in april, i should say. >> i'm going to turn now to the final -- actually i'm going to show you one more regulation. i apologize. this is a regulation that specifies you have to cement the space at least 500 feet above the casing shoe and about 500 feet above the uppermost hydrocarbon-bearing zone. would you agree this is an important regulation for the -- for the safety of the cement program of a well?
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>> yes. >> i'm going to turn now again to the apd. put two pages of it upside by side because, unfortunately, they are necessary. and i'm going to call out a small thing here. so this to our knowledge is the -- as we understand it, this is describing the cementing program at the macondo well. and this bottom area right here, which extends over to that one couple of words on the next page is the full description as we understand it of the cementing program at the macondo well so it talks about the diameters of the casing and it talks about the rating of the casing and the size of the hole and the mud type of the hole and a whole number of things. having reviewed this, the only -- the only indication we can find of any discussions of cement is the volume of cement which is 150 cubic feet. i don't know if you've reviewed
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this document in detail, but i will represent to you that this is the only place that i've seen on this where it talks about cement. i won't ask you to agree. but my question is, 150 cubic feet of cement, if you do the math works out to roughly 26 barrels of cement in volume. do you have any idea whether that's a low amount of cement for cementing a production casing? >> i don't know. >> are you aware they actually pump 60 barrels of cement down the well? >> i was aware they used more than was in the application. >> and are you aware that even bp agreed that 60 barrels of cement was a very small amount of cement to be pumping down that well at that point? >> i wasn't aware of that. >> this certainly suggests in the apd it says 150 that hopefully, you know, a drilling engineer might have flagged there was a low amount of cement in this well given the requirements of cementing a good casing?
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>> certainly the drilling engineer would have seen that number during his review. >> did they know whether bp was planning on using any centralizers at this well? >> i don't know what the drilling engineer knew about that at the time. >> are there any regulations that require information about centralizers or require their use? >> not at the time of these applications. there are now. >> are there any -- was there anything in the apd that you know of that discuss the flow rate of the cement? how fast it was going to be pumped down the well? >> again, i don't believe that was required at the time of this application. it is required under the regulations now. >> how about the type of cement? is there any required disclosures about the type of cement that would be used? >> no >> how about no indication whether they were going to use nitroagain foam cement? and were there any
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regulations -- and i apologize using the old acronym of speaking back at the time. were there any regulations that required laboratory testing of cement before its use in a well? >> no. >> are you aware that there was a 2007 study that identified cementing failures as one of the leading causes of blowouts? >> yes. >> was there any move to react to that by increasing the amount of cementing regulations? >> the reaction to that was they at the time spoke to industry about the fact that a disproportionate number of loss well control incidents were related to well control failures and discussed the need for some better standards of that. as a result, american petroleum institute formed a committee
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under its standard setting role to develop standards for cementing. some of our engineers took -- participated in that committee. it resulted in the publication recommended practice 65 part 2 in may of this year which we have now incorporated into our regulations as of last month. >> that wasn't in place, of course, at the time of the macondo incident, right? >> that's correct. >> so now i'm focusing on bp's application -- focusing too much on bp's application to modify it's temporary abandonment procedures at the well. these are the procedures that we discussed that changed quite frequently and then turned out in many ways to be crucial to the safety of the final well. and i apologize. i'm actually showing you the wrong page of this. here we go. this is the attachment to that first page that shows the
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particular procedure that we've been focusing on and the depth of the plug here it talks about setting a 300-foot plug. i talked about setting it quite deep as we've discussed. and it discusses the reasons why. it says it's for minimizing the chance for damaging the lds sealing area for future completion operations. mr. cruickshank, do you know what the lds sealing area refers to? >> i believe it's a lockdown mechanism. >> lockdown sleeve. so would it be fair to say that what bp was saying because of lockdown sleeve operations they wanted to set the plugs significantly lower than the regulations would otherwise require? >> yes. >> what do you think prompted the engineer or what would have prompted an engineer to grant this departure? >> what the engineer would have looked at is whether they felt that under the description given of what they wanted to do,
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whether that would satisfactorily plug the well or not. in this particular case, the engineer was relying on the negative pressure test that was going to be done as part of this procedure to determine whether or not that plug was going to do its job. and if it's not, then they would have revisited where that plug needed to be set. >> so he was relying on the plug? >> yes. part of the procedure as i understand it for putting on the surface plug was to do some tests of that plug. >> i don't mean to quarrel. i believe the negative test was up here. the plug was afterwards in the procedure. would you agree to the negative test procedure appears to be and even this well monitoring program appears to be before the plug was set? ..
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>> i can't speak to the depth of knowledge on lockdown. >> i want to look at one more regulation now. this is a regulation about well control. and in particular, there's a few phrases in here i'd like to focus on. can i get it -- there we go. again, the regulation here generally says what must i do to keep wells under control that
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are down here? i must take necessary precautions to keep wells, you must, for example, use the beth available and safest drilling technology to monitor and maintain the pressure for the well to control or kick. what does the best available and safest drilling? >> there's a regulation for best available and safest drilling. the technology that's economically feasible. and that would protect the -- protect the environment. >> does that best available and safest technology vary depending on the depth of the water or the well that's being drilled? >> it could. i mean i don't think our regulations necessarily specify what the best available and safest technology is all of the time. >> i want to actually close with just a few questions about the
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epic of your inspectors. it's worth noting to the commission that have interviewed the engineer who worked on the project, we found no indication that there was any bias, corruption, or undue influence on the people. these are people doing their job, trying to do it well. we found none of that at the level of employees that were doing this. do you believe there was lapses in anyone else beyond the two or three individuals that we spoke with in the new orleans district office? >> i have no reason to believe so. >> do you -- what impact as the accusations of improper influence and bias on the part of your gulf of mexico region focus had on the morale of those folks down there? >> i think it's really had a negative effect. you know, there's been a lot of stories, a lot of public attention on that possibility.
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and for the set of professional engineers and other staff that had taken their job very seriously for a long time, it's just a very, very frustrating and demoralizing picture to have painted publicly. >> with that, commissioners, i will ask you to direct your questions to mr. cruickshank. >> thank you. dr. cruickshank, as mr. bourgoyne has testified before the commission that she fully supported the expansion of offshore oil and leasing areas as president obama with the agency that she had essentially, they had adequate people and resources to cause her to support that. would you agree? >> i think at the time that was certainly what we believe, recognizing that if the program moved in the new areas, there
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would be an increase in staff to deal with operations in those new areas. >> do you think you have adequate staff and resources to carry out your responsibilities now in the areas that you are presently responsible for? >> as a bureau with the department, we are seeking substantially more resources to beef up our inspection functions and our engineering functions and environmental science. we feel that we can do a more complete job, do a lot of things that we would have liked to do in a nonresource constrained world if we had more resources. there are a number of additional things that we would like to do. >> there's a concern in the industry that although many of the industries will be able to comply with the new regulations, that has been proposed and, in fact, are being implemented, that the agency itself will have difficulty responding to the permits and making the judgments on the certification of the
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equipment and the rest in the a near term, and efficiently without delaying development further with the kind of de facto moratorium consequence in the gulf. you have no doubt heard some of those concerns. do you have any response to them? >> there is no de facto moratorium. we have moved resources around to try to address the workload issue that come with the new permitting requirement and we are focusing on resources on trying to design our processes to be able to deal with those. but they are new requirements. we are requiring new information, the process is different than it was a year ago. and properly so. and i don't think we should expect to see processing return to exactly what it was a year ago. nevertheless, as -- the steps that we are taking to try to
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address the workload issues right now involve moving folks from other offices, which we can do for a while. but i think longer term, this is one the reasons we see a need for additional resources in the bureau so that we can have a more permanent fix to this. >> commissioners agree with you on that. perhaps we can have a interaction that could help establish your stance for the kind of resources that you do need. perhaps we could weigh in on that issue as well. commissioner garcia. >> thank you. dr. cruickshank, we don't have a lot of time. so i'll ask you to be as concise as you can, you can submit information for the record if you feel that you need to supplement your answers. my understanding is that over the years, the agencies attempted to add a requirement for proactive risk management, but has not been successful. in fact, you've repeatly tried that. why is that?
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has industry supported those efforts? >> i'm not sure specifically what you are referring to. we do some risk basis for in our inspection program. there is some risk basis in the safety of environmental management system rule that was put forward. beyond that, i'm not sure of anything specific. >> so there's been no attempt to enhance the safety regulations over the last several years? >> there's been a number of changes, or safety regulations over the years. >> okay. based on what you know now, there are anything that the agencies engineers and inspectors could have done given the authority under the regulations to prevent or limit the blowout? >> i don't think that one can ever say you can prevent a blowout through these mechanisms. we will still waiting for the root cause analyses to
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understand what happened here. certainly, i don't think there's a regulatory regime that can possibly design to eliminate the possibility of there being these sorts of incidents. >> okay. we've heard over the last day and a half about the unique challenges that deepwater drilling presents. do you think there should be a specialist office within the agency that oversees this drilling? >> well, we are taking a look at organizational issues as part of the organization of the bureau and considering all sorts of issues like that. we certainly won't say that our staff that's overseeing the operations and the permit requests have the expertise -- >> but are you looking at some specific issue? >> that's part of what we are looking at, yes. >> you are looking at that. okay. are you planning on developing specialist in areas like
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deepwater drilling? >> we're still considering our options for under the reorganization about how we are going to structure. whether it's going to be around functional areas or do more cross training. these are issues that are under discussion. so at this point, i don't think we've reached a conclusion on exactly how we are going to structure the functions. >> let me ask you about an event that occurred a year ago. there was a blowout in australian waters. it lasted for over two months. was there very similar to the circumstances that we saw with macondo. was there any information transfer between regulators or within the industry as to the circumstances of that blowout? >> there's been some between the regulators recognizing that the investigative report on that incident has not been released yet. so we don't have all of the information. but there has been some discussion between the safety
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regulators in the two countries. >> and are you aware of any sharing of information within the industry? >> within the industry, not that i'm aware of. >> let me read a quote from the wall street journal and just get your reaction. this is from the may 7th, 2010 edition. and i'm quoting, steven alred, who as assistant secretary of the interior from 2006 to 2009 said the agency does conduct spot inspections of oil rigs for safety procedures, however, their roll is not to babysit the operators, he said. the agency's primary task during inspections is to verify how much oil is being pumped, which is key to a duty, maximizing payment that the government gets from energy and oil producers. do you think quote, accurately
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reflected the political expectations at the time prior to the blowout? >> i do not. certainly one the task of inspectors is to look at meters that measure production. but we consider that to be a secondary inspection. the primary inspections have to do with drilling rig production facilities, the safety inspections, those are the primary jobs of the inspectors when they go out in the field? >> why do you think he said that? >> i don't know. >> how did the regulatory approach of mms compare with other foreign regulators? >> there's a variety of systems out there. but i think, you know, what we see and a lot of the other countries is they have a performance-based system of regulation where they have less in the way of prescriptive requirements and put more of the responsibility on the company to meet goals for having safe
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operations, rather than approving permits as we do. they get the submissions from the companies and we'll review them, perhaps challenge them, and decide whether to accept or object. but not necessarily formal approval process. >> mr. chairman? >> okay. other questions from the commission? >> thank you, dr. cruickshank. mr. bromwich. pleasure to see you here again. >> yeah. >> do you have any opening remarks?
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>> i do. i have a brief statement. first of all, thank you for inviting me again. co-chairing reilly and graham and other distinguished commissioners. as you know, this is my third appearance before the commission, although this is at a greater remove. i can barely see you from here. i'm delighted to be able to take this opportunity to continue our discussions both about the changes that we've made in our future plans for drilling on the nation's shelf. the regulation and enforcement share the same goal, which is to reform the way the offshore drilling is conducted and regulated in u.s. waters. as you know in late june the president and secretary salazar ask me to become the nation's director of offshore development. their direction was sweeping and clear, to review the agency from top to the bottom, and make the
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changes necessary to give the american people the confidence that drilling in our oceans will be conducted in a safe and environmentally responsible day. since then, as you know, we've aggressively pursued reform agenda to raise the safety and accountability for my agency. these reforms are ongoing and will continue for some time. they are, i think, in many respects, familiar to the commission. let me walk through them very quickly. first we've launched an aggressive reorganization of the former mms. second, we've formed an investigations in review unit that steps up our internal investigations and external investigations in our efforts. third, clarifies what we expect to companies related to worst-case discharges, containment capabilities, and certifications of compliance, the most recent of which was issued yesterday. we have developed a policy to
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deal with real and apparent conflicts of interest. we've begun a full review which will no longer be used to approve deepwater drilling projects. we've issued for the first time, guidance for what's called idol iron. requiring companies to set permanent plugs on approximately 3,000 nonproducing wells and dismanned -- dismantling approximately 750. we have developed rules related to casing, cementing, b.o.p. certifications, and other matters. we've developed and published the rule requiring oil and gas operators to develop for the first time their own safety and environmental management programs, the s.e.m.s. rule, both in the gulf of mexico and in the arctic. now we have pursued the changes while managing hundreds of loyal and committed public servants, many of whom have been in the agency for 20 years or more, through a crisis, the likes of
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which none of them had ever experienced before. and who it's fair to say have been deeply and profoundly shaken by the unrelenting and in many ways, unfair criticism that they have received. now there are great challenges that face the country with respect to offshore oil and gas drilling. those challenges can't be minimized because they are substantial and they are difficult. let me summarize briefly several of the most significant challenges that i see for the development and regulation of oil and gas resources. issues that we confront every day and are the context for your work as well as for our reform agenda. first, to achieve the appropriate balance between ensuring that new safety environment standards are strictly adhered to my industry, and at the same time, expediting the prompt process of permits in deep and shallow water. this balance is critical and most be topmost in our minds as we impose and force regulations
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and make changes as we reform my agency. second, providing appropriate funding. we talked about this with dr. cruickshank. funding and resources for the management of regulation of offshore energy development. it's clear, and i've seen statements that the agency for decades was starved for resources and was not able to review drilling operations, conduct inspections, and enforce standards adequately. even though the agency personnel tried very hard to do so. i've been asked by the president and the secretary to fix these problems. but that will, to put it starkly, require a substantial infusion of resources to accomplish. we have requested substantial resources from congress for the hiring of personnel to review drilling permits, to inspect rigs, monitor drilling activities, and to ensure compliance with environmental standards. there is a substantial technological gap between the industry and the people who oversee it, namely the people in my agency, that has to be
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addressed through new tools and training for government personnel. i'm deeply concerned without the resources that we requested, justification for which could not be more compelling. the changes and reforms that we have pursued and will continue to pursue will not be realized. third, there is a grave need innovation and technological development with the safety, the blowout containment, and spill response. there's a tremendous opportunity here, and a desperate need for technological development offshore. i believe some, if not all of you, have gone on rigs and platforms. in many ways, they are engineering marvels. yet, the technological development that relates to safety has lagged behind the development of the rigs themselves. and so there's some questions that have come up that we need to address. what features should the next generation have in what types of
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censors and safety devices should be installed on the drilling rigs? what kind of electronic and metering should be required to get realtime and important data. both to the companies that operate, and to the regulators that oversee them. how will versatile and containment equipment be designed and be built. now the department announced the creation of the institute, called the ocean center sail institute, that we hope will draw on government, industry, academia, and ngos to help address these and many other questions. fourth we need to optimize safety and environmental compliance regime for operational and offshore regulation. we will continue to think very hard about the safety and offshore regulatory regime.
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we have the prescriptive regulations, which is the system we currently have, and increasingly holding industry to performance standards that we develop. those must be appropriate for the reality and scale of the united states as current offshore and oil and gas industry in our economy. we can't simply import foreign models into our current model. then too, the model that we adopt has to be consistent with the existing relationships between government and the private sector. finally, we must develop the strategy for offshore energy development in the arctic. as you know the resource potential there is substantial. but the arctic environment presents a broad range for challenges for oil and gas development. just to kick through them, they are whether conditions, the development of the necessary infrastructure. employs realistic still response resources and last but certainly not least, protecting sensitive arctic habitats and marine
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mammals. these are all important issues and we are considering all of them. final word, this commission is in a unique position to collect and analyze information relating to these issues. and to draw upon a broad range of expertise and perspectives in your work. i know your work is coming to a close. but the challenges for industry and agency to develop practical and effective solutions will continue. therefore, as we do already, i look forward to working with the commission, i look forward to the report, i look forward to the recommendations, and i want to thank you the commission for its work. >> thank you, dr. bromwich. we really want to be helpful to you in the task that you have set. when you first appeared some four months ago before us in new orleans, i realized the question of the experience of the nuclear industry and the nuclear power operations that encouraged you
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to consider that as a way to supplement your regulatory effort. and raise the bar within industry by defining best practice and working closely with the regulators to bring up the game. i also possibility taking some of the resource load off. have you had a chance to consider that? do you have an opinion on it? >> we have consider it. we will continue to consider it. i think your suggestions and your questions have stimulated thinking both within our agency, and i hope to some extent, within industry. i don't think it can be an immediate institute for the current system that we have now. is there the possibility and potential for the self-regulating mechanism that would enhance the regulatory system that we have and increase oversight? i think there is that possibility. i look forward to exploring it. i think we need to be realistic about differences that exist between the oil and gas and the nuclear industry on the others.
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and one is that oil and gas has been historically extremely competitive. my sense is the kind of information that would be handled in the oil and gas industry if one company inspected another or participated in inspections of another, there would be issues about technical and proprietary information that companies maybe reluctant to share with one another. i think there are larger, far larger number of participates in the oil and gas and the shallow water drilling aspects of the industry than there are in the nuclear industry. so i think we have to look at those differences square in the face and try to figure out whether they are aspects that can be adapted to the oil and gas field. but i don't think -- i'm sure your not suggesting one can take one model and import it into a very different industry with a very different structure. >> thank you. senator graham. >> thank you very much, bill. my questions are going to
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largely follow the comments that you have just made, mr. bromwich. you stated that one of your priorities was appropriate funding to carry out your responsibilities. in many areas in which private business is going to be inspected by government, there are fees or other means by which that inspection service is funded. if you take out a building permit, the funds that you pay for the permit end up going to finance the inspector who is supposed to be sure that the building is built to code and standards, safety, et cetera. why couldn't a system like that be utilized between the agency and the industry rather than relying on appropriated taxpayer funds to support the inspection function? >> that's a very good question, senator graham. my understanding was that was a
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significant element of what the administration was proposing to get us $100 million additional dollars in fiscal year 2011. there was a significant proposed increase in inspects -- inspections fees. the reaction on capitol hill was mixed. there was substantial opposition from industry to raising the fees. that's not a surprising reaction. to the extent that we are banking on or hoping that an enhancement of fees will help to fund the needed augmentations, i think we need to see what the reaction is going to be. so far it has not been incredibly positive. >> there would be a potential alternative approach, and that is all of this drilling is done on public lands subject to lease arrangements. why couldn't you include in the
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lease the fee that would be sufficient to cover the cost of inspecting the activities that the leasee is going to undertake on you the tenant, on behalf of the u.s. people's own land? >> that's an interesting suggestion. i don't know whether it's been previously explored or not. i would be intrigued, would be interested in pursuing it. i don't know whether it's ever been considered before, and if so, what the reasons were for not going forward with it. it's a way to go forward and get additional money from the industry that have used the public lands. >> another of your priorities is innovation, r&d, relative to offshore drilling. it seems to me it's a constant challenge for government to stay current much less ahead of entrepreneurial, aggressive, private sector energies.
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and that's -- we want entrepreneurial aggressive private sector entities to move the economy forward. how would you see the new entity that you described giving government some greater ability to at least stay competitive in terms of it's ability to provide effective regulatory standards and enforcement standards in a rapidly changing technical environment? >> i think we don't have a fully developed proposal yet. i think sec tar salazar made the announcement because he wanted to get the reaction of the industry and ngos, but it is in recognition of a very significant definition that exists in the knowledge and industry and that guides them to deeper and deeper water and the technological know how and the
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development capacity that exists in the government. we are at a severe handicap and always have been as people drill in deeper and deeper water. we're hopeful that one the things that may happen is we will create the institute and get the circulation of personnel. so we will get the benefits of people and industry who are involved in r&d programs who can share that information with the government, which will allow us to enhance the way we go about regulating offshore oil and gas. so the proposal, which is still very much in an outline form, is to try to develop that capacity in government so that we can stay more abreast of the industry than we have in the past. but i'm also concerned about something else which relates to the level of r&d which exists within industry. i went on a tour, recruitment tour a couple of weeks ago in
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the southwest. i dealt with the chairs of petroleum engineering schools in louisiana and texas. they expressed concern about the level of r&d in the private sector into drilling and drilling safety. i think we're really talking about two different but important things. one is to make sure that drilling safety r&d goes on at an adequate level within the industry. but then also that that knowledge in r&d gets shared with the government so that the regulator is better equipped to do it's job. >> a couple of final questions, which were not on your list, one the things that we're probably going to be talking about is governmental restructuring. are there some changes that would match responsibility with skillsets more effectively? one of those that's been suggested currently the osha
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responsibility for worker safety is invested in the coast guard for offshore rigs. it's my understanding the memorandum of the understanding the coast guard transferred that to mms. now is that continuing to be one of your responsibilities? >> yes, it is. >> what would be -- if the alternative were this should be placed in the hands of osha has onshore worker safety and comments to maybe why it should continue to stay in your hands? >> i am always concerned about proposal that further diffuse responsibility for one set of activities. in case, offshore drilling. and to put them in a larger number of hands.
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i think the coordination and collaboration problems when you go across cabinet agencies or cabinet departments tend to be far greater than they are within the cabinet department. i would be concerned not only to have the rh and number of offshore and the coast guard and you add osha, you start to create the unmanageable environment. i think we are capable of enhancing our current capabilities. i don't think we should move components in out and willy-nilly. i know you are not suggesting that. i think we can do that job sufficient already, i've had meetings with the secretary assistant of osha and i look forward to more on what the effective regulatory on rigs and
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drilling. i think that's preferable to moving some of the inspections to osha or someone else. >> could you supplement your comments with an analysis of what you think should be the criteria to evaluate the effectiveness of workers safety in an offshore environment and then why you think your agency based on it's actual performance has delivered at an acceptable level against those criteria? >> sure. we can do that. i want to remind you that i'm sure you know. we have within the last two months put out, i think, a landmark new rule in safety and environmental management system rule. and that's a rule that will be effective in october of '11, meaning we will begin doing inspections and reviewing to ensure compliance. that rule was in the works for a year before deepwater horizon. in recognition that a more
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holistic approach to workplace and drilling safety needed to be conducted. soy think our recognition that this is an issue, and that we can do better predates deepwater horizon. and i think we will make that work. >> my final question relates to what we've been hearing last delay and a half and that is the consequences of having an industrial model which is built upon a lead company where much of the most important and frequently dangerous activity is actually then in the hands of a third or either fourth parties. we've had bp, transocean, haliburton sitting exactly where you are sitting in some cases laying the blame off on each other for a particular
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circumstances. how do you -- what do you see as the role of your agency in more effectively overseeing these multiple, multicorporate relationships which constitute the actual team that goes out on to those rigs to execute to their responsibility? >> unfortunately, i haven't had a chance to listen to the evidence that you've had presented to you over the last day and a half. but certainly, if it does appear that the involvement of multiple companies seems to be a barrier to effective regulation, we will see what we can do to clarify what we -- what our expectations are with respect to each of the players who participate in a particular operation. i don't know whether that's an issue that's been focused on in the past. we obviously have an industrial model that we had no role in shaping, but we clearly have to effectively regulate that.
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i'll be looking with interest in what you conclude in the report, as well as what the other investigations conclude to determine whether we need to do things differently, given the number of players that are involved in a particular project. >> thank you. >> commissioner. >> thank you. director bromwich, nice to see you again. >> i can barely see you. >> i can see you over there. if you can elaborate, you've been talking about the prescriptive regulatory and looking more at a safety case. this morning in the testimony, you've been looking at mms regulation, i realize they have changed. they weren't that prescriptive. they were very general, the industry because it is highly competitive and very productive doesn't have sort of, uniform standards either it appeared in
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each operate. with the expertise deep in the company. in the interest of moving towards more of a combination of the two, i'm just curious as to whether since the macondo blowout with your dealings with industry, you've found a receptiveity of sharing best standards, best operations, and a more cooperative approach than certainly we've heard earlier today. >> i think deepwater horizon has not only been a wakeup call to my agency, but the industry as well. i certainly over the four months that i've been in the job had a lot of meetings with a lot of companies that tell me they've really taken to heart what happened with deepwater horizon. they are redoubling their
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efforts to improve their safety programs. i don't know whether over the long term there will be substantial changes in enhancements to company's safety programs. i have been told by executives with companies who operate both in countries where there is more of a safety case regime that it is very risky to quickly move from one to the other. that, in fact, chaos would ensue if we flipped over to safety case model any quicker than a three to five year period. i think with that learning in mind, i think what we are going to try to do is to move towards more of a hybrid model over time. i think that our s.e.m.s. rule is a first and important step in that direction. and we'll have to evaluate whether there are other
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performance-based standards that we feel comfortable creating in order to build more of a hybrid system. i can't tell, frankly, whether companies prefer the safety case system or the prescriptive regular -- regulations. i any if you ask the company representatives, i think it depends on what their own experience has been. and i think there are many differences between the country that is use the safety-case model than this one. about two years ago, i had the occasion to meet with my foreign counterparts at the international regulator forum in vancouver, i met from canada, uk, australia, and norway. it became sparkly clear to me, they face different and to my mind, less significant challenges than we do. it's far less competitive, there
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are many fewer participates, there are many fewer rigs and platforms that exist here. so i think we really are talking if not apples and oranges, we're talking about operations on a completely different scale in those countries than from what we have here. now my very purpose in meeting with those regulators was to see what we can learn from them. this afternoon, i'm meeting with one of them again. we can learn, but the mind structure here and the historical way of doing business here is different from the way it's been conducted any place else. >> although many of the same countries that are operating here are also operating there, aren't they? >> yes, that's true. >> you would assume they would participated in both cases. they would be prepared to participate in the somewhat different system here. >> i can tell you, i won't name him, an executive from one of the major companies that had
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experience in the uk said he went through three to four year of chaos moving from one system to another. he didn't want to go through that again. those are the words of one executive who made it fairly clear he didn't think transferring the experience in one place was that easy. >> uh-huh. thank you. on another point, you made the statement that you were looking much more carefully at the arctic and identifying four different areas that you were looking at. we've gotten in many comments into the commission on the challenges in the arctic. and particularly, the different gaps, response gaps, research gaps, gaps of equipment and the location of the equipment, et cetera, et cetera. can you just talk a little bit about what timeline that you are under to complete the reviews that you identified and over what period of time you will be
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making decisions relative to the arctic? >> it's going to be in the very near future. we've had meetings in the department of interior very recently and we have additional discussions that are going to be held in the very near future. i think people understand that there's a desire for and a need for clarity. and we will try to provide that as quickly as we can. this is not a back burner issue. it's very much a front burner issue that's currently under discussion. >> one the issues that we've been looking at is the scale of the area wide leases, particularly in an area such as the arctic, the areas are so vast. are you contemplating narrowing the scale of the lease sales from area wide from more defined area with more analysis from the particular resources in those. i mean marine ecological resources in those areas? >> i have not yet been involved in discussions of that kind. we may well have them in the near future. so far in my four months, i have
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not been involved in those discussions. >> okay. thank you. >> other questions for director bromwich. we appreciate very much your appearing here. wish you very well in your work and hope we can play an constructive and helpful role in your success. >> thank you. >> thanks to all of you. >> all right. we will take a break until 3:00. [inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations]
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[inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations]
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[inaudible conversations] [inaudible conversations] [inaudible conversations] [inaudible conversations] >> as you heard, another short break as testimony continues for the second day into the golf oil spill explosion and spill. the commission was set up to find out what went wrong at the macondo well in april when 11
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people dies. they are set to release a file report to the president in january. coming up next, a panel on safety standards for the industry. then 30-minute comments to wrap up the day. then a story about the hearing, a little farther down, we talk about the judicial decision regarding the federal moratorium, that was limited a short time ago. in new orleans, the federal judge barred newspaper organization that the company is moving too slowly. it said the government has not yet issued a single permit, even though the moratorium was limited in october. the government is defending the time it's taking to approve the permits that would have been suspended on the moratorium that was lifted nearly a month ago. so while we wait for this hearing to reconvene, we will hear remarks earlier today about
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drilling regulation. this is from one the earlier panels. this is about 15 minutes. >> did you also look in to see whether there were any industry standards, guidelines, and procedures as to how to product a negative pressure test? >> i did a cursory search, yes, sir. >> what did you find? >> i could not find any standard or guidelines or recommended practices, anything that would be -- kind of have some official weight. >> do you have any sense as to why with regard to what all has acknowledged is an important test the life of the wells. there were no regulations or industry standards? >> i think it's because this is a relatively rare procedure to apply. that this procedure is really important in deep water wells where you are removing the riser, you are removing the pressure that existed in the mud and the riser. it's not something that's common
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for land operations or self-operations where we are working with the surface well head. >> -- wellhead. >> just to get that straight, in deep water where you are leaveing and abandoning a well, you are removing, no matter what, all of the mud in the riser when you pick up and leave; is that right? >> that's correct. >> so it's not -- it's no those circumstances where you are most likely to balance a well in the temporary abandonment procedure; is that right? >> that's right. unless you've taken the kinds of preemptive measures. >> there are regulations, certainly on deepwater drilling aren't there? >> for sure. >> do you have any sense as to why the regulations didn't account for the particular procedure? >> well, i think the regulation that i read is the regulation that would require the operator to if they were going to remove
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the hydrostatic overbalance, to do something to prove that the well was safe to do that. and then the only practical, responsible approach to do that, would be to do the negative test. to remove the hydrostatic pressure in a control system as was done with the b.o.p. closed to verify that the well will hold back that external pressure that you are going to impose on it. >> let's assume hypothetically, that the men on the rig that night at 8 p.m. had concluded this was a failed negative pressure test. what steps would the crew and men on the rig then have needed to take to diagnosis what the problem was and potentially remediate the situation? >> well, a logical first step would have been the circulate the sea water out and regain the
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control. that would allow them to open the b.o.p.s and go back and work in a formal fashion. then the next step would have been to diagnosis wherefores the leak occurring so that we can define a way to go back and correct that. and so that beginning to be a very intense process that i haven't thought through those steps. then eventually, once you've done the test to find where the problem is, then you have to design a correction to that problem. >> let's imagine that here the rig crew and well site leaders had decided there might be a problem with the cement at the bottom. how long of a procedure would it have been to remediate the cement failure at the bottom? roughly. >> something between 24 hours,
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absolute minimum, to trip in the hole and set one of those mechanical plugs, like a bridge plug near the bottom of the well, to maybe several days if they were going to do a more thorough, remedial cementing. >> mr. bourgoyne, is that consistenting with your understanding of what steps need to be taken? >> it is. >> mr. lewis, you are as well? >> yes, those are the basic steps that would be required. >> so at 8 p.m. that night the choices were a good negative pressure test to sign off, which we all have said we believe the men there thought, or undertake what could be a substantial and lengthy diagnostic and remediation process; is that right? >> yes, sir. >> now in your experience, mr. bourgoyne, as a company man at
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chevron, when you had a seen, or if you had seen anomalous data that was seen that night, would you have called that back to shore? >> most definitely. you know, once -- probably in the process of getting the anomalous data made a call back. if i didn't understand what was happening, i'd seek counsel, seek help. and the engineer at shore's task is to provide that. >> were there any policies in place at chevron that instructed it's well site leaders when it call back to shore when they might be seeing the anomalous situations? >> i don't recall any policy. it was more of a -- do you have
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confidence in your knowledge? i guess the burden is somewhat on the company rep to recognize when something is anomalous. but there was -- there was definitely no policy or prohibition to it. i would say it's more of a cultural thing that varied from who you are working for as to whether you would call back with an inkling of an problem, versus nailing down that you really did have a problem. you know, personalities are personalityies. sometimes if, you know, like if we take this case with the negative tests, you might have tried to do the test twice and even circulate sea water around before calling in to actually say, yeah, i'm having a problem. or you might have in another -- for a different engineer, called in much earlier to seek advice
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on perhaps there's another approach or something that i'm not seeing on a more informal level. >> mr. lewis, what is your experience with regard to whether to call back on to shore whether anomalous data readings like this are encountered? >> i've not seen a written procedure in any of the companies that i've worked for as a well site leader that's so specific. i would echo and maybe even expand upon mr. bourgoyne's statements there about the relationship between the rig site personnel and the office engineering staff. i've worked for companies where basically the well site leader was instructed to do absolutely nothing that wasn't already included in that well plan.
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those were very, very complete well plans though, exactly has been described here, pressures, volumes, procedural steps. i've also worked in organizations where the well site leader was left a significant degree of personal discretion. as a well site leader, i learned early on that discussion is the better part of valor, however, and if i didn't understand something, the best possible thing i could do both for myself, everyone on the rig, and the benefit of the company that i was working for is ask for help. so there is a large amount of interpersonal relationship that goes into the willingness to go pick up the phone. the old days the company man was god. he was supposed to know everything that went on the whole time. we have evolved to an
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operational environment that is so complex and has technological elements in it that are beyond the ability of one man to be completely cognizant of. so that it's not required for your well site leader to communicate with more people, more frequently, and possibility even at an earlier level in the evolution than has historicically, traditionally been the case. >> well, even if there's not a specific policy in place, i agree it would be odd if there was one that said when you see weird, negative pressure test readings, call. you want a culture in which people are encouraged to call back to shore when there's an odd or anomalous reading that they don't understand. how does one in a company create a culture whereby the instinct is in those situations to call
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back to shore? what has been your experience, mr. lewis, in that regard? >> well, that sort of culture would have to start with a mandate from the top. but it would be something that would have to be nutured by primarily the interface between your engineering management and your operation management in town. and the bp organization, they've actually got a separate group for engineering and a separate group for operation of the well. but they interface very closely. and that sort of communication would need to start there. organizations that are smaller than that, you'll find that the engineering and operations people are the same group. and it's actually somewhat easier in those context to have these conversations. another thing that would engender that communication would be as was indicated might be the practice at another major
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company here earlier today. the environment of that field operational group, those drilling supervisors, as well site leaders is the new term, that's a bp term, by the way, it came to us courtesy bp. have them involved in the initial design and planning process, they may not have the technical skills to run an engineering program to calculate the loads on a string of casing, but they definitely are the people who are going to be managing the installation of that casing. they are the people who are going to be confirming that they have the right equipment on location. they should be involved from the very beginning. if you have these people together in a room in the designing process, it's much easier for them to go at 3:00 in the morning, charlie, i need your help as opposed to going i don't know charlie. should i call him? that sort of decision can actually play in here. it's that personal in some
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cases. so that's culture, as i said, has start at the top, be built into the system, and be nutured throughout the process of drilling the well. : mr. bourgoyne, calling people back to shore or involving other people in th
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>> and in the eyeses of most observers, they are effective of observing. it's a pleasure to welcome you here, and we look forward to your presentation. >> thank you for the opportunity to be here today. america's only natural gas resources are the nation's economy and standard of living. it is essential that we ensure the safe production of these resources. this country is the global industry and will benefit from a full understanding of the causes of the deepwater horizon incident. i'm confident that the commission's findings will enhance our goal to ensure all our nation's facilities are operated at the high standards of safety, so i am greatful for the chance to come before the commission to share in the integrity and risk management.
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many would say, especially now, that energy companies must make safety a top priority, but i believe that commitment to safety much run much deeper than simply being a priority. a company's priorities can and do evolve over time depending on business conditions and other factors. a commitment to safety, therefore, should not be a priority, but a value, a value that shapes decision making all the time at every level. every company desires to have safe operations, but the desire is to translate this into action. the answer is not found in written rules, standards, and procedures. while they are important and necessary, they alone are not enough. the answer is ultimately found in a company's culture, the unwritten standards and norms that shape mind sets, attitudes, and behaviors. companies must develop a culture
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in which the value of safety is embedded in every level of the work force, reenforced, and upheld above all other considerations. i've been asked today to explain how exxon mobile approaches these systems in culture when it comes to safe operations and risk management. some day the evolution of exxon mobile safety culture back to the 1979 oil spill, and valdez was a low point in our history, a traumatic event with enormous consequences for all involved, but it also served as a catalyst, a turning point prompting our management to reevalwait how -- reevaluate how we understand risk and safety. exxon mobile had been in business for more than 100 years, and we had always taken steps to maintain safety
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operations. we were proud of our safety record. we believed as our safety creed stated that all accidents and injuries are preventable. like many companies, we worked to meet or exceed all standard, trained our employees, had met tricks that measured our success, but we did not have the comprehensive sismatic view of this aspect of our business that we have today. so in the early 1990s, exxon mobile's management undertook what i considered to be a visionary approach, the goal to wholly reorganize the company, make safety of people, facilities, and the environment the center of everything we do. safety would come first, period. it was the beginning of a long journey for our company, and i should make it clear, this is a journey that we have not completed. we know we cannot rest or waiver from the goal of driving
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accidents and incidents to 0, and we're not there, but we have made significant progress, and as we have learned from this progress to be achieved, it had to come from within the company. we could not have government impose a safety culture on us or hire someone to do it for us. experts and consultants do provide a valuable service, but for an organization to change its culture, change must come from the inside out, not the outside in. you cannot buy a culture of safety off the shelf. you have to craft it yourself. we began. we began by creating the framework putting our safety commitment into action. today that framework is called the operations integrity management system or oims for short. because oims is multifaceted, it's hard to describe briefly. here's the basics.
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oims is a rigorous set of elements designed to identify has -- hasards and risk, design, construction, and maintenance of facilities, emergency prepareness, management of change, assessment of performance, and reporting of accidents. we guide 80,000 employees as well as our third party contractors around the world. over time, it has become embedded into every day wrork processes at all levels. through oims, exxon-mobile measures benchmarks and measures all aspects of our safety performance. it's structure and -- its structured are shared. one the greatest benefits is it enabled exxon-mobile a large
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organization operating across cultures to be of one mind when it comes to safety and risk management. i can visit a refinery, a lab, or a platform anywhere in the world and be on the same page as the local employees and contractors regarding safety practices and expectations. i want to stress that the contractors that we work with are embedded within our oims processes as well. we expect our contractors to be knowledgeable and con veer cant with our processes as with the employees. not every company has this expectation, but when everyone speaks the same language of safety, employees and contractors alike, everyone can work collaboratively and safely.
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that is why exxon-mobile measures its safety performance all the time down to every business level. we record not just our injuries, but we record our near misses, and our close calls. our goal is not just to analyze safety incidents after they happen, but identify risk and risky behaviors before they lead to a safety incident. the more elements of risk to be managed in an activity, the more frequently we test, measure, and analyze the safety approach in that activity. more broadly, oims requires us to audit the health of the overall safety approach in all of our operating environments on a regular basis. importantly, these audits are performed not only by trained safety personnel, but by cross functional, cross regional teams drawn from all over our global organization. in this way, all employees are responsible for each other's
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safety. also, the knowledge employees gain by participating in these audits is taken home to their jobs and spread throughout the organization. yet, oims by itself is only one part of the equation. even the best safety systems are not fully effective unless they exist as a broader culture of safety within the people of the organization. while other energy companies use a lot of equipment, steel pipe to supercomputers, it is people who bring this equipment to life, and people's behavior is heavily influenced by their culture. by instilling the value of safety for our employees, exxon-mobile strives to create a working environment where safety is internalize, reenforced, and rewarded. the culture of safety starts with leadership because leadership drives behavior and
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that drives culture. they set expectations, build structure, teaching others, and demonstrating stewardship. that is why the first element of oims is management, leadership, and accountability. exxon mobile managers are expected to lead the oims process by demonstrating a visible commitment to safety and operations integrity. in addition, safety leadership is a significant part of how a manager's overall performance is evaluated. as chairman and chief executive, i know that a commitment to safety and operational integrity begins with me and the rest of the management team, but management alone should not and can want drive the -- cannot drive the safety culture. it must be embedded throughout the organization to flourish. therefore safety leadership at exxon-mobile comes not just from supervisors and managers, but from employees and contractors
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in channels formal and informal. our goal is not just to have employees comply with safety procedures. compliance can lead to complacency. we seek to go beyond compliance, to create a culture in which employeings not only meet the safety procedures, but they are challenging them so they can be improved where needed. i do not want anyone to think inside our outside our pride and safety systems can provide safety. to get what we need in safety, continuous improvement is essential. in an industry like ours that operates 24/7 around the world, the need to manage risk never end. even the best framework is viewed as a work in progress. developing a culture of safety therefore is not an event, but a journey. for exxon-mobile that began 20
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years ago when we put our framework in place. once-embedded, we saw the culture changed and that improved performance. in turn, # we moved from implementing the system to improving it. that's when exxon-mobile's culture was really transformed. over the years i've seen people at all levels understand that our safety systems are put in place for them, that they were about protecting them and their co-workers and the public, and not about catching people doing the things wrong. part of that train formation is recognizing every employee's job involves some degree of risk management, even those who work in office settings. that is why oims extends even to administrative locations. when an organization reaches the point where everyone owns the
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system and believes in it, only then at that point, a culture of safety and operational integrity has been established that can be sustained. when it enters the hearts and minds of the people of the organization and becomes a very part of who we are. we often use the phrase of exxon-mobile nobody gets hurt to describe our safety objectives. some observers of our company question this. they say it can't be done. well, it can be done. we have operating units today that have gone years without a injury. our challenges to sustain that performance where it's achieved and to replicate that performance across the organization. i have no doubt every single employee shares this goal. considering that many of exxon-mobile's energy projects can span decades, achieving the goal of a self-sustaining energy culture means we have to be flexible and adaptable to
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changes in the operating environment. as a result, management of change is a key component of our oims system. our management of change processes are designed to ensure with any change in our business or operations, we recognize the change conditions, we actively identify the new changed risk, and we apply our risk safety and their consequences. risks are addressed, and the change is managed through technology solutions or operating changes in response to the potential risk. the most important, it's clear who owns the management of change, and the subsequent risk management and every employee and contractor is important to that prosays. these very deliberate well-established processes embedded in oims enabled exxon-mobile to ensue new resources and developing projects with the confidence we will do so safely and
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responsibly. such an approach is not only in the interest of employees and resource owners, but clearly it is in the interest of our shareholders which leads me to my next point. upholding the high standards of safety and operational integrity is not just the right thing to do. the phrase we sometimes associate with an act of selflessness, but it accompanies self-interest because it makes a more confident, productive employees in organizations. the rigor, discipline, and degree of accountability required to improve safety performance, are the same qualityings producing safety business results operationally and fiscally. safety is not proprietary, and we share these practices in our industry and other industries. we seek to learn from others. after the 2003 space shuttle
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explosion, they developed a team of experts to study the technological and organizational factors that may have led to the disaster and whether there was any lessons for operations. it is by learning and analyzing, but looking to best practices and other organizations and examining near misses of our own that we continually improve our own performance. i know in commission has heard a lot about the importance of deep water supplies, but the technology enabling us to reach the oil is one the significant security develops over the last 20 years. deepwater production that didn't exist prior to to 1989 today makes up 15% of production. by the year 2030 it will grow to nearly 30% along with brazil and west africa, the gulf of mexico is one the most important
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deepwater provinces in the world. in 2008 there was more oil and gas discovered in deep water, than in on shore. for the sake of our economic growth and security, we simply cannot afford to turn our backs on this resource. neither can we miss the opportunity to improve safety in the gulf of mexico. the macondo caused money and damage. if we don't learn from this disaster, it will have been a double tragedy. as chairman ryan said at this commission's first meeting in july, we must come to grips with the disaster so we can never see its life again. i spoke earlier about risk management being a constant challenge, well, exxon-mobile believes this should not happen if industry best practices are followed.
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the spill did expose that our nation and the energy industry could have been better prepared for the possibility however remote of a deepwater blowout. that is why we're leading a multicompany effort along with my colleague today to build a rapid response oil system in the gulf of mexico. this system involves a $1 billion initial commitment from the sponsor companies is unprecedented in our industry. it provides preengineered, constructings, and tested equipment to be deployed within 24 hours of a spill in the gulf. in addition, exxon-mobile and other operators in the gulf of mexico in conjunction with the department of interior instituted new requirements regarding inspection of blowout preventers, casing design, and cementing procedure. i believe that these steps in addition to the inspections performed on deep water rigs
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will enable the gulf region and the entire country to continue to develop our nation's energy resources with confidence. in conclusion, i'd like to share this thought. exxon-mobile is viewed as a cautious company. we're sometimes criticized for being too cautious, and yet meeting the growing demand for energy is risky. our employees operate some of the most complex technologies in some of the world's harshest environments. how we continue to progress technologically with risk is that advancing human progress does not mean avoiding risk, but managing risk by identifying it, and taking steps to mitigate it. no company, ngding my own, lays claim to a 100% success rate in this endeavor, yet that remains our clear goal. in closing, there's three points i hope you consider in deliberations. first, a culture of safety has
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to be born within the organization. you cannot buy culture. you have to make it yourself. second, make no mistake, creating a strong sustainable safety culture is a long process. if an organization is truly going to overall its approach to safety, it has to be committed from day one, but you can't start until you stop until you start and you'll never finish. finally i want to return to oims. i mentioned there's 11 elements fundamental to health and safety of our company, but the bookends are the most critical. these are management, leadership, and accountability, and operations integrity assessment and improvement. without leadership by example and without thoughtful, honest, and objective self-assessment, no system is sustainable. our nation and our world continues to face challenges.
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meeting the world's growing demand for energy safely and minimal impact on the environment is our biggest. in light of the incident, we are advancing our progress towards the goal. we support your inquiry and remains committed to the safety of our company and beyond. thank you. >> thank you. i'd like to ask you a couple questions that go fundamentally to the issue of whether or not your approach to safety can be replicated by other companies, and ask you to look back at the period before and then the period after the exxon-valdez tanker spill, and go into a little day till if you -- detail if you would about what you did and whether you made any false steps, whether how fast you were able to raise the game,
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and go beyond compliance and get best practices, and what you think that may mine for other -- may mean for others in the industry to do like wise. >> as i indicated in my prepared remarks, up to the time of the valdez incident, we thought we were pretty effective, and the traditional metrics used to measure that effectiveness certainly led us to believe we were. what we had come to understand is the traditional met tricks are -- metrics are just lagging indicators, and they just told you about the problems you have had, not how to prevent those problems, and so that was, i think, an important recognition early on. being an engineering and science-based company, it was natural then as we set about to understand how do we really want to change the way we manage risk to take various systems and process approach, and that's in
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fact what was undertaken, and i think in some of the early days there were some false starts in terms of how we went about understanding accountability and responsibility in particular in terms of well, who actually owns which piece of the system in the process? that has been something that has continued to evolve with time. as i said, we've been at this 20 years now, but we have now arrived at the point where throughout the organization everyone understands they own it. they own the risk that surrounds their personal activities, and they own the risk for those around them, and that the only way we manage those is integrating all the elements of risk so no one element in it's overseen is going to cause a problem for us. evolving from that realization i think there were a lot of missteps if i can say that or
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learners, maybe part effort process of us learning and our organization learning how to do this, but i think clearly the thing that i give enormous credit to the leadership of the corporation at that time was the recognition that you weren't going to go out and bring a consultant in to do that, that the problem were ours. the problems were inside, and we're the only ones to understand them and address them to make a change, and i think that was an important learning early on, and then just the relent less stick-to-itness and the recognition we had to get on with it and it was a never-ending process. this hob updated three times now and every five years it's reviewed and updated again.
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it's never ending. >> commission and staff studied your oims system, and i would be interested if you describe your cold-eye inspections and some of the things part of daily life in the company. >> yeah. there are two aspects of that assessment that i mentioned as one of the elements. there are internal assessments where the operating unit looks at its own processes and makes judgments about how effective they are. they do testing of how effingive -- effective they are and they steward the close sure of those gaps, but every three to five years depending on what the risk profile of the business is, there's an external assessment, and that's compromised of people with particular expertise in those types of operations that
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they're going to examine, and they are generally compromised of people from all over the world who then come in and undertake an exhaustive review of that unit's implementation of oims. they test the effectiveness through various means, and then they identify gaps that need to be closed. they give the unit an overall assessment, and those gaps are up through the management team as well were closure, and the real value of that, one is to strengthen the system and ensure that it is dynamic and evolving in recognizing changes within that operating unit, but that is also how we share the learnings and best practices globally because those teams on the assessments then go back and share what thaif seen in -- they have seen with similar operating units elsewhere so whether it's drilling, producing platforms, or office
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environments, all are assessed on a routine basis, and it's that process that's really crucial to the improvement process. assessments again are not about finding people that are doing things wrong. the assessments is how do we continue the improvement process. now, if a unit gets a poor assessment because the gaps are huge and they are well bind where they should be, then we deal with the local management u , but that rarely happens. >> your company has a lot to do with the nuclear operations. that's what they try to do for the whole industry and they provide a grade, working with a regulator. have you had a chance to consider whether that kind of initiative would be valuable in the industry as a whole in order to, in order really i suppose from your point of view more than anything to protect against
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someone else causing your rigs to be shut down for their misbehavior? >> well, you know, we have looked at impoe, responsible care for the chemical industry, a number of other models. when i say we, it's part of the api joint industry task force, and i think there are elements of all of those useful to us as an industry to consider. there are distinct differences between the nature of the nuclear power industry and the oil and gas industry and in particular deep water, the nuclear power industry, the facilities are, you know, they are fixed sites, the conditions don't change significantly around those sites, o. there's a lot of similarities, most are regulated utility, so they operate in a different type of environment, most of the technology is well-known, so there's lill proprietary
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involved in those sites as opposed to our industry moving to different locations, different environments, evolving all the time, new technologies being introduced, and so i think we look at the principles around in terms of how you share best practices and assess whether the companies are operating at a certain level of competency. what we evaluate within the industry is capturing the best elements of that, make a responsive to the fact that in our industry there's a lot of management of change going on all the time, and that's just the nature of the technology evolution that has been underway now for quite some time, how do we protect the proprietary aspects of companies and yet share the best practices of safety and operating practices 6789 i think the approach is one that is important. it is one that the industry is
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actively engaged in seeing if we can't construct something similar that would meet our objectives, yet protect everyone's competitive interest as well. >> do you have an opinion about how to address what has been a real disperty between the sophistication technologically in deep water and the expertise level and the resources, the number of people who are actually charged with regulating that industry. do you have a sense of how one should deal with that? one possible advantage of something like that can supplement the expertise of the regulator and relieve them somewhat of this burden which seems to us as very often one that leaves them ill-equipped to understand a lot of new technologies. >> well, i think the elements of
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self-regulation which a lot of people kind of draw back when you use that term, but i think elements of self-regulation have been proven effective in other parts of the world and have been proven effective even here, so i think to the extent that when we structure the approach, we accommodate the fact that it is in company's self-interest to improve in that area, and what we're really wanting to do is provide systems and processes and frameworks for them to do that, but as was evident in my remarks, at the end of the day you can give people procedures and tools and technology capability, but it's in the hands of human beings, and human beings have to make decisions. they have to take actions in response to events, and that involves getting at the culture of human behavior, and why, you
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know, why do people fail to act? why do people make poor decisions? that's the baffling challenge that all of us who work hard in this part of risk management struggle with all the time. as to the regulator, it is a significant challenge for the regulator to have people at competency levels come in to where the industry is technologically. we in the industry are very competitively hiring the very best and brightest people out there, and we pay them so they'll come work for us, and we invest a lot in their training after they come work for us, and most of the technologies are being developed within our industry, the step-outs, and pushing the envelopes further happen within our industry. you can't go to the academic world and find it because the
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academic world is a few years behind us, so it is a difficult challenge for the regulator to have people who would have that same level of competency. i think it is realistic though to provide some help in training people within the regulatory agencies to a level of understanding in -- it's going to require engineers and scientists to have a level of understanding to recognize when there is a risk exposure and are at least able to ask the questions of how is that risk being addressed? they may not be capable of performing the precise response, and they may not be necessary, but they need to be capable enough to say i see a risk, it's not clear how it's being managed, and say to us, how are you addressing that? that would be -- that's e enormously important to
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us as a industry. in my view, we want a constant regulator. they are part of the risk management system and redundancy in the system that can test are the risks being managed? they don't have to be capable necessarily of designing all the elements of a drill program, but they have to have a technical competency that they recognize there's a risk exposure in this operation. we need to address the risk by asking the right questions. >> thank you. this has been very helpful. we would like to continue to keep the conferring open, and if you have thoughts for us, we would welcome them. appreciate very much your being here today. >> my pleasure. >> you've given a lot to the commission. we had the advantage of richard sears and knows by name your colleagues and appreciates very much that we had the opportunity
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to sit down and look at your resources both in new orleans that i did 10 days ago with mr. boesch and senator graham. we're excited to have you hear and excited to hear your prosecution. >> thank you. i do appreciate the opportunity to speak to you today and tell you a little bit about safety in shell. now, no one company can complaim to have all the -- claim to have all the answer, and we don't make that claim. i hope these remarks are useful to you. at shell we believe in relentlessly pursuing no harm to people or significant incidents. we call that journey goal 0. we expect everyone who works for us, employees and contractors to believe it is impossible to work without incident, and we have examples to demonstrate this is true.
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we have three overarching behaviors, complying with the rules, intervening when it feels wrong, and respecting people, the environment, and our neighbors. now, this provides a clear statement about the culture we aim to build. our health, safety, and management system has eight elements each with a specific role in ensuring that hse risk are identified and managed. now, among these elements are defined procedures, audits, clear responsibilities, and come competencies for staff, hazard management, and a relationship in culture. i'll address how we manage safety through a combination of rigorous systems and the culture required to make those systems effective. safety systems essentially fall into two categories, those designed to protect the personal safety of our employees and contractors, and those focused
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on process safety or ensuring the safety and integrity of our operations and our assets. a personal safety systems include clear and firm rules. at shell, we have 12 life-saving rules. these are the do's and don't's covering activity with highest risk. protecting yourself against falls when working at heights. our employees and contractors must comply with these rules. failure to do so is a choice knot to work for shell. this has been fundamental in reducing accidents. it is fairly easy to track in mechanisms with incident rates and participation in processes such as job safety analysis. process safety is also managed through a variety of tools such as well and facility design standards, established operating
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envelopes not to be exceeded, safety intervals for equipment, and an effective management of change process. our awe approach also requires that our drilling contractors develop a safety case to demonstrate major risks are properly managed. the safety case in deepwater drilling shows how we identify the hazards on a rig, establish the barriers to prevent and control those hazards, how we aassign the critical activities designed to maintain these barriers. it gids the crews -- it guides the crew and especially those new to a rig. the safety case is owned by the drilling contractors, but it is reviewed by shell before we place the contract with the company. it is assured in practice before the rig operations begin, and it
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is audited at regular intervals while the rig is under contract to us. the case also includes bridging documents to our own hse management system. through these drilling contract ors works to make sure the well plan and operations procedures are understood by both parties and assures ?erns that risks are properly managed. it requires two barriers in place at all times to control each hazard. while abandoning a well in deep water, we found a secondary barrier that didn't pass our test, and therefore the work was stopped, installed a second mechanical barrier before proceeding with the job. a defined rule like these are important, but i believe that an organization with all the right systems and tools in place to manage and reduce risk to people
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and processes will fall short if it does not have a culture or safety theme felt in every aspect of the organization. the systems processes and culture must all work together. building a safety culture starts with leadership. this is actually the first element of the shell's lse management system, to create and sustain a culture to drive our commitment of no harm to people, the environment, or assets. leaders must engage in promoting and recognizing safety behaviors and clearly communicate to all employees and contractors that safety is not a priority, but a core value. priorities can change with the business environment, core values do not. in shell, intervention or the stop work rule is another overarching principle. every employee and contractor at
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the shell site as -- has the right and obligation to stop work that feels unsafe. everyone knows about it, and we reward people who do it. it's a key part of job planning, and it works. our british platform in the gulf of mexico was shut in after an anomaly was noted and a vessel inspection. while the operators could have run follow-up inspections to confirm the initial finding, they instead decided to shut-in this platform. later we found the inspections would have indeed avoided the need for a shut-in, but that wasn't the point. they made the right decision, and they received a hero reward as a result. the second example occurs a few days ago at our newest depp water production asset in the gulf of mexico. an operator noticed a small gas leak. it was too small to be picked up
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by the gas detectors, and nonetheless, they followed the protocol of getting out of the area, initiated emergency shut down procedures. the problem was insignificant as it turned out, and it was resolved without incident, still, the team was recognized with the proper response. these are not isolated examples. there are hundreds of recognitions we see every year of employees and contractors who intervened or stopped work in potentially unsafe situations. while most interventions involve stopping and individual work task as opposed 20 an entire -- to an entire facility shut down, they create a safety culture at the rig level. awe audits are another part of the key story providing information about whether we are doing what we say we do in compliance and leadership. in 2009, dupont administered
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their safety survey in our drilling organization comparing us as the best in other industries. we ranked world class overall, improvement areas were identified. for example, we received fedback that the structure of our tools tended to be too complicated. as a result, we con sensed the -- condensed the key points of the well site safety systems. audits such as these are an important part of not only compliance, but continuous improvement. the mind set is one of always seeking feedback and identifying gaps with the ultimate goal of ensuring safety built into every aspect of how we do work. i do believe we are seeing this way of thinking take hold in the industry today, and it points to a path forward. this has been most visible in recent months with industry and government taking steps to enhance capability and performance in three areas,
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prevention, subsea containment, and spill response. for example, we at shell applied macondo learnings in our alaska program. the limited program occurs in shallow water, our spill response assets has enhanced capability. you're aware of the marine well containment company formed, and rex mentioned that earlier and the companies involved, and we hope everyone operating in the gulf of mexico will ultimately be involved in that system to improve our preparedness in the gulf of mexico. industry members created a task force evaluating programs in the chemical and nuclear industries to identify best practices for a suitable program for deepwater drilling and completion. a safety initiative with independent third party auditing that can bring about real change. crucially the department of interior began to buster their work force with rigorous changes
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intended to prevent the occurrence of another disaster. it is a decision they continue to improve. as the industry needs a robust, expertly staffed regulator to keep pace with and augment, industries technical expertise. a competent and nimble regulator is able to establish and enforce the rules of the road that ensure safety and commercial success. now, moving forward, we must strive for a process yoind compliance and achieve a strong safety culture. an operation is not as safe as it can be unless the people doing the work share the same belief. i'll share one example from my recent experience. in the deep water of gulf of mexico, 8,000 feet of water, 2 miles offshore that started in
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2010. it holds records and is an example of technology. however, i'm most proud of the fact this went from the initial design on paper all the way through to construction, the drilling of the well, the installation of the facilities, and the startup of production. it's almost four years and many of millions of hours worked with no lost time accidents to personnel, shell or contractors, and no environmental incidents. we see this being repeated around the world. now, most importantly, this demonstrates that it can be done and helps shelf staff and contractors carry this belief to all of our operations. yes, we've seen improvement in our safety and environmental performance in shell as a result of the systems and culture that i've discussed, but we clearly do not claim victory, not by any stretch. this journey never ends. there is no room for come place
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sen sigh. you don't fix safety, and you can't put a price on the value of the safety culture. thank you for the opportunity to share these thoughts, and i welcome your questions. >> senator graham. >> thank you, mr. odum, and let me also join mr. reilly in our appreciation for mr. sears, an outstanding addition to our team and the many curtesies shell extended to us particularly to our visits to the gulf. we have very much benefited by your assistance. >> thank you. >> you are one of the great international corporations of the world, and do business in almost every significant oil production region. what is your process both within
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your company and then across companies to share information on incidents, best practices, what new learning -- earlier today we had the deputy director of the former mms talk about an incident in australia which he suggested was quite close to what then happened here in the gulf on april the 20th, and it was his sense there had not been much learning transferred from the australian incident to u.s. firms and therefore, there was not an advancement of the understanding of risk and how to respond to it. could you comment as to how that level of international cooperation on safety? >> i will, and i'll do it in the context of drilling and even deepwater drilling.
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my comments apply to all aspects of our business. we apply ourselves in a way that looks at all this business globally. we have a dweepwater drilling set of standards for the company that are not different in the u.s. than they are from the coast of africa. they are global standards and they meet or exceed the standards in any countries that we operate, but what we have in that organization then because of the design is a connected organization worldwide, so this drilling group, if you will, global drilling group, one of its main obligations is to share examples, incidents, learnings, best practices across the world, and those are implemented immediately and always result in this same set of standards across the world, so it is -- there's many mechanisms to do this, but this is one. when it comes to a particular incident, let's say something
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particularly notable happened, the process i described of having a group incorporated across the group happens quickly, but not quickly enough if you learn something very significant, and you want immediate action, and so we have a system of what we call alerts that go out across the company, and if something registers, and we keep this to few significant events because it's like an alarm and if it goes off all the time, people don't pay attention to it, but if there's something significant to learn and they need to know it today, this comes in the form of an alert to all the people to cause immediate change. >> i would like to talk about what in military terms is referred to as a layered defense where you have defenses backing
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up defenses backing up other defenses. in the industry it seems to me that one place to start might be with the individual employee. i was impressed by what you said in your prepared remarks about the employees who were willing to shut down the production rig in they suspected that something seriously bad was going on. i would think that is a difficult culture to develop because in some companies the employee's reaction if i do this, it will cost the company a lot of money and that's not good for my career advancement. you mentioned that you have recognized employees who have come forward. are there other aspects to the
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way in which you have dealt with what would a peer to many -- appear to many to be the employees being actively and proactively engaged in safety? >> i think it's a critical topic which is why i spent so much time on it in my remarks, and the other reason i spent so much time on it and i think i hear that in your question, it's not the natural bias of people to necessarily act this way, particularly contractors that come in and work for us as a company and want to make sure they're t#>0
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>> if we see somebody who can't be in that culture, we put them in other avenues. that's a main way to have an impact. >> another layer is the way in which this business typically does its business which is at a single site, multiple contractors and subcontractors as well as the company or all
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who are engaged in accomplishing the mission. we heard a day and a half of bp, transocean, and halliburton out on deepwater horizon. as strong as shell's individual culture is to safety, how do you convey that to the multiple parties with which you are doing business and bring them up to that same level and then integrate all of that into a common safety culture at the site? >> that's a great question, and it begins with understanding if a contractor owner site doesn't have exactly what we look for from the shell people, it's not working then. we need this from everyone. i'll describe a tool with a strong cultural element that we use to get there. particularly again talking about the drilling-type operation, and that is we take a safety case approach. i'll describe what that means to me when i say a safety case
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approach because there's more than one way to get there. the way we use that is a safety case in this case would rely on the contractor initially to identify all of the potential major hazards associated with the rig and drills operations, and then the obligation is to ensure that the barriers and mitigations for each risk are in place and they are effective, and so they put that together initially, we work that then in an approach with them to both have a very good understanding of that. as they build that and do that for shell, they have to understand exactly what the shell standards are. they have to understand our well plans. there's a tremendous amount of interaction in putting the safety case together. you take that one step further, and it's only an effective system, and this is what we look for to validate the system is once these critical elements and hazards are identified, the mitigations are identified, is it absolutely clear who does what in all of these potentially
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risky or hazards situations. having the roles identified is critical. is it clear because a contractor may have their own protocols. are you following the shell protocol or contractor's protocol. covering this ahead of time is critical to that. the kind of thing you see on a shell site on a day-to-day basis is how are we taking that hazard mitigation and making sure the shell and contractor crew apply that on a day-to-day basis, and the way that looks is you don't do a piece of work on a rig without having a job safety analysis and what we call a permanent to work. this is part of the multilayers that you talked about to prevent an accident. well, we ensure that the contractor is able to relay that back to the safety case, but it starts with the thinking of one of the major hazards flowing
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through to the work. it's not unusual for anyone in the organization, say myself, to visit a platform, go to an individual and ask if they know what to do in certain situations and what are the hazards you're directly related to be that is shell person or a contractor. i think keeping it live like that is actually the most critical element to making sure that it works. >> in that discussion with those three and particularly between bp and halliburton, one of the most glaring instances was in surrounding the cement of pore at the bottom of the well. there was disagreement at to who knew what about the laboratory samples of the concrete that was going to be poured. there were questions about the testing that was done after the
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pour by who was supposed to interpret it and how did you evaluate the result of that interpretation. how would you in your company deal with a specific incident like that how in this case it may have played a fundamental role in the ultimate explosions? >> i didn't have a opportunity to hear all the testimony and comments on that, but if i understand your question, let me try to relate it to the area of who is responsible for those activities in a rig for shell in a drilling operation. basically everything you mentioned the person i hold responsible and we through the safety case development hold responsible explicitly is the shell person in charge responsible for all of those elements, so just to keep it very brief, that's my answer.
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>> another layer in the layer defense is the industry-wide commitment to a safety culture. .. >> i heard it in some of the early testimony as i came in a little earlier this afternoon, that the sort of changes take
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time. these changes don't happen overnight. i think particularly to the safety initiative that the industry is now working on together, we have a joint task force type approach to did developing something here where it has come as rex said, building on the best things that we can take way that are out of double for info and from responsible care, and other elements. i think that what we can expect to see over time is that we will make a difference. and the elements out that the standout for me is that having this safety initiative up and running and having it look different for the industry means there's a commitment there for the members of this, and these will be largely industry members that says we're committed to a certain set of principles around operating at the highest level of safety, around sharing best practices that around continuous improvement. so i see that as a step up from where we are today necessary. i think the idea that this would involve third party auditing and
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independent assessments of the operators in the gulf of mexico are doing, you know, i use the deepwater example, but in terms of how we are doing, do we really have effective safety management systems, a new and different peace as i said in my coepared comments, i think it because it's important we are all operating at that level. you know, one of the points i want to make is that ati is an industry body, and that technical design, recommended practices, the technical standards element of api i think is unmatched anywhere in the world. we need to leverage that piece of capability. and so i would see something like this directly tied into the standard setting process, which already, by the way, i think it needs to be taken more seriously and emphasized more, but already has an avenue for participation by the regular and others in
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setting the standards. i think being sure that we leverage that capability in this safety initiative is absolutely critical. and again, will lead to improvements. >> and finally, the role of government in this layered defense on safe practices, what recommendations would you have from your experience, including your international experience, in terms of how should the federal government organize itself to be an effective overseer of this industry, and protect, protection of the safety of our people and the safety of the environment? and what do you think the role of industry should be in its relationship with that government entity, or in to get?
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>> a couple of things that i'd like to say about that, and these are not necessarily in priority order, but i think it has to start when we look at the system in the u.s. it has to begin with a well funded and supported regulatory agency. and i don't think that's what been the case. i'm not sure the funny has always been the. the support has always been there to do what it needs to do. so i think that's an important element in all of this. you know, as some of this was unfolding over the last couple of months i did hear a fair amount of conversation that said this interaction between the regulatory body and industry is a concern. and i understand where that what was coming from, but i think what we actually need and what was in other parts of the world, maybe even better than we see here, is there needs to be more collaboration between the regular and the industry. around setting the standards using avenues like i talked about with the api standards
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committees where they can be regulatory, there's already a system to have regulatory participation in those. i think really stepping up the game in those areas, and getting very serious about this element of collaboration is a key piece of that. >> on your second point about the industry being willing to financially contribute towards a more effective regulation, mr. michael bromwich, the current head of boem, said earlier this afternoon that the president had recommended, i believe, $100 million in additional funding for his agency, and that that had been opposed by industry. and as of this time i guess either not adopted or adopted in a substantially smaller amount. do you see industry -- is that
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an accurate reflection of industries position, vis-à-vis, funding of the new boem, and if not, what do you see apis future position relative to the industry as thunder of regulator? >> well, i mean, whether or not a couple of aspects. whether or not $100 million is the right number, what is the right number, i don't know i have a strong view on that. i mean, i think the goal is around having an effective and strong regulator are the right goals to have. you know, i'm not, i'm not feeling like now is the right time, because it's such a big picture to say what's the best funding mechanism for the. i do think the functions come from the federal government. i mean, you know, to be fairly blunt, there's a very strong
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string of resources that come from the industry to the government that i think, you know, for that should be directed towards supporting agencies like the boem. and i think that's the first place what we need to look, you know, through the bonus payments, for the royalty structures we already pay on these activities. you know, surely that should be the funding source for the regulator. >> and i thank you for that answer, and although thank you for correcting my acronym. i am still getting used to change, it is the boem. i have a final question. and that relates to the safety culture and other goals of the industry and shell specifically. some have said that a safety culture is contrary to corporate responsibilities such as
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profitability towards for its shareholders, overall international competitiveness. how do you see safety affecting those other corporate objectives? >> i think, i think, first of all i want to i think rex said this extremely well, but as i look at health, safety and environment aspects of our business, i know to my core that without being very strong in each of those we cannot be a sustainable, strong, profitable company, period. so i know to my core that that is critical. i think then goes into some of the comment you heard earlier, which is what we find, not only do have to perform well in each of those areas, but what we find is a company with a discipline to perform well in each of those areas almost naturally performs better and virtually every aspect of being a business, making a profit for its shareholders. so i see them, we the company see them completely in a related, and completely part of
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the foundation for building a successful company. >> so you don't see funds for all those layers of safety as being the version away from their other corporate goals, but a contributor to the achievement of those goals? >> no, absolutely. and is part of, well, i'm not sure i was quite a conscious in my thinking at the time, it's part of why i've used the examples that i've used here. most of the examples i used around stop work, for example, were things that cost us more money than they may be would have necessarily needed to cost us, but it was the right thing to do. and it demonstrates what we want people doing and it's the kind of thing that would prevent a significant and extensive excellence sometime in the future. so spending more money to drill a well, in a particular way because it adds the safety margins that you need, is absolutely the right decision, even if it is a more expensive
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item as a single element. >> thank you, both of you, for these very important statements. i think one cannot emphasize enough that you have made clear that the safety commitments and records that you have achieved have also come in your views, made both your companies more profitable and successful. that's a message i think that is powerful and that needs to be heard. it's one reason we wanted to invite you today, and you representrepresented those views very well. as i think about the challenges facing the industry and the government and the regulators, they are large i think with respect to both. and as i reflect on director bromwich's challenges, and think about what the nuclear industry did after three mile island, i'm reminded that a lot of oil company executives retire at 60.
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and info he is is people who've been in the nuclear industry, who have run reactors. that's one reason they're so respected by people whose reactor practices they inspect. they evaluate. and he has said that he is doing recruiting at engineering schools, and it strikes me that you might encourage some of your own graduates, who are well fixed in retirement can join enterprise to try to bring up the game because we were really have to do that, i think, to keep pace with the evolving technology and sophistication of the oil industry in water. many thanks to both of you for being here today. >> thank you very much. >> and thank you for the cooperation we've had with both of your companies. all right, i think that fred bartlit has the last word today. except for senators and my closing statements.
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>> somebody with two great-grandchildren, i do like the idea of retiring at 60 very well. [laughter] i think that something we need to weigh upon. there's one thing while richard is getting squared away i need to correct. mr. lewis said today that, i don't know the word to use, but he said maybe there was a rush, there was a question, the panel was very interested in, why get out of there on the 20. people asked that. mr. lewis said he had the feeling may be the had been heading to another area to keep from losing the lease. it turns out we have more information than mr. lewis does on the. we are all over that particular issue. we, as it stands today, it does not appear to us there was a rush to get to a nepalese, but we are pursuing it, drive in it to earth, boring in on these
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guys, getting all the answers we can. and if we will have, we will report for a final report, but we are all over it. we have more fact than mr. lewis have. we were surprised to hear him say that. just so the panel -- >> if i could, maybe i've been the one who has been asking that question the most. i wouldn't get diverted after a specific at what may be a really his suggestion as to why it happened. the fact is it happen. there was a whole series of events which a prudent person might easily have said let's call time out here until we get this matter resolved before we go further. that didn't happen. so was there anything that was causing all the decision makers on that rig and back onshore to make judgments that not to defer
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increased knowledge and make riser judgment, but rather to try to get this thing wrapped up on the 25 april. >> that is such an important and obvious point. we have been all over. we pursued it. we have a lot of information on which we can provide. so far we don't have an answer to that. so what we're going to do -- the next thing i want to say is, that we have, i want to make clear we have welcomed comments, on all the information that we developed the last two days. i told one of my partners we produce more information yesterday that would only come out of a four-month, for which federal district court trial. there's a lot of information. we welcome comments. i particularly, and maybe the panel might feel the same way, i was intrigued by shell oil saying they never, never leave a well underbalanced. when they could really abandon it. and so we would welcome comments
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from the industry and anybody in the audience or any experts that are watching this on television as to the pros and cons of a rule saying let's never temporarily abandon a well underbalanced. that just seems that something we specifically should invite comments on. that's all i would say. commissioners. >> now, when you're going to do now is, richard sears and i are going to discuss some overarching sort of safety type considerations that we have observed during the three or four months of very detailed work on this. we are not safety experts, richard and i. but this also, we collected comments of her home -- whole team of people and we've added a whole team of smart young and men and women born into this. as you can imagine, we set up that nicely what could've happened, what could we have
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done. we want the commission to the benefit of these late night discussions with all the young men and women you met and with our staff, for what they're worth. and we do not claim to be somebody who would be teaching graduate-level safety, but we do have some common sense. at least we think would do. so that's what we're going to do. mr. richard sears, to visit degrees from stanford, 30 years at shell, vice president deepwater services, has been retired for 18 months, is a visiting scientist at mit, has been the leader of our technical work. is achieved cooperation by all the majors, chevron, shell, of course, exxon. he has educated us in things we did know. we turned them every day. we have gone to dinner, what is this stuff, how do these casings were? everything. he has traveled all over the gulf with us. if there is an indispensable
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team member here, a lot of the people are team to do with sean and i and sent to do, but nobody could do what richard has been. we thank you for the. i will miss him. i hate to say that but i will miss him. >> you haven't seen the last of me. [laughter] >> so what we will do is now, we're going to go over, we have cold of these down and again, you know that they come from all of our discussions. one of our jobs is to just look at a spectrum of things to get the advice of everything we know. so let's turn to number one. individuals should be trained to repeatedly question data, raise concerns, and doublecheck assumptions. so, richard, can you sort of pull forth that, summarized the discussion with that and give us some examples? >> i will do that. that he start by saying that as we go through these examples and
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conclusions, i'm going to be pulling together danger for the last two days, my own experience and ideas, comments from other members. it's going to be a mix of facts and testimony and thoughts and ideas. and fred, if you ever want to know what space i'm in, just ask. >> i will ask you to make copies for this if you would. >> yes, sir. >> but also, i'm trying to reflect my own, and i think the commissions staff instinct about things about what we've learned and the judgments we have made. so we start with this one. the idea that there's a lot of data, we have to be in an environment where concerns are raised. data, however good, is questioned. and we think about the assumptions that are being made come in place of an exquisite. for example, go to the first slide, which really just iswe se stage for thisw
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i'm going to use it to make an important point. here's my condo. the companies that are operating in the deep water gulf of mexico are headquartered -- headquartered in new orleans, houston, around the gulf coast are geographically where ever the rig is in the deep water gulf of mexico is geographically a remote operation. that's important. so things that are being done out there are being done remotely geographically. as even more important to that, if we go to the next life. this is macondo, and prevent what macondo is that it's not a dot, a platform on the surface of the ocean. if we start the animation, which i can do with this laser by pointing there. macondo, as a welcome and all these deep water wells that are like that, 5000 feet of water. and the stuff that we are really interested in is right down there. we talked about drilling. geologist and geophysicists are
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not interested in going. they are interested in having a hole in the ground to access resources that in this case our 18,000 feet below the surface. and this is what's constructed in order to give it. everything that matters, from a geoscience perspective, from a resource perspective is way down here. now, back to the assumption, to the point at the beginning that we are in the world here where there's a lot of data. but a lot of the data is very indirect data. and this was a world that i have described many times as one of selective in partial knowledge. this is a very complex engineered systems, and a very complex natural system. we don't know everything about it, and the days that we have and the presumptions that we made and the conclusions that we draw about what's happening down here are full of assumptions. and particularly when an operation is going down this hole, again, 18,000 feet long, at the bottom it's about
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seven inches, less than seven inches in diameter. the degrees of freedom you have from the surface is you can put things down, you can pull things up, you can rotate them clockwise or counterclockwise. and you can pump fluids. that's what you can do. and in doing that the industry is able to do and make happen a lot of things down there, and you've seen some of the ingenious kids they have designed to do. and there's a distance down there in order to measure what's going on. but the point is is rife with assumption, there are important assumptions, and everybody involved in these operations has to be in tune to crushing those assumptions and think about what's actually happening. again, not to take on our hammer in but about anything, but just bring a few of the points that we have seen him the previous few days, a couple of examples. next slide, please.
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this is a comment from one of the bp team members. and this was after the float equipment had fought convert and the pressure was lower, the secular pressure was lower than in education at the mottled, that it should be the and at the end of the day they decided the rig standby pressure gauge was incorrect that we don't know exactly what they do discuss, talked about. what we have seen is this memo. what we haven't seen was, was there a long and healthy debate about that gauge and its act and the data that went into the assumption, what other possibilities might it -- >> did they put a new gauge on? >> we have no knowledge whether they did or not. >> again, the purpose of these, we're not even thinking about cost now. we are serving to illustrate as the commission, the proposition that you've got to question,
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question, check assumptions, not accept propositions like this. people have to get that through their head. it's sad like mr. odum, mr. tillerson agree with us. i was impressed. >> there are a couple more examples. the next slide. we heard a discussion of the bladder effect. again, we don't know what actual conversations went on concerning the bladder effect. and the next slide i think -- >> what we say here, we don't know if the bladder effect exists or not. ep claims, and trans ocean disagrees, that they were told there was a bladder effect. but maybe accepting that from one person on the rig, if the conversation took place, which we don't know, maybe it ought to be questioned that maybe someone should call shoreside when you 1400 pounds on the drill pipe and say it's anybody there ever heard of the bladder effect? this is the point we keep trying to make here.
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>> and what we do know from testimony at the joint hearings from one of the bp will cite team members, the next slide, this is something we showed earlier, go back one, then we are. did anyone say anything or disagree with mr. anderson's explanation that would be bladder effect? i don't recall anybody disagreeing, or agree with this explanation. so is the just there wasn't a lot of debate discussion. and it could have been an interesting discussion. well, how to do that? how do you get 1400-psi? >> what is the map? >> let's think about. and at least that is the kind of questioning that leads to ultimate i think better solutions and a better path forward. and then one final example here in the same case of looking at assumption. the surface cement plugging said
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8300 feet below, below sea level, a little over 3000 feet below the seabed. a loud discussion and testimony here from various hearings, and also from the five experts we had here today saying this is unusual, it's very unusual. and to varying degrees of feeling yesterday and today about how risky it is that i'm not going to judge a risky it was that i heard experts say they thought it was pretty risky. but i heard somebody else say, well, maybe not necessarily so. the important point is, there's of evidence that all the assumptions that went into this come is there a better way to set that lockdown ringed? can we get 100,000 pounds? and we've heard other examples of we don't have evidence that that kind of healthy debate was taken on, and again come in this world that's the kind of discussion and debate that leads to fundamentally better solutions. >> there was a fundamental proposition that we don't like
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to set cement in that. people apparently set cement and much. they need to be a discussion there as to what's wrong with setting cement and mud? if you said it in mud you don't have to display. and go around in circles. it looks like some of these assumptions were accepted without a lot of digging in deeper into the artichoke. let's go to number two. greater retention should be paid to the magnitude of consequences of all anomalies, even similar mind once. because as we've learned under the circumstances, might anomalies can become major problems in a short order. richard, what can you tell us about -- richard is giving the views of our entire team as we've had both sessions about this into the evening. what can you tell us about that? >> well, as you just said, my anomalies have a way in this environment of magnifying and becoming major problems very quickly. and we will see more examples of
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that as we go through this list. budgets, any anomaly, particularly those that are recognized as a novelist need to be investigated, they need to be discussed and the need to be understood. what could be causing that? what of the very cities that could be happening, why is it happening? and this is really important, is making sure that happens is not using okay, everybody do it. you heard mr. tillerson and mr. odum talk about how you accomplish that and how hard it is. it's a matter of leadership in setting the right tone from the top that it's a matter of training. in terms of making sure that people involved have the technical skills to know what it is. they should be thinking about, and how, how these things develop in this environment in deep water. it's about behaviors. it's about company culture. and it's about developing within the company and instinctual behaviors around these two
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points, about questioning assumptions, about him in a constructive way. and considering the consequences of various things. and two examples that we saw here, particularly yesterday, and spent quite a lot of time on because we believe they might have had some consequences for this well. here's the picture that we drew up for the float collar conversion, just before the pressure dropped from 3142-psi, down to a few hundred psi and mud started security. now, we don't know why it happened. just before it happened, we are pretty sure the to become using the button, the two, the ball were up, and the pressure dropped we don't know what happened. the tube might have dropped. the valve closed. the ball might have popped out of the body because there's a retaining ring into that fail. we don't know. or perhaps the flow was never great enough to convert it.
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when junk food out of the bottom of the reamer shoe, it just established the circulation as what might actually be reasonable pressure in that circumstance about 340-psi or something like that. we don't know. but here's a case where, when it happened, and even with the comment i brought up in the previous boycott okay, the circling pressure is a little low, they get is wrong, it has finally converted let's move on. and there was an apparently a healthy discussion of what else might have happened downhole, and what the consequences of that might've been. and then we saw one other example, and it was a negative pressure test. and it was a long period of time, three hours. there were a lot of tests, a lot of pressure measurements taken, a lot of fluids were bled off for various places, gauges look at various places. by the bottom line is, the
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successful negative pressure test in this situation would look like this. and the situation at mike honda when the pressure test was declared successful was that, 1400 per hundred square inch on the drill pipe, zero on the kill line. and it seems based on all of the day that we have that it was agreement of those imposition that this test was successful, let's move on. spent and time gets into our proposition, if the commissioners please, that greater attention has to be paid to every single anomaly. i wonder if when people saw that they realized that that may mean that the cement job is kaput. and we are going to have an explosion on this rig within an hour an and a half. i doubt of that. i don't think humans, these guys, i've been all over these weeks that i've met these guys
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did they are wonderful people. they work like crazy. they've got family. so when i say we have to teach people more about anomalies, i don't think they sat there and said, well, maybe this rig will be in fire into arctic was it an anomaly? they didn't explain it? they did that clarity appreciate what that could mean. okay, let's look at our next sort of overarching, i guess you don't have to be a safety expert to read some of these conclusions. individual risk factors cannot be considered in isolation, but as an overall matrix. personnel cannot ignore anomalies after deleting they have addressed them. as we will see some of this, well, we all believed there was a tendency it is okay, we got that behind us, forget about it, and go into the next issue without realizing that maybe that wasn't fully resolved before. so what can you tell us about that, richard, please? >> i was to was something i said a few minutes ago. what is a deepwater well?
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a deepwater well is a very complex engineered systems, embedded in a very complex natural systems, about which we don't know nearly enough. and we don't know nearly enough about the natural system, even complex ingenuity systems can behave in seemingly unpredictable ways. so that perhaps in the previous two examples. all of that has been dealt with in the business of deepwater, and you've seen over two days, a lot of the engineering complexities that have been dealt by the engineering in order to do this. and it is really impressive and it has always been a fun business to work in. we also heard today from the experts here this morning how long a time period it is that goes into developing a deepwater drilling plan and the number of skills and disciplines that go into it. it can be a year or more. and certainly if you back up to geophysical work that led to making the maps that lead to
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buying the lease that led to then programming the well and developing the plan, this is a process that plays out over years. and in the drilling of the welcome and that ultimately heading to the production of oil and gas, which in deepwater environments can last for decades. so we are getting with complex skills, longtime friends. and all along there your developing a system, a very complicated system. and the point of this is that you cannot extract an individual item from the system and look at it, no matter how smart you are, you deal with it, you resolve it. that's good. but then you can't put it on a shelf never to be considered again. it's part of the system and it has to be thought of as part of the system, and the complexity and the system and thinking of the risks and all of the components of risk need to be considered. and you can get away with it.
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and i will take a good example. yesterday, and the next slide, i think the next slide, so here's a last two hours before the explosion. and this is something we heard yesterday speed is stop for a second, richard that we don't have a transcript of what mr. ambrose said yesterday, so this is, this is our best recollection. and if we got wrong, of course we will correct it. but yesterday mr. ambrose said that sometime in this period, 2031, to 2140, write in here, the deal crew again saw the anomaly, and again saw 1400 psi. and i remembered earlier at the time of the negative test they had seen it, and sort of kind of result it. so let's pick up from there, please, richard. >> it's exactly that. here we are, about the time that
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hydrocarbons are you and the rise of ibp's calculations, that they put out in their post-incident report. so before hydrocarbons are in the rise or about the time hydrocarbons are in the rise or, the crew on the rig notices something. something anomalous. that there is, if i remember hearing a critic of the the difference in pressure between the drill pipe in the kill line was about 1400 pounds per square in. and they look at it, they stopped, they bled off some pressure. they considered what could this be. now, i don't remember hearing what it was resolved at. what i do remember thinking when i heard this yesterday was, well, wait. the negative test also saw 1400 pounds per square inch difference between the drill pipe and the kill line. and i'm wondering, was the negative test put on a shelf and now this comes off the shelf? way, what about passion and nobody is think about the negative test. here we are, and you can see
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what happens next in this timeline. that just a few minutes later, mud begins to overflow on the rig floor -- >> tell us the difference between the parties. >> wind that came out. that's fine, but i would just say i am looking at bp's calculations from the report that this is how fast something anomalous turns into something rather serious. from 2138, when hydrocarbons first into the riser, few three minutes later, bp's calculations report 1000-barrel game, 1000 year old. that's half the volume, more than half the bottom of a 5000-foot riser. and that is what the influx seemingly minor has now turned into as it is, in the riser and is expanding because of the decrease in pressure. just a few minutes later, 2149, a time of the first explosion,
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bp calculates 2000-barrel gain. we don't know where that all went, but 2000 barrels is the entire byte of the 5000-foot riser, plus about half the volume of the production casing. >> there's 1 million questions come up from this, that i think listening to mr. tillerson and mr. odum, i think i know what their answers would be, should the crew have known that 1400 maybe was reservoir pressure, that they were seeing reservoir pressure up at the surface? should the significance of that number have been clear likes that's why we say, there's a tendency to putting issues behind people, and then go on. and went another event happens, not go back and say, holy cats, now we understand what happened back there. but to basically deal with it almost from scratch. that's the point. they are itablet of more points your. >> in deep that if we look at the next slide is a list we put up yesterday. what we described as a situation at the time of the cement job on april 19. now, we can argue a lot about,
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is this list three items long or six or seven or 11 or 13? frankly, i don't care. how many it is that it could be five, you can add these together and compensated ways, and that's why. the point is that there was a lot happening that people with knowledge of the system, people's knowledge of cementing, should've been thinking about in terms of each of these, however you want to aggregate or disaggregate them, each of these have an impact on the cement job, potential impact on the cement job. now, anyone a low, even several alone, perhaps not a big deal. all of these we said, the industry faces these everyday and has developed methods for gaining with them. the physical impact of these is what aggregates. and isn't what is a team that did in my thinking. was a cumulative is the risk of regime that they're operating in
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as one after another after another of these becomes an issue that somebody should be thinking of, that should as we put it heightened awareness as to what comes next that what comes next is at the test, the negative pressure test that would confirm the quality, robustness, the integrity of the cement job. and these together, get with the list of seven items long or 13 doesn't much matter. these items and these concepts should have heightened awareness about the importance of that negative pressure test. and let me just take one in particular. the next slide -- >> let me go back. >> okay, go back. >> i have a bad habit of trying to be very specific and not general. and take centralization of some thought that been resolved, others might disagree, but maybe when they started to see 1400 on the grill line, the drill pipe in the negative pressure test, maybe some of should've said
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let's go back. maybe that centralization issue is more of an issue than we thought it was. maybe we are to stop. maybe we have to see what's going on down there. we had a dispute with halliburton. we had a lot of runs. maybe we should have just put this behind us, but we should keep we evaluate the premise. okay, richard. >> the next slide is about centralization, and the slides that we showed yesterday, we highlighted, i would rather squeeze that get stuck -- that is a perfectly reasonable, rational response to this notion of all these centralizers that might move around or come off, as they're put on this drill pipe that is being run in the hole. i'm going to be the first to say that these risky environment here is very complex, and it is changing, and you can't, you can't willy-nilly say put all those centralizers and ignore what you might do in terms of adding risk. but in my case, what i want to focus on here is who cares, end of story. this should've been the
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beginning of the story. this should've been the beginning of the story of more discussion about the complexities of the cement job and where it was leading them. >> and its again, again, it is left by a smart engineer, okay, probably be fine, probably be fine. if it was the only barrier that existed when the well was underbalanced and the people on the rig thought it would probably be fine. next. i would further have to squeeze to squeezing is of course repairing it. there is an awareness in the mind of this engineer that they might have to repair it. and again, that's behind us, you soliciting 1400, maybe someone should have said, i half, we should have squeezed it and started. that's the point the point we're trying to make. >> and this point was made also in bps post incident report, if we look at the next slide, and we showed this one i believe yesterday. a formal risk assessment might have enabled the macondo team to
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identify for the mitigation options, specifically speaking of some aspects of the cement job. a formal risk assessment would have at least elevated the level of discussion of thinking about the cement job and implications for going forward. and then they've actually, i can't say, i say, i don't know, but it might actually have had more impact than just whether to run a summit evaluation log. it might have also had something to do with a kind of thinking that was going on. now i want to say, we are talking here about systems thinking. and i don't have this on a slide, but i was thinking about it as we're preparing this. i do want to add it if we saw once led to a repeat dislike to you, and you may remember it, or just take my word for it. it was in yesterday. there was a slide from a bp member, a member of the tp staff, billy boat deck i think was his name, and it was a slide where it was a long e-mail, and
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we exited, highlighted one line out of it what he was highlighting to partners. why they had decided to call tv this well at 183, instead of at the original program depth of 20,000 the. that's like, that is an excellent example of systems thinking, and my might that at least it's a good example, and it's where individuals on the engineering team looked at what was happening. they looked at the geology. they looked at the well as it had been constructed to that point. they thought carefully about the risks of going forward, the risks not only to that well and what it been done so far, but also its future purpose as a producing or and gas well. and well. and he made a very sound, what looked to me, a very sound decision to, let's call this td. we will have to stop here and the line i believe is we can go on without jeopardizing this well. that is a good example of systems thinking, where a lot of
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data is brought together from the past looking into the future, and a decision is made. >> let's go onto our our next point, number four. they are ought to be greater focus on how to respond to low frequency, high risk events. richard and i were talking last night and we said we've got all around the industry. we said to everybody, how often do you actually go overboard with your diverter when these things happen. and people said gee, i've never done it. or they say, how often do you trigger the blind shear ram i suggested the drill pipe that they say gee, i never ask again. so gets to be kind of a big deal, and when you're dealing with events, how do you know it's bad enough to act fast? that's my way of saying that it has, there has to be more emphasis than its okay dude cut
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the drill pump, it's okay to dump overboard this tough when you're in a tough situation. and now what we are going to do is, i read the transocean handbook cover to cover. i thought it was, when i read i thought this was a brilliant document. these guys killed themselves to get it right. and i gave it to richard and we look at it again. and yeah, it is all there, everybody so aspect of the kinds of things you can face were there. so we complement key over doing that, but as we read as normal people, it seemed like it was all there but maybe, and i know mr. odum said today it could be too complicated, could be too complicated. and richard is going to go through the manual. and this is not by way of criticism. it could be too complicated, could be too complicated. and richard is going to go through the manual. and this is not by way of criticism. no, mr. tillerson said he learned from that other experience. so what we want to go through the manual. and this is not by way of criticism. no, mr. tillerson said he learned from that other experience. so what we want to do is learn. and when somebody does a job like you did on their manual we
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don't want to take them down for a. but we want to give our observations of what we saw about what somebody reading it, would they be able to know if it was bad enough to act fact that that's the point. >> and this is the manual. fred read it so i felt shamed into reading it my subject i never thought when i started, i would read a well control handbook but it is very good and very comprehensive. and it tells you a lot. and it tells you they thought a lot about the circumstances that they operate in. and some the specific environments. the next -- >> it was not meant to be a thoroughgoing analysis for every page but it is supposed to be allowed to give. >> and this is not, one of these terrible slides when a person party says you don't have to read everything on it because of course you can't. but what you can see is there are a lot of boxes. this is from a section on kick detection. and specifically, how to manage
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gas once it enters the riser, the shutting procedures for the well. >> we've already said many times from our experts at all that once gas enters the riser this is a potentially serious situation. so transocean in the wisdom and experience has put together the picture here of how, what the driller needs to do, what the staff on the rig needs to do in order to shut in the well and manage gas once it's in the riser. >> again i have to say, to t.o., we do not know about the specific training that's given in addition to the many. we have no idea about that. we look at the manual and with matched ourselves with somebody on the rig that had been handed the manual, and when you get a kick, you go through this sequence. >> and the important point here, this really references the talks are mr. odum and mr. tillerson, there are a lot of actions on the chart from watching flows, closing annular zone closing shear rams, hanging off type, a
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lot of things that go on that make up the sequence of events. all of this, and you saw a few slides previously how quickly things happen once gas enters into the riser. so all of these things have to be instinctual for the drilling staff. i'm going to say the drug staff are probably very well-trained. it probably is instinctual for them but this highlights the complexity of the business that they're operating in, and how quickly they have to act and in their mind, what do i do next, it has to be a habit for them and that means they have to be trained in it. we talked earlier today about the ability to simulate these things, and it's not like the simulations that the one in the airline industry, with pilots handling events. so there might be room, i'm just going to say, there might be room for improving how people on rigs are trained to recognize this. because again, we talked to thousands of years of experience
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from drill sites, rigs, platform installation managers. and really, can count on one hand from all about how many times people have actually diverted the flow over board, use a blind shear ram to cut the drill pipe, or operated the emergency disconnect system because of a well control problem. >> and if you never do something, it gets to be the exception. i don't know if you want to say, that's not my business. that when you never, ever do something, it is viewed as the be all and end all, you're probably wait maybe sometimes too long and how do you train people to have a state of mind that they are alert to these things that happen fast. that's not my job, but this is something we observed, that maybe there's not, hasn't been created at least in the paperwork, the sense of urgency, you better move because once he gets in the riser, bad.
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richard, you have another point. >> again, a couple of pages from the manual and i will blow up a couple of, 1 cents on the left there. and this is again, this is very good. in this manual there's 15 of 16 pages specific to deepwater environment and how to manage a kick any deepwater environ. very, very important. because deepwater environment has its own unique characteristic. and from this manual, clearly said, and this is consistent with what we're yesterday, at any time if there's a rapid expansion of gas in the riser, the diverted must be closed and the flow diverted overboard. it's very clear. now, it would stay very clear, again, i am maybe making an unfair interpretation but i would say he would stay very clear we're not for the very next sentence. the very next sentence says, to for water based as was oil-based mud, an alternate system is
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using the mud-gas separator to move gas from mud as in the figure on the next day, and in the next two pages go on to give a very detailed constructinstruction about to secondly gas out of the mud called and the riser using the mud-gas separator. by the way, it's probably all very good, and these techniques probably saved lives. i'm going to suggest that it might be a little less clear to the operating personnel that in helping them understand when an event is bad enough to be called bad. because what we saw in macondo was they did go to the mud-gas separator. it overwhelmed the system, and we have had conversations with explosion experts from other oil companies who have said, it might have made a difference, it might have delayed the explosion for at least a short period of time if they had any of the that gas flow not to the mud-gas separator, but overboard.
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it's complex, but i think there's probably room here for helping, helping the drillers make some of these decisions. and also, the starting point on this, if it encounters rapid expansion of gas in the riser, it might be nice to know that before mike is coming out on the deck of the rig. >> let's look at the next light in that regard. people will remember this. this is the sperry-sun data turned sideways so you can see it better, flipped around and expanded so you can see these trends. we have discussed drill pipe pressure increasing at constant pump rate, pressure continues to rise. mr. ambrose yesterday, and again, we don't have a transcript so this is my memory of this. mr. ambrose said something like, maybe the driller looked at the first part of this for a minute, and it looked okay and then he
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looked a way to do under the task. now, he doesn't know that. nobody knows what happened. but the point is that it seems that if there is a possibility, we think, that you haven't been, that there may be one of these low frequency high risk events, and, you know, the well is underbalanced, maybe it's not enough, maybe, maybe it's the culture of the company is that somebody might think the driller would look at this line and in turn away and do something else. maybe that's a symptom of something that needs to be addressed. >> i think that really describes it well. in this particular case, if we take a second pressure rise when the pubs were turned off as even more diagnostic as an influx into the well, it's a period of about six minutes. and we heard that for the first minute and a half or so, minute, minute and a half, that behavior is actually pretty reasonable and consistent with all of the actions going on on the rig.
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and by the way, the last minute, minute and a half or so is also a pretty reasonable behavior of pressure given the various actions that were going on the rig as pubs were being turned back on. here we have a situation where, it's not really six minutes. it's sort of four minutes, or three minutes in the middle, where the right person with the right knowledge has to be looking at the data at the right time, thinking the right spot. and as the, was yesterday, he might have looked at it, thought he was behaving as expected, and then went off to light up bums for the next activity. that's probably a reasonable thing to be doing, except that in this case it might have made the difference between seeing something serious that was happening down the well and not seeing it. >> now let's look, please come at our sixth point. failure to develop or adopt their procedures for crucial end of the well activities.
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>> we talked a lot about this, and our judgment is that there's a body of evidence that suggests that the end of well, once the negative pressure test had been passed, that the job had been done, negative pressure test past. temporary abandonment procedure, it was perceived to be a very routine low risk operation. and it didn't appear to be, based on the changes that were going on and how this evolves over time, there didn't seem to be a lot of rigor around how this ended well, these end of what processes were managed. this is dangerous. fundamentally dangerous. i think at the first commission meeting, hearings here in washington, d.c., you had the well delivery manager from a major operator to you specifically, accidents happen during routine operations. because people take their eye off the ball.
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they are less vigilant, they are less careful. accidents happen. in my own life, i think of this as if i could distinguish between with the entry risky and really and truly routine, which by definition i guess is not risky, then fine, i'm only going to drive my car when i'm doing routine things, not risky things. and, therefore, i don't ever have to think about getting in an automobile accident. it's kind of many. you take this by extension and it lead you down a path which makes no sense. so you can't distinguish beforehand between what is truly risky. and, in fact, all of these, all of these actions on one of these deep water rigs are fundamentally risky. it is a fundamentally risky environment, as that well delivery manager said. those risks never go away. you manage them carefully so that you keep them under control. >> let's turn to number six. to me, as we worked on this case, this was one of the most
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important problems. and as i listen to mr. tillerson today describe how exxon as lily insists that the contractors and all their personal, personnel around -- are on the same page, that drove it home to me. porky mediation between operator and subcontractors deprived otherwise capable personnel of information necessary to recognize and address risk. elaborate on that, please, richard. >> there's a lot that goes on on these rigs. in most, all the time there's a lot going on. and there's a lot of information that needs to be shared. there's a lot of information that is shed. when we look at the list, don't go back and the slides, but think back to all of the situations during the cement job. some of those are known to one party, not others that you are known to all parties. most of the list is known to one party.
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there needs to be better models for how to share information, not partitioned data into well, this is part of the cement job. we heard i think in some of the conversation today about monitoring flow. well, they wouldn't have known that because the blowout is going to the cement unit. that's perfectly reasonable. that's how operations happen, but here again is partitioning of the data so that possibly so, possibly critical data isn't available to the right person at the right time. and maybe isn't being shared because there's not an awareness that it needs to be shared. and it was aspects of the nature of the cement job, it might come it might be reasonable to look at that and say, well, g., the cement a wouldn't necessarily have known about it well planning decision that was made a month earlier to manage traffic annular pressure. no reason to tell the cement about trapped annular pressure, wouldn't understand anyway.
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that's fine, but here you partitioned data and partition risk as if. >> a classic example was the centralized issue. we saw -- in fact, yesterday in the conversation, and a discussion at this table, the question was about to be december model that halliburton runs for the operator to model the risk of gas influx into the well, and the centralizers are important aspect of that. flow rate is an important aspect of that. pressure is an important aspect of that. to draw out what are the parameters, some of the parameters at least they go into this. and then ask, was the model we run with the right bottom whole parameters, with the right accurate flow rates, with them of centralizers where they will
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be, six of them, where did he was going to run them on that long string casing. and again can we do have a trance get but i the answer was from this meeting expert, it wouldn't have mattered, there still would have been severe gas influx. loss lasinflux. . .