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Pryor Trust Fatal Gas Well Blowout and Fire

Overview

On January 22, 2018, a blowout and rig fire occurred at Pryor Trust 0718 gas well number 1H-9 in Pittsburg County, Oklahoma. Five workers were killed in the driller’s cabin on the rig floor. The final report states that the blowout occurred about three-and-a-half hours after drill pipe was removed from the well. The primary barrier, hydrostatic pressure produced by drilling mud, and the secondary barrier, human detection of influx and activation of the blowout preventer, failed.

Incident Snapshot

Field Value
Facility / Company Red Mountain Operating, LLC (RMO); Patterson-UTI Drilling Company, LLC (Patterson)
Location Pittsburg County, Oklahoma
Incident Date 01/22/2018
Investigation Status The CSB's final report was released at a news conference in Oklahoma City, OK, on June 12, 2019.
Accident Type Explosion and Fire
Final Report Release Date 06/12/2019

What Happened

  • January 11, 2018: Patterson Rig 219 began drilling well 1H-9.
  • On Sunday, January 21, 2018, at 6:30 am, gas began entering the wellbore while drilling at about 13,000 feet MD in the horizontal section of the well.
  • At 7:30 am, gas started to reach the surface of the well, showing as elevated gas units in the mud.
  • After 11:00 am, the crew aligned the mud piping so that the mud was routed to the Mud Gas Separator, and by 11:11 am the flare activated.
  • The crew continued drilling, continuously flaring, until 3:30 pm, when they stopped drilling so that they could remove the drill pipe from the well to change the drill bit.
  • The drilling crew stopped circulating the well at 6:30 pm.
  • By 6:47 pm on January 21, 2018, the driller closed the orbit valve in preparation to trip out of the well using Calculated Fill.
  • At 6:48 pm, the crew began tripping drill pipe out of the well, from 13,337 feet MD.
  • At 11:00 pm, with the drill bit above the top of the curve, the next step was to circulate the well.
  • Before beginning circulation, with the mud pumps off, the driller opened the orbit valve to perform a flow check.
  • The flow check was conducted for 45 seconds.
  • At 11:02 pm, the driller ramped up the mud pumps and proceeded with circulating the well.
  • At 12:35 am, the driller pumped a weighted pill into the well.
  • At 1:12 am on January 22, 2018, with the orbit valve open, the crew resumed tripping the drill pipe out of the wellbore.
  • At 4:50 am, the crew had just finished pulling out the last stand of pipe above the BHA.
  • Between 4:51 am and 6:07 am, while the crew was trying to unplug the stand of drill pipe and during shift change, the trip tank gained 31 barrels of mud.
  • At 6:08 am, the day shift driller lifted the BHA out of the wellbore.
  • At 6:10 am, with the BHA out of the wellbore, the driller closed the BOP blind rams.
  • At 7:50 am, the driller picked up the new BHA and positioned it over the wellbore in preparation to lower it into the well to test the equipment.
  • At 7:57 am, the driller opened the BOP blind rams.
  • From 7:57 am through 8:35 am, the mud pits gained 107 barrels of mud due to gas influx/gas expansion within the well.
  • At 8:35 am, the floorhand was standing over the open well hole on the rig floor when he again saw mud flowing out of the open rotating head bowl.
  • At 8:36 am, shortly after the driller communicated that he was going to close the blind rams, mud started spraying out of the well.
  • Very quickly after the mud started spraying out of the well, the diesel oil-based mud and gas escaping the well caught on fire.
  • At the time of the blowout, the motorhand and second floorhand entered the driller’s cabin; the driller, company man, and directional driller were already inside.
  • A team of Boots & Coots responders and RMO representatives manually closed the blowout preventer blind rams to shut in the well at about 4:00 pm.

Facility and Process Context

  • Pryor Trust 0718 gas well number 1H-9 was a horizontal well with a planned true vertical depth (TVD) of 7,615 feet and a total measured depth (MD) of 17,799 feet.
  • The well targeted the Woodford formation, which contained natural gas.
  • The top 2,300 feet of the well was constructed with cemented steel pipe called intermediate casing.
  • The open hole section below 2,300 feet was 8.75 inches in diameter.
  • Patterson Rig 219 drilled both wells at Pryor Trust 0718.
  • Two Patterson drilling crews worked for Rig 219 on each hitch.
  • Tour 1 worked daily from 6:00 am to 6:00 pm, and Tour 2 worked daily from 6:00 pm to 6:00 am.
  • Each Patterson drilling crew included the driller, derrickhand, motorhand, and floorhands.
  • There was also one rig manager (toolpusher) working portions of each tour.
  • Personnel called company men also worked on the rig.
  • A drilling engineer, contracted by RMO, designed the drilling program and monitored the drilling progress.
  • Other specialized personnel were on or near the rig, including directional drillers, mudloggers, mud engineers, and other contracted personnel supplying equipment, fluids, or services.

Consequences

  • Fatalities: Five workers were killed.
  • Injuries: Not reported in the provided record.
  • Environmental release: Gas and mud escaped from the well. The report does not quantify an environmental release.
  • Facility damage: The fire engulfed much of the rig floor and the driller’s cabin. The driller’s cabin was severely burned. Hydraulic hoses were severely damaged by the fire, and the driller’s cabin windows were covered by mud.
  • Operational impact: The blowout and fire interrupted drilling operations. The well was shut in at about 4:00 pm. The BOP did not seal the well.

Key Findings

Immediate Causes

  • The cause of the blowout and rig fire was the failure of both the primary barrier, hydrostatic pressure produced by drilling mud, and the secondary barrier, human detection of influx and activation of the blowout preventer, which were intended to be in place to prevent a blowout.
  • The BOP did not function likely because the control hoses that supplied hydraulic fluid to the BOP burned in the fire and leaked the hydraulic control fluid, soon depleting the accumulator stored pressure to the point the blowout preventer could not be closed.
  • The BOP did not seal the well.
  • The hydraulic hoses that transported hydraulic fluid from the accumulator to the blowout preventer were severely damaged by the fire, and this damage is likely what prevented the BOP from closing.

Contributing Factors

  • Underbalanced drilling was performed without needed planning, equipment, skills, or procedures, thus nullifying the planned primary barrier to prevent gas influx.
  • Tripping was performed out of the underbalanced well, which allowed a large amount of gas to enter the well.
  • The driller was not effectively trained in using a new electronic trip sheet, which is used to help monitor for gas influx.
  • Equipment was aligned differently than normal during the tripping operation, leading to confusion in interpreting the well data which caused rig workers to miss indications of the gas influx.
  • Surface pressure was not identified two separate times before opening the BOP during operations before the blowout, when there was evidently pressure at the surface of the well.
  • A weighted pill intended to overbalance the well was apparently miscalculated. After pill placement, the well was still underbalanced.
  • Both the day and night driller chose to turn off the entire alarm system, contributing to both drillers missing critical indications of the gas influx and imminent blowout.
  • The alarm system also was not effectively designed to alert personnel to hazardous conditions during different operating states and would have sounded excessive non-critical alarms during the 14 hours leading to the blowout, which likely led to the drillers choosing to turn off the alarm system.
  • Key flow checks to determine if the well was flowing were not performed before the incident.
  • The drilling contractor did not effectively monitor the implementation rate of its flow check policy.
  • The drilling contractor did not test its drillers’ abilities in detecting indications of gas influx through simulated pit gains.
  • The operating company did not specify the barriers required during operations, or how to respond if a barrier was lost.
  • The safety management system in place was not effective for managing safe rig operations.
  • The victims had no safe escape route from the driller’s cabin once the drilling mud and gas ignited.
  • The BOP did not close when its activation was attempted after the fire started.
  • The alarm system was off.
  • The alarm horn remained off through the blowout at 8:36 am.
  • During the tripping operation, alarms would have activated for Gain Loss High, Total Mud, Flow Low, Standpipe Pressure Low, and Torque, but these would have been non-critical alarms not indicative of a well control event.
  • During the blowout period, alarms would have activated for Flow, Mud Pit Volume, Standpipe Pressure, Gain/Loss, and Torque.

Organizational and Systemic Factors

  • RMO and Patterson did not have sufficient degradation controls in place to maintain the primary and secondary barriers.
  • RMO’s representatives chose to continue drilling with the gas returning to surface, an indication that the well was underbalanced.
  • Calculated Fill is not a standard tripping method used in conventional, overbalanced drilling.
  • No Patterson crewmembers on that night crew had ever performed Calculated Fill tripping before, and neither Patterson nor RMO had a written procedure for it.
  • No crewmembers were formally trained on Calculated Fill tripping, and neither Patterson nor RMO performed a Management of Change for the change in the tripping method from the typical Continuous Fill.
  • Patterson had just started transitioning its drillers to using electronic trip sheets instead of paper trip sheets.
  • The driller had never received formal training on using the electronic trip sheet, instead trying to self-teach using trial-and-error.
  • Patterson’s tripping procedure was overly vague such that both the “Calculated Fill” and “Continuous Fill” tripping methods technically complied with the procedure.
  • Patterson’s tripping procedure did not specify the required equipment alignment during the tripping operation.
  • Patterson primarily used MOCs for equipment changes, not for operational changes.
  • RMO did not have its own MOC program.
  • Patterson did not create an alarm philosophy or alarm rationalization for Rig 219 before the incident.
  • Patterson had not developed procedures indicating what the alarm set points for parameters should be during tripping, circulating, and surface operations to identify a well control event.
  • Patterson had not developed guidance for set-point adjustment, or prescribed certain alarm set points for certain operations.
  • Patterson did not develop an alarm philosophy or perform an alarm rationalization before the incident.
  • Patterson did not regularly test whether drillers would quickly identify and respond to simulated pit gains, as recommended by API RP 59.
  • Patterson did not effectively monitor if flow checks were performed as required.
  • Patterson did not require flow checks to be documented, either electronically or by paper.
  • RMO and Patterson did not create a bridging document to merge the two companies’ safety systems or define which company had responsibility to manage which hazards.
  • The lack of a bridging document likely contributed to the lack of hazard analysis and management of change by both companies when there were signs that the operations were veering from the original plans.
  • RMO had developed a Drilling Prognosis, but it did not specify what barriers were required to be maintained, or how to identify if a barrier was lost.
  • The RMO Drilling Prognosis did not specify that Rig 219 had only equipment and training to perform conventional, overbalanced drilling.
  • There is no drilling-specific OSHA standard, and OSHA expressly exempts oil and gas drilling from regulatory coverage by the PSM standard.
  • There is no regulatory requirement for management of change to be used in drilling operations.
  • There is no requirement for detailed procedures or management of change that applies to the drilling industry.
  • There is no regulatory requirement for developing a Well Construction Interface Document for land drilling operations.
  • Little to no statutory or regulatory guidance exists pertaining to protecting the health and safety of workers engaged in drilling and servicing oil or gas wells, or with respect to environmental protection through the elimination of fires and explosions.

Failed Safeguards or Barrier Breakdowns

  • primary barrier—hydrostatic pressure produced by drilling mud
  • secondary barrier—human detection of influx and activation of the blowout preventer
  • flow checks
  • electronic trip sheet
  • alarm system
  • weighted pill
  • Management of Change
  • Time Out for Safety
  • BOP blind rams
  • annular preventer
  • pipe rams
  • accumulator
  • control hoses that supplied hydraulic fluid to the BOP
  • mud bucket alignment
  • trip tank volume monitoring
  • drills simulating an influx
  • Patterson flow check and alarm set point requirements
  • trip sheet
  • driller’s cabin escape routes
  • BOP closing function
  • hydraulic hoses
  • accumulator charging pumps
  • alarm horn
  • bridging document
  • Well Construction Interface Document
  • well plan barriers
  • management of change
  • trip tank gain/loss alarm

Recommendations

  1. 2018-01-I-OK-R1 | Recipient: Occupational Safety and Health Administration (OSHA) | Status: Closed – Reconsidered/Superseded | Summary: Implement one of the three following options regarding regulatory changes: (a) Apply the Process Safety Management (PSM) standard to the drilling of oil and gas wells; or (b) apply the PSM standard and make the necessary modifications to customize it to oil and gas drilling operations; or (c) develop a new standard with a safety management system framework similar to PSM that applies only to the drilling of onshore oil and gas wells, including detailed written operating procedures, management of change procedures, risk assessment, RAGAGEP, a Well Construction Interface Document, flow checks, and employee participation.
  2. 2018-01-I-OK-R2 | Recipient: American Petroleum Institute (API) | Status: Closed – Acceptable Action | Summary: Establish and convene a group of experts with drilling, engineering, and instrumentation expertise to discuss methods to achieve widespread implementation of automatic safety instrumented systems that could bring a well to a safe state in the event other operational barriers fail. Publish a technical bulletin discussing the strategies to implementing Blowout Preventer (BOP) safety instrumented systems.
  3. 2018-01-I-OK-R3 | Recipient: American Petroleum Institute (API) | Status: Open – Awaiting Response or Evaluation/Approval of Response | Summary: For onshore drilling operations, develop and publish a recommended practice providing guidance on safely tripping drill pipe during overbalanced, managed pressure, and underbalanced drilling operations, including required equipment, techniques and procedures for controlling or preventing formation fluid influx, and methods to monitor the well and replace the drill pipe displacement volume with drilling fluid.
  4. 2018-01-I-OK-R4 | Recipient: American Petroleum Institute (API) | Status: Closed – Acceptable Alternative Action | Summary: Develop a recommended practice on alarm management specifically for the drilling industry based on guidance in ANSI/ISA 18.2, addressing the unique dynamic environment of the drilling industry and providing guidance on implementing a state-based alarm system for different operating modes, with IADC included in the development.
  5. 2018-01-I-OK-R5 | Recipient: American Petroleum Institute (API) | Status: Closed – Acceptable Action | Summary: Develop a new recommended practice or modify an existing recommended practice addressing the protection of rig workers on onshore drilling rigs from fire and explosion hazards in the event of a blowout, including protection of driller’s cabin occupants, minimum required evacuation methods, proximity of BOP activation controls, and evaluation of alternative drilling cabin locations.
  6. 2018-01-I-OK-R6 | Recipient: American Petroleum Institute (API) | Status: Closed – Acceptable Alternative Action | Summary: Update API Bulletin 97 Well Construction Interface Document Guidelines to specify that it applies to both onshore and offshore drilling operations.
  7. 2018-01-OK-R7 | Recipient: Patterson-UTI Drilling Company, LLC (Pat-UTI) | Status: Closed – Acceptable Action | Summary: Develop either corporate or rig-specific tripping procedure(s) that detail the required equipment configuration for tripping operations, require visual verification that equipment is lined up as specified before beginning the tripping operation, and specify well-monitoring requirements for wet versus dry tripping operations.
  8. 2018-01-OK-R8 | Recipient: Patterson-UTI Drilling Company, LLC (Pat-UTI) | Status: Closed – Acceptable Alternative Action | Summary: Develop an alarm philosophy and alarm rationalization for rig operations, specify necessary alarms for drilling, tripping, circulating, and rig floor activities, and develop a policy implementing the alarm philosophy and rationalization.
  9. 2018-01-OK-R9 | Recipient: Patterson-UTI Drilling Company, LLC (Pat-UTI) | Status: Closed – Acceptable Action | Summary: Develop a policy incorporating API RP 59 recommendations requiring regular testing of drillers’ influx detection and response skills through formalized drills, and require that driller response time is monitored.
  10. 2018-01-OK-R10 | Recipient: Patterson-UTI Drilling Company, LLC (Pat-UTI) | Status: Closed – Acceptable Action | Summary: Develop and implement a policy requiring that flow checks be documented, either electronically or with a paper record, including operation, method, duration, result, and approval by proper authorities before resuming operations, and keep the documentation as part of the well file.
  11. 2018-01-OK-R11 | Recipient: Patterson-UTI | Status: Closed – Acceptable Action | Summary: Update the Patterson metrics program to track leading and lagging indicators to measure the effectiveness of the overall safety management system, focusing on flow checks, documentation and approval, management of change, alarm set points, alarm shutoff frequency, and trip sheet completion.
  12. 2018-01-OK-R12 | Recipient: Red Mountain Operating | Status: | Summary: Develop a new policy that a well-specific Well Construction Interface Document be in place before drilling operations begin, specifying the technical requirements of the rig equipment and technical qualifications of personnel, and specifying which barriers must be maintained and the expected response if a barrier is lost.
  13. 2018-01-OK-R13 | Recipient: Red Mountain Operating | Status: | Summary: Develop a management of change policy governing real-time changes to operations and the drilling plan, requiring hazard analysis and consideration of rig equipment, procedures, and personnel training and qualifications.
  14. 2018-01-OK-R14 | Recipient: International Association of Drilling Contractors (IADC) | Status: Closed – Exceeds Recommended Action | Summary: Participate in development of the recommended practice described in recommendation 2018-01-OK-R4 to API.
  15. 2018-01-OK-R15 | Recipient: Pason Systems Corp. (Pason) | Status: Closed – Acceptable Alternative Action | Summary: Design the Pason user interface to allow drilling contractors to pre-set different alarms for different operations in a state-based alarm system.
  16. 2018-01-OK-R16 | Recipient: Pason Systems Corp. (Pason) | Status: Closed – Acceptable Action | Summary: Design the Pason electronic drilling data system so that alarm information, including alarm set points, alarm activation log, alarm horn status, and alarm system status, is provided to customers.
  17. 2018-01-I-OK-R17 | Recipient: National Oilwell Varco (NOV) | Status: Closed – Acceptable Action | Summary: Design the M/D Totco user interface to allow drilling contractors to pre-set different alarms for different operations in a state-based alarm system.
  18. 2018-01-OK-R18 | Recipient: National Oilwell Varco (NOV) | Status: Closed – Acceptable Action | Summary: Design the M/D Totco electronic drilling data system so that alarm information, including alarm set points, alarm activation log, alarm horn status, and alarm system status, is provided to customers.
  19. 2018-01-I-OK-R19 | Recipient: State of Oklahoma | Status: Closed - Unacceptable Action/No Response Received | Summary: Establish and implement safety regulations requiring operators and drilling contractors to develop detailed written operating procedures, management of change procedures, risk assessment, RAGAGEP, a Well Construction Interface Document, flow checks, and employee participation prior to conducting drilling operations.

Key Engineering Lessons

  • Underbalanced drilling requires explicit planning, equipment, skills, and procedures. Otherwise the intended hydrostatic barrier can be nullified.
  • Tripping procedures should specify required equipment configuration and alignment, because nonstandard alignment can create confusion in interpreting well data.
  • Flow checks are safety-critical for identifying a flowing well and should be performed and documented at defined points during operations.
  • Alarm systems for drilling should be state-based and designed for the operating mode so that nuisance alarms do not encourage operators to disable them.
  • Well control systems must be protected from fire damage long enough to allow activation and closure of the BOP.
  • The driller’s cabin and rig-floor escape routes should allow evacuation during a blowout and fire. Blocked exits can trap occupants.
  • A Well Construction Interface Document and bridging document are important for defining barriers, responsibilities, and response if a barrier is lost.
  • Management of Change is needed for operational changes such as switching tripping methods, not only for equipment changes.

Source Notes

  • Primary source used: FINAL REPORT: Pryor Trust Final Investigation Report (source_priority 1).
  • Recommendation status change summaries were used to update recommendation statuses and post-incident corrective actions.
  • Supporting documents were used only to supplement event timing and factual detail where consistent with the final report.
  • Where documents differed, the final report was treated as authoritative.

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