Fire on closely spaced six-well pad illustrates heightened need for well control risk mitigation in pad drilling
Close proximity of well pattern created access challenges, but contingency planning and efficient communication enabled rapid containment
By Arash Haghshenas, Andy Cuthbert and Leonardo Portillo, Boots & Coots, A Halliburton Service
Efforts to help reduce environmental footprint, infrastructure and development costs have led to an increased use of pad drilling. However, the close proximity of wells in pad drilling increases the risk of more severe consequences during well control incidents. In the case of a burning well, both radiant and direct heat can potentially ignite adjacent wells, threatening both human life and equipment and detrimentally affecting the immediate environment. This article describes challenges and lessons learned from controlling a multiwell pad blowout.
A series of six wells with 15-ft spacing was drilled on a pad. Each well was completed with multistage hydraulic fractures. However, during flowback operations, a well developed a leak through a flowback line connection. The gas exiting the well eventually ignited, and the heat from the fire damaged the seals and wellhead equipment on neighboring wells. This caused all of the wells on the pad to develop leaks, which consequently caught fire.
Successful well kill operations using surface well intervention subsequently secured all of the wells. This article provides insight into the challenges of containing a blowout on closely spaced well pad configurations and highlights lessons learned.
Pad drilling consists of closely drilled horizontal or highly deviated wells. The spacing between wells can be as close as 10 ft, and the number of wells on each pad depends on the production enhancement techniques, drainage area, and size and capability of the drilling rig. Reservoir engineers and geologists determine the appropriate number of wells for each pad to maximize drainage, which determines the economics of the field. The wellhead spacing surface layout, therefore, depends on operations, completion and production equipment.
The economic base case for well pad drilling is similar to that used for mass production. Multiple wells will be drilled from one pad. Therefore, fewer locations and less preparation are required. Consequently, the number of access roads can be minimized. Newer rigs have the capability to move under their own power onto the pad and do not have to be broken down, which significantly reduces the time between rig moves. Pad drilling can use local resources for providing services and resources, such as water and electricity, with an overall potential of reducing the cost of operations and temporarily adding to the local economy.
Contingency planning for pad drilling should place high emphasis on risk mitigation and control of operations because of the proximity of neighboring wells. It may not be physically possible to deploy certain equipment or undertake industry procedures because of the restrictions posed by the nearby presence of other wells on the pad. Therefore, the risk of any incident on a pad is several times greater than that for a single well location.
In the event of a blowout and fire, the heat from the well will impinge on neighboring wells, leading to the deterioration of the wellhead sealing elements. Prolonged exposure to the heat causes the development of leaks, which may spontaneously ignite and eventually lead to similar fires on all other wells on the pad. Consequently, the effect of a single incident automatically involves all wells on the pad. The response to the incident is more complex because it is not a matter of addressing a blowing well in isolation. The combined heat emanating from the ignited wells restricts safe access routes to the wells. Wind direction also must be considered in the contingency plan when approaching the access points to the location.
After killing the wells, the wellheads must be secured by installing a safety valve by means of the completion tubing. Wells must be protected from direct and indirect heat by installing strategically placed heat shields. It is critical to observe the wellheads to identify seals that are at risk of failure, leading to further hydrocarbon leaks to the surface. If the risk of failed seals is anticipated, contingency plans for managing leaks should be prepared in advance.
If the wells are fractured, the kill fluid in the well may be lost to the formation, reducing the hydrostatic head, and enabling gas to percolate into the tubing. As a result, the pressure at the surface increases and could compromise seal integrity. Therefore, the pressure at the tubing should be monitored for indications of pressure buildup and tubing plug failure.
Well plans and pad design should consider the distance between the wellheads to accommodate well intervention activity and source control operations, including contingency planning. Several factors, such as the pattern of wells, alignment of wellhead valves in relation to other wellheads, and spill barriers significantly influence contingency planning and potential source control operations. Risk mitigation during planning, audits and well integrity management reduce the risk of occurrence of incidents. A robust and comprehensive evaluation is required for analyzing well control risks on a multiwell pad location.
On a land location in the US, a series of six wells with 15-ft spacing was drilled on a pad site, targeting formations within different pressure regimes and with differing fluid properties. Each well was completed with multistage hydraulic fractures to enhance production. After completion, the wells were flowed back to clean the hydraulically created fractures before going on production.
A production facility was located adjacent to the drilling pad to process and measure production from each individual well. During the flowback process of the last well, a leak developed, and the exiting gas ignited. Direct and indirect heat from this fire damaged the seals and wellhead equipment on neighboring wells, eventually causing a cascade effect whereby all the wells on the pad developed leaks and caught fire. Figure 1 shows the progress of the fire: The left side shows the initial aerial view of the incident after the first well ignited in the afternoon, and the right side shows that all wells were on fire the following morning.
The location was safely evacuated, and an incident command process was put into action. The initial activities involved establishing zones, restricting access to non-essential personnel and managing spill control. The area around the well pad was divided into three zones:
• Hot or exclusion zone, which covered the well pad area where the source control team performed its tasks. Figure 2 shows the aerial view of the well pad (hot zone) during the source control operation.
• Warm or decontamination zone for preparing required equipment or personnel for certain functions. The area covered the close vicinity of the well pad.
• Cold or support zone for all support activities for containing the incident. The incident command center (ICC) and all other support operations were located in the cold zone. A staging area was located in the cold zone and adjacent to the warm zone for back-up or heavy equipment to enable a quick response to any emergency event during the source control operation.
As soon as the incident was reported, well control specialists were mobilized to the location to assess and contain the wells. The required equipment was simultaneously mobilized to the location, including fire pumps, fire monitor stations, Athey wagon, jet cutters and stingers. The well control equipment was preloaded on trailers, which enabled rapid response to the incident.
The area around the pad was contained, and a safety team on location monitored air quality, wind direction and weather conditions to alert the team to any potential hazards as the operation progressed. In addition, the safety team provided aerial views of the situation and operations that delivered information for evaluating the situation and for communication with offsite personnel.
By the time the well control specialists arrived, another well had developed leaks around the wellhead seals and caught fire. The third well indicated some degree of heat degradation, and a leak was anticipated. Based on the onsite assessment, it was concluded that flames would cause a cascade effect on the other wells and equipment on location. Debris clearance for accessing the site had already begun.
Barriers were erected around the pad as part of the spill containment plan for the pad site before beginning drilling activity. These barriers were used to define the hot zone and to manage spills. The air quality around and away from the hot zone was continuously monitored by means of a system that was installed on the edge of the well pad to provide remote monitoring of the operation and evaluation of situation.
A safety and security team monitored personnel location in case of emergency and prevented non-essential personnel from accessing the site, which was critical to the safety of the operation. Radio frequency identification cards were used as a security measure and to track personnel in the hot zone. A dedicated safety officer evaluated the hot zone before and during the source control operation, constantly monitoring the air quality and heat levels around the wells.
The prevailing wind direction for the location was ascertained to determine the safest location for staging personnel and equipment. As the source control operation got under way, the specialists monitored the behavior of the burning wells, especially in relation to the wind direction, to be able to react accordingly. An access road was built, and an emergency road was added as a contingency should an additional evacuation route be required. The spill recycling and source control staging areas were sited at opposite ends of the pad, which eliminated conflict between teams and created sufficient space to accommodate the source control equipment.
The pad spill control system proved to be effective at collecting residual water. Collection and separation ponds were located at the edge of the barrier for processing these fluids, and a series of pumps were used to transfer fluids away from the barrier (hot zone) to a safer area (cold zone) for further processing. The effectiveness of the spill control process was closely controlled and reduced the need for required personnel in the hot zone. The source control specialists graded the pad to slope toward the spill collection pond to reduce fluid accumulation.
While spill control efforts were under way with the assistance of the source control team, equipment was staged on the location. Water for fire control was delivered using a network of pipelines that provided a continuous water supply. An additional spill control barrier was built between the wells and the equipment on the well pad to prevent water pooling in the staging area. Water monitors provided a water curtain to reduce the intensity of radiant heat affecting source control activities. It also provided protection for equipment used in the hot zone.
The position of fire monitors depended on the prevailing wind direction and the activities performed. Several supply lines were connected to the fire monitors through a manifold system for temporary use and fire watch purposes. With the water curtain protection, debris could be recovered safely from the well pad and then collected in a segregated location for evidence analysis by the investigation team.
The slugging sequence in the well was identified in which water, condensate and gas are emitted from the well in a series of discrete “pulses.” Although most wells had been flowed back, a notable water flow was observed to be emanating from the wells. From time to time, the slug of water put out the fire from the well, but the gas plume from the leaking well almost immediately reignited it.
When the original production trees were installed, the casing valves, which were aligned in series, pointed directly toward adjacent wells. The initial gas leak and ignition precipitated a cascade effect in which the other wellheads developed leaks, consequently igniting and feeding one another, intensifying the complexity of the event. Figure 3 shows the cross-fire of a side valve of one well affecting two neighboring wells and hindering any immediate mitigating action as a result of the concentration of the conflagration.
The wells on the pad had been drilled with a 15-ft, center-to-center spacing, which made the available space between them very narrow and hindered the ability to easily move equipment, isolate wells or undertake an optimal source control operation. Figure 4 provides a diagram of the wells on the pad. Because of these considerations, a detailed plan for controlling and isolating the wells had to be developed quickly and efficiently.
With all safety measures in place, the source control plan was implemented. To avoid confusion or misinterpretation, the wells were numbered from the source control staging area, with well #1 being the closest well. Given the risks, the decision was made to initiate the containment and isolation of the wells beginning with well #1. Using the water curtain, well #1 was killed by pumping brine into the well by means of a stinger. Brine was preferred over other kill fluids as a means of preventing damage to the downhole hydraulic fractures in an attempt to preserve well productivity.
The well was observed for any leaking seals at the wellhead components or signs of loss of well integrity. After the well was under control, a TIW valve was installed to secure the well, facilitate pressure monitoring and pressure bleed-off, as well as enable future pumping into the well or wireline operations. At the end of each well kill operation, a heat shield was installed around the wellhead to protect it from further heat damage from wells still blowing out.
A similar technique and procedure was used for containing the reaming wells. Several leaks had developed on the #4 wellhead, and the fire from the gas leak on the tubing head valve had engulfed wellheads #5 and #6. The gas leak and intensity of the fire prevented access to these wells located at the end of the pad.
Well #4 had sustained significant heat damage, and multiple leak points indicated that seals were severely damaged and likely to fail completely. To access the remaining wells, it was necessary to guide the fire from well #4 into a vertical position. This required severing wellhead #4 below the lowest leak point using a jet cutter. The jet cutter used abrasive sand pumped at 10,000 psi to cut through the wellhead. Figure 5 shows the position of jet cutter and the profile of the resulting cut.
After jet cutting, the wellhead was removed, and a Venturi tube was installed directly on top of the remaining stump to divert the plume away from the other wells and work area. The use of the Venturi tube provided a safe environment to access wells #5 and #6. The source control operation could resume, and both wells were killed by pumping brine by means of a stinger. The wells were monitored, and heat shields were installed to isolate the wells.
After the other five wells were killed and isolated, the Venturi tube was removed, and kill fluid (brine) was pumped into well #4 by means of a specially designed stinger. The stinger was replaced by a capping stack. Because the well was severely heat damaged, however, the integrity of seals in the wellhead was compromised.
The well was monitored for several hours. It became evident that the brine was being lost to the formation, enabling gas to migrate into the 4 1/2-in. production liner and resulting in increased pressure at the surface. After several hours, a condensate leak was clearly visible. After a risk analysis was conducted, it was decided to plug the well with cement, and a similar decision was made for well #5 after a minor gas leak was observed from a seal below the tubing hanger.
With all wells contained and secured, the reheading operation began. The area around the wells was excavated to expose a sufficient length of competent casing to facilitate the reheading operation. The reheaded wells were repositioned so that the side valves pointed outward, rather than toward an adjacent wellhead (Figure 6). By day 16, all wells were under control, the damaged wellheads had been removed, and the wells were reheaded.
Pad drilling is an innovative technique based on the capabilities of horizontal drilling that improves the economics of drilling and production for unconventional resources while significantly reducing environmental effect. Nevertheless, pad drilling also attracts a more rigorous risk assessment and well planning requirement.
On a pad, the wells are positioned in close proximity and could, therefore, significantly affect one another. This article presents a case study of a highly successful source control operation for a blowout incident on a six-well pad drilling site in which all wellhead fires were extinguished, contained safely and re-capped. Efficient communication and combined coordination between the incident command team of the operator and the well control specialist team enabled the rapid procurement of required equipment and services, capitalizing on the opportunity to mobilize to the site quickly. All required equipment arrived on location in good time, enabling the source control operation to proceed without delay.
The contingency planning and rapid response facilitated the capping of most wells before heat degradation of the wellhead seals. Although two wells had to be cemented in because of the deterioration of the wellheads and associated risks involving loss of well integrity at the surface, the majority of wells were recovered and could be put on production again.
The spill recovery system proved to be effective by collecting all liquid runoff from the well pad for processing safely in an environmentally sound manner.
The close proximity of the well pattern created challenges for accessing the wells and for maneuvering equipment for the source control operation. Each well was isolated and heat-shielded from the other wells after being contained.
During reheading operations, all valves were aligned away from the adjacent wells as a contingency, should there be a valve leakage or failure during flowback or production in the future. This alignment provides for the flow of hydrocarbons to be directed away from the other wells, mitigates the effect of heat damage on the neighboring wells and provides additional time for well recovery operations. DC
Acknowledgments: Thanks to the source control specialists who provided expert information and advice on the details of the successful operation and to the Boots & Coots management for their support and feedback in writing this article.
This article is based on SPE/IADC 184656, “Blowout Control Challenges of Pad Drilling and Production: A Case History with Lessons Learned,” presented at the 2017 SPE/IADC Drilling Conference, 14-16 March, The Hague, The Netherlands.
Good article. Pad drilling is like platform drilling – but with more space. Subsurface safety valves should be mandatory in pad wells so they can be shut in easily (and remotely) for events like this.
Good job with this one – reminds me of the Hellfighters movie when they had multiple wells on one pad on fire!