Anadarko’s CEO Jim Hackett was quoted last Friday as saying: “The mounting evidence clearly demonstrates that this tragedy was preventable and the direct result of BP’s reckless decisions and actions.” Anadarko owns 25% of the Macondo Well. Assuming we have only a single well bore pipe casing look what happens thermally to the cement job when BP changes out the drilling mud for seawater.
When the cement job (reported as a peculiar “nitrided” cement which may mean fiber reinforced) was completed, BP operators waited sixteen hours (instead of normal 24 hours) for the cement to set. BP had poured in drilling fluid to push the cement out of well bore and fill the gap around the pipe and “bond” pipe to rock in formation. At this point the cement may or may not have set but BP put in a cement plug. Although there was some rising pressures in the drillpipe, BP decision maker said to replace the expensive drilling mud with seawater assuming the well was capped. This may be partially responsible for the deep-well blow-out particularly if the cement has not yet fully set.
1. The heat transfer problems associated with running monobore drill installations with/without liners (including the standard multi-casing wellhead installations to drilling installations in deepwater) maybe a showstopper if seawater rapidly replaces the drilling mud when the rig is making preparations to leave – who looked at the heat transfer issues with well bore piping changes?. Replacing the warm/hot drilling mud with cold seawater can contract the well bore piping and may readily crack the cement plug. This possibly fail various cement bonds when the 9 7/8 inch casing contracts from the temperature change because it results in placing the cement plug/cement seals in tension! It appears BP/Partners went after a leading edge technology in several areas without implementing the basic requirements (liner and locking ring required). What happens to the 16-inch casing and 18-inch casing? How hot is the well bore?
2. There are major issues with which cement seals are intact in the BP Deepwater Horizon if this is truly a monobore installation with no liner as well as the drilling rig string/casing pulling up on the BOP wellhead connector when it lost position and/or capsized. Does anybody have any test data on this condition to see if cement seals between 36-inch casing can remain intact as again a portion of the annular cement maybe in tension? With either no/single liner and no locking ring the BP design looks to be flawed with no back-up safety systems if the cement plug fails. The BOP can be taken out by the drill string buckling and cement projectiles coming thru the riser if pressures are at 5000+ psi. If the cement plug breaks loose the internal BOP shear rams can be easily wiped-out by dynamic impact forces of cement resulting from a high pressure formation blow-out.
3. There is probably no integrity left of any internal seals within the BOP which is now basically just a thick-wall cylindrical shell. Was there only a 10,000 psi rated BOP which was refurbished in the Deepwater Horizon installation? Federal regulations should require all deepwater installations should have a new Cameron DWHC BOP (or equivalent) with armored cables and the super shears until an acceptable redesign can be tested for ultra-deep wells.
4. Replacing drilling mud with seawater in ultra-deep wells maybe an unacceptable situation which leads to blow-outs in ultra-deep monobore wells. It can exist in both deep drilling on land and offshore and probably has resulted in setting the initial conditions for numerous of high pressure oil/gas well blowouts (i.e., the euphemism of “loss of well control”). A entirely new material is needed for current cement technology for ultra-deep wells. Well bore piping in the last 2000 ft may require a special thermodynamic design to mitigate piping length changes due to quenching with seawater. Perhaps, it is better to leave the drilling mud in the well as a “sunk cost”. Drilling operators need to have much better tools a (software/sensor package) when replacing drilling mud with seawater.
5. Obviously a rigorous, transient heat transfer analysis (simulation) should be done on each proposed deepwater well as well as the current ultra-deepwater well completion protocols actually employed – do we have standardized procedures or not ? We could be sitting on a number of deepwater ticking time bombs if they involve monobore SET technology (beyond depths of 20000 ft) even if this technology is used with various options for a liner. In particular, how have the Russians addressed this problem in ultra-deep wells or have they?
6. How does one quantify the shear bond strength of a cement bond between a casing and the rock in a reservoir formation at 9000+ psi at 20000+ ft and temperatures greater than 350 F? Is there any such data – how were the lab tests done?
There is a need to standardize the cement formulations and training for US ultra- deepwater drilling and “cements”. Cement properties can vary by 50% (on land) depending on who is doing it and how they do it!
7. It appears the oil companies were running way ahead of MMS in terms of Set Technology implementation and MMS had little or no control regarding the installations. It is unclear how there can be any suitable reliability with OHL System unless it is an extension of standard hanger system and a bottoms-up (component level) reliability analysis together with a full FEMCA (Failure Modes and Effects Analysis) per tailoring the MIL-Standard used by DOD has been performed. This does not exist today.
8. Shell Deepwater Operations may have one of the most conservative approaches of all the majors to ultra-deep drilling and Shell has one of the best oil patch research centers. Shell’s Joseph Prospect installation (or whatever Shell recommends) should be the minimum standards and configurations for deepwater drilling and installations in US waters. If we just have to get back out there drilling to save jobs, let’s do it with the full knowledge that numerous more safety issues need to be addressed and there should be a Federal Regulator/nominee/team of consultants on the drilling rig empowered by Federal Law to “Hit the Kill Button” with no questions asked during the final well completion or drilling rigs leaving the scene.
9. Redesign the ultra-deepwater BOP after a full functional specification is developed including all failure modes and how to mitigate all major well-blow outs from damaging the BOP. Reliability should be triply redundant as a goal. How can a BOP mitigate a drill string buckling inside the BOP? Drill strings can easily buckle in an ultra-deep well if well casing is over 20000 ft. I do not see where this issue has been addressed.
10. Develop a significantly improved (carbon nanotubes?) cement or entirely new material for bonding at high temp and pressure to fifty+ different layers of formations (data to be developed from mud logs) to withstand pressures greater than 15000+ psi (match to API standards for flanges, valves and piping).
11. Immediate review all current ultra-deep wells (land/sea) to determine of there are heat transfer issues with either how it was completed, tested or installed as well as pull the files on all offshore wells having well control problems. Determine shut-in criteria now for all problem wells. Determine if proper pressure tests of well bore integrity were done and who is permitting “workovers”? Do well workovers now mean there is a significantly deeper drilling than the public is being told?
12. There should be a fully automated system to notify the US Coast Guard in case of any major fire on a rig. Any fire on a rig must be immediately reported – no longer the call of the Rig Captain. There should be a Comm Protocol which can be activated by any crew member on the Drilling Rig with regards to fires onboard drilling rigs and all offshore platforms.
13. Since President Obama approved BP’s total liability at $20 Billion, this would only pay for people’s condo losing 50% of their resale value (already happening) in Miami (much less than entire Florida or Gulf Coast) and who is going to compensate the States for loss of tourism? Florida’s impacts for the next 12 months could be $60 Billion to $100 Billion a year. If this occurs for the next ten years, Florida’s losses alone will be over $500 Billion from just loss of tourism. Why is $20 billion constitute a real settlement? It remains a possibility that BP, Chevron, Shell, Anadarko and others are heavily involved in an “ultra-deepwater” drilling program (since late 1990s) at the direction of the US Government and essentially the deepwater (> 4000 ft depths) of the Gulf of Mexico just maybe the “mother of all oilfields”. Does the US Government (taxpayer) carry the burden of all restorations costs (whatever that means) above $20B as well as all future liabilities form ultra-deepwater drilling/production? Does it pay for all homes abandoned if the US Government orders permanent evacuations of a given local due to unacceptable air quality? What are the threshold airborne/ground concentrations of the VOCs which will mandate an evacuation? Let’s see what happens to people in Venice, La and Grand Isle, La by mid-August – they are living on the lead edge of possible coming major air quality issues.
14. USGS has stated there are no cracks or leaks in the seabed (at this well location or all wells in Gulf of Mexico?). Thus, the probability of success of relief wells is said to perhaps be 80%. We shall see in mid- August but possible we may not know until late Nov 2010. This well may have drilled beyond 20,000 ft given the extended time quoted to drill the relief wells and no transparency forthcoming from USGS. I have not heard of any signed affidavits by US Officials stating categorically that this well was not drilled beyond 20,000 ft. Unclear what happened in Top Kill except that there is possibly an underground blow-out at the bottom of the 18-inch casing (3900 ft down hole) resulting in high pressure oil/gas going into another formation underground (how many more complications do we need?). This may require an unknown amount of heavy mud to try and seal leaks into secondary formations so we need all the capacity we can muster in drilling mud capacity and high pressure mud pumps. Are the relief wells currently or expected to produce oil and gas requiring extra capacity (enter the Loch Rannoch shuttle tanker)?
15. The Louisiana Offshore Oil Project (initially completed in 1980s when a company called Petro-Marine in Gretna was Project Mgr) uses the Louisiana Salt Domes for massive storage of oil. In fact, it is possible to store significant quantity of oil from the Gulf of Mexico in LOOP if there are major worldwide oil disruptions (possibly involving Iranian situation) including further expanding LOOP onshore. The oil being supplied by Mississippi Canyon wells could be tied into LOOP for emergency storage. In fact, if these wells can produce 50,000 bpd and we drill 100 wells in next five years (Texas over to Alabama) that would go a long way to addressing US energy dependence issues if coupled to aggressive (micro) nuclear plant development and solar installations. How much are we willing to sacrifice any further?
16. It is possible we have already lost the battle for the Eastern Gulf of Mexico – it could be several years to assess the types of environmental damage done as well as coming significant environmental impacts to the East Coast of the US, Cuba and Mexico. It is not going to ever be the same in our lifetimes. Oil will be reported by August in North Carolina and by Christmas will have traveled across the Atlantic Ocean!? We have never had unrefined crude to these levels from perhaps the earth’s mantle being injected into our lives before. What happens with hurricanes entraining this sheen and stirring up the bottom of the Gulf of Mexico? We need to know how toxic this particular material is as well as fate and transport. People on beaches should not touch this material or get around if not involved in clean-up.
17. Disposal of this unrefined oil sludge remains a major environmental issue. Where does it go after placing in plastic bags? Does it react with plastic long term? The Fire Branch (AFRL) at Tyndall AFB should be contacted to burn a small amount of this material to identify the toxicity of airborne contaminants since they are already set-up to do this kind of testing. Let’s start getting a handle on the airborne issues in burning massive amounts of this material offshore with regard to airborne plumes coming onshore before we assume this is safe because it is not safe near coastal areas (the plume of a Shuttle launch was capable of peeling the paint off cars if the wind was in the wrong direction at launch and that is a minor plume issue compared to ongoing massive offshore oilfield burns). It is possible that huge Supercritical Water Reactors (technology developed by General Atomics in San Diego) may be needed to safely deposing of this material by converting it to basic carbon dioxide, oxygen, hydrogen, nitrogen, etc. This needs to be addresses as a major environmental issue.
18. Why did BP reject the use of large “suction pile over the BOP” at the outset which is a standard technology for anchoring deepwater systems and one could have been lowered over the entire BOP at the outset!? Ask the Dutch and any number of other manufactures. The current “containment cap” is nothing but a mini-version of a “suction pile” that does not go down to the seafloor and is too small in scale to collect all the oil.
19. DOD has the only Command and Control Structure on the planet to address the evolving Gulf Oil Spill Crisis (now coming up Florida’s East Coast (see www.floridaoilspilllaw.com)) – this is way beyond the scope of the Coast Guard and using DOD C-130 assets to spray airborne chemicals (CorExit 9725A) all over the place (which is another major problem). Quit spraying airborne CorExit 9725A until you can produce tests on lab specimens that show toxicity levels. Where is the data? Is the problem that DOD cannot both address a forthcoming Iranian front in conjunction with the Gulf Oil Spill? There are many more questions which remain unanswered.