For each casing size there are a range of casing weights available. The weight of
the casing is in fact the weight per foot of the casing and is a representation of the
wall thickness of the pipe. There are for instance four different weights of 9 5/8″ casing:

casing weight

Although there are strict tolerances on the dimensions of casing, set out by the API, the actual I.D. of the casing will vary slightly in the manufacturing process. For this reason the drift diameter of casing is quoted in the specifications for all casing. The drift diameter refers to the guaranteed minimum I.D. of the casing. This may be important when deciding whether certain drilling or completion tools will be able to pass through the casing e.g. the drift diameter of 9 5/8” 53.5 lb/ft casing is less than 8 1/2″ bit and therefore an 8 1/2” bit cannot be used below this casing setting depth. If the 47 lb/ft casing is too weak for the particular application then a higher grade of casing would be used (see below). The nominal I.D. of the casing is used for calculating the volumetric capacity of the casing.

The length of a joint of casing has been standardised and classified by the API as follows:

table 1

Although casing must meet the classification requirements of the API, set out above, it is not possible to manufacture it to a precise length. Therefore, when the casing is delivered to the rig, the precise length of each joint has to be measured and recorded on a tally sheet. The length is measured from the top of the connector to a reference point on the pin end of the connection at the far end of the casing joint. Lengths are recorded on the tally sheet to the nearest 100th of a foot. Range 2 is the most common length, although shorter lengths are useful as pup joints when attempting to assemble a precise length of string.

The size of the casing refers to the outside diameter (O.D.) of the main body of the tubular (not the connector). Casing sizes vary from 4.5″ to 36″ diameter. Tubulars with an O.D. of less than 4.5” are called Tubing. The sizes of casing used for a particular well will generally be limited to the standard sizes that are shown in Figure 3. The hole sizes required to accommodate these casing sizes are also shown in this diagram. The casing string configuration used in any given location e.g. 20” x 13 3/8” x 9 5/8” x 7” x 4 1/2” is generally the result of local convention, and the availability of particular sizes.

When the casing configuration (casing size and setting depth) has been selected, the loads to which each string will be exposed will be computed. Casing, of the required size, and with adequate load bearing capacity will then be selected from manufacturer’s catalogues or cementing company handbooks.

Casing joints are manufactured in a wide variety of sizes, weights and material grades and a number of different types of connection are available. The detailed specification of the sizes, weights and grades of casing which are most commonly used has been standardised by the American Petroleum Institute – API. The majority of sizes, weights and grades of casing which are available can be found in manufacturer’s catalogues and cementing company handbooks (e.g. Halliburton Cementing Tables).

Casing is generally classified, in manufacturer’s catalogues and handbooks, in terms of its size (O.D.), weight, grade and connection type:

A liner is a short (usually less than 5000ft) casing string which is suspended from the inside of the previous casing string by a device known as a liner hanger. The liner hanger is attached to the top joint of the casing in the string. The liner hanger consists of a collar which has hydraulically or mechanically set slips (teeth) which, when activated, grip the inside of the previous string of casing. These slips support the weight of the liner and therefore the liner does not have to extend back up to the wellhead. The overlap with the previous casing (liner lap) is usually 200ft – 400ft. Liners may be used as an intermediate string or as a production string.

The advantages of running a liner, as opposed to a full string of casing, are that:
1. A shorter length of casing string is required, and this results in a significant cost reduction;
2. The liner is run on drillpipe, and therefore less rig time is required to run the string;
3. The liner can be rotated during cementing operations. This will significantly improve the mud displacement process and the quality of the cement job.

After the liner has been run and cemented it may be necessary to run a casing string of the same diameter as the liner and connect onto the top of the liner hanger, effectively extending the liner back to surface. The casing string which is latched onto the top of the liner hanger is called a tie-back string. This tie-back string may be required to protect the previous casing string from the pressures that will be encountered when the well is in production.

In addition to being used as part of a production string, liners may also be used as an intermediate string to case off problem zones before reaching the production zone. In this case the liner would be known as a drilling liner (Figure 2). Liners may also be used as a patch over existing casing for repairing damaged casing or for extra protection against corrosion. In this case the liner is known as a stub liner.

casing string

Institute of Petroleum Engineering, Heriot-Watt University

The production casing is either run through the pay zone, or set just above the pay zone (for an open hole completion or prior to running a liner). The main purpose of this casing is to isolate the production interval from other formations (e.g. water bearing sands) and/or act as a conduit for the production tubing. Since it forms the conduit for the well completion, it should be thoroughly pressure tested before running the completion.

Intermediate (or protection) casing strings are used to isolate troublesome formations between the surface casing setting depth and the production casing setting depth. The types of problems encountered in this interval include: unstable shales, lost circulation zones, abnormally pressured zones and squeezing salts. The number of intermediate casing strings will depend on the number of such problems encountered.

The surface casing is run after the conductor and is generally set at approximately 1000 – 1500 ft below the ground level or the seabed. The main functions of surface casing are to seal off any fresh water sands, and support the wellhead and BOP equipment. The setting depth of this casing string is important in an area where abnormally high pressures are expected. If the casing is set too high, the formations below the casing may not have sufficient strength to allow the well to be shut-in and killed if a gas influx occurs when drilling the next hole section. This can result in the formations around the casing cratering and the influx flowing to surface around the outside of the casing.

The conductor is the first casing string to be run, and consequently has the largest diameter. It is generally set at approximately 100ft below the ground level or seabed. Its function is to seal off unconsolidated formations at shallow depths which, with continuous mud circulation, would be washed away. The surface formations may also have low fracture strengths which could easily be exceeded by the hydrostatic pressure exerted by the drilling fluid when drilling a deeper section of the hole. In areas where the surface formations are stronger and less likely to be eroded the conductor pipe may not be necessary. Where conditions are favourable the conductor may be driven into the formation and in this case the conductor is referred to as a stove pipe.

A casing string consists of individual joints of steel pipe which are connected together by threaded connections. The joints of casing in a string generally have the same outer diameter and are approximately 40ft long. A bull-nose shaped device, known as a guide shoe or casing shoe, is attached to the bottom of the casing string and a casing hanger, which allows the casing to be suspended from the wellhead, is attached to the top of the casing. Various other items of equipment, associated with the cementing operation, may also be included in the casing string, or attached to the outside of the casing e.g. float collar, centralisers and scratchers. This equipment will be discussed in greater depth in the chapter associated with cementing.

casing string