BP's Deepwater Oil Spill - Oil Spill Cementing - Open Thread

We have not had an open thread on the oil spill in a while. The oil spill commission released a letter with an attached 38 page analysis this week indicating problems with Halliburton's cementing.

This is a link to the letter from Mr. Bartlit to the Oil Spill Commission, dated October 28. It says, in part,

We asked Halliburton to supply us samples of materials like those actually used at the Macondo well so that we could investigate issues surrounding the cement failure. Halliburton provided us off-the-shelf cement and additive materials used at the Macondo well from their stock. Although these materials did not come from the specific batches used at the Macondo well, they are in all other ways identical in composition to the slurry used there. . .

We attach Chevron’s report of its laboratory tests, and we have invited one of its experts to discuss that report with you at the public hearing on November 9.

Chevron’s report states, among other things, that its lab personnel were unable to generate stable foam cement in the laboratory using the materials provided by Halliburton and available design information regarding the slurry used at the Macondo well. Although laboratory foam stability tests cannot replicate field conditions perfectly, these data strongly suggest that the foam cement used at Macondo was unstable. This may have contributed to the blowout.

Chevron's report regarding its analysis can be found at this link (pdf). It is 38 pages in total. The table of contents lists analyses in a number of areas, including thickening time, mud balance, and mixability.

Halliburton was not too happy with all of this, and released its own press release. It says, among other things:

Halliburton believes that significant differences between its internal cement tests and the Commission’s test results may be due to differences in the cement materials tested. The Commission tested off-the-shelf cement and additives, whereas Halliburton tested the unique blend of cement and additives that existed on the rig at the time Halliburton’s tests were conducted. Halliburton also noted that it has been unable to provide the Commission with cement, additives and water from the rig because it is subject to a Federal Court preservation order but that these materials will soon be released to the Marine Board of Investigation. Halliburton believes further comment on Chevron’s tests is premature and should await careful study and understanding of the tests by Halliburton and other industry experts.

With respect to Halliburton’s internal tests, the letter concludes that “only one of the four tests” showed a stable slurry. Halliburton noted that two of those tests were conducted in February and were preliminary, pilot tests. As noted in the letter, those tests did not include the same slurry mixture and design as that actually used on the Macondo well because final well conditions were not known at that time. Contrary to the letter, however, the slurry tested in February was not “a very similar foam slurry design to the one actually pumped at the Macondo well….” Additionally, there are a number of significant differences in testing parameters, including depth, pressure, temperature and additive changes, between Halliburton’s February tests and two subsequent tests Halliburton conducted in April. Halliburton believes the first test conducted in April is irrelevant because the laboratory did not use the correct amount of cement blend. Furthermore, contrary to the assertion in the letter, BP was made aware of the issues with that test. The second test conducted in April was run on the originally agreed upon slurry formulation, which included eight gallons of retarder per 100 sacks of cement, and showed a stable foam.

BP subsequently instructed Halliburton to increase the amount of retarder in the slurry formulation from eight gallons per 100 sacks of cement to nine gallons per 100 sacks of cement. Tests, including thickening time and compressive strength, were performed on the nine gallon formulation (the cement formulation actually pumped) and were shared with BP before the cementing job had begun. A foam stability test was not conducted on the nine gallon formulation.

As expected, Halliburton's legal team will muddy the value of the evidence, muck up the responsibility factor, and cement in place reasonable doubt, prior to any criminal charges being brought.

I would like to know how a variable called "stable" is defined in the context of a specific site.

It would seem to me to vary from rig to rig (location), or even from time to time on the same site (e.g. depth, bore conditions, etc).

My reading of earlier posts on this issue is that the rock / soil condition around the casing is what was unstable long before the blowout.

Were they saying the cement was "volatile" or weakened in and of itself, or contaminated such that it would not work at any site at any time?

Halliburton still has not given up trying to sell the centralizer meme. And they keep spinning the cement bond log, ignoring the fact that it could not image the cement that actually failed because it was deeper than the float collar, the lowest point they could image with a CBL.

Of course this means that Congress has done the impossible, they have made Tony Hayward look smart for declining to comment on the number of centralizers. Unlike the congressmen, he followed Abraham Lincoln's advice, "Better to remain silent and be thought a fool than to speak out and remove all doubt."


One thing I have noticed in this monumental fiasco is that "lay folks can make things worse, but it takes a real professional to profoundly mess things up".

The same guy who said that also said "Ah yes, reminds me of the time I was forced to live on food and water for three days".

Now that the spill is behind us, and the appearance of the situation is that there is no noticeable (to the average person)environmental catastrophe, and the deep water oil drilling ban has been lifted,does anyone know if the U.S. government has mandated any more stringent deep water drilling safety measures to lessen the probability of future deep-water spills?

Improved BOPs? Mandatory relief wells drilled in parallel with the producing well?


Some environmental links:

Alleged huge oil slick in West Bay, LA, confirmed to be only an algae bloom. The T-P ran the original story with no hedges, based on reports by fishermen and reporter’s observation from an overflight. HuffPost and other sites featured the “discovery” story and seem not to have retracted nearly a week after the T-P began retracting. The Coast Guard said on the second day of the scare that it seemed to be algae.

Water mostly clean, per Zukunft, Oct 19.
http://www.nola.com/news/gul f-oil-spill/index.ssf/2010/10/federal_leaders_of_gulf_of_mex.html

Lessons learned, CNN, Oct 19.

Substantial essay by William J. Mitsch on responding to oil spills: “What Would Nature Do?”

Richard A. Kerr in Science Aug 13—informed commentary on the govt. oil budget, estimated that 13% to 39% of oil remained as of August (paywall). If someone with a subscription to Science would write a summary, I'd appreciate it.

Deepwater corals 20-40 miles north of the well look good. This is maybe 10-15 miles from where Samantha Joye found the deepest deposits of floc sediment. Story and interesting video.

Girguis of Harvard: Studies of seep communities show anaerobic methane-eating bacteria work much faster than previously thought.

UMD scientist thinks the spill has not made the Gulf’s seasonal dead zone worse.

For all: Just a reminder back from the days when we beat the cmt issue to death: cmt failure is common. So common that no cementing company warrants that any of their cmt jobs will test good. Not only no warranty but a no money back deal: the cmt fails and the operator still pays full price as well as paying full price to recmt. They can try to replicate the original cmt all they want and everyone, without exception including Halliburton, can say "Yep...the cmt was crap" and even then none of the responsibility falls on Halliburton as long as the cmt was formulated and ran AS PER BP'S DECISION. Halliburton will repeatedly point out the they only make cmt recommendation. How the cmt is formulated, how it is mixed, how it is pumped and how it is tested will always be the sole responsibility of the operator. As long as Halliburton followed the specs and pumping procedures as BP directed they aren't liable. If the cmt wasn’t mixed as per BP’s direction or it was pumped in a fashion that BP didn't authorize then it's a whole different ball game. That's the issue we need to keep an eye on IMHO: At some point does BP claim the cmt mix or the pumping procedures didn't conform to their orders?

Rockman - The Wall Street Journal suggests that this may help BP avoid criminal prosecution. I'm not a lawyer, but my understandng is that for an act to be criminally negligent it must be such that a "reasonable" man would believe it to be dangerous. If the Halliburton "experts" didn't think it was dangerous (and they have testified so) then it seems difficult to assert BP's employees were criminally negligent. BP may think that is enough blame to pin on Halliburton. BP and its employees walk on the criminal charges and the higher fines for the pollution.

That would be quite likely to PO the congressmen, but given their gross ignorance and meddling, it seems like karma.

Bruce I have a suspicion that BP is working on attaining "reasonable doubt" with the future jury pools thoughout the country. How hard would it be to demonize Halliburton and get at least 30 to 40 percent of any jury to have some thought that Evil Halliburton was behind this fiasco? Hell BP may even show pictures of Dick Cheney at random though the trial.

I don't think BP is trying to get Halliburton to have to foot the bill, but they are trying to get the future jury members to not make them (BP) foot as much of the bill, as well as not having BP officials serve time behind bars.

It's a good move!

Bruce - that may well be the plan by BP. I don't think about the legal position...leave that to the TOD legal eagles. But BP might argue that H. gave them faulty advice. That might be proven. But here's the problem: if BP can make a strong case today that H. advice was faulty then why didn't they come to that conclusion before the cmt job? They can say the advice was faulty now that they know the cmt failed but that's a circular logic that requires the belief that something H. did caused the problem. Might work with a less sophisticated jury.

BP is still in the same box regardless: whatever testimony they offer to blame the H. cmt just condemns BP for using it UNLESS they show the H. cmt/procedures didn't follow BP's orders.

Any opinion on the results of the Chevron report Section 4, Table 3, page 5 "channel present"? That's got to hurt Halliburton's defense!

This seems to agree with BP's complaint that the nitrified foam was not stable under test conditions, let alone down hole. Which brings us back to the fact that the cement did indeed fail, so we want to try and figure out why. The section that failed was subjected to variable pressures (both the positive and negative tests) with a place for the cement to flow that would not apply to the cement in the annulus. By that I mean the cement could move back and forth like the shuhttle in a shuttle valve in the shoe track, not the annulus. There could be artifacts of channeling left in the cement extending the final setting process. (Think handprints in the Hollywood Walk of Fame)

Bruce - Channels are common in many cmt jobs. Again, another reason why no cmt company warrants it's work. I know it may be difficult for folks to appreciate but getting a good cmt job is always difficult and can never be taken for granted. That's why it's always the operator's sole responsibility to test every cmt. The only fault that could ever be pinned on H. is if it's proven they didn't mix or pump the cmt as per BP's orders. H. can get on the stand and say:"Yep...no doubt what so ever the cmt had channels that led to the failure." And that's why it was BP's responsibility to rectify that situation...not H. No different than ordering a meal in a restaurant that the menue says contains peanuts and you go into allergic shock after eating it. You are responsible for the outcome...not the restaurant. The restaurant knows peanuts can have a bad effect on some folks but it's those folks responsibility to avoid the risk. Same thing with foamed cmt. I would bet lunch that H. can show documentation that they indicated some level of possible failure of foamed cmt in the BP well. That sort of disclaimer is very standard in all third party agreements. As long as H. complied with BP's instruction BP agreed to release H. of any liability when the signed the work order. Companies like H. would be put out of business in no time if they didn't have such disclaimers. Sh*t happens all the time when drilling wells. It's never a question of "Will part of the system fail?" but "What next?"

I respect your experience, but I do not remember your explanation as to why channeling would be so common. It is definitely not what any operator wants. Obviously, it would be a substantial advance in the state of the art to significantly reduce the incidence of channeling during the initial cementing procedure.

Here are some thoughts out loud for your consideration in view of your experience. Reading the patent application, there was a discussion of the channels forming between different sands. The suggestion being that the cement and/or hydrocarbons would flow from the pay zone into another sand layer. (This flow could be in the general form of an underground blowout.) This is a recognition that in a oement slurry, you're dealing with a nominally incompressible fluid. So to clear out the channel, you must push the cement somewhere else.

Nitrified cement changes the situation by providing supercritical nitrogen which is compressible. If you squeeze it, there is the possibility that you can separate the nitrogen just as you squeeze water from a sponge. You'd get tracks of nitrogen.

While Haliburton seems to have followed the API Recommended Practice, I not sure the RP itself is sufficiently realistic. API lets them use a blender to ensure a homogenous mixture. According to the patent, the nitrogen is injected into the flowing cement line through six nozzles. So right at the injection site, the mixture resembles toothpaste coming out of the tube, the cement is the paste and the nitrogen is the stripes. With the nitrogen being compressible and constituting over 50% of the total volume of the resultant mixture, there will be a lot of mixing. But I doubt it is truly homogenous and there may exist enough of an artifact of the "stripes" that you have a natural site for channels to form. And squeezing it with positive/negative pressure tests when it has not cured would be asking for trouble.

Bruce - I can't offer a specific reason why any channel forms. I know this sounds simplistic but consider how difficult is can be to just pour a good concrete slab of the ground. Now do a similar job at the end of a 3 mile long 5" pipe. Add the temperature, pressure, geochemical interactions, proper spacer design, mechanical aspects of pumping, etc, into the equation and one might wonder how they every get a good cmt job. I can offer that one relatively common cause of channels is the formation flowing oil/NG/water while the cmt is curing. Just because the chart book says the well should be static doesn't mean it is. Given that cmt failure is the most common failure during a drilling op IMHO, it should tell you how difficult a proposition is. That's why you always test your cmt...always. And those test will often indicate cmt failure to some degree. So you recement. This is how it's been done for 60+ years and will continue to be done in the future.

Rockman - I appreciate how difficult it is to identify the causes of cement failure, but what is needed is an effort to try and figure out the most likely causes of the failures rather than simply a try and try again ethos. Building a database of likely causes and details of the job might lead to a better long term understanding of what is happening down hole. Clearly, you have enough experience to believe that eternal vigilance is the price of safety. But stuff happens and it would be best to have almost all cement jobs succeed so that inattention does not lead to disaster.

IIRC - The Halliburton cementer, Vincent Tabler, told the MBI that he had never done a nitrified cement job at depth before. But he made the batch. And when questioned whether he thought they had a good cement job, he said yes. So in his mind a good job is one that had been completed per spec, not one that maintained the overriding purpose of the cement job, retaining the pressure of the formation. It seems that a "good" cement job has been defined down to a point where it is meaningless to the overall success of the project. Mr Tabler seemed to lack curiosity about the whole process, he just did his part of it by the book. It reminds me of the comment that the Apollo 1 fire was due to a lack of imagination. Those involved seem insufficiently curious about the causes of cement job failure, they simply accept that failures are common. A squeeze job will fix it later. That's not the way to improve the safety of the industry. If you pay twice as much for bad jobs as for good ones, you've incentivized failure.

Bruce, let me a deepwater oilfield "hand" with a few years experience in the GOM give you a litle insight on cementers in general if I can. The cementers job during a cement job is making sure the cement job goes good on the cement unit. A cementer running the average unit on a deepwater rig with along with a liquid additive system has many responsibilities all at once and it's kind of an art in a way. Many cementers don't have a college degree and it's not a requirement. Many cementers don't have the in depth downhole knowledge that you may expect them to have, but they can follow directions, parameters and recipes in order to make a cement job go as designed and they can get it in the pipe.

Once the cement is in the pipe they clean their cement unit and they get ready for the next job whatever that may be. They get the information on how the job went from the time the rig pumps took over displacing after the job is over. It's not that they are not curious, but it's not a responsibility that they can control or alter. They have job distinct job roles and duties and they must complete them.

So his part of the job(on the cement unit)was a good cement job and that's the part he could control. There were multiple engineers and there was a nitrogen foam team leader involved, they were all specialist. Mr. Tabler is the blue collar guy who takes direction, he makes it happen as directed and that's not an easy job, he too is a specialist (on the cement unit).

A "good cement job" is not meaningless, but it has many meanings. Did the job mix good on the deck of the rig? That is the main the role of the cementer.

Did you loose returns? Did the wiper plugs bump on time or at all? Did the float equipment hold? Did the cement get hard too slow or too fast? Did the CBL show adequate bond? Did the well flow? Any of these are even one of these could mean a bad or good job. If the cement gets mixed as per design, then the cementer did his job. The fact that they may not be as educated or knowledgeable in anothers role of the process does not mean they aren't curious.

Ok I'm done!

A "good cement job" is not meaningless, but it has many meanings. Did the job mix good on the deck of the rig? That is the main the role of the cementer.

Did you loose returns? Did the wiper plugs bump on time or at all? Did the float equipment hold? Did the cement get hard too slow or too fast? Did the CBL show adequate bond? Did the well flow? Any of these are even one of these could mean a bad or good job. If the cement gets mixed as per design, then the cementer did his job. The fact that they may not be as educated or knowledgeable in another's role of the process does not mean they aren't curious.


The answer to all the questions you pose (except the missing CBL) appear to affirm that this was a good cement job. Everyone involved seemed confident it had gone well. So given that they had evidence of no losses, bumping the plugs indicated perfect placement, the floats held on flow back, what went wrong?

The answer may be what happened at 17:02 on 4/20/10. That was the beginning of what was supposed to be a negative test.

Let's look what the hydrostatic pressure at the top of the DP was supposed to be had there been a proper negative test. As the seawater was pumped down the pipe the pressure would steadily increase. When the seawater got to the bottom of the drill pipe the pressure would reach a maximum of ~2800 psi. Then as the seawater went up the backside the pressure would steadily decrease to a little less than 1600 psi. At that point closing off the riser and opening the kill line filled with seawater would simulate the state the well would be in when the riser is displaced.
That means the pressure at the wellhead would be around 2250 psi (ambient sea floor pressure) and the pressure in the casing at the float would be around 11,000 psi.

But that isn't what happened. Two things differed significantly from what was supposed to happen if done correctly and what did happen.

1) They didn't bleed the pressure off the kill line they bled it off at the Drill pipe.

2) The static pressure on the drill pipe was at 2400+ psi not the roughly 1580 psi it was supposed to be when the fluids were all positioned correctly.

They attempted to bleed off the pressure down to zero, but it wouldn't go below 290 psi and then quickly increased up to 1200 psi. It has never been made clear but I believe the rig crew blamed this phenomena on a leaking annular in the BOP stack. But another explanation is far more ominous.

Take a look at Appendix M of the BP investigation report. In that report BP had 3rd party engineering firm analyze what forces would be required to lift the casing off the hangar. Unfortunately this report does not tell us what down-hole pressures they used to determine their findings. The report however does appear to be using pressures that would be expected if the negative test had been conducted properly. That study does not appear to be using the pressures that the well was subjected to at 17:02 on April 20. In other words they used ambient seawater pressure at the wellhead and the corresponding pressures down hole. the down hole pressures would be correct but the pressure they assumed at the wellhead may be off by a lot.

Given that 70% of the lift forces on the casing come from the pressure differentials at the wellhead and given that the pressure recordings we have suggest that the rig crew caused the pressure at the wellhead to drop something like 700 psi below seawater gradient (700 psi below what the study assumes), that makes it almost certain that the casing did lift off the hangar. In other words it appears that there was in excess of 120 Kips of lifting force on the casing caused by the incorrect configuration of the piping for the negative test. The study it appears does not account for this.

The effect of lifting the casing would be a rapid influx past the hangar seal. That influx would raise the casing pressure which would then reduce the lifting forces and allow the casing to drop back to its original position. But what else? Swabbing, damage to the bottom hole assembly, damage to the cement are all likely if the casing did lift off the hangar at 17:02.

Is it possible that prior to 17:02 there was nothing wrong with the cement or shoe track assembly?


A very interesting scenario. One big question, however, is how did the hangar seal fall back to its original location? As you know, a lead impression taken after the BOP was removed showed the hangar in exactly the correct location. It would seem that given the flow, disrupted bottom hole conditions, and the lack of intentional sealing forces that the return of the hangar to its proper position would be difficult.

From what I can gather the seal when installed is locked to the casing. So if the casing lifts up and then settles back to original position the seal moves with it. The weight of the casing would be what causes it to return to its hung position. According to the BP investigation report if the casing lifts upwards 6" then the seal is can allow flow because the ID at the well head is larger just above the seal.

As I said the study in Appendix M doesn't specify the pressure used to make their calculations. But it does say they based there calculations of pressure on their assumption that there was a seawater gradient at the well head (~2250 psi). The recorded pressure data clearly indicates this is a fiction. The pressure at the drill pipe of 2400 psi instead of the 1600 psi it was supposed to be when they started to bleed off the pressure suggests the pressure at the wellhead dropped far below the pressure of the ambient seawater.

"The answer to all the questions you pose (except the missing CBL) appear to affirm that this was a good cement job."

Jinn read the questions again. I think the well did flow, so that answer too does not affirm a good cement job. All I'm saying is that the cement job was mixed and pumped as designed and that pointing any finger at a blue collar guy that followed directions and worked to the best that knowleage base and job duties allowed him to, when his part went well is just plain wrong. The well design could have been flawed, the cement job design could have been flawed, the processes after the cement job could have been flawed, but WE need to appoint blame where it should be properly placed. The rig cementer does not make these any of these decisions, the rig cementer is normally not capable and certainly not responsible for making these decisions.

I also should have added did the pressure test and negative test pass or fail? What was the long term success of the cement job? I think we know that this cement job didn't give the Macondo well zonal isolation.

So yes when I say that a "good cement job" has many meanings there also many more expectations, by many more people in the short and long term life of a well which labels the job good or bad. You could have a cement job fail twenty or thirty years after the original cement was pumped and it may be deemed a bad cement job at that point.

In summary I don't think this job provided adequate zonal isolation. Whether the job was broken down due to BP's actions after the job is another story. I don't like many of BP's actions and engineering prior to and after the cement job. In my view they had a mess going on at that location and they should be ashamed of themselves to run an operation like that.

Jinn read the questions again. I think the well did flow, so that answer too does not affirm a good cement job.


The point you are ignoring is they may well have had a good cement job prior to 17:02 and it would have remained a good cement job to this day if they had not made a serious error that caused the production casing to lift up. The hanger and its seal may have survived what happened at 17:02 but it looks like the bottom hole assembly did not.

It looks to me that The DWH drilling crew had developed a shortcut method for conducting a negative test when displacing the riser. It was a simple and quick - just stick the drill pipe below the stack, fill it with seawater, close the stack against the DP and bleed off the pressure. That method had always worked fine in the past, but do that with the DP 3300' below the mud line and the results are fatal.

Where I'm stuck at with this theory or is that it appears the well's flow path was via the inside of the casing string not the annulus (contrary to what I previously thought).

So are you saying that the shift in the casing string damaged or fractured the cement sheath and somehow allowed the well to flow into the inside of the casing?

If the flow was not from the annulus what does the hangar seal have to do with anything?

Now as far as the short cut negative test that was and is a bad procedure and should have never been done.

Leakage at the hanger seal explains why they were unable to bleed off pressure below 290 psi. As the casing moves upward the seal also moves up until it reaches a point where it starts to leak (moving 6" up according to BP). That leakage created a limit to how much they could drop the pressure. At that point they soon realized that something was amiss and stopped trying to bleed off the pressure. Other than an indication in support of the idea that the production casing had moved the hanger seal has little to do with the blowout.

As far as what would have been damaged down at the bottom of the hole - I could only speculate. My point was that prior to that point in time there was every indication of a good cement job and that the production casing was effectively isolated from the reservoir.

It is probably correct that Halliburton has a strong position against BP from a civil lawsuit perspective. The reported terms of the contract appear pretty clear. However, since there was a violation of Federal water pollution laws, the Feds can go after virtually anyone connected with the incident. The terms of the civil contract would not matter at all.

It is highly likely that Halliburton will desperately tried to remain completely blameless, not merely insulated from civil damages.

ROCK. I get your point. Consider this scenario; contractual obligations may be different under US law compared to UK law.

Say; my hip joint is knackered; I go to my General Practitioner (GP = primary health care Doctor) and say so. My GP says, "I think you may need a hip joint replacement; I will make an appointment for you to see a specialist at a hospital". Eventually, I get to see this specialist; he agrees with my GP and says I will book you in for the operation. (Several months later). I have the operation and after a few weeks, I and my GP realise that the hip job was faulty and I am in a worse state than I was before I went to my GP with the problem.

Who carries the blame for the state I am now in after the faulty operation; the GP or the specialist who did the operation? Under UK law, the specialist in hip joint replacement who did my operation.

There is something wrong here if I, the owner of the problem hip, engage a professional to solve my hip problem; via my primary medical health care agent (GP); have to hold my GP responsible for the faulty hip operation.

Acorn - I get your point. But here's the qualification of your story that makes the comparison correct: did you (or your expert staff of doctors that are on your payroll) evaluate the proposed procedure and approve it as appropriate and necessary? And when the surgery was done were those same experts in your employ supervising the operation directly and giving step by step instructions to the other doctors? And did you employees test you new hip and deem it successful before you were removed from the operating room?

Always remember with third party contractors on every well ever drilled: they have absolutely no authority to make any decisions as to how a well is drilled. They render opinions, equipment, chemicals and manpower. But have no authority to do any operation without the operator's consent. And no third party contractor controls any aspect of the process other than how they do their job. As long as H. mixed the cmt how BP ordered it and then pumped how BP ordered than they were just following orders as their contract with BP specified. The Neuremburg defense might not have worked for the Nazis but it's 100% solid in very court in the US in situations like the BP nightmare.

The world can hate Halliburton all they want. But if Halliburton ran a crappy cmt job tht led to the blowout then they did so at the direction of BP. I've sat in literally thousands of meetings where third party contractors made recommendations on every aspect of drilling a well. And not once..not once...did anyone other than the operators's staff make the final decison on how a well was to be drilled. Not once.

ROCK. Thanks for the explanation, I am understanding the relationships in this well drilling business better now.

You may remember that a while back, I wondered why any of the sub-contractors did not say that they did not agree with the way the well was being drilled, and walk away from the contract. I worked for a long while for a company that always had its own experts in every aspect of our power generation business. The idea was that we could write contract specs that were state of the art and clear on responsibilities of the parties involved. We know we paid premium prices for jobs because the sub contractors had to build in a risk factor on such tight specs. We even held back a small percentage of the invoice for a year, pending subsequently evident deficiencies in their work. It worked for us and the contractors learnt to up their game when putting in tenders to our company. A successful job with us was a ticket to get more work, world wide.

I am wondering why BP did not have the same approach. They should have had their own experts, who new as much about cementing wells as Halliburton did; and the capabilities and track record of such sub contractors. If there is no performance clause in the contract, what the hell, keep doing it wrong and keep getting paid to do it wrong again and again. Sounds like easy money to me for a cementing contractor.

It may be of interest to US posters on this forum, in the different response of BP's Tony Hayward, when he appeared before a UK Parliamentary Select Committee. Members of Select Committees are not allowed to politically grandstand when taking evidence; unlike the US equivalents. The UK government does not dismiss their reports lightly and they can be debated in the House of Commons.

In a written memorandum to the Committee, The following text appears. It is pertinent to Rockman's comment above about the operator's responsibility in the US regulatory regime.

"The UK Safety and Environmental Regulatory Regime

20. In the UKCS there are two main regulators: the Health and Safety Executive (HSE), which regulates offshore safety; and the Department of Energy and Climate Change (DECC), which regulates the offshore environment for oil and gas activity.

21. In the UK, the design, construction and maintenance of a well must be independently verified, and it is the Well Examiner’s role to examine all stages of a well’s planning, execution and operation throughout its life cycle.

22. In addition, the HSE Safety Case Regulations (SCR) and related regulations require the identification and assessment of the major accident hazards associated with an installation and require measures to mitigate those hazards and to ensure the rescue of personnel. Under the SCR, UK companies must manage wells to avoid unplanned escapes of oil or any other well fluids. It is an important principle that the risks of escape of hydrocarbons and of personal injury must be demonstrably as low as reasonably practical.

23. In essence, the UK regime involves goal-setting based on an analysis of major hazards and risk assessment, with the emphasis on prevention of accidents. By contrast, the US regime identifies precisely what an operator is expected to do. Operators in the UKCS are required to demonstrate the identification and assessment of major accident hazards; they must also provide assurance that necessary measures have been taken to minimise these risks and to give precedence to the safety of personnel. This allows for a process of continuous improvement, based on a growing body of information and knowledge. This ‘goal-setting’ approach was largely developed in response to the Piper Alpha disaster in the UKCS in 1988."

Acorn - Actually it's not uncommon for any subcontractor to express a disagreement with an operator. We'll do in politely and avoid making the guy that signs your invoice look stupid. But there is also a tendency to do it in front of witnesses. You may recall one of the players on the BP rig made the comment that they always had the BOP to fall back on. I doubt it was an accident he did it in front of a witness or two. It's a basic "cover your ass approach" all us consultants use. We can always play the "I told you so card". In my youth I once used that "BOP" slap with a company man. As a result my contract wasn't renewed. But I did feel very self righteous. And I didn't really want to work for that company anymore...they had a habit of hurting hands. As far as walking off the job over a disagreement about procedures I've done that more than once. But only because it involved safety concerns.

Otherwise if the client insists on making a dumb move I'll just express my disagreement (politely , of course) and sit back and watch. In 2000 I geosteered 4 wells for ExxonMobil in Wyoming. The young company man was very full of himself and wouldn't take my advice. I was supposed to be on contract with the first well for 12 days but it took 35 days. So my invoice was triple what I had expected. A big plus was that I didn't have to stay on the rig while he corrected his mistake. So in addition to a fat check I drove over 3,000 miles (at XOM expense) to Yellowstone and lot of other amazing sight for a boy who grew up in S La. But I made very sure my XOM counterpart in Houston understood the situation. So when the Houston drilling manage complained to him about my incompetence he had the documentation to show exactly who did screw up (his guy). After that the drilling manager never said another word about my performance.

As far as BP not having their own "experts" handling the situation that's a problem most companies have. Many aspects of drilling a well are very specialized. Take cementing which might seem rather basic. But cmt companies will spend a large part of their budget on continual training programs for their hands. Additionally it's the service companies who are doing the cutting edge research. The majors gave up much of their research efforts in the 70's. How bad is this knowledge shortage? Several years ago I worked for a very large independent drilling DW GOM and Brazil. The majority of the hands in the office were consultants and in house service company reps. That is a big hook the service companies use to get contracts: Halliburton will put a very experienced cmt engineer in a client's office full time. He'll do the design work and hand it over to his supervisor who'll then present it to management and thus preserve the illusion of competence. A perfect symbiotic relationship. LOL. Yes...very easy money. I have a "well from hell" being operated by another company right now. The drilling mud bill should be around $600,000 today. Instead, thanks to poor decisions, it's around $2 million. Very easy money for the mud company: the operator keeps losing mud down hole and the mud company keeps mixing more and running their invoice up. As long as the mud engineer keeps his mouth shut about those poor decisions he get that nice fat check too.

Have been lurking on this site since May, this is my first post.

Background: Engineer with a fair amount of drilling, cementing in some difficult holes/delicate formations.

I've changed my mind a number of times about the root cause(s) of the blowout, and who bears how much share of the blame. At this point, I think of the cement failure and all the issues that go along with it as just one contributing factor to a number of bad decisions made on the drill floor.

Watching the hearings, I'm starting to think the lawyers will be the only winners - All the parties are filling the room with questions designed only to confuse the juries who will hear all this again at trial. That said...

While I don't think this cement job had much chance of success, I'm hard pressed to come up with any scenario I'd have put on the table with much confidence, and I think BP knew full well that it was playing a long shot (but if it worked, the payoff would be considerable). So they decided to go for it, and told Haliburton to come up with their best shot.

I don't have a problem with this approach, as long as margins are maintained for when the gamble doesn't pay off.

I don't fault Halliburton for trying to do this cement job for their customer, but for BP to say over and over again that they thought it had a high probability of success is beyond reason.

There just wasn't any real margin to play the density game with. More centralizers might have made a difference, but even with 21 the ECDs were marginal, and they weren't even trying to get to their 1000' TOC requirement. They pumped a short job because if they put enough weight in the hole to push the TOC up where it should have been, they thought (and the models said) they would have broken out of the formation and lost circulation (even using foam).

How many models did Haliburton run trying to get a plan the crew would even try?

The one thing I can't grasp is how the tool pusher and driller accepted no flow on the kill line as an indicator of a good test with 1400 lb. showing on the string. If they hadn't displaced all the spacer/mud up to the BOP (and/or maintained clean sea water in the kill line), there would have been a differential, but 1400 lb.(?!!). My back-of-the envelope says it would take more than 1300' column of that heavy spacer pushed up into the kill line (or still below the BOP in the casing) to stop flow in the kill line if the no-flow was due to fluid imbalance alone. Not likely in my mind.

After that point, my brain goes off into a whole list of "Why didn't they just..." questions.

I just can't grasp any of the answers as something anyone who wanted to stay alive would buy.


I'm curious about your "They pumped a short job because. . ." statement. Was it really pumped short?

As I understand it, there were two pertinent BP requirements: 1) get TOC to 17300' and 2) don't seal the annulus; that is, keep TOC below the 9-7/8" liner shoe at 17157' TVD. BP's DH Accident Investigation Report, and their 24 May 10 Washington Briefing, both give TOC as 17260'. (I have no idea whether they knew that to be the true TOC, and if so, how they knew it.)

I found it interesting that Halliburton's OptiCem simulation for the 21-centralizer case estimated TOC at 17258', which is virtually identical to the apparent 17260' result achieved with only 6 centralizers. (This suggests to me that, barring fluid losses, there was very little, or no, channeling between 18304' and 17260'.)

Another thing I found interesting with that OptiCem result was that the final fluid levels and densities give a hydrostatic pressure at 18300' of 13487 psi, assuming an average foamed cement density of 14.4 ppg. That pressure is all but identical to that for 18300' of 14.17 ppg mud (13484 psi).


Edit spelling

I'm curious about your "They pumped a short job because. . ." statement. Was it really pumped short?


I think what he means is that there was a requirement (really just a BP best practice I believe) that a CBL be performed if there is less than 1000' of cement in the annulus above the producing zone.

BP engineers reply to this is that a CBL would have been performed before the well was put in production. The reason the cement was "short" by design was they were trying to keep the annulus open at the bottom so they didn't have room for 1000' of cement. Having an open annulus at the bottom was also the main reason for the long string casing.

Anyway all of this still begs the main question which is that the current prevailing theory says that the premium cement in the shoe track and the 2 float check valves had to fail to cause the blowout. So what does the foamed cement have to do with the causation of the blowout?

JINN. Remember they had nine attempts to convert the float collar and over pressurised the thing doing it. There is a chance that after that episode, the float collar was in no state to isolate anything. See page 11 on the following.


The BP DH Accident Investigation Report modified the original claim of nine attempts to convert the float collar to nine attempts to establish circulation (pages 23 and 70). This acknowledged the possibility that the elevated pressure was required to unblock a port, or ports, in the casing shoe, not convert the collar. If this were the case, and if the two circulating ports in the float collar's Autofill tube were open, there'd have been little differential pressure across the collar itself. If a blocked shoe port then cleared with the casing pressurized to over 3100 psi, all sorts of things could have then happened.

The report doesn't rule out the possibility that the collar never converted.


CHUCK. Thanks for explanation. Another question please. There is reference to "bottoms up", which appears to be a flush out gas procedure. How does the "bottoms up marker" get in and where does it go?

Acorn - I didn't see the original bottoms up comment but if I understand the question: one method to determine BU is to dump a certain chemical (a carbide compound) into the mud when it's pumped down. The chencical reacts at depth and produces a gas spike the mud loggers can ID. Typically BU is expressed in time: i.e. 3 hours. In practice they actually measure how many pumps strokes it takes to get BU. Since they can radically change the stroke rate the BU time can vary accordingly. By the time they were cmtg the well the BU time was very well established. While BU time changes very slowly as the well is depened, it can change significantly when a new string of csg is run. That can change the hole volume greatly and thus significantly reduce the volume of mud needed to get BU. Maybe the BP engineers didn't make that correction. Don't have the details to know if that was a factor.


The original bottoms up comment was the question Acornus asked, and you answered.

I suspect the question arose from diagrams on pages 6 and 7 of the document Acornus linked upthread:


Can you take a look at it and give your assessment of what is being indicated by "Bottoms-up Marker" on the two diagrams? (The document is about 1.5 MB in size.)


ROCK / CHUCK. That is the diagram that showed the "bottoms up marker" I questioned.

The question arose because an oil man I know, said he was not sure that the method used for setting the casing hanger seal, was as I had posted months back. I referred to the seal being set with a running tool and pressure applied via the kill line. I got this from the following see page 29 http://www.energytrainingresources.com/data/default/content/Macondo.pdf

According to the BP report, the seal was set purely with the weight of the drill string, which is why they had the circa 3000 feet of drill pipe down the whole, to get the 100,000 pounds of weight to set it. The length of this drill string then set the height of the cement top plug in the hole. He implied; that would not have been the recommended method of setting a hanger seal for that make of well head equipment. Did it matter, who knows. I think there is going to be a lot of good engineering knowledge yet to come from this disaster. The GOM deserves to benefit from it.


I think you'll find that what you describe in your final paragraph (the 100,000-pound weight, etc.) was to be the method for setting the casing hanger lockdown sleeve. The well blew before that was ever done.

What Paul Parsons describes on p29 of your link is setting the casing hanger seal, and is pretty much in accord with the high level procedure, dated 15 April, here:


See page 7, step 11. (The lockdown sleeve is mentioned later in conjunction with the surface cement plug. See page 8, step 7.)


Chuck - I see the notation in the diagram and in reality I've never seen such a notation before. I was taking a guess with my answer to Acorn and I'm not sure that marker notation relates to bottom up circulation time. It seems to refer to a point in the well bore. Maybe some DW hand can shed some light on that terminology.

Thanks, Rockman.

After taking a closer look, I see what's going on with the so-called bottoms-up markers on the diagrams. The dot on page 7 (at the top of 13-5/8" liner) is showing where the fluid that was at the shoe (dot on page 6) ended up, given the limited circulation that was actually done.

Rather than a true bottoms up, only 342 bbls was circulated. I calculated the annulus volume some time ago and found that the volume (using caliper data from the Halliburton reports) between 18304' and the top of the 13-5/8" liner at 11153' was 346 bbls--so the match is pretty good.


Let us continue to forget...

"highlighting actions that might save time or money.":
"One example involves BP's use of a gooey chemical mixture in the well during a pivotal pressure test that preceded the blowout.
The report says that the mixture could have clogged a line involved in the test, masking the fact that hydrocarbons were flowing into the well.
The material that went into the mixture - more than 400 barrels of products called Form-A-Set and Form-A-Squeeze - was left over on the rig after the well drilling. The material was designed to plug leaks, such as cracks in rock formations.
Under environmental protection standards, if BP used the leftover material in the well, it could then dump the product directly into the gulf instead of transporting it to shore for disposal as hazardous waste, Leo Lindner, a drilling fluid specialist for contractor M-I SWACO, testified at a federal hearing in July."
"KENNER, LA. -- In the hours before the Deepwater Horizon drilling rig exploded, BP pumped into the well an extraordinarily large quantity of an unusual chemical mixture, a contractor on the rig testified Monday.
The injection of the dense, gray fluid was meant to flush drilling mud from the hole, according to the testimony before a government panel investigating the April 20 accident. But the more than 400 barrels used were roughly double the usual quantity, said Leo Lindner, a drilling fluid specialist for contractor MI-Swaco.
BP had hundreds of barrels of the two chemicals on hand and needed to dispose of the material, Lindner testified. By first flushing it into the well, the company could take advantage of an exemption in an environmental law that otherwise would have prohibited it from discharging the hazardous waste into the Gulf of Mexico, Lindner said.
The procedure mixed two substances. "It's not something we've ever done before," Lindner said.
A BP specialist said using the two substances together would be okay. Nonetheless, the night before the rig exploded, Lindner was busy conducting an improvised chemistry experiment to double-check. He mixed a gallon of one of the substances with a gallon of the other and observed their reaction.
When the well became a gusher on April 20, a fluid that fit the general description of the mixture rained down on the rig.
Stephen Bertone, chief engineer on the rig, said in testimony earlier in the day that part of the rig was covered in an inch or more of material that he said resembled "snot.""
Could this unusual procedure, this substitution of mixture, have caused fouling of the instrumentation ports?
Could earlier use of Form-A-Set and Form-A-Squeeze as a "Mud" or "Spacer" or "Flushing Fluid" or "Drilling Fluid" or as "Seawater"... have contaminated the cement?
"Section 10: Effect of Mud Contamination on Un-foamed Slurry Sonic Strength Development
The effect of drilling-fluid contamination on unfoamed slurry sonic strength development was measured according to API RB10B-2/ISO 10426-2 Clause 16.5,..."
Section 11: Stability of Foamed Cement with Mud or Spacer Contamination
The original plan included evaluating the effect of drilling fluid or spacer contamination on foamed cement stability by two methods:
1) Stirring 5, 10, and 15 percent volume of drilling fluid or spacer into the foamed cement slurry in a manner similar to the CSI testing contained in the BP report.
2) Coating the interior of the 250-mL graduated cylinder used for the foam stability test with mud or spacer, then adding the foamed cement and evaluating the effect."

Let us never speak of these things again.


FORM-A-SET Polymeric lost circulation material FORM-A-SET ACC Accelerator for FORM-A-SET pill FORM A-SET AK Polymeric LCM FORM-A-SET AKX Variant of FORM-A-SET AK pill for water shutoff FORM-A-SET RET Retarder for FORM-A-SET pill FORM-A-SET XL Crosslinker for FORM-A-SET pill FORM-A-SQUEEZE High-solids, high-fluid loss plug



I searched Google and found this reference to new drilling safety rules (took about 1 minute):


Workplace Safety rules (drilling rigs):


other commentary:



No mandatory relief wells drilled in parallel with the producing well...probably not deemed to be worth a couple of cents more per gallon at the pump I suppose...

Rockman, et al.: Do these “reports” have any validity?

Edmund Coyote


Conclusive evidence that BP capped the wrong well, and by grouting the faults, they are spreading the oil far and wide.


Posted on October 26, 2010 by concernedcitizensofflorida

Mother Nature’s SOS distress signals from a Haunting Well.

BK Lim
Monday, October 25, 2010


What is going on at West Sirius?


Posted on November 1, 2010 by concernedcitizensofflorida

A New Drilling Rig at the Macondo Site?

BK Lim
31 Oct 2010

Coyote - No chance they capped the wrong well. We covered this in some detail a while back. Every aspect of the process was covered by independent third parties. Everyone knew where they were and what well they were working on. But, having said that, could the well still be leaking some oil? Certainly. I've always had concerns about the integrity of the shallow csg and the various cmts in the shallow sections. But, having said that, there could be some natural seeps as well as residual secondary sea floor leaks caused by the blow out.

No idea why the West Sirius rig is out there. But wouldn't take the MSM much effort to come up with an answer. Any activity in the OCS has to be permitted thru the gov't. And all permits are public records. Instead of blind speculation it might serve the public better for the authors of the report to just go ask the feds what's going on.

Rockman, I checked rigzone and they still show the West Sirius waiting on location in 300+ foot of water. I don't know what that means or if rigzone's data is accurate and up to date.

I had alluded to the fact a couple of weeks ago that the activity in and around the Macondo area hasn't ramped down. Why? I don't know for certain, but whatever it is neither the government or BP is talking about it. Maybe they do have issues that they have not completely repaired.

wildman - I saw that. If RZ is correct maybe BP just moved the WS to shallower water for logistical reasons.

There is no way this well is killed. The BOP still sits on it and there are still numerous leaks. So much for the bottom kill.

Still jetting hydrate buildup on the BOP from the leaks on the well.


Pipe valve leaking on the well.


Possible cement squeeze leaked out around mud line at well.


Leaking at the mud line.


Leaking at the mud line.


Bruce Thompson,

Two months ago today you asked if I had any insight into why Transocean claimed that 2 bbls of foamed cement ended up in the production casing shoe track. Beyond the possibility of backflow to set the float collar flapper valves, I had nothing to offer.

On 29 Sep you posted a link to a 26 Sep Halliburton Preliminary Insights document, and sought comments from a specific, but unspecified, TOD poster regarding your interpretation of aspects of the charts on Slide 8 of that report. There was no response.


I have recently spent time with those charts, and they reveal a possible explanation for Transocean's claim--assuming they had access to Halliburton's 20 April post-job report, from which the charts were apparently taken.

Taking the tail cement to be the volume pumped after the nitrogen injection was stopped and before the spacer pumping started, I find the tail cement volume to be 4.6 bbls--whether measured against the volume axis or computed from time and rate (2.3 minutes at 2 bpm). With the shoe track volume at 6.9 bbls, the deficit of 2.3 bbls would presumably be made up by foamed cement intended for the annulus.

I make the lead cement volume to be 8.3 to 8.5 bbls. When compared to the volumes used in the 15 and 18 April OptiCem reports (5.26 bbls lead and 7.22 bbls tail), the volumes are reversed; that is, the lead cement volume is greater than the tail cement volume.

What I found most curious was that they pumped foaming agent (surfactant) during 24 of the 25.6 minutes cement was pumped. So that, unlike the OptiCem simulations where a total of 11.7 gallons of foaming agent was pumped--and only while the base slurry for the foamed cement was being pumped--they pumped over 22 gallons and included all the tail cement and most of the lead cement in the process.


Chuck the foaming agent can be added to the all slurries pumped and it should only have effects to the cement if and when nitrogen is added. So having the surfactant in a non foamed slurry is not a big deal it's not uncommon from what I have been told.

Thanks, wildbourgman.

I had found a reference to surfactant being used in weighted spacer that preceded and followed foamed cement (to create a stable interface if mixing with the foamed cement occurred), but found nothing like that for lead and tail cement.


Here's an article on a newly published scientific report about toxic PAH concentrations in a dispersed oil plume 1000 m deep near the wellhead.

By three weeks into the accident, total-PAH concentrations had spiked to about 190 parts per billion in the near-seafloor plume they were tracking — one that extended out at least 13 kilometers from the wellhead.

. . . PAHs that proved especially high in the plume — particularly the smaller, two-ringed molecules like napthalenes — tend to be broken down pretty rapidly by bacteria in the water. “Like on the order of days,” he says. And that seems to have occurred in the Gulf, he observes, as later tracking of formerly oil-rich subsea plumes “showed that the signals [of these PAHs] had really dissipated.”

These are not surprising findings. 190 ppb of PAH would probably do substantial damage to deep-sea animals near the wellhead. About naphthalenes, they are water-soluble and, along with the BTEX fractions, would have dissolved out of larger oil droplets on their way up as well as from the dispersed oil that stayed deep. It is good to hear that it biodegraded rapidly.


The underlying article by Diercks et al is behind a paywall at at Geophysical Research Letters. One way to keep up with the science of the spill is to Google >authored janet raloff. She has reported on all the journal articles that have appeared so far and her reportage is good.

For all those Macondo data hounds out there, there is some more stuff up on the Department of Energy site here (loaded 19th October) :


Of some interest is the pressure data recorded during the top kill attempts - looks like the net effect of the kill+junk shots was to lower the flowing wellhead pressure by about 1000 psi (oops), though a lot of this was down to the opening of the test rams. This spreadsheet also contains many details of the initial ROV intervention attempts on the BOP on the 22nd April.

Also, NatResDr made a late post on the last spill thread about the Purdue University video library resource :


There is some fascinating footage on there from the very early days of the ROV activities. Their initial arrival at the BOP on the 22nd April is covered, together with their attempts to activate the rams while the rig was burning overhead. There is a particularly poignant moment when the ROVs back off and the riser slowly bends over as the rig comes down. Awful to contemplate.

The subsequent survey of the fallen riser is also available. The first discovery of the venting riser-end is worth seeing; I was completely wrong in my earlier suspicion that the early flow rate appeared low. While clearly a suppressed rate compared to what we later saw, the volumes venting from day 1 appear very substantial indeed.

A long article in New York Times Magazine about the upcoming oil spill litigation from the point of view of a trial lawyer

[Judge]Barbier has set the first big trial in the case for February 2012, which is when he is expected to apportion liability among the defendants involved with the blowout. In October, Barbier made his selections for the 15-person plaintiffs’ steering committee.

Rockman, wildbourgman, ledgeman, anyone--

A Macondo well diagram in the BP DH Accident Investigation Report (p54) shows a 9-foot interval centered around 17689' that has an equivalent density of 14.1 ppg. It was believed to contain brine.

If, during the cement job, annular fluids at 17689' had a hydrostatic pressure as much as 75 psi less than these brine sands--and the underpressure was greater than 60 psi for more than 38 minutes--is it possible, given only this information, to project what might happen regarding flow?


Chuck, I think we would need more information. When did the 38 minute period take place? What was the rig activity at that time? is this before cement was in place?

One thing to remember about nitrogen foam cementing, it's considered to give you the best chance for a good cement job in the worst case senario hole situations.

If you have a well with a high gas flow potential. N2 cement is the answer.
If you have a well with possible loss circulation issues. N2 cement is your answer.
If you have a well with possible water flows, expecially shallow water flows. N2 cement is the answer.
If your having a bad day N2 foam cement is good for that too!

I think BP was using N2 cement to cover up the poor well design and the other hole problems they had. They thought N2 cement was a cure all that can fix anything and it's not.

I've been on wells where someone will ask for the pore pressure and the frac gradient for a given open hole section based in equivalent mud density. I'll tell them 14.5 pounds per gallon equivalent mud density. Then they ask which one is that, (pore pressure or frac gradient) and I'd tell them "both". So our pressure in which we will frac the well is the same or near pressure that the well will come in at. We can't raise the mud weight to hold the well back and we can't lower the mud weight so the well won't have mud losses. We can't circulate fast enough to clean the cuttings out the hole and we can't stop circulation to pull out of the hole, because we will swab the well in with all the cutting beds left in the annulus.
That's a mess and I hate working for operators that pull that BS, but when they finally finish the well, nitrogen foam cement is the best way to hold the well back and not break the formation down so you can get a good cement job in place. Many operators are too cheap to use N2 cement, where BP was too cheap to properly construct it's well. I think that's what BP was thinking. So the N2 cement should have held the brine formation back in theory. Although a flowing salt water sand can and will lower your mud and cement density allowing a well to not have the hydrostatic pressure that it needs for well control.

After cement jobs you must remember there is a critical time where the cement does not have enough hydrostatic pressure to hold the well back and it neither has enough strentgh to hold the well back. That's where cement job design, the chemicals they use and the well design play a critical role. Transition time is designed to be as short as possible, basically you want the cement to be either a liquid or a solid, not jello for very long.


Thank you for the reply. I'm not one of the foamed cement detractors, so no defense of it necessary on my account.

To provide the details behind my question, I've uploaded three images to my webspace that I hope will clarify things. I've called them data, graph, and calcs.

First, data, which is at: http://mysite.verizon.net/yenrav/data.jpg

This image comprises two plots I extracted from a 26 September Halliburton PowerPoint presentation, and put together so that their time axes align. I've taken pumped volumes and rates from these plots. The portion of interest is the period from 20:00 to about 21:00. In this time frame the spacer is pumped, then pumping stops for a fraction under 20 minutes, after which the cement is pumped. I take the end of foamed cement to occur a bit after 21:00.

Second, graph is here: http://mysite.verizon.net/yenrav/graph.gif

I calculated the hydrostatic pressure in the annulus at a depth of 17689' as the spacer and cement are pumped, subtracted the formation pressure (12970 psi) from it, and plotted the result. I treated everything as static, so there's a good chance that only the results at the beginning, end, and the 20 minutes the pumps were stopped are valid. Time 0 on graph is the same as 20:00 on data. (I need to go back and see why I have about 4 extra minutes in my plot.)

Finally, calcs is here: http://mysite.verizon.net/yenrav/calcs.gif

It's based on an Excel sheet I did to calculate fluid levels using caliper data. It may give some idea how I came up with graph.

A note: the amount of underbalance depends on what one assumes for pumped volumes and how one models the open hole and liners. Here's a comparison for the stopped-pump case:

1) -72.6 psi for caliper data with some diameter reduction, and with volumes from data
2) - 54.6 psi, as for 1), but with volumes from Halliburton OptiCem runs
3) -52 psi, using clean gauge hole and liners, with volumes from data
4) -36 psi, as for 3), but with volumes from Halliburton OptiCem runs

(You can see how the pumped volumes I assumed compare if you check out the grayed-out font in calcs, mid-screen, about a third of the way down.)



Are you asking if its possible to calculate the potential flow rate into the wellbore from a 9ft water bearing interval based on a delta-P at the sandface of 60 psi for a 38 minute period?

If so the answer is yes. Most of the required parameters can be estimated within reasonable ranges (eg water viscosity). However the key unknown is the permeability of the formation, and the range on this will be so wide that the calculated flow rate will also have a very wide range.

The only data I've seen across this interval is the LWD log presented in the BP Production Casing plan presentation 'BP-Production.Casing.TA.Options-Liner.Preferred.Long.Version'. Page 6 for example shows that the pressure obtained in this interval was by GeoTap which is a fairly coarse device run during the drilling process itself (and built into the drill string) rather than the better measurements made in the other sands by tools run on wireline after the drilling was completed. A washout is noted at this depth which can complicate pressure probe placement, and the sand also looks a lot more silty to me than those below. In lower permeability formations like this it is quite common to read higher pressures closer in value to the mud column pressure, as the formation becomes charged by the pressure in the wellbore which is not able to dissipate. This is known as 'supercharging'.

In summary there is a good chance that the pressure in this stringer is not as high as advertised, and even if it is, the poorer quality of the formation will limit its ability to flow. But if you are interested I will run a couple of models next week for you based on an assumed range of permeabilities.


You wrote: Are you asking if its possible to calculate the potential flow rate into the wellbore from a 9ft water bearing interval based on a delta-P at the sandface of 60 psi for a 38 minute period?.

Yes, exactly.

As you'll see from my reply to wildbourgman, some of that 38 minutes was not for a static condition, but there should be a valid 20-minute window where the differential ranges from 36 psi to 72 psi, depending on model used.


Where does the temperature at the bottom of this well come into the calculations? What happens with volumetric expansion of the fluids and the cements due to temperature? Can the cement crack or loose its bond with the casings etc; if there is a rapid change in temperature of fluids?


Perhaps you can do similar calculations to mine, but including temperature effects. We can then compare results.

(I used temperature only in estimating the volume of foamed cement.)


This is my story and I am sticking to it.

ROV Spots Crater on seafloor near wellhead


DD3 Pulls the BOP


BP lowers a cement drill pipe into the well about a thousand feet and starts pumping cement into it. It over flows the cement for about 2 hours off and on.


ROV Showing Moving Rig and BOP to a Safe Zone.