Macondo History Before the Blowout By: CEOoftheSOFA July 4, 2010 This history of the Macondo well blowout has been assembled using information from the Oil & Gas Journal and the Houston Chronicle, two of the more reliable sources of information on the oil and gas industry. The information released to the public on the cause of the blowout has been insufficient. BP is unwilling to release information due to the liability issues. The federal government has much information that it is not releasing. I have assembled as much reliable information as I could and tried to make a reasonable guess as to the cause of the blowout. My opinion on the cause differs from the views of the popular press. History of the Macondo well The Macondo well is an exploratory well, in search of a new oil field at a water depth of 4992 ft. The well was estimated to require 51 days to drill at a cost of $96 million. The well was spudded on October 7, 2009 by the Transocean Marianas. The drilling rig was damaged in Hurricane Ida on Nov. 8-9 and was towed to a shipyard on November 26 for repairs. The Transocean Horizon rig resumed drilling when they landed the BOP stack on February 8, 2010. The well experienced four well control events. A well control event is when formation fluids (oil, gas, water) enter the wellbore, also known as a “kick”. These events occurred on Feb. 17-23, March 2-5, March 8-14, and April 4-7. The primary method of detecting a kick is to measure increases of drilling mud volume in the mud tanks. Typically, when this is observed, the pipe rams on the blow-out preventer are closed. The pipe rams seal around the drill pipe. The mud flow exiting the well is directed through a choke valve which is partially closed to increase the surface pressure. This increases the bottom hole pressure and prevents further influx of formation fluids into the wellbore. The formation fluids are then circulated out of the well while increasing the mud weight by adding barite to the drilling mud. When the mud weight is increased, it is no longer necessary to hold back pressure with the choke valve. At this point, drilling can resume. A synthetic, oil based drilling mud was used. At the completion of the drilling, the mud weight was 14 pounds per gallon (ppg). This equates to a formation pressure of 13,366 pounds per square inch (psi). The well was drilled to a total depth of 18,360 ft. A tapered string of production casing consisting of 7” and 9-5/8” casing was run from the total depth of the well to the surface. The casing was cemented by Halliburton. The purpose of the cement is to seal out formation fluids. When the well is ready to be put on production, holes will be perforated into the casing to allow oil and gas to enter the wellbore. The following table is a summary of the casing program:

Outside Depth Depth Cement Casing Casing Casing Yield Diameter Bottom Top top Weight Type Strength (burst)

Inches feet feet feet ppf psi 36 5312 0 N/A * * Casing is jetted in mud 28 6217 0 5067 22 7937 0 5067 224 X-80 18 8969 7900 8040 117 P-110 16 11585 0 10500 97 P-110 30,000

13-5/8 13145 11585 12100 88.2 Q-125 31,000 11-7/8 15103 13145 13760 71.8 Q-125 25,000 9-5/8 17168 15103 15934 62.8 Q-125 22,000

7 - 9-7/8 tapered 18303 0 17300 7" - 32 Q-125

9-7/8" -

62.8 Q-125 TD 18360

Rupture disks at 9560, 8304, and 6047

This represents a very aggressive casing program and is the primary reason the well drilling was behind schedule. The casing program was increased in response to the four well control events. The well is encased in steel down to a depth of 17,168 ft. The well is currently flowing behind the 7” production casing, so the three lower liners and the 16” casing are exposed to the oil flow. The 9-5/8” liner is the weak point with a yield strength of 22,000 psi which is 9,000 psi greater than the shut-in reservoir pressure. The well is therefore capable of withstanding the shut-in reservoir pressure if the well were shut in. After the cement job of the production casing, the next task was to temporarily plug the well by setting several cement plugs in the well. This is done by running drillpipe and tubing to several different depths and spotting cement plugs. Prior to doing this, it was necessary to replace the oil based drilling mud with sea water, since the drilling mud would contaminate the cement. Seawater weighs about 5 ppg less than the drilling mud, and would not exert sufficient hydrostatic pressure on the oil formation to prevent fluid flow into the wellbore. If the cement were holding properly, it would not matter if the hydrostatic pressure were high enough since the cement should have sealed the well. There was a difference of opinion on the rig concerning the results of the pressure tests that were run to evaluate the cement job. A meeting was held at 1:00 PM on April 20, between the BP head drilling engineer and the lead Transocean engineer. It is not known what they were arguing about, but it is likely they were arguing over the results of the pressure tests. Apparently, the Transocean engineers thought the results showed that formation fluids were entering the wellbore due to a failed cement job, but they were overruled by the head BP drilling engineer who made the decision to continue. (One of the Transocean people was heard saying “well at least we have the BOP’s”, after leaving the meeting.) At 7:50 PM a pressure test was performed after which BP incorrectly concluded that formation fluids were not entering the wellbore. However, right after that, personnel on the rig floor reported that the fluid rate exiting the well was greater than the fluid rate entering the well. At 9:00, gas began coming out of the riser. Despite this, the pumping of seawater did not stop until 9:31. The gas ignited at 9:49 and the entire rig was engulfed in flames. The blind shear rams on the blowout preventers were not closed until after this. These rams should shear the drill pipe and completely seal the well. 8,300 feet of drill pipe was then dropped into the 18,360 ft well. The blind shear rams only partially sealed the well. Because of the bad cement job, the well is

now flowing outside the 7 inch production casing. The well pressure is now being exerted on the three lower liner strings and the 16” casing which was set at a depth of 11,585 ft. Shortcuts BP took several shortcuts which may have compromised the integrity of the well.

1. A cement bond log was not run. The usual practice is to run a cement bond log to evaluate the effectiveness of the cement job. Schlumberger was on site to run the cement bond log, but BP decided not to run one, presumably to save the 12 hours it would take to run it. Pressure tests were run instead, but were inconclusive.

2. A lockdown sleeve was not used in the wellhead seal assembly for the production casing. This could cause the seal to unseat if there is upward movement of the casing, allowing fluid to enter the riser. Upward movement is normal as the casing expands when the temperature increases during the production of formation fluids.

3. Only 261 bbl of mud was circulated prior to the cement job, which is far short of the usual 1.5 times the hole volume that is recommended by the API. The purpose of this is to clean the hole of debris and formation fluids, to improve the integrity of the cement job. This also saved 12 hours of time.

4. BP has been criticized for running production casing instead of a liner. The liner would have been sealed inside the next higher liner which would have given an additional seal to prevent migration of formation fluids. The liner could have then been tied back to the surface. As it is now, the well is producing oil and gas from behind the production casing.

5. There was testimony that BP only used 6 centralizers instead of the recommended 21 on the production casing. Centralizers cost about $100 each and take about 2 minutes to install. Centralizers keep the casing in the middle of the hole to improve the cement bond.

The popular press has focused on these shortcuts as the ultimate cause of the blowout, and that these shortcuts were taken just to save money. These 5 items together only saved one or two days of rig time, or about a million dollars. The press has charged that BP ordered these short cuts because the well was behind schedule and over budget. I don’t buy it. It is not uncommon for exploratory wells to be over budget. They should have been happy that they had a discovery. I don’t think the fault should be focused only on the failed blowout preventer or the bad cement job. Bad cement jobs happen occasionally without resulting in burned rigs. Blowout preventers are supposed to be activated before the rig is engulfed in flames. I think the key cause of the blowout is simple human error (SHE) on the part of the BP head drilling engineer, who did not notice that the well was kicking. The well was likely kicking all afternoon and evening, and no one noticed until gas was coming out of the riser. It is inexcusable to allow this to go unnoticed for such a long time. All drilling engineers must be certified in well control. An annual class must be taken, with a written test and a test on a rig simulator. The primary thrust of the class is to determine when a well is kicking.

For this reason, I believe the primary cause of the blowout is simple human error on the part of BP. If the BP employees noticed that the well was kicking, the shortcuts would never have come into play. An undetected kick could have caused a blowout during any of the four well control events, where the failed cement job would not have been a factor. For this reason, I believe BP will be found to be almost completely at fault. Transocean had the right to stop the operation, and for this reason they may bear a small amount of responsibility. The only way I can see Halliburton taking a small part of the blame is if it is shown that the cement was improperly mixed or displaced. I don’t fault the Transocean blowout preventers because the rig was already on fire when they were activated. Blowout preventers are supposed to be activated before the rig is on fire. It is possible that the rig may have moved during the explosion and may have put the riser at an angle and prevented the proper closing of the BOP. Subsequent investigations will reveal if this was the case. The above indicates how easy it is for a blowout to occur. I’m surprised it doesn’t happen more often. Since it is so easy for this to happen, it is inexcusable that BP should have been so completely unprepared for the aftermath. BP should have had the containment system built and tested ahead of time. (Shell had one on standby) And there should have been much more surface cleaning assets on standby, such as booms and skimmers. BP was so unprepared, that I believe they should have their drilling bond revoked in the Gulf of Mexico and they should be made to pay for each individual’s loss due to the spill, even if it causes BP to go bankrupt. Politicians that are paid off by the petroleum industry have indicated that this liability will prevent smaller companies from drilling in deep water. That’s too bad. I also believe that the 6 month drilling moratorium is necessary because all available oil containment assets are already in use and there would be nothing available if there were another blowout on another well.