Deepwater Oil Spill - the BP CEO and Congress

There are many people who have questions for Tony Hayward, the CEO of BP. (For those behind the times, they changed their name from British Petroleum some 9 years ago) today was the turn of Congress. But before going to that testimony, the current status for things in the Gulf, as far as oil recovery from the Deepwater Horizon well oil spill is:

Optimization of the dual system, LMRP Cap and the Q4000 Direct Connect, will continue over the next few days.

For the first 12 hours on June 17 (midnight to noon), approximately 8,000 barrels of oil were collected and approximately 4,500 barrels of oil and 25.8 million cubic feet of natural gas were flared.

On June 16, a total of approximately 14,750 barrels of oil were collected and approximately 3,850 barrels of oil and 40 million cubic feet of natural gas were flared.

That means that oil recovery from the well, which is the usm of that collected and that flared is now reaching a level of 25,000 bd. The capacity of the current system is around 28,000 bd, beyond which they will need to wait for the change in vessels, risers and for the new cap now planned for the end of the month. This will mean that the Q4000 will be disconnected, and control of the valves at the BOP also transferred.

Although it is difficult to tell from the ROV feeds, it appeared earlier that the venting ports at the top of the LMRP cap might have been closed, so that BP are now much closer to capturing all the oil and gas leaking from the well. The feed from the Skandi ROV1 for example seems to have more gas in it than previously. Similarly at the time this was written the vertical feed into the DP at the top of the cap can be seen, from the Enterprise ROV2 feed.

ROV view of the LMRP cap June 17th 8:30 pm

There were five questions that Mr. Hayward was warned that he would be asked about, before he appeared before the House Energy and Commerce Subcommittee on Oversight and Investigations. However while the committee obviously focused on the events at the particular well (Mississippi Canyon 252 – the Macondo well ) which had the disastrous failure, they seemed to find it difficult to accept that, prior to the disaster, and with BP drilling hundreds of wells a year, the CEO’s only knowledge of the well had been that he had heard that it was a successful discovery. Congressman Waxman, for example, dwelt on the ignorance of BP top management about the well.

You are the CEO, so we considered the possibility that you may have delegated the oversight responsibility to someone else. We reviewed the e-mails and briefing documents received by Andy Inglis, the chief executive for exploration and production, and Doug Suttles, the chief operating officer for exploration and production and the person now leading BP’s response to the spill.

According to BP, these are the senior officials who were responsible for the Macondo well. But they too were apparently paying no attention. We could find no evidence that either of them received any e-mails or briefings about the Deepwater Horizon rig or the drilling activities at the well.

It was the Subcommittee Chair, Congressman Stupak who outlined the areas of concern that are being investigated:

We have learned that time and again BP officials had warning signs that this was – as one employee put it – “a nightmare well”. They made choices that set safety aside in exchange for cost cutting and time saving decisions. For example
 They disregarded questionable results from pressure tests after cementing in the well.
 BP selected the riskier of two options for their well design. They could have hung a liner from the lower end of the casing already in the well and install a “tieback” on top of the liner, which would have provided additional barriers to a release of hydrocarbons. Instead they lowered a full string of new casing, which took less time and cost less, but did not provide the same protection against escaping hydrocarbons.
 BP was warned by their cement contractor Halliburton that the well could have a “SEVERE gas flow problem” if BP lowered the final string of casing with only six centralizers instead of the 21 Halliburton recommended. BP rejected Halliburton’s advice to use additional centralizers and in an e-mail on April 16, a BP official involved in the decision explained: “it will take 10 hours to install them. ... I do not like this.”
 BP chose not to fully circulate the mud in the well from the bottom to the top, which was an industry recommended best practice that would have allowed them to test for gas in the mud.
 BP chose not to use a casing hanger lockdown sleeve, which would have provided extra protection against a blowout from below.

In his written response, Mr. Heyward first addressed the processes that BP are going through to address the current problems (cutting off the oil flow to the Gulf, cleaning it up and compensating those who have been damaged and economically impacted). He pointed to seven areas in which BP have focused their inquiries into the incident.

The investigation is focused on the following seven mechanisms:
1. The cement that seals the reservoir from the well;
2. The casing system, which seals the wellbore;
3. The pressure tests to confirm the well is sealed;
4. The execution of procedures to detect and control hydrocarbons in the well, including the use of the blowout preventer (BOP) and the maintenance of that BOP;
5. The BOP Emergency Disconnect System, which can be activated by pushing a button at multiple locations on the rig;
6. The automatic closure of the BOP after its connection is lost with the rig; and; 7. Features in the BOP to allow ROVs to close the BOP and thereby seal the well at the seabed after a blowout.

The video of the testimony is available from the Subcommittee website.

In his opening questions Congressman Waxman noted that the BP decision to use a single production casing was rebutted by the heads of the other large Oil Companies who had earlier testified before Congress. The reason being that it provided “”an unrestricted pathway for gas to travel up the well through the annular space that surrounded the casing, and of course, it blew out the seal.” Mr. Heyward pointed out that this was the original design for the well, and that it had been approved by the MMS. There was then a debate as to whether a long string, or a 7-inch liner would be most appropriate. The decision to use the long string was based in part on the long term integrity of the well.

Congressman Waxman pointed to a BP memo which included that the use of the long casing consequence would include that “it is unlikely to be a successful cement job, and that it would provide an open annulus to the wellhead.” In contrast the use of the 7-inch liner would largely obviate these risks.

When Mr Heyward tried to answer that the Congressman cut him off and accused him of stonewalling, refusing to accept that the decision was made based on an engineering judgment – which was the point that the CEO was trying to make. Mr Hayward tried to make the point that the long casing was not an unusual design in the Gulf of Mexico wells, to which the Congressman responded with Halliburton testimony that it was only used in 2 – 10% of the wells, and when My Hayward said that he would not personally judge which decision was correct, which the Congressman found unacceptable.

It was that sort of a day for the BP CEO and the full video of the investigative hearing can be downloaded, as I noted.

As the above exchange illustrated, there was not a lot of useful new information that came from the afternoon (though I must admit I had other things to do and did not watch most of it).

Deepwater Oil Spill - the Congressional Illustrations

One of the considerable problems that arise in writing about the Deepwater Horizon oil spill in the Gulf of Mexico comes in determining what information that is given is actually accurate. I’m going to assume however, that when a company provides information to Congress that it is, to the best of their knowledge, correct. Since the illustrations that accompanied the testimony of BP officials is now available, albeit in draft form, I am going to summarize some of this so that, as discussion and later posts require, it can serve as a useful point to find reference material. This information was presented the Energy and Commerce Committee of the House, on May 24th. (Note that the illustrations have been condensed to fit on the page, clicking on the image should lead to a larger view on a separate page).

UPDATE: 9:00 pm Monday In regard to the metal cutting post just before this one, they have lowered the big shearing cutter down to the riser, and cut off the power cables, so I suspect that the first shear may be sooner rather than later, END UPDATE

There are several points that I want to highlight, and so I will be taking selected parts of the BP slides to record separate pieces of information. The first of these is where the actual pay zones of oil and gas are, relative to the total depth of the well, and what the pressures are within them. Notice that the pressure at the bottom of the well is about a thousand psi lower than I had been using in earlier posts.


There are several different parts of the overall structure for which more information is available in these slides (and my many thanks to several folk that have pointed me to their existence).

Consider first the Blow-Out Preventer, on which I have focused recently. The exact nature of the different rams is not the same as that illustrated by the paper from which I took the illustration.


The various components of the BOP, from the top are:

UAP – Upper Annular Preventer, used in normal drilling operations for well shut-in, rated at 10,000 psi
LAP – Lower Annular Preventer - down rated to lower wellbore retaining pressure to 5,000 psi.
BSR – Blind Shear Rams – cuts through the pipe and seals the well. 2 rams, one on either side of the drill pipe (DP).
CSR – Casing Shear Rams – non sealing, cut drill pipe and casing, but not designed to seal the well.

The three variable bore rams (VBO) would normally be the following with the functions designated:
UPR – Upper Pipe Rams – Ram packers can close on a range of drill pipe, from 3.5” OD to 6 5/8” OD and seal at 15,000 psi well bore pressure.
MPR – Middle Pipe Rams - Ram packers can close on a range of drill pipe, from 3.5” OD to 6 5/8” OD and seal at 15,000 psi well bore pressure., can also be used to hand-off drill pipe to a maximum weight of 600,000 lb.
LPR – Lower Pipe Rams – A Test Ram that can hold up to 15,000 psi.

The lowest ram did not function, I believe, and there was evidence of hydraulic leakage which has raised questions as to whether, or which, of the other rams functioned. However, as a part of the protocol for the positive pressure test, the drill pipe is lifted out of the BOP, and the BSR is closed to seal the well, while fluid is pumped into the well through the kill line, to raise the pressure and ensure that the cement job had held pressure. That test was successfully completed.


Following the positive pressure test the drill pipe is lowered back into the hole, note that it is in three sizes, as it goes down the well, with the upper segment at a diameter of 6 5/8” , and the lowest at a diameter of 3.5” bextending down to 8,367 ft below the rig.


To separate the seawater that is then going to be pumped into the riser a special, heavy mud known as the Lost Circulation Material (LCM) which has a weight of 16 pounds per gallon (ppg) is injected into the well, through the DP, and it circulates from the bottom of the DP back up to the BOP. The choke and kill lines had been filled with seawater, and the kill line pressure gage was still reading 1200 psi. (This takes the time to 16:28 on the 20th April. The green color is 14 ppg mud, the pink the 454 barrels of 16 ppg LCM, and the blue is seawater at 8.6 ppg.


The sea water is pumped into the well and circulated behind the spacing LCM, material. Once it has filled the drill pipe, and started to rise back up the production casing, the pressure rating of the water in the DP is at 2325 psi, and that in the kill line is 1200 psi. The annular seal is closed around the BP, and the pump is switched off. The pressure in the DP (on the rig floor I imagine) is reduced to 1200 psi, to equate with that of the kill line. Once the two are at the same pressure the kill valve at the BOP is opened, but this is where, at around 5 pm the first signs of a problem appear. The fluid in the well, for the first time, exerts less pressure on the fluid in the rock, than the value of that pressure.


The annular that is leaking is, presumably, the annular seal at the top of the BOP. The term “U-tube” I believe refers to the fact that there is not a pressure balance at the point it is measured. At this point there are two separate scenarios as to how fluid starts to migrate into the well, as the pressure in the DP is bled back to zero. It is now 17:52. Note that the oil/gas flow is shown as an orange arrow and in either case has a path to the bottom of the DP.


Pressure in the well now starts to rise, fluid is flowing from the kill line (about 3 – 15 bbls, the kill line was closed. Pressure in the DP was monitored and held steady at 1,400 psi, This was the negative pressure test, at 19:55 the decision to continue pumping seawater was implemented, at 20:58 it was noted that the flow out was greater than the flow in. The flow meter indicates that the well is flowing. Pressure in the DP continues to build, even after the pumps are shut down.


The first indications of this flow was 51 minutes before the explosion occurred. Seawater displacement restarted, at 21:14 and at 21:56 the Emergency Disconnect System (EDS) was activated, which should have led the shear rams to activate, and released the riser from the well. It did not work. The gage results leading up to the explosion were provided.


The activation time for the EDS should be 46 seconds. In this time, after the EDS button is pushed, the blind shear rams close, cutting the drill pipe and sealing the well.
The choke and kill line valves are closed and the lines unlatched
The LMRP is unlatched and disconnects
The sequence is complete and the rig can move away from the well.

There is no evidence that the EDS fully activated. Even if hydraulic power to the BOP had been lost there was a second procedure, the AMF, that should have sensed the loss in power, communications and hydraulics and closed the blind shear rams. But it required all three to have been lost to activate. It should take 37 seconds. There is no evidence that it fully activated.

The subsequent use of ultrasonics and gamma ray examination suggests that the blind shear and VBRs may have functioned, and could have reached the locked (closed?) position.

The testimony also showed a simplified version of how the shoe at the bottom of the casing should act to stop re-entry of fluids into the bottom of the production casing. The flappers stay open as first mud, and then cement is pumped down the well. Once the plug reaches the well, and all the cement has been ejected, then the flappers swing back horizontal, sealing the well. (The testimony pictures has the flapper in the wrong place in the middle figure so I deleted it from this copy).

Congressional Testimony and the Deepwater Horizon Gulf oil spill

Leading officers of BP, Transocean, Halliburton and Cameron appeared before the Subcommittee on Oversight and Investigations, a Sub-committee of the Committee on Energy and Commerce today. There are a number of documents available at the Committee Site, including the opening statements of Chairman of the Committee Waxman, and Congressman Stupak, Subcommittee chair. I am largely going to review the documented information on the Sub-committee web site, since it included virtually all of the information that was also gone over in the subsequent questioning of the witnesses. I am also going to use more extensive quotes than usual, since there was significant information given at the hearing that is useful to know.

In his opening remarks Congressman Waxman focused on four issues. The first was that while the cementing operation of the well may have passed the first positive pressure test, it may not have passed the following negative pressure test. The second related to the pressure monitors and what they told the people on the rig. He then noted that the blowout preventer that sat on the top of the well at the sea bed had, according to Cameron who made it, a leak in a crucial hydraulic system and a defectively configured ram. And the fourth area being examined is the response of the companies to the spill of oil.

To illustrate his concerns he used a submission from BP called “What we Know.”

The first bullet says: “Before, during or after the cement job, an undetected influx of 2hydrocarbons entered the wellbore.” What this means is that there was a breach somewhere in well integrity that allowed methane gas and possibly other hydrocarbons to enter the well.

The second bullet says: “The 9 7/8” casing was tested; the 9 7/8 “casing hanger packoff was set and tested; and the entire system was tested.” BP explained to us that this refers to a positive pressure test in the well. What this means is that fluids were injected in the well to increase pressure and to monitor whether the well would retain its integrity. The well passed this test.

Rigs like the Deepwater Horizon keep a daily drilling report. Transocean has given us the report for April 20, the day of the explosion. It is an incomplete log because it ends at 3:00 p.m., about seven hours before the explosion. But it confirms that three positive pressure tests were conducted in the morning to early afternoon.

The next bullet says: “After 16.5 hours waiting on cement, a test was performed on the wellbore below the Blowout Preventer.” BP explained to us what this means. Halliburton completed cementing the well at 12:35 a.m. on April 20 and after giving the cement time to set, a negative pressure test was conducted around 5:00 p.m. This is an important test. During a negative pressure test, the fluid pressure inside the well is reduced and the well is observed to see whether any gas leaks into the well through the cement or casing.

According to James Dupree, the BP Senior Vice President for the Gulf of Mexico, the well did not pass this test. Mr. Dupree told Committee staff on Monday that the test result was “not satisfactory” and “inconclusive.” Significant pressure discrepancies were recorded.

As a result, another negative pressure test was conducted. This is described in the fourth bullet: “During this test, 1,400 psi was observed on the drill pipe while 0 psi was observed on the kill and the choke lines.”

According to Mr. Dupree, this is also an unsatisfactory test result. The kill and choke lines run from the drill rig 5,000 feet to the blowout preventer at the sea floor. The drill pipe runs from the drill rig through the blowout preventer deep into the well. In the test, the pressures measured at any point from the drill rig to the blowout preventer should be the same in all three lines. But what the test showed was that pressures in the drill pipe were significantly higher. Mr. Dupree explained that the results could signal that an influx of gas was causing pressure to mount inside the wellbore.

Another document provided by BP to the Committee is labeled “What Could Have Happened.” It was prepared by BP on April 26, ten days before the first document. According to BP, their understanding of the cause of the spill has evolved considerably since April 26, so this document should not be considered definitive. But it also describes the two negative pressure tests and the pressure discrepancies that were recorded.

What happened next is murky. Mr. Dupree told the Committee staff that he believed the well blew moments after the second pressure test. But lawyers for BP contacted the Committee yesterday and provided a different account. According to BP’s counsel, further investigation has revealed that additional pressure tests were taken, and at 8:00 p.m., company officials determined that the additional results justified ending the test and proceeding with well operations.

Congressman Stupak began with a list of recent incidents that BP had been involved in, including problems on the North Slope and in Texas City. He focused on problems with the BOP, specifically

Our investigation is at its early stages, but already we have uncovered at least four significant problems with the blowout preventer used on the Deepwater Horizon drill rig.

First, the blowout preventer apparently had a significant leak in a key hydraulic system. This leak was found in the hydraulic system that provides emergency power to the shear rams, which are the devices that are supposed to cut the drill pipe and seal the well.

I would like to put on the screen a document that the Committee received from BP. This document states: “leaks have been discovered in the BOP hydraulics system.”

The blowout preventer was manufactured by Cameron. We asked a senior official at Cameron what he knew about these leaks. He told us when the remote operating vehicles (ROVs) tried to operate the shear rams, they noticed a loss of pressure. They investigated this by injecting dye into the hydraulic fluid, which showed a large leak coming from a loose fitting, which was backed off several turns.

The Cameron official told us that he did not believe the leak was caused by the blowout because every other fitting in the system was tight.

We also asked about the significance of the leak. The Cameron official said it was one of several possible failure modes. If the leak deprived the shear rams of sufficient power, they might not succeed in cutting through the drill pipe and sealing the well.

Second, we learned that the blowout preventer had been modified in unexpected ways. One of these modifications was potentially significant. The blowout preventer has an underwater control panel. BP spent a day trying to use this control panel to activate a variable bore ram on the blowout preventer that is designed to seal tight around any pipe in the well. When they investigated why their attempts failed to activate the bore ram, they learned that the device had been modified. A useless test ram – not the variable bore ram – had been connected to the socket that was supposed to activate the variable bore ram. An entire day’s worth of precious time had been spent engaging rams that closed the wrong way.

BP told us the modifications on the BOP were extensive. After the accident, they asked Transocean for drawings of the blowout preventer. Because of the modifications, the drawings they received didn’t match the structure on the ocean floor. BP said they wasted many hours figuring this out.

Third, we learned that the blowout preventer is not powerful enough to cut through joints in the drill pipe. We found a Transocean document that I would like to put on the screen. It says: most blind shear rams are “designed to shear effectively only on the body of the drillpipe. Procedures for the use of BSR’s must therefore ensure that there is no tool joint opposite the ram prior to shearing.”

This seemed astounding to us because the threaded joints between the sections of drillpipe make up about 10% of the length of the pipe. If the shear rams cannot cut through the joints, that would mean that this so-called failsafe device would succeed in cutting the drillpipe only 90% of the time.

We asked the Cameron official about the cutting capacity of the blowout preventer on the Deepwater Horizon. He confirmed that it is not powerful enough to cut through the joints in the drillpipe. And he told us this was another possible explanation for the failure of the blowout preventer to seal the well.

And fourth, we learned that the emergency controls on the blowout preventer may have failed. The blowout preventer has two emergency controls. One is called the emergency disconnect system or EDS. BP officials told us that that the EDS was activated on the drill rig before the rig was evacuated. But the Cameron official said they doubted the signals ever reached the blowout preventer on the seabed. Cameron officials believed the explosion on the rig destroyed the communications link to the blowout preventer before the emergency sequence could be completed.

In other words, the emergency controls may have failed because the explosion that caused the emergency also disabled communications to the blowout preventer.

Still, the blowout preventer also has a “deadman switch” which is supposed to activate the blowout preventer when all else fails. But according to Cameron, there were multiple scenarios that could have caused the deadman switch not to activate. One is human oversight: the deadman switch may not have been enabled on the control panel prior to the BOP being installed on the ocean floor. One is lack of maintenance: the deadman switch won’t work if the batteries are dead. The deadman switch is connected to two separate control pods on the blowout preventer. Both rely on battery power to operate. When one of the control pods was removed and inspected after the spill began, the battery was found to be dead. The battery in the other pod has not been inspected yet.

And one appears to be a design problem. The deadman switch activates only when three separate lines that connect the rig to the blowout preventer are all severed: the communication, power, and hydraulic lines. Cameron believes the power and communication lines were severed in the explosion, but it is possible the hydraulic lines remained intact, which would have stopped the deadman switch from activating.

These are not the only failure scenarios that could impair the function of the blowout preventer. The Cameron official we met with described many other potential problems that could have prevented the blowout preventer from functioning properly. Steel casing or casing hanger could have been ejected from the well and blocked the operation of the rams. The drill pipe could have been severed successfully, but then dropped from the rig, breaking the seal. Or operators on the rig could have tried to activate the shear rams by pushing the shear ram control button. This would have initiated an attempt to close the rams, but it would not have been successful. The shear rams do not have enough power to cut drill pipe unless they are activated through the emergency switch or the deadman switch.

The BP document on what we know notes that BP are focusing on

Cementing – design and execution
Casing - design and installation
Casing Hanger – design and installation
BOP-- configuration, maintenance and operation;
Well Control Practices

Halliburton provided the well log for the last two hours of the rig operation



The Daily Drilling Report ends before the fire.

There is a procedure given for the running of the negative pressure test RIH means Run In Hole, POOH means Pull Out Of Hole,
DP is Drill Pipe, DS is Drill String (I believe).

1. Test casing per APD to 250 / 2500 psi
2. RIH to 8367'
3. Displace to seawater from there to above the wellhead
4. With seawater in the kill close annular and do a negative test -2350 psi differential
5. Open annular and continue displacement
6. Set a 300' balanced cement plug w / 5 bbls in DP
7. POOH -100-200' above top of cement and drop neft ball / circulate DS volume
8. Spot corrosion inhibitor in the open hole
9. POOH to just below the wellhead or above with the 3-1/2" stinger (if desired wash with the 3-1/2" / do not rotate / a separate run will not be made to wash as the displacement will clean up the wellhead)
10. POOH and make LIT / LDS runs
11.Test casing to 1000 psi with seawater (non MMS test / BP DWOP) - surface plug
a. Confirm bbls to pressure up on original casing test vs bbls to test surface plug (should be less due to volume differences and fluid compressibility -seawater vs sobm)
b. Plot on chart / send to Houston for confirmation

The Testimony of the President of BP America (Lamar McKay) included spill remediation activities but specifically talked about their ongoing program to seal the well, including continued efforts to activate the BOP; using a containment and riser system to collect the oil still leaking; drilling two relief wells; and looking at a “top kill” where the well will be re-entered at the top and sealed around the area of the BOP. Their analysis of the failure of the well is focused on the failure of the BOP.

Steve Newman, CEO of Transocean testified as to the different subcontractors that had responsibility for the different phases of the operation, from mud monitoring through casing insertion and cementing. He dealt with the actual failure thus:

the one thing we know with certainty is that on the evening of April 20, there was a sudden, catastrophic failure of the cement, the casing, or both. Therein lies the root cause of this occurrence; without a disastrous failure of one of those elements, the explosion could not have occurred. It is also clear that the drill crew had very little (if any) time to react. The explosions were almost instantaneous.

What caused that catastrophic, sudden and violent failure? Was the well properly designed? Was the well properly cemented? Were there problems with the well casing? Were all appropriate tests run on the cement and casings? These are some of the critical questions that need to be answered in the coming weeks and months.

Over the past several days, some have suggested that the blowout preventers (or BOPs) used on this project were the cause of the accident. That simply makes no sense. A BOP is a large piece of equipment positioned on top of a wellhead to provide pressure control. As explained in more detail in the attachment to my testimony, BOPs are designed to quickly shut off the flow of oil or natural gas by squeezing, crushing or shearing the pipe in the event of a “kick” or “blowout” – a sudden, unexpected release of pressure from within the well that can occur during drilling.

The attention now being given to the BOPs in this case is somewhat ironic because at the time of the explosion, the drilling process was complete. The well had been sealed with casing and cement, and within a few days, the BOPs would have been removed. At this point, the well barriers – the cementing and the casing – were responsible for controlling any pressure from the reservoir.

However he did note that while the BOP failure was not the root cause of the incident, the inability of the BOP to properly function needs investigation.

With the failures of both cementing and the BOP being thus headlined, it was appropriate that testimony also came from the companies involved. Thus Tim Probert, President of Global Business Lines for Halliburton, testified about the cementing. Halliburton’s jobs included:

With respect to the Mississippi Canyon 252 well, Halliburton was contracted by the well owner to perform a variety of services on the rig. These included cementing, mud logging, directional drilling, and measurement‐while‐drilling services. In addition, Halliburton provided selected real‐time drilling and rig data acquisition and transmission services to key personnel both on board the Deepwater Horizon and at various onshore locations.

He showed a schematic of the well showing the intervals that were cemented, and the stages of casing down the well.



It was interesting to note that he stressed that the well was not fully cemented over its full length, but

It should be noted that cement is used at specific designated spots and is not designed to be a complete barrier through the entire wellbore.

He noted some of the factors that can influence the cement job:

There are many external factors that impact the design and execution of a cement job. These include the variability in the hole geometry, relative location of hydrocarbon zones, hydrocarbon content and the prior condition of the wellbore and associated fluids as determined by the drilling fluid provider. Casing strings are typically run with devices to centralize the casing concentrically in the wellbore and prevent incomplete displacement of drilling fluid, or “channeling”. . . . . . . . Confirming cement integrity after placement would require the well owner to direct the wireline provider to obtain cement evaluation logs.

(It should be noted that later response to questions elicited the response that running these integrity logs was not always carried out, and was not done on the Mississippi Canyon well).

Following the placement of 51 barrels of cement slurry, the casing seal assembly was set in the casing hanger. In accordance with accepted industry practice, as required by MMS and as directed by the well owner, a positive pressure test was then conducted to demonstrate the integrity of the production casing string. The results of the positive test were reviewed by the well owner and the decision was made to proceed with the well program.

The next step included the performance of a “negative” pressure test, which tests the integrity of the casing seal assembly and is conducted by the drilling contractor at the direction of the well owner and in accordance with MMS requirements. We understand that Halliburton was instructed to record drill pipe pressure during this test until Halliburton’s cementing personnel were advised by the drilling contractor that the negative pressure test had been completed, and were placed on standby.

The final witness before the panel was Jack Moore the President and CEO of Cameron, who made the BOP. He basically said that he did not know enough facts about what went wrong at this time.

There were many questions from the Committee, but the main points that they went after were those which I reviewed as part of Congressmen Waxman and Stupak. I believe that the testimony can be viewed using access from the bottom of the Web Page.

There will be more hearings, and more information will come to light, but this can, perhaps, act as a basis on which to build an understanding as the additional information comes to light.