After the spill: well incident response

How have industry's emergency response measures evolved in the years following Deepwater Horizon?

THE Deepwater Horizon incident will forever be remembered for its uniqueness, total commitment by all responding parties, its size and complications in the response, and as one of the worst oil spill disasters in US history.

Before Deepwater

The first offshore blowout in the US occurred in 1969 in the Santa Barbara Channel, when a well being drilled for Union Oil Company blew out on a bottom-supported platform, located in water depths of near 300 ft. After trial-and-effect efforts for 11 days, and a resulting oil spill of around 80,000 bbl, the blowout was contained. The blowout prompted public outrage and an immediate federal drilling moratorium. It also led to the establishment of the Environmental Protection Agency, and development and enactment of the Clean Air, Clean Water and Endangered Species Acts.

In 1989 the tanker Exxon Valdez strayed off course, ending up on Bligh Reef in Alaskan waters, and resulted in an oil spill of around 260,000 bbl, outsizing the Santa Barbara Channel spill and causing vast environmental damage. Once again the federal regulators responded with a new law. This one – called OPA-90 , the Oil Pollution Act of 1990 – put in place sweeping changes for both onshore and offshore companies transporting or handling oil and petroleum products with an impact extending to offshore exploration and production operations.

This new regulation now required verifiable response plans, standby equipment and trained personnel. It also required a clearly-identified "qualified individual" (QI) who has the authority and is required by law to initiate response operations with qualified resources for an effective and immediate response. This applied to a spill or potential for a spill, originating from any source, which includes responses to a blowout or potential for loss of well control or containment.

Industry embraced the requirements and implementation of OPA-90 by thinking only of the oil spill, and never really thinking about the fact that in exploration and production incidents, you have three components: point of discharge; mid-water transport; and surface slick and sheening, all of which can only be resolved through source control (blowout control).

By the late 1990s, deep-water exploration and production was in full swing with deep water producing twice as much as shallow water; the results encouraged oil companies to push the limits, exploring in ultra-deep water (5,000 ft and deeper). But it was not until 1999 that a well control company recognised the need to change well control response expertise requirements, and added the expertise and understanding to deal with the loss of structural integrity and stability for large bottom-supported structures and floating hull structures (TLPs, and semi-submersibles). This would combine well control, offshore vessel firefighting, and damage and stability expertise for effective response offshore.  

In 2001, Petrobras P-36 – the world’s largest semi-submersible – suffered an explosion and fire, killing 11 members of the fire brigade. The incident resulted in loss of stability and eventual total loss by sinking of the semi-sub. That should have been a major red flag to industry that the number one concern after personnel safety is the stability of the rig. If you allow the rig to sink, then you have already lost the battle for the best and shortest route to incident resolution, because it is easier and faster to work from a damaged floating platform compared to working subsea (which always takes longer and is much more difficult).

In 2004 and 2005, hurricanes Ivan, Katrina and Rita caused 46 large offshore platforms in the Gulf of Mexico to collapse, and resulted in leaks from many of the 500+ wells beneath these platforms. This resulted in the first major response for subsea well control, resulting in developing a small group of specialists to respond for containment, killing, and plug-and-abandonment (P&A). The need had been identified for a specialised component group within the response community for offshore oilfield subsea well control and debris removal. The mindset of subsea well control combines well control operations and engineering with debris removal (subsea salvage), and geotechnical and structural engineering, for gaining access into the well bore for a kill solution.    

An ever-changing industry learning curve requires many new plans and procedures. Typical planning prior to beginning any exploration programme has oil companies developing their emergency response, training and safety plans, including the selected subcontractor companies. These plans historically have been based on cross-matrix philosophies, relying on each individual company’s plans, and based on the standard incident command structure with validation audits typically conducted for compliance.

As offshore development in deep water and ultra-deep water was gaining momentum, response to pollution emanating from a subsea blowout was being considered as a minor impact, because scientific studies as far back as 1988 were still citing that oil would break up in the water column when originating from deep sources and not have sufficient structure when influenced by deep-water temperatures to cause significant surface impact. This type of logic is what allowed deep-water programmes to move forward based on subsea pollution control to be achieved through drilling programme management and the citing that “surface response resources were already contracted to meet OPA-90 requirements” of a worse case discharge (based on surface slick response criteria).

Deepwater Horizon

In 2010 a blowout occurred at BP’s Macondo Well in the Gulf of Mexico while being drilled from Transocean’s Deepwater Horizon semi-submersible drilling rig. The morning the incident occurred, BP’s response focussed on safety, and accounting for personnel. While Transocean and its appointed salvage contractor joined the BP incident command structure, their immediate needs for resources were delayed or slowed and they were unable to take control of directing the onsite vessels pouring water onto the Deepwater Horizon, despite the salvor holding a Lloyds Open Form to assume response control for the marine asset. Even the United States Coast Guard (USCG), in its final report, acknowledged a failure to assign a USCG Fire Marshal position, to assure that the fire was being responded to. What played out in the incident command structure (ICS) that day raises a major question that has yet to be addressed: Who is in charge of this type of response? The marine contractor or the oil company? The vessel captain, by law, is always responsible for the safety of their crew, passengers (contractor personnel) and vessel; the oil company is responsible for the well.

The typical stance of an oil company ICS team is focussed on responding to a well blowout, control of well, minimisation of reservoir damage and any oil spillage into the water, so it assumes it is in charge or just takes charge in an effort to limit its pollution liability and reputational damage. Because an oil company’s ICS team stands up for most emergencies whether pipeline, onshore, offshore production, drilling or maritime, those leading the response at the top are most likely not experts in all components of the specific emergency situation, especially subsea blowout control, but are trained in executing the response under the incident command system. This was the case in 2010 with the primary response components being:

1. The floating rig Deepwater Horizon and associated components owned and operated by Transocean, whose response objective and expertise is to save personnel and the Rig.
2. The well, known as Macondo, belonged to BP along with the well design and responsibility for all activities associated with the well site location, which puts their focus on saving personnel and shutting-in the well.  

A few conclusions can be garnered from the incident:

• With the ICS response being focused as a well blowout, there was a failure to immediately manage stability and integrity of the asset, and the offshore standby vessels were engaged with onsite search-and-rescue along with the USCG’s resources. No-one within BP’s ICS “circle of trust” had expertise in damage, stability and marine firefighting for a semi-submersible major event involving a well fire, that was able to take control of the vessels of opportunity or BP contracted vessels. The vessels self-coordinated and applied firewater to the Deepwater Horizon’s topsides, trying to do what they thought was the right thing, but this resulted in down-flooding inside of the rig compartments, leading to loss of stability and eventual sinking.
• Until the Deepwater Horizon was completely lost, it was evident that the rig was still connected to the riser and the well by the continuing fire fuel source and relative stationary position of the Deepwater Horizon, with the rig using the riser as a mooring to the seabed. The result was the conductor and riser became bent, resulting with the well structure out of perpendicular orientation and having limited options to gain future well control access with the loss of the rig and riser at the surface.

Relief wells have been employed at oilfields since the early 1900s as a final method for dealing with well blowouts that could not be brought under control using blowout preventer (BOP) equipment, and the same still holds true today. Relief wells in the early days targeted killing the wells at or near the well shoe (lowest point) by plugging the porous formation. Today, relief wells can be drilled with high levels of accuracy locating any point of the well, allowing milling (cutting) directly into the casing and providing the ability to pump kill fluids down the well bore to bring the well under control. The problem with relief wells is the time it takes to contract and mobilise resources, engineer the relief well, drill, intersect and kill the blowout well. This can take anywhere from 40–270 days, based on conditions. Macondo took 87 days because of the inability to gain access into the wellbore for a quick kill solution.

One of the most proven methods onshore for killing a well is known as a “well control stinger” to “bullhead” kill (ie pumping a kill solution down the well against the exiting pressure and fluids by inserting a stinger into the well conductor. This has been a proven method to bring an onshore or surface accessible well under control. Today when the conductor is not in the vertical position or orientations prevent landing an emergency BOP, as happened at Macondo, we have  the “subsea stinger” that has interchangeable stabbing tips for length and diameter, and is manipulated by ROV (remotely operated vehicle) to assist in latching onto the well at virtually any angle. With the stinger inserted, it can kill the well in the shortest amount of time and provides easy connection to equipment back at surface.

Once again the federal reaction to the Macondo blowout and loss of the Deepwater Horizon was the same as the response seen to the Santa Barbara blowout in 1969: a moratorium banning all offshore drilling until new safety precautions could be put in place for personnel and environmental protection.

As the oil industry grappled with quickly-implemented regulations that now required enhanced capabilities to respond and contain potential damage from future offshore blowout events, teams of oil company personnel and support contractor personnel headed to Washington DC to understand what it would take to get the offshore exploration industry and projects back on line and meet the new expectations. The results of this new regulatory requirement resulted in the initial development of two co-operatives (Helix Well Control Corporation and Marine Well Containment Company) providing drilling coverage in the Gulf of Mexico, and one response system specifically built for Arctic drilling programmes in the US waters of Alaska, known as the Arctic Containment System. All three were based on the same drivers: emergency BOP stacks ready for deployment, to cap the blowout well if they could be actually installed during the blowout, and subsea collection of oil blowing from the well with surface storage and or disposal capabilities.

All three systems are based on the same principles regarding the topside process equipment and systems for oil-water separation and flaring capabilities. All three systems were proven for throughput capacity validation, but only the Arctic Containment System was required to be put to full system operational testing at depth for operational approval. This system is the only one that used a positive mechanical subsea pump suction collection dome to assure a zero sheening operation, built to rigid oil company requirements, Class Society (Marine and Polar Codes), USCG, EPA, and State of Alaska standards and 100% redundancy of all systems. Today the co-operatives have amassed major warehouses of equipment for oil entrapment at its exit point to be in place while a relief well is in process, along with an assortment of emergency BOPs (if it is possible to install a BOP). Today, the oil industry’s main focus is to ensure the drilling BOPs are the main defence, since BOPs are the most important piece of equipment for the safety of the crew and natural environment, as well as the drilling rig and the wellbore itself. With new inspection and test requirements (and new inspection services such as real-time monitoring for BOPs) it is believed a higher level of safety has resulted.

However, there is still no formalised training programme to certify standby vessel personnel as having the knowledge to manage response to an offshore casualty, understanding of rig stability, nor how that combines with firewater application and rig crew evacuation and recovery.

The industry still needs an integrated “full mission” training simulator which can, in a safe environment, bring all functions of the drilling, the rig and the standby vessel missions together. Real-life scenarios would help to work out the human factors involved in a full response and communication-action results tool. This raises the question: why do the oil companies not require this level of training and coordination planning, and why have more of the funds BP provided not been spent on improving the offshore response capabilities?

Response philosophy

The lessons learned and insights gained since Deepwater Horizon have reshaped the overall response philosophy. Industry improvements in its response capability include developing co-operatives to manage the equipment inventories, BOP equipment testing and worker training, real-time BOP monitoring, and subsea containment response systems.

However, there still exists only a very small group of personnel with the available expertise in subsea emergency response, and limited means to gain this knowledge. First-hand experience gained in the field of subsea well control needs to be brought into the planning phase of well design, new BOP configurations, review of co-operatives' equipment and subsea kit, and personnel qualifications for those involved in response decision-making. As shown by the Macondo response, future deep-water responses will likely require ALL of the known resources to bring a subsea blowout to conclusion.

Well control is a very specialised body of knowledge that has always resided within a niche industry and subsea is an even smaller group of specialists, that live and breathe this type of work, drawing on career-long experiences, experience that very few in industry are educated and mentored to hold. The importance of survival for these small niche experts is more important than industry and government realise, which explains the continuing lag in using and seeking out this knowledge during programme development because well control fails to be a budget line item.

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This article is part of series called Deepwater Horizon: a Decade On. Read the rest of the series here

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