OGJ Production Editor
HOUSTON, Jan. 12 -- The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling found several immediate causes contributed to the Macondo well blowout on Apr. 20, 2010, although its Jan. 11 report concluded that the root cause was a failure of management by the three main companies involved in drilling the well: BP PLC, the well’s operator; Halliburton Co., which provided cementing services; and Transocean Ltd., the rig's owner and operator.
The immediate causes listed in the report include the cementing, pressure testing, temporary abandonment, kick detection, fluid diversion, and blowout preventer activation procedures.
Because of the ongoing investigation by a government-sponsored forensic analysis team, the commission did not speculate in the report on why the blowout preventers failed to operate as designed.
Factors that may have led to a poor cement job of the production casing string included:
• Running a long-casing string instead of setting a liner. The report said it was unclear whether this directly contributed to the blowout, but running a long string did make it more difficult to obtain a good primary cement job.
• Inadequate number of casing centralizers. Again the report noted that it was unclear whether this was a direct cause but it did find fault with BP's management and centralizer design procedures, as well as poor communication between BP and Halliburton on the centralizer design.
• Float collar conversion. The report said it may never be established with certainty that the float collar valves closed, but it did fault BP personnel for not considering how anomalous pressure readings might increase the cement job's risks. The report noted that because of equivalent circulating density concerns, BP engineers used a very low circulating pump rate, lower than the flow rate needed for closing the float collar valves.
• Not running cement evaluation logs. The report said BP personnel erred by focusing on full returns as the sole criterion for deciding on whether to run a cement evaluation log. It said receiving full returns indicated that cement or other fluids had not been lost to a weak formation but full returns provided limited or no information on where the cement went, channeling, contamination, or stability of the foam cement. Cement evaluation logs although of limited use in a well such as Macondo should have been run, the report said.
• Foam cement instability. The report noted that Halliburton may have pumped foam cement into the well that available tests indicated would be unstable.
Other factors that the report said BP did not adequately consider in assessing the cement job risks included serious lost returns in the cementing zone, no bottoms up circulation, and low cement volume.
The report said the failure to properly conduct and interpret the negative-pressure test was a major contributing factor to the blowout. The report noted that the cement spacer may have clogged the kill line and that pressure data showed that formation fluids were flowing into the well. The commission identified several factors that may have led to an incorrect test interpretation, such as:
• The Mineral Management Service and the industry having no standard procedures for running or interpreting the test and lack of any requirement to run the test.
• BP and Transocean having no internal procedures for running or interpreting negative-pressure tests and not formally training their personnel in how to run them.
• BP Macondo personnel not providing the wellsite leaders or rig crew with specific procedures for performing the negative-pressure test.
• BP not having in place (or not enforcing) any policy that would require personnel to contact the shore office for a second opinion about confusing data.
• Due to poor communication, the personnel performing and interpreting the test may not have had a full appreciation of the context in which they were performing it.
Temporary abandonment procedures
BP’s temporary abandonment procedure also may have contributed to the blowout, the report said. It noted the following problems in the procedures:
• Replacing 3,300-ft of mud below the mudline with seawater because of BP's preference for setting cement plugs in seawater instead of in mud to avoid mud contamination.
• Not setting one or more noncement bridge plugs.
• No evidence that BP evaluated the risks for removing 3,300 ft of mud from the well.
• Setting the planned cement plug as deep as 3,300 ft. The report noted that BP Macondo personnel planned that in order to set the casing lockdown sleeve last in the temporary abandonment sequence to minimize the chances of damage to the sleeve and to generate the 100,000 lb force for setting the sleeve by hanging 3,000 ft of drill pipe below the sleeve.
• Displacing mud from the riser before setting the cement plug was the most troubling aspect of the procedure, the report said. This left only the cement at the bottom of the well as the only barrier to fluid influx.
The report said the drilling crew and other individuals on the rig missed signs that a kick was occurring but it is unclear on why they missed these signals, such as the Sperry Sun mudlogger data between 8:00 p.m. and 9:49 p.m.
These signals included increasing drill pipe pressure after the pumps were shut down for the sheen test at 9:08 pm and the anomalous difference between the drill pipe and kill line pressures recognized by the driller and toolpusher at 9:30 pm.
The report noted the crew may have missed these signals because after 9:08 p.m., they began sending well fluid returns overboard, bypassing the active pit system and the flow-out meter (at least the Sperry Sun flow-out meter). The mudlogger then only performed a visual flow check.
The report recommended that in the future, the rig instrumentation and displays should be improved by installing more sophisticated, automated alarms, and algorithms to alert the driller and mudlogger of anomalies.
The report faulted the current rig operations in which individuals sit for 12 hr at a time in front of displays with the operations requiring the right person to look at the right data at the right time, and then to understand its significance in spite of simultaneous activities and other monitoring responsibilities.
Diversion, BOP activation
The report said the crew should have diverted the flow overboard when mud started spewing from the rig floor to reduce the risk of gas igniting.
It said the crew possible did not do that because of:
• Not recognizing the severity of the situation, although this is unlikely because of the amount of mud spewing from the well.
• Not having much time to act. The explosion occurred about 6-8 min after mud first emerged on the rig floor.
• Most significantly, not having been trained adequately how to respond to such an emergency.
The report recommends that in the future, well-control training should include simulations and drills for such emergencies, including engaging the blind shear rams and triggering the emergency disconnect.
Contact Guntis Moritis at email@example.com.