Coiled-Tubing Applications for Blowout-Control Operations
- N.J. Adams (Neal Adams Firefighters Inc.) | S.K. Mack (Schlumberger Dowell) | V.R. Fannin (Schlumberger Dowell) | Thierry Rocchi (Schlumberger Dowell)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1996
- Document Type
- Journal Paper
- 398 - 405
- 1996. Society of Petroleum Engineers
- 1.10 Drilling Equipment, 1.14 Casing and Cementing, 1.11.4 Solids Control, 1.6 Drilling Operations, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.6.1 Drilling Operation Management, 1.7.5 Well Control, 1.11 Drilling Fluids and Materials, 4.2 Pipelines, Flowlines and Risers, 1.7 Pressure Management, 2.4.3 Sand/Solids Control, 3 Production and Well Operations, 1.11.5 Drilling Hydraulics, 5.7.5 Economic Evaluations
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Coiled-tubing drilling is now being used in various operations. Its complete field of applications is not currently established. Coiled tubing used for well control while drilling is a new field where its limits are being explored. This paper provides guidelines on topics to be considered in determining the applicability of coiled tubing for well-control problems. The information provided is based on recent field experiences with several well-control problems when drilling vent and relief wells. In some cases, coiled-tubing drilling capabilities, by necessity, were significantly extended beyond levels the industry considered to be upper limits.
Well control cannot always be handled by coiled tubing. It is a special-application tool that can handle many situations and is, in some cases, clearly the optimum choice for the application. This paper presents guidelines for selecting coiled tubing for each application and discusses economics. It also describes coiled-tubing operations for regaining control of blowout wells in certain situations and gives technical requirements for planning and executing these types of jobs. Case histories where coiled-tubing units (CTU's) have been used to regain control of drilling and producing wells are provided for illustration.
Typical Well-Control Operations
Several types of well-control problems can be handled by coiled-tubing operations. Some are (1) blowout of producing wells, (2) drilling blowouts, (3) underground blowouts, (4) vent wells, (5) observation wells, and (6) outside-casing flow. Each situation must be examined individually to determine whether coiled tubing is the appropriate application.
Blowout of Producing Wells.
Producing wells are an ideal application for coiled tubing if the blowout exit point can be controlled and diverted to allow a safe rig-up of the injector. In this case, a tree exists to allow rig-up, and rig-up is not a problem if the flow can be diverted safely. In some cases, the gas may be wet and will not burn or the flow can be covered with a heavy fog spray to allow a safe rig-up on the well.
In a recent case offshore, the well was blowing out with the flow perpendicular and below the wellhead. Fire pumps were used to set a water curtain between the flow and the wellhead. This operation wet the gas so it would not burn and also provided a safety curtain so that any possible sparks while rigging up would not ignite the gas. The CTU ran pipe in the well and killed it (Fig. 1).
Blowouts while drilling are a possible application for coiled tubing. A deciding parameter is the flow exit point and the ease of rigging up on the blowout-preventer (BOP) stack, which is not usually designed for easy connection to a CTU. Also, getting the injector on the rig floor during the blowout may not be possible.
If the blowout occurs while drilling with coiled tubing, killing the well typically has been easy. A recent re-entry of a prior blowout encountered a major gas cap below a bridge is an example. The well lost all circulation and then gas blew out to surface. The flowline valve was closed immediately, and the well diverted through the bypass valve on the choke manifold. Pumping fluid into the well continued. After 36 hours of high gas-flow rates, liquids started returning to the surface. The flow was then run through the gas buster, and the choke was used to kill the flow ( Fig. 2).
The kill operations were made easier because the coiled tubing could be moved to various depths in the well while the blowout occurred. It was lowered so that the 4 3/4-in. motor was in heavy-walled, 7-in. casing and could act as a choke. Also, drilling was resumed after about 24 hours while the well was blowing to deepen the hole into the pocket and get all remaining gas.
This type of application is ideal for coiled tubing. The pipe can be moved throughout the well to points where it can do the most good. The downside is that small tubing may not be able to pump at sufficient rates to stop the flow. In addition, barite pills and heavy slugs of mud are often solutions to underground blowouts that coiled tubing may not be able to handle. They may be more likely to cause pipe plugging because of the small pipe diameters.
Vent wells are drilled to relieve pressure from underground blowouts. They usually are drilled into the charged zone and converted to a vent well, after which the gas is flared. Fig. 3 shows a recent vent well drilled to 800 ft. The gas is being produced from a charged zone at 372 to 387 ft. The charging is coming from a downdip underground blowout in a well a few miles away. The charged area was erupting at the surface, making the vent well necessary to handle the uncontrolled eruptions in the populated area surrounding the eruptions.
Observation wells typically are used to evaluate subsurface changes after a shallow-gas blowout. These changes can include pressure charging, gas filling, depletion, and altered drilling conditions compared with preblowout conditions. Observation wells are being more widely used in recent industry history.
Coiled-tubing application for observation-well drilling is a good alternative to use of a conventional rig. Because further gas blowouts may occur, the ability to move quickly off site is attractive. The primary benefit, however, is that the hole is always full and swabbing should not occur as long as the pumps are running. Drilling with coiled tubing in this application is not significantly different than conventional coiled-tubing drilling (i.e., matching motor sizes with tubing torque limits). A full BOP stack with diverter is still required although the diverter line sizes can be smaller than normal because the small-diameter hole acts as a choke to some degree.
Wells flowing outside the casing string are not uncommon, particularly in older wells that have not been properly abandoned or where the casing is corroded. This is one of the ideal problems that can be handled by coiled tubing. The pipe with a motor can be used to clean out the well to a depth where it can be killed. Personnel are only involved near the well during the initial rig-up period in contrast to a conventional rotary rig or snubbing unit where personnel are always involved near the well.
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