January 2017
Special Focus

Inferno in the Caspian: Regaining control of a 30-well production platform

Hurricane force winds led to a multi-well fire on a 30-well production platform. In spite of continuing adverse conditions, well control specialists were able to safely extinguish the blaze in 64 days, 25 of which were non-productive due to the weather.
Mike Foreman / Boots & Coots—A Halliburton Service Miguel Munoz / Boots & Coots—A Halliburton Service Will Paulsen / Boots & Coots—A Halliburton Service


 Gunashli field lies in the Caspian Sea, 75 mi east of the city of Baku, Azerbaijan, and 7.5 mi southeast of the city of Neft Daşları, Fig. 1. The Shallow Water Gunashli (SWG) field, on the northwestern tip of Gunashli field, is situated in a water depth of 390 ft, and is tied into the infrastructure of the giant Azeri-Chirag-Gunashli (ACG) oil field.

The platform produces about 6,700 bopd and 38 MMcfgd. Approximately 60% of the oil produced by the State Oil Company of Azerbaijan Republic flows through it. Given the large number of personnel working on the platform, the enormous value of the assets, and the colossal volumes of oil produced, the threat of fire is an essential aspect of the overall risk management associated with oil platforms such as these.

Fig. 1. Gunashli field lies in the Caspian Sea, 75 mi east of the Azerbaijani capital, Baku.
Fig. 1. Gunashli field lies in the Caspian Sea, 75 mi east of the Azerbaijani capital, Baku.


On the night of Dec. 3, 2015, the wind across the western Caspian Sea rose to hurricane-force levels. The waves built to 11 m high, more than 30 km offshore from the Absheron Peninsula, which juts into the sea, just north of Baku, the capital of Azerbaijan. The winter storm did not subside, and it built through the morning and afternoon of Dec. 4, with winds of 89 mph. Without warning, at 17:40 local time, the storm caused a rupture in a high-pressure, subsea, natural gas transmission riser on the 30-well production platform. The gas ignited spontaneously, and an explosion ripped through the platform, causing a fire to break out in the northern part of platform No. 10.

As a result of the fire, the platform—which had been in service since 1984—began to partially collapse. The explosion and the consequent radiant heat produced from the pipeline rupture quickly initiated damage to adjacent wellhead seals. As the seals progressively failed, five oil-producing wells and three additional gas-producing wells on the platform caught fire, triggering blowouts as escaping gases ignited. The remaining 22 wells on the platform also were damaged and were in danger of catching fire. Production from all 30 wells (26 oil wells and 4 gas wells) connected to the platform was suspended, and pipelines that connected the platform to the shore were closed.

Constant wind, and waves up to 11 m high, prevented supply vessels from approaching the platform. In the meantime, the Incident Command was organized, and well control contingency plans were activated. Well control specialists arrived in the country within hours of the occurrence of the incident. As they boarded the platform, the specialists were briefed by the Incident Control team and incorporated into ongoing operations. A site survey of the platform was conducted immediately, and an assessment of the damage and access routes was established.

This assessment provided a precursor to the comprehensive risk analysis that was performed to evaluate the condition of the wells, and to identify existing hazards. This enabled detailed procedures and protocols to be constructed for the forthcoming operations and future intervention. As part of the existing platform safety features, steel firewalls had been installed; these firewalls separated the well bay area from the production facility and living quarters.

Although the integrity of the firewalls had been compromised by the blast, and subsequent direct and radiant heat, they still provided sufficient protection and insulation, limiting what would have otherwise resulted in further, extensive structural damage to the platform. In addition, the extreme heat from the burning wells caused the top deck of the well bay area to collapse onto the wells, resulting in further damage to the wellheads. This collapse also threatened the stability of the platform, and it further impeded access to the well bay area.


One of the main concerns was to maintain the stability of the platform, which was deteriorating rapidly, as a result of prolonged heat exposure. Three oil wells were positioned at one end of the well bay, and five wells were at the other end. Fortunately, the remaining wells were producing by means of a gas lift process, and the operation could be shut down, thereby extinguishing these wells and limiting fires to the two ends of the well bay area.

The initial task of securing the three oil wells on the northwestern side of the platform became a priority, because they were producing excessive smoke that created extremely hazardous working conditions. Over the following week, the local well control team, with the assistance of well control specialists, tied onto the existing injection lines on each well, pumped and killed these three oil wells, and extinguished the fires on these wells. This work was completed under an umbrella of seawater, provided by five fireboats and a temporary fire system rigged up on the platform by the operator.

Fortunately, the structural integrity of the firewall remained intact and sufficiently prevented the conflagration from damaging the main platform superstructure, including the accommodation block. Multiple fireboats were mobilized to the scene and assisted in mitigating direct and radiant heat damage by continuously showering the platform with seawater. However, in creating a heat shield and isolating the well bay area, the firewall also restricted access to the blowing wells. This was a challenge for the well control team to overcome. 

Yet, after careful consideration, it was concluded that a section of the firewall had to be cut away to gain access to the well bay area. This was to be completed despite the intensity of the burning wells and the hazardous instability of the immediate area. Because of the obvious uncertainties, a further risk assessment was conducted, and a plan of action was formulated to mitigate the dangers that the team could encounter.

Ongoing severe weather and exceptionally heavy seas continued to be encountered, which provided additional challenges that consequently delayed progress. There were several days in which the well control team was unable to board the platform safely, because of the adverse winter weather conditions.

Fig. 2. Plan view: fire monitor rig-up. Monitors are fed by pumps, which, in turn, are fed  by seawater.
Fig. 2. Plan view: fire monitor rig-up. Monitors are fed by pumps, which, in turn, are fed by seawater.


In typical blowout situations, a relief well is planned and will often be drilled from an offset rig to kill the blowing wells at the source of the hydrocarbon influx. Because of the complexity of this event, and the challenges involved with constructing relief wells in such conditions, the operator agreed to continue to plan the wells, but, in the end, chose not to follow through with their construction. The well control team had the utmost confidence that surface intervention would be successful on all wells. 

With the protocols developed, the team could begin the well control operation. When sea conditions became more favorable, the firefighting equipment was brought aboard; the fire pumps were lifted from the supply vessels and rigged up in strategic positions on the platform, and electric submersible pumps were installed to feed the water supply required, ensuring a reliable deluge system was continuously operational, Figs. 2 and 3.

Fig. 3. View looking northwest: fire monitor rig-up. Monitors are fed by pumps,  which, in turn, are fed by seawater supply.
Fig. 3. View looking northwest: fire monitor rig-up. Monitors are fed by pumps, which, in turn, are fed by seawater supply.

This rig-up made it possible for crews to work more efficiently and enabled them to continue to work, even during severe weather days, as long as crews could maintain a safe working environment. The remaining components of the fire system were rigged up with water monitors on both the upper and lower decks, to provide the water coverage required for personnel to work safely.

With the operation in full swing, with fireboats providing a blanket of water, and the well control company’s firefighting package fully operational, the well control service team began the forward plan to gain control of the remaining wells. To limit further environmental damage, all wells were left to continue to burn as much of the hydrocarbons as possible, until they could be killed and capped. Furthermore, this strategy eliminated the danger of unexpected re-ignition, had they been extinguished, Fig. 4.

Fig. 4. The wells were left burning until they could be killed and capped.
Fig. 4. The wells were left burning until they could be killed and capped.

The operation to secure these wells began by removing damaged sections of the top deck, water storage tanks and a section of firewall on the southwestern side of the platform. Temporary safety barriers were put in place to create a safer work environment, but still enable access to the remaining wells. After the debris removal, the other two oil wells were capped, using a capping assembly on the existing wellheads. Smaller debris was removed from around two of the three gas wells, to provide access for the abrasive jet cutter.

The abrasive jet cutter is used for cutting and removing the wellheads, which is essential to redirect the fire from the blowing wells in a vertical direction. Because of the erratic sea conditions and the resulting instability of the crane, the decision was made to fabricate a rolling boom section with a track system for positioning the abrasive jet cutter around each of the three remaining wells.

 The abrasive jet cutter was installed on the outermost gas well, on the southwest, side. Halliburton pumping and sand delivery equipment, which had been rigged up previously on a workboat, was tied off to the safe area of the platform, and the high-pressure pump line was rigged up to the cutter. The cut was completed successfully between the A and B sections of the wellhead, where the flange connection had separated and the 7-in. casing had been exposed.

With the cut completed and the wellhead removed, the fire plume was directed vertically, making the well accessible to personnel. A pre-assembled capping assembly was then installed on the well, and the well was shut-in and killed by pumping seawater into it.

The abrasive jet cutter was then moved to the center well, which was cut successfully above the lower flange of the B-section of the wellhead. With the well now flowing vertically, the A-section was inspected for damage. After it was determined that the wellhead was too damaged for capping operations, an oxylance cutting system was used to split the wellhead, to enable its removal.

 The casing was stripped back to expose the 7-in. and 95/8-in. casing in preparation for the capping operation. With the new wellhead installed, slips set, and the manual seal energized, the well was capped with an operator-supplied capping assembly. The well was shut in and killed with seawater. 

The completion of these two wells enabled access to the third and final well, in the west corner, on the port side. The debris remnants were removed from around the well to gain access, and the abrasive jet cutter with the track was rolled into position. The B-section of the wellhead was severed above the lower flange, and the fire was immediately directed vertically. The well control specialists were then able to inspect the A-section of the wellhead and determined that the damage was too extreme for capping operations. The oxylance cutting system was used to remove the A-section, enabling the casing to be stripped back for capping operations, similar to the process used in the previous well. A new wellhead was installed, and the slip and manual seals energized. The well was then capped with an operator-supplied capping assembly.


The well control intervention was completed, and the last fires were extinguished on Feb. 10, 2016; these efforts required a total of 64 days. Of these 64 days, 25 were non-productive because of adverse weather that prevented access to the platform, a fact that attests to the severity of the operational environment. It was essential that the deluge system remain effective, and reliable, to significantly reduce heat damage and to provide protection for the teams working in these highly hazardous surroundings.

The planning that occurred after the initial site survey was essential to gain safe access to the wellheads, by managing both direct and radiant heat, which, left unchecked, could have resulted in the collapse of the entire platform and led to a far more complex situation. The job was performed safely, and no injuries were recorded. The involvement of experienced well control specialists, who are practiced with working multi-well incidents, contributed significantly to the successful completion of the task.wo-box_blue.gif 

About the Authors
Mike Foreman
Boots & Coots—A Halliburton Service
Mike Foreman started his career in 1985, working for Red Adair. Since then, he has been involved in the maintenance and repair of firefighting equipment, served as shop manager, and then as a well control specialist and senior well control specialist. Mr. Foreman has traveled around the world multiple times, controlling oil and gas wells on six continents. At Red Adair Co., Mr. Foreman’s roles ranged from helping to control the Piper Alpha disaster in the North Sea, to fighting fires in Kuwait following the first Gulf War in 1991. Highlights of this period in his career include controlling a gas well in India that produced in excess of 500 MMcfd, as well as being team leader on his first job controlling a well producing more than 20,000 bopd in Venezuela. Mr. Foreman is now a senior well control specialist for Boots & Coots.
Miguel Munoz
Boots & Coots—A Halliburton Service
Miguel Munoz is a Boots & Coots’ well control engineer. Mr. Munoz holds two degrees and has 20 years of experience in the oil and gas industry, working for companies involved in workover and drilling operations. In 2010-2011, he held the position of snubbing-HWO operational manager for Boots & Coots in Venezuela. He is now a member of a group of nine specialists who provide response services. Since joining Boots & Coots in 2003, Mr. Munoz has worked in highly diverse situations all over the world.
Will Paulsen
Boots & Coots—A Halliburton Service
Will Paulsen began his career with Expro Group in 2007. He has worked extensively throughout the Gulf Coast region, as well as on assignments across the continental U.S. Mr. Paulsen joined Boots & Coots in 2008 and worked in Equipment Services as lead operator on projects in the Haynesville shale, the Eagle Ford shale, Poland and Slovenia. He expanded his experience by being a member of a team of well control specialists assigned to complex source control projects in the Gulf of Mexico, the Bay of Bengal, and the Caspian Sea.
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