Well Control and Intervention

Hydraulic snubbing unit works over, recovers well after blowout

After a recent blowout was capped at the surface, well recovery operations successfully recovered a majority of the wellbore, allowing the operator to sidetrack the well and re-drill to TD at reduced cost

Tyson Foutz, Cudd Pressure Control, Edmond, Oklahoma

Well recovery often presents challenging problems. In the US, a well was capped at surface after bridging off downhole, but this left it unstable. Drill pipe was lost in the wellbore, and a bridge downhole provided an unreliable pressure seal. The well recovery operation' objective was to recover as much of the wellbore as possible. If the drill pipe could be pulled, casing could be run. Otherwise, the wellbore would have to be cleaned out to a depth below the intermediate casing.

The well recovery operations discussed in this article were a success. Workovers performed through the use of snubbing units and coiled tubing units recovered the majority of the wellbore, allowing the openhole section to be permanently abandoned. Recovering the wellbore to a depth below the intermediate casing shoe allowed the operator to sidetrack at that depth and re-drill to TD, at a reduced cost.

PRELIMINARY ACTIONS

A large independent operator experienced a surface blowout after taking a drilling break and a gas kick. While attempting to circulate the kick out of the wellbore, the 5,000-psi, annular blowout preventer (BOP) failed.

The remainder of the BOPs failed to achieve a pressure seal, and the well continued to flow uncontrolled, washing out the BOPs. The drill pipe inside the BOP stack was flow-cut, and the drill string fell into the wellbore. At the time of the blowout, the well was being drilled at 9,900 ft. The well blew out for two days before it bridged off downhole. After bridging off, the well was capped on surface. The capping stack consisted of a two-BOP ram stack. The wellbore condition after capping is shown in Fig. 1.

Fig. 1. A diagram of wellbore conditions, shows that capping did not kill the well downhole.

The capping operation did not kill the well downhole and provided only a temporary solution. The wellbore could not be abandoned in its current configuration. Plugs needed to be set deeper in the well than could be achieved. The drill pipe needed to be recovered below the intermediate shoe, so that a plug could be set to successfully P&A the wellbore.

Cudd Pressure Control was contracted to perform the well recovery operations. The operator specified that as much of the wellbore as possible was to be salvaged. The first step was to fish the severed drill string with an overshot. The next step was to re-establish circulation at the deepest point possible. Recovery or abandonment of the wellbore' openhole section would then be investigated.

WELL RECOVERY

Recovery operations commenced with the rig-up of the 600k, hydraulic jack snubbing unit and the snubbing stack on top of the capping stack. The self-contained snubbing unit, capable of pulling 600,000 lb., hook load, provided adequate over-pull for the drill string weight.

The snubbing stack consisted of two stripping rams, a 20-ft spacer spool, safety rams, a drilling cross and two additional safety rams. It was configured to allow the fishing tools to be snubbed into the well. The fishing tools consisted of a pack-off overshot assembly. This configuration would result in a work string with no restrictive internal diameters. The full-bore work string would allow more flexibility for running tools inside the work string and drill string.

Surface pressure had built up to 4,000 psi after the capping operation. Lowering the surface pressure would benefit the snubbing operations. To lower the surface pressure, 13-ppg mud was displaced into the wellbore using the volumetric (lubrication) control method. This method was accomplished by pumping a small value of mud into the well. This process was repeated until surface pressure was 0 psi, or when the well was unable to bleed off gas at the surface. In this case, the surface pressure was reduced to 1,200 psi.

Prior to attempting to fish the drill string with the pack-off, overshot fishing assembly, the fish needed to be dressed off. A mill was snubbed into the well on a 4.5-in. work string, and it tagged the fish 60 ft below the surface, Fig. 2.

Fig. 2. Drillstring latched with packoff/ overshot.

Then, 13-ppg mud was circulated into the well. The fish was dressed off by milling 2 ft off its top. After the fish was dressed off, the mill was snubbed back out of the well, and the fishing tools were snubbed into the well. The fish was successfully swallowed, and the overshot grapple and pack-off were energized.

CT RIG-UP ON 600K SNUBBING UNIT

With the original drillstring latched, the first well recovery step was completed. The next step was to re-establish circulation, so that the drillstring and wellbore could be recovered. A decision was made to make the initial trip into the drillstring with 1.5- in. coiled tubing. The original drillstring was made up with a float in the drilling BHA. The float would have prevented any debris from entering the drillstring.

Barite fill was expected inside the drillstring, due to the barite settling out of the mud. Coiled tubing would be able to circulate out the old mud, run in the drillstring and determine the depth of any fill/bridges. Coiled tubing would run in the drillstring to the depth of the barite fill, and wash the drillstring to the BHA depth. Coiled tubing provided the safest, quickest method to perform the drillstring clean-out.

The rig-up of coiled tubing on the 600k, hydraulic snubbing unit placed the injector head at a 90-ft height above the ground. To achieve the proper angle for the coiled tubing to run off of the reel and onto the goose neck, the CTU had to be located 150 ft from the wellhead. To accomplish this rig-up, an additional 250 ft of hydraulic hoses had to be connected between the injector head and the power pack. The rig-up of the injector head to the work string was accomplished by spacing out the work string to place the top joint at the level of the snubbing basket.

A gate valve and drilling cross were nippled up onto the TIW valve atop the work string. The CTU' BOP stack and injector head were nippled up on the drilling cross. Fluids could then be pumped down the coiled tubing, taking returns up the work/drill string annulus and out through the drilling cross to a ground-level manifold.

After the CTU was rigged up, the BOP stack was tested against the closed TIW valve to 5,000 psi. A BHA, consisting of a 2.5-in. bit and a 2.063-in. mud motor, was run into the work string on 1.5-in. coiled tubing. An obstruction was tagged 15 ft inside of the fish, Fig.3.

Fig. 3. A BHA run on coiled tubing tagged an obstruction at 15 ft 1 in.

Milling started at this point, and returns showed large metal shavings and large slivers of shale. The metal shavings were remnants of the milling done to dress the top of the fish. After milling the first couple of feet, no more metal shavings were seen in the returns. Milling continued to progress slowly, and only 300 ft were made with coiled tubing that first day. This placed the top of the fill at 375 ft from surface.

The original assumption that the drillstring only had barite fill proved to be wrong. The condition of the remainder of the drillstring was unknown – was the entire drill string full of shale fill, or was there a series of small bridges in the drillstring? The daily progress shown by coiled tubing in cleaning out the shale would not be sufficient for the job. Another method to clean out the drillstring needed to be developed.

SECOND OVERSHOT/ PACKOFF ATTEMPT

After cleaning out 300 ft with coiled tubing, communication existed between the work string and the annulus. The communication was suspected to be in either the pack-off overshot or in the top joint of drill pipe. This joint had been flow-cut by the erosion velocities created by the uncontrolled gas flow and sand around the drilling rig' BOPs.

The overshot was released, and the fishing tools were snubbed out of the hole. An inspection of the pack-off showed no damage, confirming that the leak was in the original drillstring. An external cutter was snubbed into the wellbore one joint of 7.375-in. wash pipe and the 4.5-in. work string.

The fish was swallowed, and an external cut was performed 20 ft below the top of the fish. This removed the remainder of the drillstring' top joint and left a clean fish to latch with the pack-off overshot. The pack-off overshot was snubbed in the well again, and the fish was latched. The pack-off overshot provided a positive pressure seal against the drill string.

150K UNIT RIGGED UP ON 600K UNIT

The decision was made to use a 1.25-in. jointed work string and a snubbing unit to perform the remaining clean-out of the severed drillstring. This required rigging a 150k snubbing unit on top of the 600k snubbing unit. This type of dual snubbing unit operation had been performed on previous workovers. The rig-up of the 150k hydraulic jack on top of the 600k hydraulic jack would place the upper basket more than 100 ft above the ground.

Rig-up of the 150k snubbing unit on the 4.5-in. work string was similar to the rig-up of the CTU. The 4.5-in. work string was once again spaced out to place the top joint at basket level. The TIW valve was topped by a gate valve, a safety ram and a drilling cross. The snubbing BOP stack was then rigged up on the drilling cross. The snubbing stack consisted of two stripper rams and one safety ram.

The BHA run in the well comprised a 2.5-in. bit, two back-pressure valves and an N-profile nipple. This BHA was snubbed in the wellbore on the 1.25-in. work string. The bit tagged shale fill 295 ft below the top of the fish, 375 ft from surface. This was the same depth washed to by the coiled tubing. The clean-out performed by the snubbing unit was hard and slow.

In the drillstring, fill was continuous, not a series of bridges. The snubbing unit was able to drill 7,800 ft of shale in 11 days. This placed the top of the fill at 8,160 ft, a depth that was below the shoe of the intermediate casing, Fig. 4.

Fig. 4. A clean-out operation succeeded in reaching a point below the shoe of the intermediate casing.

OPENHOLE ABANDONMENT

The wellbore was successfully cleaned out to a depth where the openhole section could be abandoned sufficiently. A decision was made to abandon the wellbore' lower openhole section, kickoff below the 7-in. intermediate casing, and re-drill the well to TD.

The 1.25-in. work string was snubbed out of the wellbore, and the 150k snubbing unit was rigged down. Wireline was rigged up on the 600k snubbing unit, and the original drill string was perforated at 8,160 ft.

Circulation was established through these perforations and up the annulus. The well as killed successfully, when 13-ppg mud was circulated into the wellbore. A 150-ft cement plug was spotted across the drill pipe and the openhole section, Fig. 5.

Fig. 5. A 150-ft cement plug was inserted and tested after the well was killed successfully.

After the cement was pressure-tested, wireline was rigged up, and a jet cut was performed at 8,100 ft. This permanently abandoned the wellbore' lower, open-hole section. After confirming that the drill pipe was free, the 600k hydraulic snubbing unit was rigged down. A drilling rig was rigged up, and the work string and 8,100 ft of the original drillstring were tripped out of the hole. The drilling rig then commenced to sidetrack the well and drill to TD, Fig. 6.  

Fig. 6. The well was sidetracked to TD after the original drillstring was tripped out of the hole.

THE AUTHORS
	Tyson Foutz is an engineer with Cudd Pressure Control. He has worked onshore and offshore, and has considerable experience in blowout and well control, corrosion, hot tap, conventional freezing, cryogenic freeze testing and field implementation, cryogenic freezing through multiple casing and cement layers, hydraulic snubbing, conventional and hydraulic rig assist snubbing, and offshore drillship, jackup and semisubmersible rig work. Mr. Foutz holds a BS degree in petroleum engineering from Colorado School of Mines. He has completed a variety of certification training including: IADC WellCAP, IADC Rig Pass, Well Control School MMS and IADC, HAZWOPER, Survival Training for Canadian Offshore and Cudd Well Control First Responder. He is a member of SPE and AADE, and resides in Edmond, Oklahoma.