April 1999

Handling a shallow gas blowout in Southeast Texas

Drilling of a relief well to control an early 1998 gas well blowout is described, including planning, drilling and plug/ abandon operations
April 1999 Vol. 220 No. 4 
Feature Article 

Handling a shallow gas blowout in Southeast Texas

Three hours after initial blowout, the gas ignited and the derrick collapsed. Fluids broached the casing and formed a crater under the collapsed rig. Drilling a relief well should have been straightforward, but circulation could not be maintained

Neal Adams, Well Control Consultant; and David Strickland, Well Control Engineer, Cudd Well Control, Houston

W. S. Rhodes 18 was spudded on Jan. 31, 1998, in Montgomery County, Texas, by Whiting Petroleum Corp. By February 7, the well had reached 3,703 ft when a gas kick blew out of control. The gas ignited, burning down the derrick, and fluids broke through the surface forming a crater, Fig. 1. Throughout the evening, the crater enlarged and the rig was engulfed. During the next few days, the well started producing trace quantities of oil, further complicating cleanup operations.

A relief well was required since the BOPs and casing head had fallen into the crater. A plan was developed and a relief well spudded. The well bridged off 10 days later. However, to meet Texas Railroad Commission (TRRC) plugging requirements, the relief well was continued to allow proper cement plugging of the blowout well. This article details events leading to the blowout and actions taken to bring it under control.


The W.S. Rhodes 18 well was drilled in Conroe field in Southeast Texas. The field is operated by Exxon with an 18% interest held by Whiting Petroleum. During the field’s history, 105 wells have been drilled, of which about 15 have blown out. Three blowouts were in the immediate vicinity of W.S. Rhodes 18.

The Rhodes well began by driving of a 16-in. conductor pipe to 42 ft; then a 12.25-in. hole section was drilled to 1,660 ft TVD with no apparent problems. An 8.625-in., 24-lb/ft surface casing was run and cemented with 800 sacks. The rig experienced many mechanical problems throughout this section.

A 7.875-in. hole section was drilled to 3,703 ft, when a rotary kelly hose began leaking. A 2-in. pump line was connected to the standpipe to circulate bottoms-up.

On February 7, a kick occurred while POOH with the bit at 28 joints off bottom (2,832 ft). The annular was then closed, but the closing line started leaking, then the annular BOP failed. The BOP stack had no other components (rams, etc.) for control, so the well blew out.

On the evening before the blowout, gas bubbling in the cellar around the surface casing was noted. Bubbling indicated a poor, non-sealing cement bond on the surface casing. The crew pumped fluid from the cellar into the shaker’s possum belly with a submersible pump. This situation probably contributed to, or caused, cratering around the casing and under the rig. Unfortunately, the well was near its proposed total depth when these problems occurred.

Initially, the well blew gas and water at a high rate, so the crew evacuated. Attempts were made to move vehicles off location but failed due to traffic congestion on the small site. Water continued flowing at a high rate.


Cudd Well Control’s initial assessment of the situation included the following:

  • The flowrate and fire were substantial, with flames in excess of 200 ft high.
  • Rocks and other debris were being thrown from the well.
  • Firefighting, capping and relief-well operations would be required.
  • High-volume water flow was occurring with the gas.
  • Residential population in the immediate area was not in imminent danger, so evacuation was not necessary.
  • The gas did not contain hydrogen sulfide.
  • Water-handling operations would be necessary to prevent pollution.

Other activities, begun the evening of the blowout, included:

  • A staging-area site was selected, and preparation efforts were initiated.
  • Boards and mats from the existing location were moved to the staging area.
  • Frac tanks were ordered to temporarily store water run-off.
  • Vacuum trucks were organized to move large volumes of produced water.
  • Heavy equipment and matting boards were ordered.
  • Location building contractors were contacted.
  • Construction on water storage pits began.
  • Exxon was notified and requested to locate pipelines and wells in the immediate area.
  • Traffic control was initiated, including fire department notification and blocking of secondary arteries leading to the site.
  • Montgomery County sheriff’s department was already on-site, assisting in securing the area.

A recommended program for well-control operations was developed. The next day’s activities included:

  • Additional heavy equipment, vacuum trucks, frac tanks and firefighting foam were ordered.
  • Whiting Petroleum personnel from Denver headquarters arrived.
  • TRRC and Environmental Protection Agency (EPA) personnel arrived on location.
  • Cudd rigged up its firefighting equipment, including heavy-duty athey wagon, fire pumps and monitor stands. Tin shields were installed on bulldozers.

Development of comprehensive well-control plans requires evaluation of a variety of data. To assist in data collection, the following list was prepared and provided to Whiting:

  • W.S. Rhodes 18 well records: ADC daily reports; schematics for casing profile, BOP stack and BHA/drillstring; well logs, mud records and contingency plan
  • Well records for all wells in the surrounding area
  • Shallow seismic from surrounding area, up to 5-mi radius
  • Formation contour map (5-mi radius)
  • Anomalous conditions, especially formations
  • Two-week weather forecast, including wind speeds / directions
  • Available logging tools (noise, temperature, caliper, severing tools)
  • Formation evaluation report from geologists (permeability, lithology)
  • Area fault map
  • Exxon pipeline map and well plot for Conroe field.


Surface capping operations must have access to a competent BOP stack or casing string; neither was available in this well. It became immediately apparent that a relief well would be needed. The pressure-control team of relief-well engineers was mobilized, arriving the day after initial blowout. They commenced work on relief-well design and plan.

Before pressure-control engineers arrived, a relief-well rig had been selected by Whiting. Although the rig was not ideally suited for relief-well operations, it was immediately available and being prepared for transportation to site. Several modifications were needed to make it suitable for the task.

Surface-clearing operations were started for the firefighting staging area before rig arrival. The firefighting team directed board-mat and frac-tank placement. One tank was identified for kill-mud storage, if required, the others to hold firewater.

Site planning. Primary considerations in site-selection planning for this relief well were as follows:

  • Site close to blowout well to facilitate a simple, directional-intersection plan
  • Must not endanger personnel or relief-well rig due to fire, heat, smoke or possibility of crater encroachment
  • Site acceptable to rig underwriters and owners.

Location of existing flowlines, roughly 400 ft from the blowout, set an upper limit on offset distance for rig location. Closest offset was determined by concerns that another rig might be lost to a blowout (the rig owner had lost two rigs to blowouts in seven months). After consultation with well-control specialists, a 300-ft offset from the blowout was eventually agreed to, which was 100-ft closer than the rig owner originally would allow. A surveyor was sent to location, and several sites were investigated.

Casing selection. Since the relief well’s objective is blowout control, well-kill parameters must be the controlling factors. Several well-kill computer programs were used, including a "dynamic kill" program and a "reservoir flood" program. Results showed the well should be easy to kill, since it was normal pressured, shallow and would be affected by depletion. It was desired to use casing that would allow easy mud pumping with high pump pressures, yet allow another casing string to be run in case of difficulties.

Due to restrictions imposed by rig-size, 9.625-in. casing was the largest adequate size that could be used. Since predicted pressures were low, high-strength casing was not required. Software indicated 40.5-lb/ft grade-K55 pipe was acceptable. However, a 47.0-ft/lb string was planned; the added wall thickness was for directional-drilling considerations.

Intercept point selection. Selecting an intercept point(s) is a function of several items, including possible bridges, determination of flowing intervals and casing / drillstring in the blowing well.

The blowout well had several productive zones that could have contributed to the flow. Primary zone of interest was located at about 2,800–2,900 ft; the relief well had to intercept this zone. The bit was in this depth range when the blowout occurred.

After the blowout started, other zones up-hole probably started flowing. This meant that the intercept well also had to hit these zones. The relief well was designed so that it would traverse the entire openhole section of the blowout well.

  Magnetic-ranging tool surveys for intercept  
Depth, Closure distance / direction
run ft, MD (ft) / (deg)

 1 1,330 2560 / 72610
 2 1,426 1863 / 562
 3 1,620 261 / 1262

Magnetic ranging tools, used to locate the blowing well from the relief well, require a steel source in the blowout well to provide a magnetic field. The ranging tools detect magnetic fields and provide input for distance and direction calculations, see table.

Fig. 2 shows the blowout well to have 8.625-in. casing to 1,660-ft TVD and drill pipe/BHA to 2,832 ft. This assumes the worst case, in which the drill pipe did not fall when the derrick fell. If the drillstring had fallen, magnetic ranging tools could more easily locate the blowout well at any depth of interest.

Directional plan. Intercepting all exposed zones dictated that the directional plan incorporate an "S" curve. This pattern requires additional time to drill, compared to a straight kickoff, but allows certain well-control advantages.

Several directional plans were considered. The upper boundary was to initiate a build rate immediately under the drive pipe. Although not a necessity from a theoretical view, it was considered desirable in this case, since the shallow formations may not have been conducive to building the desired angle.

Choosing casing depth. The following factors were considered for selecting casing-setting depth:

  • Isolate shallow, weak zones
  • Isolate possible gas-bearing, charged zones
  • Provide protection from differential sticking.

A zone at 1,300-ft TVD could have been gas filled and / or gas charged. If the relief well took a kick from this zone, the conductor casing would not be able to contain it. If the zone were depleted from the blowout, it could cause sticking problems. A decision was made to set surface casing above the zone to provide kick protection, since this was a terminal problem. If sticking occurred and was not controllable, another string of pipe could be set.

Conductor pipe would be set as deep as possible. A survey of drive records from the surrounding area indicated that more than 150-ft penetration could be achieved if the pipe were washed out as it was driven.


A D-15 drive hammer with a 16´ 0.50-in. wall was used to drive the conductor pipe. Penetration depth of 152 ft was achieved with 240 blows per ft. The 16-in. casing was cut off, and a 13.625-in. wellhead was welded on the casing. A 13.625-in. diverter stack was nippled up on the wellhead.

Drilling to surface-casing depth. Drilling commenced six days after the blowout. A 12.25-in. bit with motor was used to drill the directional hole. The angle built as desired, and drilling was uneventful in this section.

The original well had encountered a lost-circulation zone at 1,150 ft, so the mud system was pre-treated with lost-circulation material and mud weight carefully monitored to maintain a 9.5-ppg density. Due to these precautions, no losses occurred.

The hole was drilled to 1,250-ft TVD (1,283-ft MD). Due to sticking tendencies, tripping out prior to logging required care. The bit was heavily balled, so the motor was laid down and a wiper trip made without problems. The subsequent triple-combo log did not indicate soil disturbance or gas invasion in shallow formations. It appeared that most gas flow was up the surface casing.

On the third day of drilling, 9.625-in. pipe was run to 1,283-ft MD. Two Spirolators were used on each joint to improve cement bond, and a float shoe and float collar were run. Circulation was maintained while running the pipe. After pipe was set, the well was circulated until annular fluids were clean.

A 4-hr set time was allowed before nippling down the BOPs. After the waiting period, the diverter stack was nippled down and the secondary seal installed. A 13.625-in. BOP stack was rigged up and tested. A motor and BHA were run in before successfully testing casing to 3,000 psi.

Drilling to intercept. The directional BHA was used to rotate and slide drill from 1,293 ft to 1,393 ft. Directional surveys were taken with a gyro to assist in steering along the planned course path. A magnetic ranging tool was run to locate the blowout well relative to the relief well. Three runs were needed to ensure a direct hit on the blowout well, as shown in the accompanying table.

The first ranging run was made 100 ft below the surface casing in the relief well, so the 9.625-in. surface pipe would not exhibit any magnetic interference with the ranging tool. The first run showed a strong magnetic anomaly at 1,376-ft MD. However, the hole was not sufficiently deep to evaluate strength and reversal tendencies of the trend. An additional 60 ft of hole was drilled. The second run showed the relief well to be on its planned course.

The final ranging run was made at 1,625-ft MD. This was about 10 ft above the casing seat in the blowout well. Magnetic saturation confirmed that the relief well was adjacent to the blowout-well pipe.

In addition, analyses of signals between 1,546 and 1,579 ft suggested a split in the blowout-well casing. This interpretation was supported by reported drilling conditions through this interval in the relief well. The bit was bouncing heavily through this section. Offset-drilling conditions do not provide a basis for this bouncing.

Intercept. Before drilling for intersection, drilling conditions at intercept were discussed at a safety meeting with key supervisory personnel. Contingency plans for probable mud losses, gas cutting and kicks were discussed. If losses or kicks were observed, the annular BOP was to be closed, and circulation would be through the choke until normal conditions were regained. Experienced well control personnel were assigned to the closing unit, mud logger’s trailer, shale shaker, pits and rig floor.

Drilling continued after the safety meeting. The hole above the blowout well’s casing shoe was drilled without incident. At around 1,650-ft MD, it was apparent that the relief well had entered the old hole. Bit weight needed to drill reduced. Gas cutting, up to 10,000 units, was observed on bottoms-up circulation. There were no losses or kicks.

Circulation problems. The first mud loss happened at 1,727-ft MD. Kicks associated with lost circulation were noticed. Partial losses were observed, followed by total loss. Circulation rate was reduced; lost circulation material was mixed and pumped, and return flow was regained.

Circulation problems intensified from 1,848 to 1,885 ft. According to Whiting’s original well prognosis, this section correlates with the Miocene 15 sand projected for the blowout well. Interpretation of drilling conditions through this interval suggests that the zone was a substantial blowout contributor, as evidenced by soil disturbance. Large amounts of drilling fluids were lost to the zone during relief-well drilling. Relatively small amounts of gas cutting were observed which, under current conditions, suggested the zone was substantially depleted.

The BHA was POOH, the motor was removed and the well re-entered. Maintaining fluid circulation eventually became an acute problem. Regaining circulation after the initial losses required pulling the drillstring into the casing and allowing the hole to heal. Attempts at regaining circulation with the bit on bottom were unsuccessful, and large volumes of mud were lost.

After waiting for the hole to heal and liquid mud to be transported to location, the bit was again lowered to bottom. Returns were again lost. It became apparent that continued drilling in a safe, hydrostatically balanced mode would be difficult. Substantial volumes of lost circulation additives were added, but they did not improve the situation.

Another attempt was made to continue drilling. Realizing that lost circulation was an insurmountable problem, blind drilling was initiated. The hole was deepened to 1,934 ft, where it became apparent that drilling could not continue safely. The annulus could not be maintained full to the surface, so a kick could have been initiated without the ability for surface monitoring. Well control engineers recommended that drilling operations be halted for safety reasons and abandonment operations (cement plugging) be initiated.


Attempts at regaining circulation with the bit on bottom were unsuccessful, and large volumes of mud were lost.



An amended plug and abandonment program was prepared and submitted to TRRC. The relief-well drillstring was to remain in the hole permanently to serve as a cementing conduit to various formations. Shallower sections of drill pipe would be perforated, as necessary, to cement upper zones in the blowout well.

Monitoring of all aspects of the plugging program would be needed to identify subtle indicators of cement effectiveness. Significant pressure testing was not possible, as in conventional cementing, due to soil disturbance from the blowout and inherently low virgin-fracture strengths in shallow zones.

The cementing company was rigged up. After all systems were pressure tested, an attempt was made to re-establish circulation down the drillstring, which was found to be plugged, presumably with lost-circulation material. This situation occurred several times during the last day but was thought to have been resolved. A wireline tool was run in the drillstring to determine the plugging depth. If the plug was deep, a perforating gun would be used to develop a circulating path. If the plug was shallow, a coiled tubing unit would be used to clean the pipe prior to perforating and / or circulating.

The plug was determined to be at 1,908 ft, which was the float-sub depth, above the bit. A perforating gun was rigged, and the pipe was perforated from 1,884 to 1,894 ft, with 6 shots/ft. A zero-phased gun was used to assist in splitting collars. An 800-psi pressure was applied to the drillstring when the gun was fired. The pressure dropped to zero, indicating that the collars had been successfully perforated.

Initial slurry was 2,000 sacks of Class A cement, mixed at 15.6 ppg. The slurry was displaced with 40 bbl of water, resulting in excess displacement to maintain a clean drill-pipe conduit for further cementing. Pumping indicators did not show any sign of achieving squeeze pressure on this slurry. After WOC for 12 hr, an attempt was made to test the cement to 500 psi. It did not test.

The drill pipe was next perforated at 1,685 ft. A second 2,000-sack cement slurry, mixed at 15.6 ppg, was pumped. The slurry was in place with a final squeeze pressure of 65 psi; although small, this was seen as a positive indicator that some buildup was occurring. After WOC, wireline tagged cement at 1,588 ft in the drill pipe.

A temperature log was run which indicated top of cement at 1,220 ft, with cement still green in some areas. A second temperature log was run 12 hr later and showed the TOC to be at 1,310 ft.

The drill pipe was again perforated, and a third cement slurry of Class H, mixed at 16.4 ppg, was pumped. This time, the slurry included calcium chloride as an accelerator. Although 2,000 sacks were planned, only 855 sacks were pumped to prevent a seat fracture due to increasing annulus pressure.

After setting a cementing plug at 331 ft in the crater using 2.375-in. coiled tubing, the drill pipe in the relief well was perforated from 1,300 to 1,306 ft. A fourth, and final, Class H cement slurry, mixed at 15.6–16.0 ppg, was circulated through the perforations, back to surface, and into the BOP stack in accordance with TRRC instructions.


A crater began to form below the rig substructure immediately after the blowout. It grew until most of the major rig components had fallen into the well. After the blowout was killed, debris had to be removed from the crater prior to P&A operations. The crater was about 45 ft deep and 110 ft across. Crater walls were vertical, shear planes, without any visible angle of repose. Although the crater wall began sloughing, it remained essentially stable and did not hinder ongoing debris removal and dewatering operations.

A vertical entry hole was drilled to 331 ft with coiled tubing, and a cement plug was pumped to seal off shallow zones. Another cement plug was placed in the bottom of the crater, and the crater was subsequently backfilled.


The W.S. Rhodes 18 used a water well drilled to a depth of 240 ft. Consideration was given to the possibility that it may have been flowing into the crater. A water-well sample was taken and its analysis reported to TRRC. The water well was to be secured by Whiting after P&A procedures were completed.

The blowout initially flowed only gas and formation water, but eventually began flowing trace amounts of oil. The quantities of oil observed floating on the collected water, and salt levels in the produced water, indicated pollution would not likely be severe. However, fluids could not be permitted to flow offsite and enter streams or aquifers in the area. Effluent from a blowing well must be contained and removed to mitigate pollution and maintain access for well-control operations.

A containment dike was constructed between well roads. Two containment booms were located along an adjacent road, another on nearby Crystal Creek, and 2,100 ft of boom behind and downstream of the containment area for bypassed fluids. Ultimately, more than 149,000 bbl of fluids were trucked from the site.

Although plagued with problems, well control was accomplished in 20 days, without injury. Remediation continued for some time thereafter.


The authors appreciate Cudd’s management for its support and permission to publish this article. In particular, thanks to Bob Cudd, Ray Saliba, Paul Saulnier and Mike Smith. This article was originally presented at the IADC Well Control Conference of the Americas, Caracas, Venezuela, Oct. 29–30, 1998.


The authors

AdamsNeal Adams has 30 years of experience in the petroleum industry, mostly in drilling and well control. He has authored six books, more than 70 articles and participated in several videos. He is currently an independent drilling and well control consultant. Mr. Adams is a registered P.E. and was an SPE distinguished lecturer in 1982–83.

StricklandDavid Strickland is a well control engineer for Cudd Well Control, a division of Cudd Pressure Control, Inc. Before joining Cudd in 1996, He was employed by Conoco as a production and completion engineer. Mr. Strickland graduated from Louisiana Tech University with a BS in petroleum engineering.

contents   Home   current

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company

Connect with World Oil
Connect with World Oil, the upstream industry's most trusted source of forecast data, industry trends, and insights into operational and technological advances.