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This panel is going to discuss the following question: What real-time technologies are
available to measure the health of BOPs in service and aid in the detection and response
of kicks? The moderator for this session is Pisces Carmichael. Sheís the SEMS product
manager for Lloydís, where she is currently leading several major teams. She has 15 years
of experience in safety engineering, system auditing, and equipment design. She has a
bachelor's degree in electrical engineering and a master's degree in safety engineering.
She is a member of a variety of industry groups including the Center for Offshore Safety Audit
Committee, API and ASSE. Thank you.
I want to thank BSEE for the invitation to be here today and Doug for the introduction.
We have a good group in panel four where we will be discussing real-time technologies
available to measure BOP health as well as kick detection and response. Our group consists
of -- we have an operator, we have a drilling contractor, we have operational integrity
engineering and consulting as well as software development represented on our panel. So weíll
go ahead and get started with Mr. Gary Davis. Gary is the global manager of the Well Control
Equipment Center of Excellence at Moduspec, the leading global experts in innovative services
designed around people, systems, and equipment to assure operational integrity. Mr. Davis
has a background in the electro mechanical design and has more than 16 years in upstream
and downstream subsea experience. We welcome Mr. Davis. [applause]
good afternoon and I would like to start out my presentation by thanking BSEE for facilitating
the meeting today and a special thanks to Sharon who has over the last two weeks has
really worked very hard to make sure everything came together for today's event. Basically
myÖ[applause] yeah. My presentation today is based on technology demands from the industry,
what is being asked post-Macondo to help mitigate losses in the industry, to help mitigate some
of the issues we have been faced with over the last 24 months. The question came to Moduspec
and Lloydís quite simply. How much of a leak of BOP is -- would constitute a degradation
in reliability that would force the stack to come to the surface for repairs? And the
response was simple. How long is a piece of string? The reason this type of response is
warranted is because these systems are very complex and are designed in such a way that
redundant capabilities are built in. And the assessments that were being undertaken had
as many of my colleagues this morning mentioned had not been taken into account, the capabilities
to mitigate loss and maintain its reliable status in some cases had not been taken into
account. Our agenda for today is the challenge which Iíve just spoke of. The solution which
we and the industry have worked together to come up with. The analysis itís undertaken
to build such a model. The model itself. And defense in depth, which is user interface,
which is the application that goes into the field for our individuals, and the continuing
benefits. The challenge was to develop the capabilities based on input to assess risk
and reliability instantaneously and communicate to all interested parties effectively and
that is very important to point out, the communications portion of this. To date the industry has
multiple ways of providing information to the regulators from the drilling contractor,
to the operator, and then to the regulators to be able assess this information in such
a way that all parties can come to an agreement on the decision that has to be made. Which
is either to pull the stack or leave it in service until such a time as you could safely
secure the well. Of course, as I spoke of, an effective way to communicate this risk
assessment, how we evaluate these losses or how we communicate each failure in a subsea
BOP and how that information is communicated across the board to try to standardize how
we communicate from drilling contractor to operator to operator to regulator. And account
for the full capabilities of the BOP - this was very important for us to be able to take
apart the BOP system and it controls in all of its complexity and make sure that each
portion of the system was accounted for in this assessment, to understand that its full
capabilities and be able to report it effectively with the communication. The question was quite
simple. When does a failure or failures affect the reliability functional levels such that
continued operations cannot be maintained in operational circumstances it is intended
to perform? The BOP risk modeling is built in a software package that has typically been
used in the nuclear industry. So this is where we have taken technologies or initiatives
outside of our industry and tried to incorporate them. The risk spectrum is used in 53% nuclear
facilities to do just what is in here in our industry today. The model thatís built into
the software has to be customized for the BOP that it is intended to operate under or
report on. The risk spectrum model ñ modules, excuse me, they utilize block diagrams to
demonstrate the connection, the interconnect ability between the assembly, the systems,
and the components. The fault tree analysis is a logic application, how we access this
information once built into the software. PSA is a suite of softwares that brings this
information together. And then the FMEA -- once the model that has been built, we go through
a FMEA process, or a very similar FMEA process to validate and verify that what we have come
up with is in fact accurate and acceptable by all parties. And then risk watcher is the
dashboard or defense in depth, what Iíll show you later, the dashboard in which the
operators will plug in their failures and the model will assess it and give them an
output. The result is the instant display of revised risk levels for all stakeholders
and regulators and a reliable, standardized way of communicating. And thatís what we're
really trying to get to. We want to assess these systems with all of their technical
content and be able to transmit that information effectively and uniformly from one party to
the next so all parties understand the risks that they are evaluating at the time that
they are evaluating them. This exercise is very important because the typical time for
this assessment to take place is sometimes hours or even days. The risk model having
done this exercise up in the front and having to assess the system in such a way, in such
a way that everyone can see and challenge the model greatly reduces that time for communication
in decision making. Basically, we take it apart by system to upper level components
to sub components and sub-sub components, which is basically the reason I put in this
slide just to show you how we start out by looking at the very simplest of information
first. Ah-ha. The next thing we do in this initiative is we build block diagrams. And
as youíll see, each of these blocks are colored green. In an actual application, which this
is reflective of, each of the green blocks actually clicks into another field of equipment
or sub equipment that belongs to that top level assembly. After we have finally built
our block diagrams and all of our associations between systems, components, and assemblies,
then the information needs to be put into logic to make sure that we understand there
is a minimum bar that this stack must not fall below in order for its reliability to
stay in such a state that the equipment can stay in service. And this is a real simple
depiction of how the information is assessed and pulled together. Basically, you have a
stack, we have taken all of the top level components and then weíve assessed them through
their circuit affiliations and their component by component failures. What we have typically
done is a very simple exercise, and itís an exercise that weíve done in this industry
for a long time. This is a component, this is what has failed, this is what is affected,
and this is what remains intact to mitigate a loss or maintain a safe and reliable operation
of the equipment. We do, in fact, analyze the entire BOP system and its controls. Examine
how a fault affects its redundancy or reliability levels. The analysis that takes place is what
goes into and builds the model itself. The model can now be and has been interrogated
by industry experts. After each model is built, the opportunity for us to go through do that
FMEA and make sure we go through every single component -- that is what has failed, how
it affects the system, and what remains in the system to mitigate the loss -- but like
I said, there are minimum requirements. The emergency functionality of the stack can never
be deterred. And that is the portions of the system such as the dead man and auto sheer
circuits. Basically weíve broken it down into four categories thatís recognized by
the industry, which is red, of course, meaning unacceptable risk, orange being high risk
additional assessments necessary, moderate risk meaning redundant capabilities are still
available and maintenance is required. And low risk meaning that full system availability
is a ñor the full system has its availability. Basically, this is the interface.
What you are seeing here is a defense in depth. The top bar--I do not know if we have a pointer
-- but the top bar in this particular screen is the overall health of the BOP system. And
each of the subtitles that you see under that are the system as it breaks down by assemblies
and sub-assemblies and sub-sub-assemblies. As we go through, I am just going to -- I
got my two-minute mark ñ Iím going to quickly go through this. This is what it would look
like as you input failure into the system. You get a read back that basically says what
system has been affected, what component is now out of service, and as you did degradate
that down further in the case of a critical component or major components on the BOP,
you notice that the stack, status of the stack turns yellow meaning that you are down to
a level of redundancy that will require maintenance on the next stack retrieval. Once we have
degragated down to the point where we get orange, meaning that an additional risk assessment
must be undertaken, this is where we take into account the variables. The variables
in this case would be where we are at in our well program? What are the environmental concerns?
What are the operational concerns that may affect this decision? It means that we are
more than likely on a top level component down to a single point of reliability, and
redundancy has been reduced. And of course, once the stack falls below that minimum criteria
for safe operations, the model will automatically say or indicate that the stack must come to
the surface for immediate repairs. And basically, the continual benefits are the instant verification
of new risk levels by all stockholders and regulators. The BOP, even though independent
individuals may not be present during the actual inputs or the assessment of the system,
the evaluation was taken care of or undertaken by people who are not stakeholders with any
particular venture. Another very, very important continual benefit of this particular project
is its after benefits to the industry. The way that this information is taken apart with
its fault trees and block diagrams, it immediately shows personnel in the field who are doing
these exercises the association from their equipment to their systems and their circuits
theyíre attached to, which gives them a point of verification and allows them to go back
to their system and insure that their findings are 100% correct so it gives them that little
edge to ensure that the examination has been thorough and itís complete. Thank you very
much. [applause]
Thank you, Gary. Wonderful job. I think your presentation kinda tied into the complexity
that Chuck mentioned during the GE presentation and rolls us into looking forward and looking
at things that we can do as an improvement going forward. So, next we have Dr. Fereidoun
Abbassian. Heís the vice president for wells technology with British Petroleum. He started
out as a mechanical engineer, after completing his Ph.D. in structural mechanics at the University
of Cambridge. In 1996, he transferred to Houston and began to be in the development of the
Gulf of Mexico deep water strategy within BP. He later did work in Angola and is now
based back in the Houston area. So let's welcome Dr. Fereidoun Abbassian. [applause]
Thanks, Pisces, for the kind introduction and good afternoon, ladies and gentlemen.
On behalf of BP I would like to thank the BSEE for the opportunity to participate in
this forum. Today, I would like to highlight three recent efforts in BP which aim at enhancing
the safety of our drilling operation through use of real-time monitoring capabilities for
safety critical equipment and safety critical operations. So, the three efforts that I would
like to highlight are the development of capability for real-time BOP health monitoring, remote
BOP pressure testing and establishment of BP's Houston monitoring center. The first
two are efforts which are currently in piloting stage, and the third effort, the Houston monitoring
center, is well established and has been up and running since July 2011. Let me start
with the first of these three efforts. Over the last 18 months, we have been developing
capabilities for real time BOP Health monitoring. The aim is to simplify and broaden the reach
of BOP control diagnostics beyond the rig sight. Currently, BOP diagnostics that contain
thousands of alarms is not brought back to shore. We did mention transparency earlier
this morning. This system really attempts to make the diagnostics of the BOP more transparent.
So, we believe that the capability really improves communication and will aid in decision
making process. So the system as you see on the right-hand side of the slide provides,
at a glance, a display of all of the pertinence -- pertinent BOP health information. [Clears
throat] Excuse me. At the center of the display and towards the left, you see a traffic light
status on the availability of key functionalities in the BOP. That includes availability of
sub-sea BOP elements -- that is rams and annulars operated from either blue or yellow part -- availability
of surface systems including power supply, control panels, PLCs, as well as the availability
of emergency systems including emergency disconnect and emergency high- pressure shear. The system
also displays BOP element health history along the top as well as a history of valves position
to the right hand side of the display. So, this provides capability to review, if you
like, whether any valves have been opened or closed or whether there has been an alarm
over a period of 24 hours. So, last year we partnered with NOV and Ensco to pilot the
system on DS4 in Brazil. The system has been up and running since February of this year,
and we believe this is an industry first. We talked about collaboration this morning
-- this is a great example of collaboration between an operator, a drilling contractor
and an equipment manufacturer. Our first installation of the system in Gulf of Mexico will occur
later this year on Ensco DS3. We are also working with other equipment manufacturers
on similar systems to be able to extend a reach of the capability to all our deepwater
rig fleet. At the second real time capability that I would like to share with you is remote
BOP pressure testing. Currently all BP rigs operating in Gulf of Mexico uses an offshore
based system to digitally interpret pressure -- BOP pressure test data. The remote BOP
Pressure testing is to provide an independent means of witnessing the BOP Pressure test
from onshore. So the system digitally interprets the pressure test data directly by accessing
the data from mark system ñ BOP mark system ñ as opposed to the data coming from the
*** unit, and in doing so it eliminates complexities associated with choke line temperature
effects. The system also sensors BOP, the position of BOP elements, and provides a direct
confirmation of the actual pressure pass. Essentially what component of the BOP is actually
being tested. So the system has got -- has been designed in a way to minimize human factors
in interpretation of BOP test data. So, we successfully demonstrated the system, an early
version of this system, by streaming real time BOP pressure test data from the ***
unit on West Sirius rig in April of this year. And we brought that data on shore and the
processing of that data was done on shore in real time. The next stage is to pilot the
final version of the system which will use BOP marks data, directly using BOP pressure,
or pressure in the BOP cavities, and that will occur later this year on Ensco DS 4,
followed by installation of the system in Gulf of Mexico on Ensco DS 3. We are also
planning to extend the capability of case -- you know, digital pressure testing, to
casing pressure testing in 2013. BP Houston monitoring center is the third of the real
time capability that I would like to share with you. HMC enables a 24/7 monitoring of
well parameters from onshore. Essentially the data that is available to the offshore
personnel is also available in the HMC Environment to the staff working within HMC. So essentially,
HMC provides an additional pair of eyes to monitor well parameters. It staffs 30 specialists,
full-time monitoring well parameters, and specialists have got extensive experience
in deepwater operation with relevant key stills in well bore monitoring. The center provides
a constant communication with offshore rig teams. It monitors real time data. The real
time data that it monitors includes hit levels, flow in, flow out, standby pressure, mud weight,
and you know, the typical mud logging data. The center also utilizes standardize processes
and procedures which have been derived from best practices across of our deep water fleet.
So accountabilities are very clear within HMC, the control remains at all times offshore.
The driller has got primary accountability to monitor the well. We also have processes
and procedures for escalating if any observed parameters fall outside defined and agreed
range. And those processes are followed and usually leads to consultation. And if there
is any need for escalation, the procedure is very clear. HMC, as I mentioned earlier,
it has been up and running since July of 2001. The focus of HMC has primarily been on well
control, however we are extending the capability of HMC as we gain more experience in the use
of such real-time environment to other safety protocol operations such as cementing and
also pressure testing. So in summary, let me reiterate the three real time capabilities
that I shared with you. First, real time BOP monitoring, the aim of this capability is
to simplify and broaden the reach of BOP health diagnostics beyond the rig site. Make the
system more transparent. Second, is remote BOP pressure testing which provides an independent
means of witnessing a BOP pressure test from onshore. Again, when that capability is field
tested on DS 4 that will be a first, an industry first. Last is BP's monitoring center which
enables 24-7 monitoring of well parameters from onshore. We believe all these capabilities
help enhance the safety of deepwater operation and that is really want I wanted to share
with you. Thanks very much for your attention.
Thank you, Dr. Abbassian. Next we will move on to Dr. Frank Chapman. He is the president
of Ashford Technical Services. He co-founded Ashford in 1989 and worked on the development
of a number of systems for controlling and monitoring equipment in several industries,
including petroleum, semiconductor and telecom. Before founding Ashford, he worked with FPS
and Kellogg Round and Route, where he developed structural analysis software for early offshore
production platforms. Dr. Chapman has a B.S. from the University of California at Berkley
and a Ph.D. in physical chemistry from the University of Michigan. Let's welcome Dr.
Chapman.
Thank you, Pieces and thanks to BSEE for the opportunity to come here to speak today. So
what I'd like to talk about is offshore BOP monitoring using today's technology and going
beyond today's technology as well. So let me start with a brief summary of Ashford's
what we call rig watcher BOP monitoring system where we sort of focus on proactive maintenance,
early identification of problems, providing guidance to guys on the rig from folks onshore
and follow that with a summary of our experience over the last three years. Lessons learned,
feedback from users, some of the insights we have had, and lastly, indicate the big
picture where this might actually take us in the future. So let me start here with just
a big picture of how this thing works. Starting over here with the rig on the left and we'll
walk sort of counterclockwise around the slide. On the rig we collect data from various sensors,
pressure switches, solenoids, pressure transducers, flow meters, what have you, we get that data
off -- that raw data off the rig to a secure server on shore where we turn that raw data
into useful information and present that back to the user via website and then completing
the circle. That gives the user the ability to look not only to the current status of
the BOP, but look at some historical information as well. I think the key thing right there
is the anytime, anywhere, a lot of times the most experienced guy is not on the rig, but
if he has access to current information he can help troubleshoot problems taking place.
So, we'll look at three or four slides here. I want to give a flavor of the kind of information
we have been collecting. Let's start with, with sort of a preventive maintenance slide,
tracking usage. What we are doing here is tracking the usage of the equipment in terms
of the number of times the equipment's been cycled. This is a report for the upper annular
listing all the different valves that are associated with opening and closing the upper
annular. The cycle count in that fourth column there -- what we're gonna talk about a little
later is moving from a time-based maintenance regime to a cycle-based maintenance regime,
so you can see the cycle counts. Then the fifth column is sort of interesting question,
you know, what is the expected life for some of these valves and some of these components?
There's not a lot of real good information out there, so weíve got a placeholder. I
think part of the takeaway is as this kind of information is gathered the industry needs
to correlate that with maintenance and actually have a better idea as to what the expected
life is in terms of these components. So, moving on real quick here, this is sort of
an overview of operations, tracking operations. This is the bar chart here that pretty much
summarizes for a 24-hour window what's been going on with the BOP. Each one of those bars
represents one of the major components of the BOP. So, the first bar on the top there
is the upper annular. The color coding corresponds to the driller's panel, green being open for
the annulars and rams, red being closed. If you go down to the middle of the slide you'll
see a yellow and blue one, that's the pod select. At about 4:00 a.m. in the morning,
they switch from the yellow pod to the blue pod. And a lot of this activity, at the bottom
is the choke and kill lines, a lot of this activity is associated with pressure and functional
testing corresponding to that pod change. The next slide is something similar to that.
I just want to emphasize the fact ñ well first of all it's obviously presented as a
web interface. This is a partial day about -- this is a screen shot taken about 3:30
in the afternoon. The gray on the right-hand side is of course the future. And weíre about
15 seconds behind the rig. That's the lag time associated with getting the data off
the rig and turning that raw data into useful information and presenting it back to the
user. Looking at some of the hydraulic pressure kind of information that we collect here at
the top is another one of these -- we call them control charts. It's the upper and lower
annular and the four rams. You can see they were doing some, probably again function pressure
testing here. It's a one hour window. And then down at the bottom of the slide you see
the ñ thatís the read back, manifold read back pressure. And you can see every time
one of the functions is opened or closed we get a spike in the pressure here. Weíve also
got the ability to look at these pressures -- profiles I call them, time versus pressure,
at a much higher resolution, about a 90-second window corresponding to one of those transitions
there and then using that as a way of characterizing some of the details about the actual transition.
So, you know we talk to people about this; this whole concept of black box always comes
up. They ask, you know gosh, what you guys have is a black box. And indeed, that's the
case, but it's important to realize the black box is something that's used for forensics
after the fact. You know, for finding the root cause of a problem after it's actually
occurred. We want to focus here really on, you know, using it as a tool to review and
monitor the drilling and safety equipment on a regular basis, identify problems before
they become critical, help transfer knowledge from the guys that are onshore to the people
on the rig, view operationals on a regular basis. The goal here is outlined in the third
bullet there, basically, proving operations, increasing safety, reduces the need, hopefully,
for the black box. These are some of the objectives that we use
when we initially laid out the design of our system. This whole idea moving from time ba
ñ time base-- to cycle based maintenance. We can now do that because we can now collect
that data about its actual usage, the cycle counts. You know, time base is fine for equipment
that's used in a very regular pattern, say for example, a pump in a processing plant.
And yet, the BOP is an interesting device. It sits there most of the time doing nothing,
accumulator bottles all charged up, and then boom, a signal comes to close a ram, and a
lot of stuff happens to a small piece of the components of the system over a very short
period of time. So it's really better to characterize in terms of a cycle based maintenance paradigm.
And so part of that sub-bullet there, we can begin to gather information about what the
actual life -- useful life cycle is for some of these components. We are looking at developing
some metrics using to identify potential problems before they become critical: looking at pressure
versus time profiles, looking at flow versus time profiles in those very detailed, 90-second
windows where the action is really taking place. And using those pressure or flow profiles
to develop metrics which can then be looked at over time to identify subtle changes in
the performance and behavior of the system. Last major bullet there, it just emphasizes
the fact this whole monitoring business is sort of a three -- three-part problem. There's
acquiring the raw data. You know, weíve been doing data acquisition for 50 years now. That's
not to say that new sensors and things aren't going to come on line. But that's not really
where the major problem is today. And storage is not a major issue. We have multi-gigabyte
the hard drives; we can store this data. It's the last two bullets that are really critical,
I think today and thatís, you know, getting this: analyzing the raw data that comes back
from the rig, turning that into useful information and presenting that back to the interested
people so they can quickly understand what's going on on the rig and, and hopefully identify
problems before they become critical. Let me back up one minute, the, the key bullet
here is at the bottom: common information format so. Here is where that becomes a problem.
And this is sort of, you know, my idea of where the future is for this. We have on the
left-hand side sort of a mixed bag of rigs. We have jack-ups, weíve got semis, weíve
got drill ships, weíve got surface BOPs, weíve got sub-sea BOPs, we got fully hydraulic
control systems, we got mucks control systems. You know, weíve got equipment from a whole
variety of different vendors. But at the end of the day, it's a BOP. And at the end of
the day, you ought to be able to that convert that raw data from any one of those systems
into a common format stored in the middle of the slide there and then on the right-hand
side be able to take that common information and present it back to the user in a standardized
format, so that no matter what rig youíre looking at, it looks pretty much the same.
Again it's a BOP, folks. So, something for everybody here. You now,
this is sort of in the spirit, I guess, of open, transparency, sharing of information
about the various different stakeholders. Let everybody sort of share in that information.
So the biggest ñ you know we think with the kind of things that I just showed in the last
couple slides you can get this standardized format out there, then one person ought to
be able to easily monitor multiple rigs on a fairly regular basis. The biggest benefactor
of all this is of course the drilling contractor, preventive maintenance, monitoring and improve
operations, provide expertsí guidance to the guys on the rig. Again the guy with best
30 years of experience probably isn't on that rig. Operating companies don't really have
direct responsibility for the BOP, but you know they are responsible legally in most
cases for safely drilling the well. So you know, maybe it's a good idea for them to occasionally
take a look at what's -- how the equipment is being maintained, how the equipment is
being used. And lastly, the regulators who are tasked with you know effectively ensuring
the adherence or regulatory requirements something like this gives those guys with limited resources
a capability for actually implementing that. I thank you very much. And I look forward
to your questions. Thank you, Dr. Chapman. And last but not least
we have Mr. Tony Hogg, director of subsea engineering for Ensco. He has ñ Tony has
more than 30 years in international subsea work, including working for drilling contractors
as well as the deep coal mining industry in the U.K. He joined Ensco with the acquisition
of Pride last year, after working with Pride since 1999. Tony has been involved in several
joint industry activities, including five API committees, and he's currently chairing
the impending rewrite of API RP 64. So, let's welcome Tony Hogg.
Thank you, everybody, for staying around to listen to me. I think you'll find a lot of
what I say a follow on from what Fereidoun told you. It's part of the same initiative.
It's just more from the operator's -- sorry from the contractor's perspective rather than
the operator's. Whoops. Too much technology. The question's what real time technologies
are available to measure the health of the BOPs in service. For me the easiest way and
the best way to monitor the health is by the guys onboard the rig. And a lot of the discussions
we have had today have talked about the redundancy of the equipment on the BOP itself. Nobody's
mentioned the redundancy of the control panels and opportunities we have from the rig side.
PPI thereís at least two fully redundant control stations on the rig, one of them is
in the drillers house, the otherís in the tool pushers or on the bridge or somewhere
in a safe area. But there's two fully redundant places to function everything. And on conventional
systems there's also the HPU. And on the Mox systems youíve got the event logger, which
allow a third place to monitor the health. May even be just a pump running can alert
an experienced guy to an issue. Looking at these panels and the information displayed
on them can quickly guide them to what the issue might be. Competent crews -- there's
no substitute for competent crews, not in any discipline. The industry has lost a lot
of experience over the last years and we need to get it back. But there's no substitute
for time to get experience back. I talked with somebody earlier saying, you know what's
the substitute for 10 yearsí experience? It's 10 yearsí experience. Thereís ñ Weíve
got a big gap in the industry. I thought I was old with many years, but listening to
everybody here I have less experience than you all. There is a huge gap behind us to
the people who are coming through. So any support we can give the guys on the rig obviously
improves the benefit for everybody. So the ability to be able to display the information
on the rig is -- it's incredible support. It's an incredible crutch for the guys. Youíve
seen this before. It's virtually the same one that Fereidoun showed a few minutes ago.
This is the top level edge. This system we have, lots of green lights there. Actually,
you see one yellow light. That tells us there was a small problem. You can go deeper into
these pages and see what that problem was. And matter of fact, this one here was sort
of them starting up the drill, we got a lot of vibration, and it created a momentary error
on the riser angle monitor. So it gives a flag. It's something that happened. You need
to understand what happened to cause it. It doesn't hurt anything. But you need to know
what it is. It flags, and you go deep into it to find out exactly what it was. There's
many layers to this. I haven't shown them all. This shows the surface system. Everything
here is fine. You can see very quickly it shows all the components exactly as you would
expect them to be while youíre drilling normally. This is the lowest stack. Can you see the
connectors locked? Everything else is in order. We have mentioned many times today that the
vast majority of the time the stack does nothing at all; it just sits there and hums away merrily.
And this is what you want to see. This is what you do see for the vast majority of the
time. Everything is good. The big benefit of this is -- actually it's got many benefits
of course, but one of the benefits is if a guy on a rig sees something on this he's not
seen it before, as I said we have a lot of experience out there but we still have young
guys going through and if there's anything he's even unsure of, he can call somebody
and they can look at exactly the same information he's looking at and help him to fully understand
and deal with it. This shows the read backs -- this is the pressures that we select. This
is the pressure we want the various components to see. And it also tells us the pressures
we do see. Fantastic tool. Fantastic tool for surveillance and inspection and support.
I actually thought that Fereidoun would have shown all of these slides, which is why I
didn't put any more, but this is being developed further, weíre ñ weíre not ready to release
some of it yet, which will show all of the cycle counts and the fingerprinting of solenoid
valve operation and the history of all the components within the system. But, you can
see from this and the other presentations youíve seen from my colleagues here, we are
all driving in generally the same direction and I have little doubt that eventually they'll
ñtheyíll all pick up from the benefits of each. The beauty of this particular one is
that it's live today. We know this is-- this works. The screens Iím showing you are actual
screen from this rig, from this particular rig. It does work. And it's going to get better.
Short and sweet I'm afraid. That's all I've got. Thank you.
Thank you, Tony. So I think we have -- we definitely have time for questions. So, just
to run back through. Gary, discussed the Moduspec risk model. Dr. Abbassian discussed the BP
monitoring center. Dr. Chapman discussed the rig watcher. And then Tony went over the Ensco
BOP Dashboard. So, we will take questions from the audience. If you want to stand up,
we can recognize you. Yes, sir.
This goes to the panel. But as my role in API, and I look at this which presenting today
and my question is which API document, if any, do you foresee the guiding document as
far as standardization goes? When I was watching the presentation, I got to thinking about
53 and how weíre required to test and verify the equipment reliability and so on, so forth.
So I was trying to keep this in context of that mindset. So my mark on effect was ok,
does this go into API 16-d, which is a control systems? Or is this like an add-on type system
that's a stand alone? Do you see where I'm coming from? I'm not understanding how do
I-- from the API side, how will we measure the success of this thing? How do we validate
it?
Was the question directed at anyone or? Well I guess IíllÖ QuestionÖ while we are evaluating
any particular BOP or control system of course API, industry recognized specifications and
regulatory considerations are all taken into account during that assessment. I don't know
if that is a direct relation to your question or not, but, yes, API is in fact accounted
for in that. And some of the recognized practices are -- which apply to any one BOP. Of course
every BOP is a custom model of a base model of some sort. So of course those considerations
are ---
Yeah, just a little bit more clarification. Tony's been working with me on 53 for a while.
I'm going to go specifically to Tony. Tony, you know what we -- the trials and tribulations
we have been through and all the discussions and how we do the maintenance and testing
and verification. All these operations and I'm trying to get an understanding of this,
how does this kit fit into that bigger picture? Catch me now?
Yeah, yeah, I think it will fit into 53, Frank. I'm pleased you just finished the current
version so we have some time to get it right. I think it's going to be very difficult to,
to, legislate is maybe too strong a word, but to legislate a new product. I think it
has to find its feet and find out how it develops from each of these initiatives. Before that,
you can put a box around it. But, eventually, I would see it in 53.
Maybe, Maybe let me address a slightly different problem here that's associated with that.
Itís sort of, itís alluding to my last, next to last slide there, where weíre starting
to standardize this across a wide range of rigs. We have this standard, I think it's
called WITS, well information transfer standard, which really focuses on well parameters. You
know, I think we are going to need to have something similar to that, but, that's, itíll
focus on the equipment parameters, if we are going to achieve a standardized presentation
that allows people to, you know, look at this across multiple rigs. Thank you.
Just, just one comment. Whether it is going to sit within 16-D or 53, I think monitoring
is a component of maintenance, very closely linked with maintenance. And I think there
is an opportunity for standardizing the requirement for monitoring as it was -- opposed to what
the screen would look like. I think there is an opportunity to come up with maybe minimum
requirement for real time monitoring of BOP, sub-sea BOP system.
The panel topic included technologies, real time technologies for kick detection. Does
anybody have anything to report on that area rather than specifically in BOP Monitoring?
Well, the focus of this session was obviously on BOP and real time monitoring as pertain
to BOP, but there are efforts within the industry on improving capability to detect kick early.
And you know one such focus is in the area of better metering of what goes in and what
comes out, essentially better flow metering, that I am aware of. And of course there are
opportunities to, to, developing a means of analyzing the modeling, real time monitoring
data we saw an example this morning. So there are a number of opportunities out there but
a huge focus at the moment on improving essentially the flow meters we have at the rig site. So
that is one area of focus that I am aware of.
Ok, I will ask one question to the panel, and that is what specifically can your individual
industries, so as a consultant, as an operator, etc., what can your industry do to help push
along the progress of these example models and monitoring that you showed here today,
so for instance, what can be done to help push that along, to help encourage not only
within your company, but even amongst your competitors maybe, to just push that real
time monitoring along and encourage its development?
Somebody said earlier that one test is worth a thousand opinions, so I think the best thing
we can do is get these systems on the rigs and develop them, test them, make them work
and let everybody get comfortable knowing that they do work correctly.
Also I would add to the question itís very Öall of the interested parties, including the regulators, come to
some consensus as to what the requirements are, whatís the criteria for monitoring and
come to an agreement how weíre going to do it and how weíre going to assess the information
and what actions are going to be driven from such a software. Itís very important for
us to look at potential unintended consequences by automating such a system as well control.
So, it is very important that we have the interaction of allóof all parties involved
with this type of decision making. I would echo what, what you just said. I think
collaboration is important. What I had described was an example of collaboration across three
parties. We certainly in BP look forward to any opportunities that we -- we have to closely
the work with industry and also with the regulators to, to extend capabilities such as, such as
the one we just described and the one we have successfully implemented on Ensco DS 4, and
we plan to implement it on a number of our rigs in GOM and elsewhere.
I guess, hello, the only thing I would add to that, is I think it's ñ you know, we have
a lot of data coming from well parameters. Now we are talking about adding data coming
from monitoring the equipment. Someplace all that needs to come together to give us a complete
picture of what's going on on the rig, with the well, with the equipment. And that's a
pretty big integration problem. But, I think it needs to take place at some point.
Tony, did you -- are you just taking better advantage of the existing instrumentation?
Or did you install additional instrumentation on the BOP?
We actually took advantage of the instrumentation, the sensors that were already there. We did
add some pressure transducers, but a lot of it, the pressure switches, solenoids were
already in place. The system we have got on essentially transmits
the information from the event logger, puts it under the GUI, the graphical screen that
you saw. But in the background you can sort data, you can take advantage of the numbers
behind the pictures, if you like. But it's the existing information; it comes from the
event logger as is.
Any more questions? Ok. Thank you very much. [applause]