Relief-Well Planning and Drilling for a North Sea Underground Blowout
Authors: Leraand Frode , Wright J.W. , Zachary M.B. , Thompson B.G. 
Published: December 2007

Summary.
This case history describes relief-well planning and execution for a deep, underground blowout. Key achievements include an innovative relief-well strategy, locating and tracking the target casing with electromagnetic ranging and conventional surveying techniques, and integrating kill pumping units and associated equipment on a semisubmersible. This was the first known instance of relief-well intersection and kill without a plugback and redrill after ranging. The techniques and equipment, plus good teamwork, provided the necessary ingredients to place a bit into a 215.9-mm open hole 5 km away and to regain well control successfully. This work also summarizes a parallel kill effort with a snubbing unit for surface intervention.

Introduction
In Dec. 1988, Saga Petroleum A/S set 244.5-mm casing at 4437 m on Well 2/4-14 in the Ekofisk area of the North Sea. Saga was drilling from a semisubmersible in 68 m of water to evaluate the Jurassic hydrocarbon potential 300 m deeper. This exploratory well was the first drilled to such a depth in the prospect.
Drilling continued through the Cretaceous with 215.9-mm bits and water-based mud. A sharp transition occurred and formation pore pressure increased from an estimated 1.65- to 2.11-g/CM3 equivalent mud weight (EMW) near the reservoir top. Formation integrity at the casing shoe was 2.18-g/CM3 EMW. The hole penetrated several potentially weak formations above the objective, and while drilling near-balanced, narrow margins between influx and lost circulation were encountered.
On Jan. 11, 1989, the crew observed a 1-m drilling break at 4733 m. The well began to flow immediately. The upper annular blowout preventer (BOP) was closed and attempts were made to establish circulation with the driller's method and to bullhead, but without success. After fighting simultaneous loss and influx for several days, the bottomhole assembly (BHA) was cemented at 4700 m, and a backoff and sidetrack planned. The drillstring, however, became plugged, requiring a coiled-tubing operation to remove the obstructions. Well control was lost on Jan. 20, malting it necessary to shear the 127-mm drillpipe with 4482 m of coiled tubing inside. Wellhead pressure increased to a maximum of 70.3 MPa.
An attempt was made to bullhead down the kill line but the flex hose burst at the slip joint. The well flowed for approximately 1 minute before being shut in by the fail-safe valves. The crew disconnected the riser and moved the rig off location (Fig. 1). The subsea stack was vertical. No hydrocarbons were discharging into the sea.
Saga, with cooperation from partners Statoil A/S, Amerada Hess Corp., and Elf Aquitaine, immediately formed an internal task force to manage the operations and to regain control. This task force studied project management, engineering, field supervision, rig mobilization, and blowout and relief-well specialists.

Choosing the Kill Method
The flowing reservoir consists of fine- to coarse-grained sandstone with an estimated 100-md permeability. The fluid was light oil or gas condensate with a high GOR and a reservoir pressure estimated at 98 MPa. Bottomhole static temperature (BHST) was 167 degrees C.
From data before the pipe was sheared, the team decided that the annulus around the BHA probably was sealed (by cement or settled barite) and that flow was passing through the bit and up the drillstring to the wellhead. The annulus contained 2.09-g/CM3 mud. The introduction of 70.3 MPa on the surface might have fractured the formation at the casing shoe. There was no significant wellhead pressure drop (during the 16 hours from shearing the pipe to leaving the location) that would indicate a casing rupture and underground blowout. However, because a similar blowout in 1984 held at 82.7 MPa for 6 days before rupturing its casings, a rupture was anticipated.
Operators facing a blowout must choose how many relief wells to start and how to use them (Table 1). Two simultaneous, redundant, intervention projects historically prove sufficient. The team decided that a single relief well, designed for a worst-case scenario, would act as a backup to surface intervention. The team designed two extra relief-well geometries.
Surface Intervention. The task force, assisted by Boots and Coots Inc., adopted a surface intervention plan. The operation would use the existing subsea BOP, combined with a custom-built stack and high-pressure riser system designed for a snubbing unit. This stack and riser maintained pressure integrity from the seabed to the jackup, Nedrill Trigon.
The surface team intended to latch on to the severed drillpipe with a custom-made packoff overshot and to fish out the coiled tubing. Afterward, they could examine several kill alternatives.
JPT
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