Azeri 2008 BP Blowout

The South Caspian AIOC Central/West Azeri Blowout – September 2008

In September 2008, nearly two years before the Deepwater Horizon explosion in the Gulf of Mexico, another BP rig had blown out in the Caspian Sea—which BP concealed from U.S. regulators and Congress. Had BP, Chevron, Exxon or the Bush State Department revealed the facts of the earlier blow-out, it is possible that events leading up to the Deepwater Horizon disaster could have been different.

Azeri-Chirag-Guneshli (ACG) Field Development

The Azeri offshore oil field lies in the South Caspian Sea, roughly 120 km off the coast of Azerbaijan and is a part of the larger BP led Azerbaijan International Operating Company [AIOC] Azeri-Chirag-Guneshli [ACG] field (Ref. 1). Formed in February 1995, AIOC is a consortium of 10 companies. The field contains 5.4 billion barrels of recoverable oil and was put into production in November 1997. During the first six months of 2012 it produced 124.5 million barrels and 11.5 million m3 of associated gas per day from 56 production wells. The AIOC participants include: BP as operator with 35.8% stake; Chevron 11.3%; SOCAR 11.6%; INPEX 11.0%; Statoil 8.6%; ExxonMobil 8.0%; TPAO 6.8%; Itochu 4.3%; and Hess with 2.7%. In September 2012, ONGC acquired Hess’s stake.

A BP presentation from 2006 entitled “Building A New Profit Centre: Azerbaijan” (Ref. 14), is an appropriately named summary of the BP story in Azerbaijan. This started with the infamous Mrs. Thatcher visit of 1992, delivering cheques to the Azeri government on behalf of BP, the initial AIOC “Early Oil” project in 1997 following the signing of the 1994 “Deal-of-the Century”(Ref. 15) between BP and the Azeri government, the development of ACG, the continually expanding Sangachal receiving terminal south of Baku, the Baku-Tbilisi-Ceyhan [BTC] and South Caucasus [SCP] oil and gas export pipelines and the new BP “flagship” Shah Deniz 1 and 2 projects currently under development.

fig-1

Fig. 1. Map Showing Azeri-Chirag-Gunashli, Shah Deniz, Absheron & Other South Caspian Offshore Fields. Source: Greenfields-Petroleum.com

The Azeri field includes the Central, West and East Azeri production platforms and a compression and water injection platform (C&WP). Oil and gas is exported from the offshore fields through the Sangachal terminal across Azerbaijan, Georgia and Turkey via the 1,768 km (1,099 mile) long BTC and SCP pipelines (Ref. 4) connecting ACG to the south-eastern Mediterranean coast

Central Azeri is a production, drilling and quarters (PDQ) platform located in 128 m water depth in the central part of the Azeri field, constructed to produce approximately 420,000 bbl/d (67,000 m3/d). The facilities include a 48-slot PDQ platform 30-inch (760mm) oil pipeline and 28 inch (710mm) gas pipeline from the platform to the Sangachal terminal and operations started in February 2005. West Azeri is also a PDQ platform located in 120 m water depth, constructed to produce oil from the western section of the Azeri field. West Azeri adds 300,000 bbl/d (48,000 m3/d) to overall ACG production and facilities include a 48-slot PDQ platform and 30-inch (760 mm) oil pipeline from the platform to Sangachal. Operations started in December 2005 (Ref. 2). East Azeri is a PDQ platform in 150m water depth constructed to produce oil from the eastern section of the Azeri field and produces 260,000 bbl/d (41,000 m3/d), consisting of a 48-slot PDQ platform, which started operations in October 2006 (Ref. 3).

The C&WP supplies the Central, West and East Azeri platforms with water and gas injection services, manages gas export and provides electrical power using 10 Rolls Royce turbines and is bridge linked to Central Azeri platform. The gas injection capacity at the C&WP is 1 billion cubic feet per day (28 million m per day) with 5 gas injection wells. Water injection capacity is 1 million bbl/d (160,000 m3 per day) with 12 water injection wells. Gas export capacity stands at 250 million ft3/d (7.1 million m3). The Azeri C&WP has some of the largest water injection pumps and gas injection compressors among BP platforms worldwide. The topsides were constructed in the ATA (AMEC-Azfen-Tekfen) construction yard in Bibi-Heybat.

Fig. 2.gif

Fig. 2. ACG Gunashli, Chirag and Azeri Platforms. Source: APC Engineer.com

Central Azeri Platform Gas Blowout

On 17th September 2008, a gas leak was discovered in the seabed immediately beneath the Central Azeri platform after gas bubbles were observed in the water, with a drilling mud blowout occurring to the drilldeck reportedly via a gas injection well (Refs 5, 6, 7 and 19). The platform was in production at the time, so was shut down and evacuated, the biggest emergency evacuation in BP’s history. It was extremely fortunate that all 212 workers were able to removed safely without ignition and explosion. The incident resulted in two fields being shut and output being reportedly cut from 900 k to 300 k barrels a day, representing a loss of 40 to 50 million USD per day to the Azeri government, with production disrupted for months (Refs 5 and 6). West Azeri was powered by a cable from Central Azeri, so this was also shut down (Ref. 8). Production at West Azeri resumed on 9th October 2008 and at Central Azeri in December 2008 (Refs 10 and 11).

Gas or water injection is a technique commonly used to raise pressures and improve well extraction and enhance waning pressure within formations. Gas injection wells effectively “sweep” the formation for oil, thus boosting production. At Azeri, BP explicitly stated the blowout was due to a “bad cement job” (Ref. 9) but no further details were provided and public statements indicate there was considerable uncertainty as to the real cause. It is reported that nitrogen foam cement (Refs.20 and 21) as used at the Gulf of Mexico Macondo well two years later was adopted at Azeri. A “number of wells” were shut off, which were presumably subsequently investigated in order to log the cement integrity throughout. These may have been repaired at a later date, but again further details were not provided.

Fig. 3.jpg

Fig. 3. AIOC-ACG Seabed Rendition Showing Extent of Mud Volcanoes, Slope Failures and Faulted Zones. Source: Azerbaijan International Operating Company

Apsheron Ridge Geohazards

The ACG fields situated along the subsea Apsheron Ridge contain several extreme geological hazards (Ref. 12). The seabed is notoriously faulted, unstable and weak and susceptible to medium strength earthquakes. The ACG ridge is dominated by a continuous 5,000 year old submarine slope failure escarpment. In order to generate “first oil” in the late 1990’s to fund future development BP always planned to use the half completed Soviet Chirag jacket, the only structure present at the time, which lay very close to the failed slope edge. This was achieved by designing and constructing a new topside for the jacket, including a seismic isolation module to guard against the prevailing levels of seismic shaking.

It may be reasonably assumed that it will have determined at what depth the gas problems initially occurred, based upon well logs and previous geophysical surveys, and along exactly which stratigraphic horizon(s) flows occurred. This will have indicated the likely source of the gas, possibly high permeability ancient Palaeo-breccia deposits of varying ages and depths associated with mud volcano flows. The ACG mud volcanoes and associated seabed and subsurface features were mapped during the Soviet period and were well understood, based upon extensive Russian and other geological literature. The seabed was then geophysically surveyed and mapped in considerable detail, including initial regional BP surveys in the late 1990’s and subsequent detailed well site, facility and pipeline surveys. It has always been strongly suspected that gas hydrates may be present across the area at relatively shallow depth (Ref. 24).

The articles listed in a Wikipedia link (Ref. 13) summarise the situation that arose in September 2008: A 1998 article describing planned geohazard studies at ACG in relation to facilities siting and drilling risks summarises the geohazard situation and views of AIOC at the time (Ref. 12).

Previous Well Drilling Problems

There had already been well drilling problems from 2003 onwards at West Azeri, causing severe well casing buckling problems. These have been described in detail and were not gas related, but caused by the uniquely weak and variable clay formation mineralogy present across ACG (Ref 18). This well buckling was directly caused by formation weaknesses at certain stratigraphic levels as a result of the upper ~200 m of clay strata consisting of a unique geochemical make-up and particle structure, including highly saline pore fluids all resulting from the presence of vast quantities of upwelling gas/mud/saline deep waters associated with the mud volcano on a geological time scale. It is for this reason that the a “Riserless Mud Recovery” drilling technique [RMR] was specifically developed at great expense and subsequently used successfully at West Azeri. Some of this information is in the public domain (Refs. 16 and 17), although only success stories tend to be publicised, rarely the initial problems. The (in)famous “Lessons Learned” in the oil industry are usually for internal consumption and are rarely made fully available.

Fig. 4.png

Fig. 4: Locations of Pipelines, Platforms and “Traffic Light” Risk Zones at Azeri-Chirag-Gunashli. Source: Azerbaijan International Operating Company.

Lessons for The Future For Drilling in Gas Hydrate Areas

It is fairly certain that BP will have learned from the problems encountered at ACG and the lessons learned should have been transferred across to the adjacent Shah Deniz project. However, and this is a key question, how much of that information was taken onboard by BP Houston is another question. In most people’s experience, oil companies in different centres operate quite independently at project levels, with separate teams and different ways of working and reporting and even different procedures and processes. The “top-hole” shallow section drilling hazard reports produced by a group operating from one location may be quite different to those generated by another, even though ostensibly containing a similar make-up of technical expertise and experience. Despite there ostensibly being some cross-pollination, any detailed consultation between such groups is often somewhat superficial, with hazard reports from each often not even being viewed, much less reviewed, by the other teams.

Certain questions should be asked with respect to how much the technical people on the ground in BP Houston involved in planning and designing the Macondo MC 252 well knew about what had happened years previously offshore ACG South Caspian at West and Central Azeri. It should be determined how much those experiences and the (theoretically anyway) “lessons learned” were transferred from Baku, through Sunbury out to Houston and how much, if at all, these affected the Macondo initial well design, shallow hazard assessments and the defined drilling and well completions procedures.

Locating of Facilities in Relation to Surface and Drilling Geohazards

At Central and West Azeri, the closer the pair of platforms were placed to the mud volcano cores, the higher the risk to both surface facilities and drilling operations and these were positioned very close indeed. It was estimated that very 100 m of shift away from the target Balakhany X reservoir axis (the synclinal hydrocarbon “trap”, see risk map above) cost in excess of a million dollars in extra well length costs alone for a 48 well slot directionally drilled platform. There will have been great pressure from management to position the platforms as close as possible to the mud volcano cores and slope edges, since the “axis” is more or less coincident with the line of the mud volcano cones and the distinct seabed slope escarpment failure seen along the ACG field is just downslope of that. To minimise these costs, the platforms were placed very close, possibly intersecting permeable gas charged breccias flow deposits tied back into the mud volcano “gas core” which plunges more or less vertically many km below seabed. .The breccia layers are old flow deposits, many 100s of thousands or even millions of years old, which were very well mapped geophysically. If these were drilled too close without having stepped the facility back sufficiently in mitigation, there would have been some degree of risk.

Methane Gas Hydrates in South Caspian and Gulf of Mexico

It is likely that frozen gas hydrates are present in the seabed at some depths/locations at ACG. Indeed conditions are such that there are possibly widespread features of the deep water of the South Caspian, characterised by

  1. Depth-restricted, lenticular bodies well beneath the seafloor,
  2. The apparent accumulation of free gas within the underlying sediment, and
  3. Evidence of associated recent slope failures in the overlying strata.

For the SOCAR/Total field, Absheron, adjacent to ACG. hydrates were assessed as likely to be present from predicted thermobaric modeling, perhaps developing in water depths as shallow as ~150 m, and could form layers as thick as 1350 m It is believed that an assessment of the likely presence and depth of hydrates at Shah Deniz adjacent to ACG (see Figure 1) has been carried out. This may be comparable to the assessment carried out for Macondo in the Gulf of Mexico by BP in Houston, where there is brief mention in the pre-drilling shallow hazards report (Ref. 22). However the Macondo calculations are incorrect since they assume pure methane throughout, using an outdated relationship between temperature, pressure, salinity and methane content. The presence of substantial quantities of ethane and propane (~13%) known to be present at MC252 (and in the South Caspian) was ignored, such that the predicted depth/thickness of hydrates below seabed was too shallow at 1,279 to 1,905 feet (390 to 580 m), for temperature gradients of 35 to 25 deg./km (see Section 7.2.4, p.9, entitled “Hydrates”).

The offshore industry may never find out exactly how and why shallow gas blew through which specific wells at Central Azeri unless further details of well numbers, locations, azimuths, stratigraphic depths, dates, times and geology are provided. Investigative reports on how many “bad cement jobs” were discovered and how these were assessed and determined would need to be provided, with information as to whether or not these wells were repaired/remediated and eventually put back into commission or not.

Ultimately, “Dual Gradient” RMR riserless drilling was developed and adopted at West Azeri, although at Macondo, BP do not appear to have done anything different to that done previously in the GoM, based upon their corporate experiences in Azerbaijan. Indeed based upon what is known in the public domain, the company appears to have simply moved ahead with the development and design of the Macondo well from 2009 onwards as a deepwater exploration well to be converted to a producer as if nothing had occurred in the South Caspian which was out of the ordinary.

It is clear that at ACG. BP played a dangerous game in locating major new offshore facilities as close as possible to extremely hazardous geological features. The price of taking those risks was paid very shortly afterwards and that price could have been far higher. In situations such as that, one should never arrogantly play dice with Mother Nature and hope to win for the sake of a few dollars saved. But this was the all-new slimmed down cost-cutting rather secretive BP, more concerned with reputation, cost control, their bottom line and keeping information from partners and the industry at large. Certainly more concerned than informing those partners and the global oil industry of the background and detailed reasons behind what could easily have been a major fatal blowout disaster, rather than just another big profit loss.

References:

  1. “Azeri-Chirag-Guneshli; The Largest Oil Field under Development in the Azerbaijan Sector of the Caspian Basin”.

http://www.bp.com/sectiongenericarticle.do?categoryId=9006667&contentId=7015091

  1. “BP Begins Production at West Azeri Field in Caspian Sea”, Rigzone, 5th January 2006

http://www.rigzone.com/NEWS/article.asp?a_id=28317

  1. “Production Begins at East Azeri in the Caspian Sea” (BP Press Release), 23rd October 2006.

http://www.bp.com/genericarticle.do?categoryId=9006615&contentId=7024882

  1. “Golden Weld Ceremony Links Azerbaijan and Georgia”, Azerbaijan International, Sec. 12.4, pp. 84 – 87, Winter 2004.

http://azer.com/aiweb/categories/magazine/ai124_folder/124_articles/124_bp_developments.html

  1. “BP Halves Azeri Oil Production After Gas Leak”,.Reuters Edition UK,17th September 2008.

http://uk.reuters.com/article/2008/09/17/bp-azerbaijan-idUKLH11994620080917

  1. “BP Shuts Down Two Azeri Oil Platforms After Gas Leak”, Bloomberg, 17th September 2008.

http://www.bloomberg.com/apps/news?pid=newsarchive&sid=aEw7N7UprOpc&refer=energy

  1. “WikiLeaks: BP’s ‘Other’ Offshore Drilling Disaster”, Time World, 18th December 2010.

http://content.time.com/time/world/article/0,8599,2037830,00.html

  1. US Embassy in Azerbaijan; 8th October 2008; Original Title: “Azerbaijan Seeks to Develop ACG Deep Gas, can Supply Georgia with Winter Gas; US Embassy Cables: BP May Never Know Cause of Gas Leak, US Told”, Guardian, 15th December, 2010.

http://www.theguardian.com/world/us-embassy-cables-documents/172998

  1. US Embassy in Azerbaijan; 15th January 2010; Original Title: “Azerbaijan: BP Downbeat on 2009 Shah Deniz Phase Two Progress; US Embassy Cables: BP Blames Gas Leak on Bad Cement Job, 15th January 2009.

http://www.theguardian.com/world/us-embassy-cables-documents/187280

  1. “BP Resumes Oil Output at one Azeri Platform”. Reuters Edition UK,. 10th October 2008.

http://uk.reuters.com/article/2008/10/10/bp-azerbaijan-production-idUKLA26181320081010

  1. “BP Partially Resumes Production at Azeri Platform”, Reuters Edition UK,.23rd December 2008.

http://uk.reuters.com/article/2008/12/23/bp-field-resumption-idUKLN67920520081223

  1. “Mud Volcanoes Top Hazards for Future Azeri Operations”, Offshore, Pennwell, 3rd January 1998.

http://www.offshore-mag.com/articles/print/volume-58/issue-3/news/general-interest/mud-volcanoes-top-hazards-for-future-azeri-operations.html

  1. Azeri Oil Field Wikipedia.

http://en.wikipedia.org/wiki/Azeri_oilfield#West_Azeri

  1. “BP in Azerbaijan, September 2006”, Presentation, p. 87.

http://www.bp.com/content/dam/bp/pdf/investors/IC_azerbaijan_fieldtrip_presentation_slides_sept06.pdf

  1. “Pipe Dreams, Part 1; Azerbaijan’s Riches Alter the Chessboard”, 4th October 1998.

http://www.washingtonpost.com/wp-srv/inatl/europe/caspian100498.htm

  1. Alford & Asko (M-I Swaco), Stave, R. (AGR Subsea), “Riserless Mud Recovery System and High Performance Inhibitive Fluid Successfully Stabilize West Azeri Surface Formation”, 2005 Offshore Mediterranean Conference, Ravenna, March 2005, Paper No. OMC 038.
  2. Stave, R. (2007), “Riserless Mud return Technology Solves Shallow Wellbore Instability Problem: A Case History”, Presentation to American Assoc. Drilling Engineers, 23rd May 2007, p. 30.
  3. Allen, J.D., Hampson, K., Vermeijden, C. And Clausen, C.J.F. (2005), “Well Deformations at West Azeri, Caspian Sea”, Proceedings of the International Symposium. on Frontiers in Offshore Geotechnics (IS-FOG 2005), 19th – 21st September 2005, Perth, WA, Australia
  4. US Embassy Cables: “WikiLeaks Cables: BP Suffered Blowout on Azerbaijan Gas Platform”, 16th Secember 2010.

http://www.theguardian.com/world/2010/dec/15/wikileaks-bp-azerbaijan-gulf-spill

20. Earth Island Journal, “Part 2: BP Covered Up Blow-out Prior to Deepwater Horizon”, April 24th 2012.

http://www.earthisland.org/journal/index.php/elist/eListRead/part_2_bp_covered_up_blow-out_prior_to_deepwater_horizon

  1. Environment News Service, “Halliburton May Have Pumped Unstable Cement Down BP Oil Well”, 29th October, 2010.

http://www.ens-newswire.com/ens/oct2010/2010-10-29-091.html

  1. BP “Shallow Hazards Assessment; Proposed Macondo Exploration Well MC 252 #1; Surface Location in Block 252 (OCS-G-32306); Mississippi Canyon Area, Gulf of Mexico. 8th June 2009, p. 46.

http://www.mdl2179trialdocs.com/releases/release201303071500008/TREX-07502.pdf

  1. Diaconescu, C.C. and Knapp, J.H. (2002), “Gas Hydrates of the South Caspian Sea, Azerbaijan: Drilling Hazards and Sea Floor Destabilizers”, Proc. Offshore Tech. Conf, Houston, May 2002, Paper No. OTC 14036.
  2. Bagirov, E. and Lerche, I. (1997), “Hydrates Represent Gas Source, Drilling Hazard”, Oil and Gas Journal, 12th January, 1997.
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Treasonous Trump

Anyone who does not understand why the CIA, the FBI, the Dept. of Justice, many (most?) senior people in the Army, Navy and USAF, most of the US Defense Dept., as well as the entire honest media in America is going to work very hard to change this around legally, then they should simply read the 25 pages of the declassified document ICA_2017_01

https://www.intelligence.senate.gov/sites/default/files/documents/ICA_2017_01.pdf)

I imagine the Classified version is a lot more revealing. This is about competence and professionalism. The US Presidency has been turned into an appallingly embarrassing and eternally damaging circus. Harward turned him down. Mattis was seriously considering doing so and was horrified he had been nominated. Clinton was a bad candidate. So was he. Both too old in any case. people will start to open their eyes.

“Somebody once said that in looking for people to hire, you look for three qualities: integrity, intelligence, and energy. And if you don’t have the first, the other two will kill you. You think about it; it’s true. If you hire somebody without [integrity], you really want them to be dumb and lazy.” – Warren Buffet.

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Melted Shallow Gas Hydrates Blowing Through Burst Disk Triggered Macondo

It now seems highly probable that the offshore oil and gas industry’s infamous and long feared Gulf of Mexico Gas Hydrates [GH] caused drilling blowout was ultimately the cause of the horrors which occurred at the Block MC252 Macondo well  in the GoM in April 2010. This potential trigger has been well documented in the technical literature for many years, although probably required the compounding sequence of drilling mistakes that happened as BP continually adjusted their threadbare well design “on the hoof”. The incompetence and arrogance of BP has become breathtaking in recent years and this hydrate melt blowout was a direct result of that. Wells have been drilled through frozen gas hydrate formations in the Gulf of Mexico before, and the potential hazards were understood. It would be very surprising if the 1st trial finding arrived at was not gross misconduct and wilful misconduct, but that remains to be seen. This is and will continue to be a highly politicised situation. The question that arises is: Should a technique of cementing together smaller and smaller steel pipes in much the same way as done a century ago on land continue to be used in drilling very deep wells in very deep water in such hazardous geological situations?

A number of individuals, including senior members of the Deepwater Horizon Study Group [DHSG] have believed for some time that there was some sort of “casing breach” higher up in the drillstring. If one reads the events surrounding the workings of the US federal Steven Chu led team when they were “embedded” in the BP Houston office prior to the attempted Top Kill, one can see that there was a strong suspicion/fear that a casing breach or fracture had occurred or that one of the three 16” casing “burst disks” had blown. There is a remarkable first hand witness account held by the DHSG written in the immediate aftermath. Reading that, it is obvious to anyone who has any understanding about what an expanding Gas Hydrate generated methane cloud would consist of and what it would look like spreading across and flooding a drilldeck that this was the trigger. The cold methane cloud was quickly followed by mud being siphoned up the inner drillstring followed by oil as the shoe track at the well bottom was blown to pieces under an immense suction force at reservoir level. The DHSG have produced work of great diligence and fair-mindedness, but for whatever political reasons, have stayed away from the potential hydrate/burst disk scenario, presumably since such a scenario is effectively “unprovable”.

A senior member of the DHSG e-mailed me on the 14th December 2012 in response to a broad outline of my views I supplied to him:

“Thank you for the updates.

I share your observations and conclusions.

The civil litigation trial (Phase 1 – developments to the blowout) is scheduled to resume February 25th. the Phase 2 (post blowout developments) trial is scheduled to start “late summer 2013). 

I do not think that much more of the developments, including the current surveys, will become public until the litigation processes force them to become public.

Thank you again for the insights and www links”

What is remarkable when one considers the geological context is that the words “Gas Hydrate”, “Methane Clathrate”, “Burst Disk” and “Shallow Water Flow” do not appear at all in any of the thousands of 1st trial transcript documents. When one considers where Macondo was drilled and its location in relation to the well known gas hydrate bearing zones in the Gulf of Mexico, this is odd to say the least, or perhaps not so odd.

BP could and should have used “Riserless Drilling” techniques which they helped to develop in the South Caspian sea, where they also had serious blowout problems..This would have allowed better control of the formation fracture pressures and was used by BP in similarly hazardous geological conditions at West Azeri and elsewhere in the South Caspian after an earlier blowout and other problems. This is detailed in a separate post.

The belief in some quarters is that the US Govt. will await judge Carl Barbier’s 1st decision on “Gross Incompetence and Wilful Negligence” after Part 1 and then Part 2 will be all about how much BP pay up, based upon best estimates of oil which flowed. The attempted COREXIT clean up was a disgrace which compounded the original incompetence and this dreadful attempt to “disappear” oil thus reducing future fines is well covered elsewhere.

The truth will out. It is far too important not to be. But we are all just tiny individuals struggling to make sense of a hugely complex event, which is why some parties hope that the complexity and obfuscation can continue.

There is a least now a vast amount of Public Domain information on the subject, and there are a handful of people around who have now figured out what went on. Mr. Dan Zimmerman is the person who first warned of what may happen offshore California, but his work was not listened to in 2009. However obtaining critical documents has been akin to getting blood from a stone. For example, the rather prescriptive Macondo “Shallow Hazards Assessment” report was only made available as a Court Exhibit in April 2013 [TREX-07502], see http://www.oilspilldocs.com/exhibits.cfm?start=301

Based upon information received and the opinions of a very few independent specialists it is now quite convincing that in addition to the seven major drilling and completions errors, the root geological “geohazard” cause of the blowout was drilling into uncontrolled Gas Hydrates on the shelf edge area. These are frozen gas beds in the seafloor 100’s of metres thick and expand considerably when warmed/melted, or cause pressure build-up if constrained. The situation was compounded by the presence of 6 distinct  Shallow Water Flow [SWF] sand units mapped at well known intervals, the somewhat unusual placing of burst disks in the 16″ casing and some shorter casing strings than planned leading to the GH stability zone and sub-zone being exposed directly to the 16″ uncemented casing. This all has shades of the MARS/URSA drilling problems some years ago (1998-1999), which Shell are of course well aware of. There will be people in a number of oil companies who are well aware of what happened there and there are a few publications on the casing crimping and buckling that led to abandonment.

The melted frozen gas hydrate most likely blew through the lowest Burst Disk (essentially a valve) which was unprotected/uncemented and open to the sand layer, due to the 16″ casing being stopped early about 950 feet shallower than planned. After the pressure reduction in the well caused by the final negative leak off test, he gas blew up through the so-called outer annulus direct to the drill deck. It is unlikely this gas did not come from reservoir level at 18,000 feet. That high velocity gas plume siphoned the oil up through the inner drillstring from depth later on ( a few minutes) and off went the flow for 87 days. The main evidence provided to explain why the blowout flowpath was internal and not via the annulus was the lack of hydrocarbons identified in the annular fluids. However only gas entered the annulus. The oil flowed through the drillstring as erosion inspections of the wellhead showed.

Having the lowest burst disk in the centre of a thick permeable sand layer, unprotected from the outer strata by casing or cement and in a highly likely hydrate depth zone was a huge error, probably not realised by anyone onboard at the time in all the horrible confusion.

Image

If this is the case, and I think the evidence is fairly conclusive, then not only could deep drilling be stopped in GoM beyond a certain water depth, but also in deepwater regions around the world offshore West Africa and elsewhere. This in combination with the almost certain ban on exploration drilling of any sort in environmentally sensitive areas such as Alaska, the Antarctic Basin and elsewhere, will likely lead to a rocketing oil price in the coming years. BP has not come clean and there is possibly a degree of covering up going on. This does a disservice to the rest of the GoM oil industry and that secrecy will lead to problems for the other players when the truth actually does come out.

Bhopal and Exxon Valdez took years to come out and the same may be true here.

Why does it matter that the gas came from much shallower gas hydrate [GH] layers and not reservoir depth? Well, Alaska, amongst others, is a big hydrate area, which has been looked at for GH exploitation as an energy source, as has the Gulf of Mexico and other parts of the world. You can perhaps guess what might be going on here.

The description given on Page 5 of Peter Folger’s US Congressional Research Service document is almost certainly what happened at MC 252:

http://www.fas.org/sgp/crs/misc/RS22990.pdf

Guardian

http://www.guardian.co.uk/environment/2010/may/20/deepwater-methane-hydrates-bp-gulf

http://www.guardian.co.uk/environment/2010/may/26/bp-top-kill-mud-gulf-of-mexico-deepwater-horizon

Solve Climate

http://solveclimate.com/blog/20100524/investigator-warned-mms-2009-about-deepwater-gas-blowouts-gulf-mexico

Boing Boing

http://www.boingboing.net/2010/05/26/did-methane-hydrates.html

In These Times

http://www.inthesetimes.com/article/6067/bp_bets_the_planetwe_lose/

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Lord Browne of Cuadrilla

Lord Browne of Cuadrilla

Not content with screwing up the GoM, Browne is now Chairman of Cuadrilla, all set to screw up much of Lancashire.

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BP Did Not Use Riserless Drilling at Macondo

BP Development of Riserless Drilling

Following severe and expensive drilling problems experienced by BP in 2003 at the West Azeri template in the South Caspian, a decision was taken to develop a system of riserless drilling in order to avoid such problems in the future. The company AGR Subsea developed a Tophole Drilling Package names Riserless Mud recovery System [RMR] which enables drilling the tophole section using weighted inhibited drilling mud, leading to improved hole stability, reduced wash outs, improved well control both with regard to shallow gas and shallow water flows [SWF].

A field trial was conducted in December 2004 following the establishment of a Joint Industry Project [JIP] was established funded by the Norwegian Research Council, Statoil-Hydro and AGR in order to qualify the RMR technology for use in up to 450 m water depths.

The RMR system was used on 15 wells at the BP West Azeri problem site (see previous) and in Deepwater Gunashli and Shah Deniz in the South Caspian. By mid-2007,  28 wells had been drilled on BP projects in the South Caspian using this technique, as well as at Sakhalin offshore Russia, specifically to avoid potential problems related to geohazards. By 2007, Shell E&P and the BP America Production Company had joined the original Demo 2000 JIP, with the specific aim to “develop, manufacture and perform a field trial of an RMR system for use in 5000 ft. of water depth in the GOM”.

Subsequently a large-scale field trial was conducted from a deepwater semisubmersible offshore Sabah, Malaysia, in September 2008. A joint industry group comprising AGR Subsea, BP America, Shell and the Norwegian Research DEMO 2000 [the original RMR JIP] program and supported by Petronas undertook this work. This group set out to advance subsea mud return technology from its established commercial market of shallow-water applications, 1,800 ft (549 m) or less, to deepwater depths and drilling requirements. Novel equipment and deployment methods were designed, developed, delivered, tested and proven to a demanding schedule.

The shallow water (< 450 m) version of RMR has been used commercially since 2003 on more than 100 wells worldwide. Statoil was the first operator in the GoM to adopt the RMR system, which has been used on the Discoverer Americas drill ship on the Statoil-operated Krakatoa prospect. The RMR system allows the circulation of mud, reducing the total consumption and discharges to sea to a quarter of the amount compared with conventional methods. The cost of mud and the transportation to the drill ship are significantly reduced and technology allows deeper drilling depths for shallow casing strings, again reducing the overall drilling time per well. Minimising the number of casing strings in deepwater drilling where you may run out of options.

Statoil currently has two drilling units in operation in the Gulf of Mexico. RMR technology has successfully been used by Statoil on the Norwegian Continental Shelf in 19 operations over the past years. As a partner with BP in the South Caspian and with BP America a partner in the successful development of the RMR technique, the question must be asked as to why it has not been adopted in the GoM by BP in general and at Macondo specifically, in view of the known severe potential geohazard related drilling problems that might be encountered at location, specifically related to shallow water flows , a weak unstable formation and gas hydrates, all common to the South Caspian.

 If the RMR system was not considered to be available or suitable for use at Macondo, for whatever reason, when it was used extensively by BP in the South Caspian and at Sakhalin then it is arguable that the Macondo well should not have been drilled where and when it was, using the outdated riskier conventional technique of cementing casing strings with a long riser. Could it be that BP in Houston were not fully aware of the RMR developments or rejected its use on cost grounds or as an “unknown step-out for the GoM”? BP are generally not as innovative as Statoil.

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Tony Hayward – Libya and Iraq Involvment

Two recent articles (20th September) by Tom Bawden of the UK Independent Newspaper on oil exploration in Libya and northern Iraq involving the newly formed Vallares investment vehicle, headed up by Tony Hayward, Nathaniel Rotchschild, ex-Goldman Sachs CEO Julian Metherill and mining metals and coal financier Tom Daniel are interesting in the context of events in recent years in those countries and as a piece of information to consider when wondering if the wars were partly aimed at preserving “Western” access to massive oil and gas reserves. However, how many people when reading of this feel a sense of disgust and revulsion that the former CEO of BP, having presided over the worst environmental disaster caused by mankind in the history of this planet should find it appropriate to be doing business in those countries. Presumably Mr Hayward has happily got some sort of a life back and he and his “managers” in BP felt that Macondo was just not really their fault at all, which could well be the case as they may have had no real idea of what was being done in their name and their shareholders names by the poor handful of overwhelmed BP employed individuals on the Deepwater Horizon and in offices in Houston for a few days during April 2010. Hopefully the new governments in Libya and Iraq will be able to judge the value of his and others involvement accordingly, coming so soon as it does after the hard fight to succeed in developing these fledgling democracies, at great cost in money and lives. This man’s conscience must be in shutdown, if indeed he ever had one.

http://www.independent.co.uk/news/business/analysis-and-features/a-tale-of-two-gulfs-the-rise-and-fall-of-oil-prospecting-2357617.html

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Macondo – Gas Hydrates, Shallow Water Flows and Burst Disks

Ignore the geology at your peril. As news comes through of probable seabed seepages of oil being observed again at Macondo, the only question will be whether or not these are reactivated “residual” seeps or the nightmare scenario of new flow paths through the shallow strata. Whichever it is, the latest events are clear evidence that the Macondo well casing was breached, a belief held by several commentators in the past.

http://madmikesamerica.com/2011/08/new-oil-leak-at-bp-macondo-site-in-gulf-of-mexico/

Macondo MC 252 is in an area of well known severe geological hazards, including gas hydrates and weak shallow (< 5,000 ft) artesian pressurised sand layers which can cause casing distortion and even buckling collapse, high inflow of drilling fluids, washout and partial collapse of those layers due to rapid drilling disturbance.

This “geohazard” is known as “shallow water flow” [SWF] and the associated risks have been extensively reported in the technical literature, and were ranked and mapped by the MMS. [Mississippi Canyon SWFs]. They were well known by individuals within BP America. In addition, the potential presence of extensive layers of in-situ frozen gas hydrates [GH] along the Mississippi Canyon continental shelf edge is understood and documented. Furthermore, this well location was selected and drilled very close to a gas hydrate bearing mud volcano feature in order to maximise the potential for a positive result at Target Depth. A safer method, known as “Riserless Drilling” does not appear to have been considered and was probably seen as too costly.

Despite all the above, BP took the decision to continue to attempt to drill the one of the world’s deepest wells to date in a slapdash, corner-cutting, driving down cost, “maximise added” value fashion. These cut corners and lack of management control have been well documented to date.

With proper drilling design, control and cementing, wells have been completed under these conditions in the past. However the risks should always be thoroughly assessed, with appropriate prevention and mitigation techniques and controls in place. Such measures are also well documented based upon the past experiences of GoM operators, including BP. However, as well as designing a high risk “long string” well, the MC252 Exploration Well was designed with safety valves (known as “Burst Disks”) at shallow depths which were close to the levels of three known and mapped SWF sands, and in a GH prone area. This was part of the plan to convert the exploration well to production at a later stage. More savings.

Indications are that the drillstring at Macondo was fractured/damaged as a result of SWF drilling fluid fracture, washout and collapse over a certain depth interval. Severe problems and drilling mud losses were recorded at the time. The expanded pressurised melted hydrate gas may have blown through the damaged casing and weak pathways in the bad cement job following the final negative leak off test. Drilling mud was displaced by seawater within the drillstring over too great a depth, leading to reduced internal hydrostatic pressure and a sudden imbalance between the internal (fluid) and external (expanding gas in sand) pressures. The hydrate almost certainly would have been steadily melting around the casing due to heat given off by the curing cement, a problem well understood by Haliburton, explaining their concerns over the use of a nitrogen foam cement.

The recent very detailed DNV forensic report on the BOP failure as well as an internal highly detailed Transocean Report leads to the conclusion that any BOP would have failed even if it had been in perfect condition, due to the condition of the well, it’s out of vertical alignment and the sudden immense force of the gas and fluid flow.

The question that should have been asked to date is: where did that huge quantity of gas really come from? Calculations may show that the valve system at the bottom of the well is unlikely to have “somehow” failed as a result of pressure changes far up the drillstring, causing a sudden influx of a vast quantity of gas from the hydrocarbon reservoir some two and half miles below seabed to burst upwards through fairly dense drilling mud at such a high velocity.

Consideration of the temperature and pressure regime in the shallow hole section below seabed suggests that natural in-situ hydrates are very likely to have been present at the Macondo location over a depth interval of a few hundred metres below mudline. The heat generated as a result of cement curing is likely to have led to melting of section of this natural hydrate bearing zone some distance radially from the cement and a subsequent increase in pressure as the gas tried to expand within one or more of the known SWF sand
layers. The presence of channels at certain levels within the cement is likely to have permitted a pathway(s) to form along part(s) of the 16” casing. Due to possible earlier drilling disturbance of the known layers of SWF sands prior to the melting of the hydrates, the 16” casing may have been out-of-straight or even slightly buckled as a result of partial liquefaction and softening of the SWF sands (similar to that observed at the BP/Shell URSA in 1999 in the GoM). This loss of lateral support may have caused a crack or breach in the casing, or even a loosening or damage at the casing joint(s). This casing is suspected to have been of too low a yield strength for the well design. At the point during the negative leak-off test when the pressure differential became sufficiently high, it is now well documented and accepted that the three “burst disks” (essentially pressure relief valves) placed at certain points on the casing joints down the casing string probably blew out at their inwards blowing rated burst pressure of 1600 psi. At this point the large pressure drop occurring within the mud fluids in the annulus between the production casing and the 16” casing might have been sufficiently large to allow a rapid influx of trapped pressurised gas lying within the SWF sand(s) and in the pathways which had formed in the bad exterior cement job. Melted hydrate expands to approximately 64 times its original frozen volume. This gas build up may have caused a very high pressure jet to blow out one of the rupture disks in the 16” casing, if the pressure differential between the seawater filled production casing and the annulus on the other side were sufficiently high. This immensely powerful gas jet stream would have travelled very quickly up the production casing.

This subsequent upwards rush of gas would have caused a siphoning of seawater, mud and subsequently oil with it as the production casing shoe was blown due to the very high suction force exerted. Once the initial shallow blast of GH sourced gas blew the BOP, reservir pressures would have been sufficient to allow the flow of oil to be maintained.

Much detail has been written in formal reports, books and publications to date about the mechanics of what happened. However virtually nothing has been stated about the root “geohazard” causes – shallow water flows and gas hydrates, a horrible but all too feared combination.

thegallowglaich@gmail.com

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