The complexity of capping an oil and gas well fire

Controlling and resolving oil and gas well control incidents requires an expert team and specialized equipment. The author provides insight into this complex and challenging part of the oil and gas business and the path to safely remediating an unplanned event.

Chris Stover / Wild Well Control
Oil and gas well fires are among the most fearsome and devastating disasters in the energy industry. When these fires erupt, they can quickly transform into towering infernos, spewing smoke and flames into the atmosphere, causing immense environmental damage, and posing significant risk to human life, Fig. 1. The process of capping an oil and gas well fire is an intricate and perilous operation that requires an expert team and specialized equipment. This article explores the complexity of capping an oil and gas well fire, exploring the challenges involved and the strategies employed to bring these blazing giants under control.

Before we can understand the complexity of capping an oil and gas well fire, we must first comprehend the anatomy of such fires. Oil and gas well fires occur when hydrocarbons from the wellbore are unexpectedly released into the atmosphere and ignite. These fires are characterized by a variety of elements that make them particularly challenging to extinguish, as follows.

Intense heat. Oil and gas well fires produce extreme heat, with temperatures often exceeding 2,000oF. This intense heat not only exacerbates the fire but also makes it challenging for well control specialists to approach and control the incident.

Unpredictable behavior. The behavior of an oil and gas well fire is highly unpredictable. Factors like the wellbore geometry, reservoir pressure, and formation stability can cause the fire to behave erratically, changing its direction and intensity suddenly.

Environmental concerns. These fires can release copious amounts of pollutants into the atmosphere that must be managed and contained until the well is brought under control.

Capping an oil and gas well fire is an intricate process that involves several challenges, both technical and logistical. Below, we examine these challenges in detail.

Safety is paramount during any well fire capping operation. Well control personnel face extreme heat and hazardous conditions. Proper protective gear, training, and risk management are essential.

Remote locations. Many oil and gas wells are in remote or harsh environments, making access and logistics a significant challenge. Whether it’s a desert, offshore platform, or Arctic tundra, reaching the well and transporting equipment can be an arduous task.

Equipment and expertise. Capping a well fire requires specialized equipment, such as Athey wagons, heavy equipment, and firefighting pumps. Expertise in proper utilization of this equipment is essential for a successful operation.

Rig debris. Wells that are in the drilling or workover phase utilize a drilling rig that sits over the wellbore. When a well ignites, the drilling rig has the potential of collapsing, due to the heat stress. The team must have a deep understanding of the techniques used to remove debris from around the wellhead to prevent further damage.

The process of capping an oil and gas well fire can be broken down into several stages, each with its own complexities:

Assessment. The first step is to assess the situation. Before work on location can begin, a site inspection is done to identify any hazards that may be present. Once this is complete, a forward plan can be developed.

Evacuation. If human lives are at risk, evacuating the area is the first priority. Well control personnel must ensure their own safety and that of anyone in the vicinity.

Firefighting. Specialized firefighting pumps are employed to protect personnel from radiant heat while working near the well. The water curtain allows personnel and equipment to remain cool while gaining access to the wellhead in preparation for capping. This stage of the process includes installing a new wellhead, if deemed necessary.

Capping. Installation of a blowout preventer (BOP) capping stack allows the well to be shut in or diverted. Diverting the well occurs, if there is a possibility the casing string has been damaged, due to the uncontrolled flow of the well. The well is allowed to flow in a controlled manner to earthen pits or a temporary production facility while kill operations are conducted.

Environmental cleanup. After the fire is extinguished, the environmental impact must be addressed. Contaminants released during the fire, such as oil and gas, need to be contained and cleaned up.

Depending on the scope and size of the event, a relief well may be often considered as a contingency option alongside capping operations to regain well control. Relief wells are complex operations that often involve operational and safety-related risks. Relief wells can complement capping operations, and in the rare cases where capping is impossible because of the absence of well infrastructure at the surface, a relief well offers an alternative solution.

Importance of preparedness. Well Control Emergency Response Plans (WCERPs) provide a strategic process for responding to, and safely managing, well control emergencies. Usually, they form an important subset of a company’s corporate-level all-hazards emergency response plan. The characteristics of onshore, offshore and subsea wells are different from each other. The complexity of subsea wells and the need for specialized equipment to access them means they require their own dedicated and highly detailed Source Control Emergency Response Plan (SCERP). A good well control planning provider will invest time in exploring all their customer’s logistics, organizational details and operations to create the best tailored solution.

The WCERP also must include the necessary initial notifications and responsibilities at the outset of a declared well control event. This may involve organization charts in line with your incident management philosophy. Completing this step creates a clear definition of how a well control emergency is to be declared, as well as who is responsible and what initial notifications must occur. Once the WCERP is published, the response strategy and expectations should be shared with local first responders. This is often accomplished during exercises and workshops, where relationships are built before an incident occurs and broadens the scope of resources. Ultimately, this should make initial notifications much easier and pave the way for the most successful response.

Offshore Well Control events, which occur on offshore rigs and platforms, present their own set of unique challenges. Offshore blowouts are a true test of the industry’s capabilities, and the solutions often involve a combination of specialized equipment, detailed planning, and highly trained personnel. The complexity of capping an offshore well is amplified by factors such as:

Remote location. Offshore rigs are often located far from shore, making it difficult to transport personnel and equipment to the site quickly.

Subsea wells. Deepwater events involve wells that are located on the ocean floor, adding a layer of complexity in terms of well access and capping.

Environmental concerns. In offshore well control events, environmental damage is exacerbated, due to the release of pollutants into the ocean, affecting marine life and ecosystems.

A production well in a mature field in the Middle East blew out gas from a known formation to a tortuous flow path of unknown sections of the compromised casing and packer via compromised tubing. Surface broaches from the production tubing and casing were observed as far as 300 m from the blowout well. There was an uncontrolled flow of formation fluids, due to the irregular and ever-changing surface tubing and production casing pressures. Furthermore, cathodic protection wells in the area were showing signs of gas and fluid production that were not in production intervals.

Identifying the problem. The wellhead showed no signs of broaching or instability, allowing wireline logs to be run and evaluated. Production spinner survey, temperature, and tubing integrity logs were performed. The production spinner survey demonstrated changing velocities, as the log progressed to the bottom of the well. Usually, this is an indication of holes in the production tubing. The temperature log highlighted a significant cooling interval at approximately 2,000 ft, indicating a large volume of gas expansion to the annulus and most likely outside of the production casing. A tubing integrity log was performed, but results would take several days before they were available for evaluation. At the client’s direction, an inflatable plug on coiled tubing was installed as deep as possible and set to block the flow, but this was unsuccessful.

As pressure built up in the thief reservoir, nearby cathodic protection wells began to flow oil, gas and water from a shallow, water-bearing formation. As they did, they were filled with cement. This process was initially successful at stopping the flow, but as pressures in the shallow reservoir were unable to relieve themselves, they increased, and additional water and cathodic protection wells (up to 800 m away from the blowout well) continued to flow, to relieve the pressure that was building.

Initial remediation efforts included pumping mud and brine from the surface to attempt a well kill, which was unsuccessful. It was determined that a hydraulic workover unit would have to be installed to pull the tubing as the well continued to flow, and a new, uncompromised string of tubing could be installed, and a dynamic kill performed.

BOP installation. Since the tubing was compromised, it was agreed that BOPs would have to be installed to allow the cutting and removal of the tubing from the well, one or two joints at a time while maintaining pressure integrity on the well. A snubbing unit and additional BOPs were mobilized. After the production tree was removed, and the hanger was latched, a radial torch cutter on wireline was used to cut the production tubing above the inflatable plug (above the production packer). The hanger was pulled into the BOP stack, the tubing was cut with BOP shear rams, and the hanger was laid down, Fig. 2. The tubing fish required milling within the BOP stack to allow latching the lower fish with an overshot. This drastically increased the timeline to cut and pull the tubing string from the well.

Contingency planning included utilizing a relief well to intersect and perform a dynamic kill operation. Initial planning considered using an existing nearby wellbore for re-entry and side-tracking. Satellite imaging showed that the area near the wellbore was increasing in height, making drilling a new well risky. Teams were mobilized to engineer and plan side-tracking operations on an existing well to make an intercept and dynamic kill.

Under control. Additional broaches occurred and caught fire, increasing the incident visibility, and requiring a rapid resolution. By the time the hanger was removed and laid down, the tubing integrity log was available for field personnel to review. The integrity log showed the location and size of the holes through the tubing string. It was suggested to the operator that a dynamic kill was a feasible option through the open-ended tubing, even though there were holes throughout the tubing string. A surface broach ignited that evening, and due to wind conditions, the location was shut down and evacuated. After the location was secured, a dynamic kill through the damaged tubing string became the primary option to regain control of the well.

Fluid densities, pump rates, and volumes required for a successful, dynamic kill attempt were calculated. After the fluid was mobilized, a high-pressure pack-off was installed to the tubing fish in the BOP stack, and a dynamic kill through the tubing was simulated and completed with 500 bbl of 9+ ppg NaCl brine, followed by about 500 bbl of 17+ ppg OBM at a maximum rate of 10 bpm. The well was topped up with five bbl of 9+ NaCl brine before the pressure was observed, indicating the well was full. The pressure was monitored for 30 min. without any changes, confirming the well was dead.

Plug and abandonment. Once the well was confirmed dead, the tubing was pulled and laid down conventionally, without the need to shear and lay down each joint. Visual assessment indicated that the radial torch cut failed to cut the tubing, and the production packer was still attached to the tubing. This eliminated a separate trip to recover the packer. With the tubing and packer removed, a cement retainer was installed above the production perforations, and the well was secured with a cement plug.

Benefits of frequent monitoring. Operators in mature fields experiencing well integrity problems in aging assets regularly monitor tubing and casing pressures to determine when the casing barrier envelope may have integrity issues. Having a clear insight into their well’s integrity makes planning significantly easier. Wells that are left unattended, or not monitored regularly, require significant diagnostic efforts to remediate. Wells flowing underground pose an additional risk of broaching before ultimate resolution. This factor should always be planned for, in case a surface broach migrates to the well pad or around the wellhead itself.

Producing wells with compromised barriers and poor wellbore integrity present some of the most complex well control challenges. Loss of wellbore integrity above the depth where natural sediment strength can contain reservoir-induced pressure creates a situation where the kill operations must be implemented from the bottom of the well. However, uncontrolled downhole flows and mechanical tubular damage often make re-entry difficult or impossible. Furthermore, broaching adds significant risk to personnel and assets during control operations. These situations, even on normally pressured producing wells, require extensive diagnostics and extraordinary means to resolve safely. Many of these difficult and costly events can be avoided via frequent monitoring to identify the first indications of wellbore integrity issues and acting immediately to isolate the problem, well before an uncontrolled flow develops.

Capping an oil and gas well fire requires extraordinary skill, specialized equipment and unwavering determination. The complexity of these operations cannot be overstated, as they involve a combination of firefighting, well control, and environmental management. These efforts, often conducted in remote and hazardous environments, demonstrate the incredible dedication and innovation needed to control oil and gas well fires. For nearly half a century, Wild Well Control has been at the forefront of preventing and resolving all types of well control events across the globe.

About the Authors
Chris Stover
Wild Well Control
Chris Stover is GM of Well Control Operations for Wild Well Control, a Houston-based company that specializes in firefighting, engineering, and training services. Mr. Stover has been with the company for 25 years and has extensive experience capping oil and gas well fires, maintaining client relationships and conducting presentations to showcase the company’s expertise in responding to global well control emergencies. His role also involves dispatching personnel and equipment to well control emergencies, assisting clients with tabletop exercises and supporting clients both in their office and the field during well control events.

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