Green is the New Black: Making a Gas Cartel

As the disastrous civil war in Syria stretches into its sixth year, the conflict is beginning to take shape as a struggle for influence between Russia and the United States and their respective proxies. The Russian interest in Syria, initially limited to protecting the naval base in Tartus and keeping Bashar al-Assad in power, is now widely believed to have a regional and global power dynamic. Russia controls 26% of proven global natural gas reserves and has long been frustrated by its inability to export to customers other than the European Union (EU) and NATO member states. Not only does this geographic reality leave Russia dependent upon a single block of customers that has access to other suppliers, but it limits Moscow’s ability to influence politics with its overwhelming market share. In late 2015 however, the Russian military mission in Syria began to present other opportunities to exploit the politics and the pipelines that crisscross that war-torn region, thus giving birth to the prospect of a new natural gas cartel.

The global energy market is changing. Traditional, fossil-based energy supplies like coal and oil are becoming increasingly expensive to find and extract. Political turmoil in the Middle East coupled with popular pressure to address climate change, make natural gas a more attractive option for future energy needs, particularly in Europe. With average global gas consumption likely to increase approximately 1.6% annually until 2040, Europe needs a strategy to secure supplies from beyond the Russian monopoly. This is not a minor concern in Brussels. Moscow’s 2014 closure of gas pipelines into Ukraine highlighted the linkage of Europe’s energy future to Russia’s political ambitions, yet EU sanctions against the Russian oil and gas industry are seen as a delayed and ineffective western response. Europe, like Russia, now has its eye on massive natural gas reserves in the Middle East.

A Layered Strategy

The war in Syria is a catalyst for strategic cooperation between Russia and Iran. By bringing together the combined weight of their massive natural gas reserves, Moscow and Tehran would be able to influence Europe in powerful ways. If they bring Qatar’s reserves into the deal they could create an OPEC-like gas cartel with control of 60% of the world’s reserves; a frightening degree of dominance over the increasingly strategic commodity. However, there are many geographic and political obstacles to this ambition, and it is in these spaces the Russian strategy is taking shape.

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Together, Russia, Iran, and Qatar possess more natural gas reserves than the rest of the world combined. Photo credit:

Distribution of Iranian reserves to Europe depends on the outcome of conflicts in Syria and Iraq and on the political independence of Kurdistan. These countries contain much of the existing regional natural gas pipeline transmission capacity. Stabilization of those conflicts presents an opportunity for positive Russian engagement with Turkey and forms the basis for a recent trilateral accord signed in Kazakhstan between Russia, Turkey, and Iran aimed at ending the Syrian civil war; an agreement made possible by an expansion of the Russian military mission there. Turkey, with an intense interest in the political future of Kurdistan, plays a unique role by controlling access to many of the natural gas pipelines aimed at Europe. More importantly perhaps, Turkey is the southernmost outpost of NATO and hosts the important US military base at Incirlik.

The notable absence of the EU, the US, and the United Nations from the Kazakhstan talks reflects an important aspect of Russia’s strategy: limiting western—particularly US—influence in the region. Though Iran is an enthusiastic and powerful ally in this endeavor, strategy alone is not enough as the US has some very real ties to the region. American bases in Turkey, Iraq, Kuwait, Bahrain, and Qatar form a defensive network that bolsters the political stability of many of Iran’s rivals; not the least of which are Israel and Saudi Arabia. As mentioned, Turkey’s own security is still based largely on NATO, and most of the Gulf Emirates are completely dependent on American hard power for their defense. Given robust and longstanding support for this political-military structure in Washington, it is not surprising that Russia and Iran are exacerbating tensions between all of America’s allies in the region, particularly Qatar and Saudi Arabia.

Russia and Iran are the unseen beneficiaries of fractured relations between the two important US allies. Saudi Arabia’s main regional rival, Iran, is hardly an ally of Qatar, though enduring cultural links exist between the two states that can form a basis for renewed affinity. There is evidence Russia is encouraging an economic tie as well through business deals between Rosneft, the integrated oil company controlled by Moscow, and the Qatar Investment Authority (QIA). It is here, where Russian, Iranian, and Qatari interests converge, that the possibility of a joint pipeline project begins to make sense.

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The eventual route from the Persian Gulf South Pars/North Dome gas field (red region, bottom right) to Turkey is of strategic importance in the Middle East. Photo credit: (pipeline routes added by Chris Golightly)

Overland transport of gas reserves from Qatar’s North Dome gas field will converge at the existing terminal in Ceyhan, Turkey, but could take several different paths. While Russia prefers a pipeline (IGAT-IX, above in black) along the Iran-Iraq border, the US backs a route that transits Saudi Arabia, Jordan, and possibly Israel and Syria. Whatever the eventual route, stability in Syria is vital for security of the entire coastal strip. Achievement of the Russian design depends upon three key elements: politically isolating the United States, fracturing its allies, and stabilizing the Syrian conflict on terms that are favorable to the Kremlin.

Though Russia clearly hopes to position itself as the lynchpin in the arrangement, neither Moscow nor Tehran possess the technology required to construct IGAT-IX or the high-end LNG export facilities required at its terminus. For that they require easing of western sanctions that currently prohibit US or European oil companies such as Exxon-Mobil from sharing technology. The framework for this collaboration already exists. In August 2011, Russian President Putin, and the Executive Chairman of Rosneft, Igor Sechin, met Rex Tillerson in Sochi when he was still CEO of Exxon-Mobil. There, the three signed co-operation agreements for ten joint ventures, including drilling projects in the Russian Arctic, exploration in the Black Sea, a joint Arctic research center, and substantial options for Rosneft to invest in projects in the Gulf of Mexico and Texas. Consequently between 2011 and 2013, Exxon-Mobil became the partner of choice for Rosneft and now puts Russia and Iran high on the priority list for exploration. The reciprocal cooperation and the elevation of Tillerson to Secretary of State increases the expectation that sanctions will eventually be lifted, or at least not increased. Already, the bill for increased sanctions against Russia, which includes prohibitions against certain dealings with its oil and gas industry, is hung up in the House of Representatives due in no small part to efforts by the US oil lobby.

The Cost of Inaction

The prospect of Russia and Iran controlling 60% of the world’s proven natural gas reserves aims right at the heart of European security. Addressing it will require energy-specific strategies that not only reduce demand through the use of renewable sources, but also political solutions that guarantee supply by stabilizing the Middle East. With European unity hamstrung by homegrown nationalist movements, and the United States distracted by an endless series of domestic political dramas, it is difficult for either to formulate such strategies for the long-term. While the West limits its efforts in the Middle East to defeating the Islamic State of Iraq and the Levant (ISIL), Russia and Iran are playing a much broader game that will ultimately be more effective.

The potential for a tightening of gas supply options is a sober call for Europe to overcome domestic distractions and concentrate on a comprehensive energy security strategy; one that incorporates development and commercialization of a suite of renewable energy technologies. This should include solar and offshore wind, advances in nuclear fusion, offshore methane gas exploration, and clean, dry fracking. Until Europe reduces its reliance on Russian gas and takes measures to ensure political stability in the Middle East, there will be a risk of unwanted influence from Moscow and continued uncertainty.

Chris Golightly is an Independent Consulting Engineer specializing in offshore renewable energy, based in Brussels. Prior to 2010 he worked in the Oil & Gas industry.


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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. Map Showing Azeri-Chirag-Gunashli, Shah Deniz, Absheron & Other South Caspian Offshore Fields. Source:

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.

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

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.

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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.

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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.


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

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

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

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

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

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

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

  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.

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

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

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

  1. Azeri Oil Field Wikipedia.

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

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

  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.

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

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

  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.

  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

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

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.


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:


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In These Times

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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.

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