Crisis situations call for a readiness plan and emergency solutions.

It is inevitable. Disaster does strike in the industry, and though no one wants to encounter potential tragedy, emergency situations call for proactive readiness plans. On June 9, 2000, a workover rig blowout occurred south of Neiva, Colombia, and a Houston, Texas-based well control company responded.
The workover rig blowout required on-site experts at a remote location with equipment to handle any contingency. Using an in-place preparedness system, the company assembled a team of well control specialists to assess the situation, mobilize equipment and dispatch work crews.
Three well control experts flew to Bogota, Colombia. David Thompson, George Hill and Gabe Gibson arrived in Bogota within 24 hours and took a 45-minute helicopter flight to Neiva the next morning. At the well site, they found the location size, environmental implications and logistics of moving equipment and people would pose special challenges.
From the helicopter, company representatives showed the well control team the limited area surrounding the well site - about a 400 ft by 400 ft (122 m by 122 m) area - to use to contain the fire and recover the well.
The well was flowing oil from the drill pipe and bell nipple and from a casing valve that had been broken off by shifting debris from the fire. The bell nipple was bent at about 90° from the casing valve, and the extreme heat had caused numerous leaks on the wellhead.
The 160,000-sq ft (14,400-sq m) well site also had a drop-off of more than 200 ft (61 m) on two sides with slopes that ran directly into a river. This was the sole water supply for several towns below the mountain. Concerns arose that the excess wellbore fluid would run off into the nearby river. Contamination of the river would pose a direct threat to the lives of the citizens as well as potentially destroy the ecosystems of the plants and animals in the surrounding areas.
The Colombian government sent environmental officials to oversee and review the progress of the well emergency and assure the careful handling of the petroleum disaster. Their primary focus was getting the well capped as soon as possible. This was Colombia's first blowout in more than 12 years, so it attracted significant interest from the government, scientists and the media. They all wanted to understand the implications and ramifications of the blowout for nearby communities, the economy and the environment.
"We couldn't put the fire out, and we couldn't let the oil get into the river," said Thompson, senior well control specialist and team leader. "Our main objective was to do the entire job with the well on fire to prevent the spread of oil down the slope and into the river. There was no other way to stop the runoff - certainly not with a well that was producing 3,000 to 4,000 b/d. We needed to keep it burning until we capped the well using conventional methods."
The equipment was flown into Bogota in the belly of a 747 aircraft. Once it left Houston, the equipment took 5 days to arrive at the site, mostly because it had to go through mountains and poor roads. In addition, the surrounding areas did not have heavy rental equipment available to remove the debris.
Gibson, a senior engineer, said, "We created a plan to address the containment and disposal of the wellbore fluid away from the rig site. We knew that we would have to keep the well burning, but this would not address the excess fluid still flowing from the well. Two separate earth pits were dug out and created about 150 ft to 200 ft (46 m to 61 m) from the rig. The surrounding rig area was dammed up using large mounds of dirt to keep the flow directed to the earth pits. Vacuum trucks were running 24 hours per day to drain out the earth pits to avoid overflow."
The vacuum trucks would take the wellbore fluid away from the well site to another pit on the other side of the mountain. This offsite pit was lined with heavy plastic material to protect the fluids from being absorbed into the ground. The fluid would be pumped into the pit and then the mister. This mister was used to evaporate any water from the wellbore fluid. The volume of the fluid in the pit was reduced continuously, leaving the remaining fluid as pure crude. This helped to conserve the natural resources by minimizing waste of the crude oil and provided safe transport of the petroleum away from the rig site.
Added to the team's concern was the extreme summer heat in Colombia. The sun and the intense fire from the burning oil created dangerous levels of heat. The team leader needed to oversee the safety of the crew working to put out the fire and recover the well. Safety personnel and emergency crews would be needed on-site at all times to ensure that heat exhaustion and dehydration were minimized.
After the well conditions and information had been assessed, a plan was presented and implemented with the utmost concern for safety, impact on the environment and the ability to prevent any damage to the well and surrounding areas. The team then met with the hiring company to develop recommendations to control the well.
Upon arriving on location, pertinent well information was requested, gathered and evaluated. Requested materials included:
• International Association of Drilling Contractors well records, casing profile, blowout preventer (BOP) information and the bottomhole assembly and drillstring schematic,
• well records for adjacent wells with common formations;
• all available logs from the well;
• shallow seismic from surrounding areas within a 3- to 5-mile (5- to 8-km) radius;
• a formation contour map;
• mud records for the well;
• mud records for surrounding wells;
• a weather forecast for the following 4 weeks;
• a contingency plan;
• information about anomalous conditions;
• an inventory of logging tools available;
• a formation evaluation report from geologists; and
• an area fault map.
Careful consideration was required while preparing rig removal operations where any type of flow was concerned. The location, small site and pollution potential presented special challenges. The well's size and geographical location made all operations difficult. With the potential for ground fire and wellhead failure extreme, precautions were undertaken for all personnel involved.
The team divided the control effort into three segments.
The first operation involved the stinging of the casing outlet valve. Since the bell nipple was bent at 90° and the drillpipe could have been bent as well, the team thought it might be possible to get plugging material to plug off some of the flow while it pumped kill-weight fluid down the wellbore. The second operation called for the team to make two cuts with the abrasive cutter and sting the 7-in. casing. The first cut would direct all of the flow from the well vertically. That would allow the team to remove debris around the wellhead so it could get access to the 7-in. casing. Finally, it would remove the lower casing head flange and install a capping stack.
The team members set up a debris removal plan, deciding they would remove only enough debris to control the well. Even that operation was delayed by the lack of local rental equipment to handle heavier pieces of debris. Once they removed that minimal amount of debris, they could go forward with the stinging operation. The debris removal strategy included a contingency plan that if the stinging operation was not a success, there would still be enough room to perform a conventional capping operation.
"We were confident that the stinging operation would work and proceeded with that recommendation," Thompson said. "It soon became apparent that there was something else happening with this well. We had originally planned to cut the drill pipe so it would fall and sting into the casing and bullhead the kill-weight fluid to kill the well. After removing the casing-head flange, we saw that the 7-in. casing had fallen downhole at some point, either causing the blowout or after the blowout had taken place. This explained the failure of the stinging methods.
"When the stinging operation didn't work, we switched to the contingency plan and capped the well using conventional methods. Once capped, we could let the well flow in a controlled manner," Thompson said.
At that point, the team realized it would need a snubbing unit for the final work in killing the well. The team brought in a snubbing unit and obtained a BOP from a rental company. The teams' rapid response would save valuable time and costs for the clients. This turnkey solution offered a perfect fit for this particular project.
After controlling the flow of hydrocarbons to the surface, the team members decided they had to rebuild the entire location, converting it from a wreckage site to a workable pad. They used parts of the original rig to build a substructure that would eventually support the snubbing unit being mobilized. They built anchors on location and brought in an army of support, including clean-up crews, surveyors, equipment operators, welders, safety support technicians, rig crews and customer representatives for the site preparation.
Site cleanup and preparation was completed when the snubbing crew arrived at Neiva July 27, 2000, and the team completed rig up in 7 days. A national transportation strike delayed the project 1 day.
The team finished testing in another day and a half. It made the first trip in the hole Aug. 7, 2000, with a spear mandrel and no seals or slips to a depth of 323 ft (99 m), tagging the top of the 31/2-in. tubing.
Seals and spacers, but no slips, were installed on the spear, and the casing was engaged 3 ft to 4 ft (1 m to 1.2 m) below the wellhead. The team recorded a pumping schedule for 4 days. It filled the well and pulled the seals from the casing. The well was stable.
With data recorded during the pumping schedule into the casing and from the trip out of the hole with the tubing, team members decided they could stabilize the well with a kill string run into to the well to a depth of 8,000 ft (2,440 m).
Once the well was stabilized, the crews began breaking down equipment. The recovery operation was a success, and the operator put the well back in production. The Colombian citizens were able to ensure the safety of the environment and the quality of the drinking water from the nearby river. Environmental agencies were able to see the size and scope of the emergency and the care that was placed by the customer and the team of experts to protect Colombia's land from pollution.
"We didn't choose the easiest or quickest course of action for controlling this well emergency - we chose the best," Thompson said. "When you work on-site and realize that an entire community is counting on you to protect their water supply, you make it your priority. We left Colombia knowing that there wasn't anything more that we could have done to ensure the integrity of the site location. We are grateful to the company who called us to take part in this unique project and to the crews who worked hard at our side to protect the land."