Types of Casing

Casing is categorized into four different types, based primarily on functionality and depth. Aside from the four primary types of casing, most well completions include other important elements, such as liners and packers, to maximize production potential and minimize cost.

Conductor, or stove casing, is typically the first casing string cemented in place, and is therefore the largest, outermost casing. The conductor casing serves primarily to prevent the cave-in of unconsolidated formations near the surface, and to isolate shallow ground water. It may be used to support wellhead equipment, or simply cut off at the surface after the surface casing has been set. The conductor casing is not designed to be shut-in, or sealed using the BOP, and is therefore not capable of holding integrity under such pressures. To prevent contamination of shallow water sources, the hole for the conductor casing is either drilled using air or freshwater based drilling fluids, or driven into place like a structural pile (API, 2009). The proper setting depth of the conductor casing may be determined by soil bearing tests and coring, which determine the structural stability of the soil. A rule of thumb when determining the depth of conductor casings, in absence of soil tests, is to follow established practice in the region that has been shown to be effective (Byrom, 2007). A typical onshore well will use between 40 to 500 feet of conductor casing, depending upon geological conditions. Diameters vary from 7 to 20 inches. Generally, the deeper a well is, the larger diameter conductor casing it will use (Rahman and Chilingarian, 1995). In the Marcellus Shale, companies typically employ a 15-1/2 inch diameter conductor casing set to a depth of 40 feet (Anonymous, 2012).

Much like conductor casing, surface casing is primarily used to prevent the collapse of unconsolidated shallow formations, and to isolate freshwater-bearing formations. The surface casing, however, is set in a competent, consolidated formation, and is capable of holding pressure. For this reason, the BOP is most commonly installed on the surface casing string. For onshore wells, the surface casing is usually cemented to the surface. Cementing protects fresh-water formations from contamination, and forms a structural connection between the casing and formation (Lyons and Plisga, 2005). Setting depths for surface casing vary from a few hundred feet to as deep as 5,000 feet. Sizes of the surface casing vary from 7 to 16 inches in diameter, with 10 and 13 inches being the most common sizes (Rahman and Chilingarian, 1995). In the Marcellus Shale, companies typically employ an 11-3/4 inch diameter surface casing set to a depth of 700 feet

(Anonymous, 2012).

Also called a protection string, intermediate casing is usually set to allow for drilling to total depth by isolating troublesome formations such as lost-circulation zones, zones with abnormal formation pressures, corrosive zones, or easily fractured shales or salt sections. Depending on sub-surface geology, the well may require two or more intermediate strings to reach total depth (Lyons and Plisga, 2005). Typical lengths for intermediate casing are between 7,000 to 15,000 feet and diameters range from 7 to 12 inches. It is common for the intermediate casing string to be hung from the surface casing as a liner, and cemented up to 1,000 feet from the casing shoe, but longer cement

columns are sometimes needed to prevent buckling (Rahman and Chilingarian, 1995). In the Marcellus Shale, companies typically employ an 8-5/8 inch diameter surface casing set to a depth of 2000 feet (Anonymous, 2012).

Production casing is the casing string through which the well is produced and is usually the last casing string to be set in the well. The function of production casing is to provide zonal isolation between producing zones and other subsurface formations (API, 2009). The size of the production casing depends on the expected production rate from the well, with higher production rates requiring larger production casing strings.

Common sizes range between 3 and 7 inch outside diameters (Serene Energy, 2012). In the Marcellus Shale, companies typically employ a 5-1/2 inch diameter production casing set to a depth of 7000 to 8000 feet (Anonymous, 2012).

In addition to the primary types of casing, there are other elements used to

implement a casing string that warrant mention. The first is a liner, a string of casing that does not extend to the top of the well and is instead suspended inside the next largest casing string using a liner hanger (API, 2010). These devices are connected to the last casing string by setting slips or through expansion of the hanger against the inner wall of the previously set casing. Unless the liner is tied back to the surface, there is no need for an inner casing string above the hanger, which can greatly reduce the amount of casing required to complete the well. Liners are usually set to isolate troublesome sections of the well or producing zones, and for the economic benefit realized by reducing the amount of casing needed (Rahman and Chilingarian, 1995). Both intermediate and production casing are commonly set as liners. A scab liner is used to repair existing damaged casing and may be cemented or sealed with packers, or tied back to the surface, as shown in Figure 12.

Figure 12: Various Liner Types (Rahman and Chilingarian, 1995)

Packers are mechanical elements used to seal an annulus. There are many types of packers, and they are classified by use and retrievability. The two most common types of packers are production packers and inflatable packers. Production packers, or test

packers, are set in cased holes between the production tubing and the cased hole, which allows for controlled production. Production packers are typically set through forced extrusion of an elastomeric element (Schlumberger, 2013). Inflatable packers are typically set in open or cased holes, and are set by filling an elastomeric bladder with fluid, the expansion of which seals the annular space.