In this case the casing may be hung safely with the full buoyed weight on the hanger without danger of collapse. Whenever doing this type of calculation it is important to know whether the angle of the slip segments is measured from the horizontal or vertical. If the angle is measured from the vertical it must be subtracted from 90° before using in this formula. It is also important to compare to the biaxial collapse rating of the casing (though many assume the safety factor of 2.0 is sufficient to ignore the combined collapse/tension effect and that may be acceptable for many companies).
Wellhead Equipment for Casing
While wellhead selection is primarily a function of the completions discipline a good deal of the selection parameters for the lower portion of the wellhead equipment are based on the casing and drilling operations. In this section we will discuss some of the aspects that are related to the casing and cementing practices. We will look at the portion of the wellhead that is directly related to the cased portion of the well since the remainder of the wellhead equipment is the tubing head and Christmas tree and is entirely in the realm of completions and production.
As far as drilling and casing is concerned there may be only one or two sections of wellhead involved (sometimes more). These sections are generally referred to as casing heads and casing spools.
The first head installed is usually called a casing head and subsequent sections are referred to as casing spools (you may also hear the terms A-section and B-section). The casing head is of two types, a slip-on welded head or a threaded head. The figure below shows typical casing heads of these two types.
Casing Heads
Figure 7 - 10. Typical welded and threaded casing heads.
The slip-on welded head requires that the casing on which it is installed be cut with a cutting torch; then the head is slipped on and welded in place. It has the advantage of
allowing the casing to be landed at any depth and is the only possibility if the casing should become stuck off bottom or while reciprocating during cementing operations.
This type of head is usually the preferred choice of most operators. Most of these casing heads are installed on the surface casing after the conductor casing is cut off.
But some of these heads have a large base plate flange that is welded to the conductor instead of the surface casing, and the surface casing is then hung inside the conductor casing head.
The threaded casing head has the advantage that no cutting or welding is required and it generally installs much faster. There are disadvantages:
• It requires precise landing of the casing string so that a coupling is at the proper distance in relation to the ground level which cannot be visually verified since it is landed below the conductor bell nipple and/or diverter.
• A casing coupling must be removed for installing the casing head. It may be difficult or impossible to back off the coupling under the rig floor and often the coupling has to be cut off with a torch at the risk of damaging the casing threads to which the head will be attached. Typically the initial loosening of the coupling is done on the rig floor before the landing joint is installed.
• The casing may be some distance (up to 40 ft ±) off bottom as determined by the top coupling location.
• The casing must be cemented all the way to the surface.
• If the casing is not adequately cemented at the surface, the casing may slump down into the hole and the connection for the head may be too low to attach the head.
This type of head is usually selected for very shallow surface casing applications.
The next casing related section of the wellhead is a casing spool and is required if more than one additional string of casing is to be run. After the initial casing head is installed drilling resumes then the next string of casing is hung in the initial casing head. Then a casing spool is installed on top of that which will serve to hang the next string of casing.
Casing Spools
Figure 7 - 11. A typical casing spool with threaded outlets.
A spool of this sort is flanged on top and bottom, has a bowl in the top for the casing hanger for the next casing string and two outlets to install valves that allow fluid access to the casing string hung in the previous spool or head. The illustration above shows threaded outlets which are typical for low pressure applications on land wells.
However, higher pressure wells and those on inland waters and offshore typically have flanged outlets. The top and bottom flanges on casing heads and spools are selected so that the bottom connection and the side outlet connections all have the same pressure rating of the casing string below it and the top flange has the pressure rating of the casing string that will be hung in it. For example, a spool may have a 3000 psi flange on bottom and 3000 psi flange outlets, but a 5000 psi flange on top.
There are two general types of casing hangers available for hanging casing. The most commonly used is a slip type hanger similar to those shown in the figures below. The slip type hanger is almost always installed after the casing has been cemented and the cement has been allowed time to set.
Casing Hangers
Figure 7 - 12. A two piece slip type hanger.
Figure 7 - 13. A one piece slip type casing hanger.
These types of hangers are usually installed by removing the BOP bolts and raising the BOP assembly to install the hanger around the pipe while it is still supported by the landing joint(s) and elevators. Once the hanger is seated in the casing head or spool
the casing string is then pulled with the landing joint(s) to the desired tension then lowered slightly to allow the slips hold the casing in place.
With a slip type hanger you can always increase the tension in the pipe once the slips hold, but you cannot reduce it.
An alternative and much safer procedure is to install the slips on the landing joint above the rotary and let it slide down the pipe and into the head. This procedure requires though that the landing joint be long enough that its lower coupling be below the casing head or spool. There is also the problem that if the pipe is not perfectly concentric in the BOP and well head that the hanger will not slide all the way to or into the head. Attempts to push it down manually with small diameter pipe or other devices are usually not very successful.
The other type of hanger commonly used is a one-piece mandrel type that is threaded on top and bottom and had a sealing element for the spool bowl. A coupling is removed on the top joint and the hanger is threaded onto that joint. A landing joint is threaded into the top of the hanger and the casing is lowered into place. This type of hanger is simple, the safest to use, and results in very few problems. However, there are a few considerations to note.
• This type of hanger is always installed before cementing so the return flow during cementing operations must be routed through the side outlets of the casing head or spool on which it is hung.
• It is not advisable to reciprocate the pipe while cementing with this type of hanger because if the pipe should stick while reciprocating it may not be possible to seat the hanger in the head.
• It is not possible to select the landing weight since the hanger is installed prior to cementing.
• The casing shoe will be off bottom by a distance determined by the coupling location at the top of the string.
All side outlets on casing heads and spools should have valves of the proper type (i.e., no blind flanges or bull plugs). A bull plug or blind flange may be installed outside the valve for protection of desired. At least one valve on each head should have a good working pressure gage so that the casing pressure may be monitored. Casing heads, casing spools, and valves like all wellhead equipment have a rated working pressure or maximum service pressure (MSP) as it is sometimes called. It also has a test pressure which is often higher than the MSP by 50% or more. It has become an all too common practice for some operators to rely on the test pressure rather than the MSP when the actual well pressure is slightly above
Precautions
the MSP of the wellhead. This condemnable practice does result in a significant cost savings, but at a considerable risk to the field people who are the ones exposed to the risk. One should always use only the MSP rating in selecting equipment. If the well pressure expected is 3050 psi, then the only choice for a wellhead is 5000 psi, not 3000 psi. It is unconscionable to choose otherwise.