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The most important mechanical properties of casing and tubing are burst strength, collapse resistance and tensile strength. These properties are necessary to determine the strength of the pipe and to design a casing string. If casing is subjected to internal pressure higher than external, it is said that casing is exposed to burst pressure loading. Burst pressure loading conditions occur during well control operations, casing pressure integrity tests, pumping operations, and production operations. The MIYP of the pipe body is determined by the internal yield pressure formula found in API Bull. This equation, commonly known as the Barlow equation, calculates the internal pressure at which the tangential (or hoop) stress at the inner wall of the pipe reaches the yield strength (YS) of the material.
The table also includes an indication of the primary uses and benefits, along with the cements that they can be used with. The primary effects of the cement admixtures on the physical properties of the cement, either as a slurry or set, are presented in Table 2. This is a quick reference, and individual additives in a given category may not agree in total with the effects as given. It is also typically defined for individual additives, the properties and effects of which can be modified when additive combinations are used.
When a well is drilled on land, an interface is required between the individual casing strings and the blowout preventer (BOP) stack. When drilling a well on land, a spool wellhead system is traditionally used, as shown in Figure 1. This wellhead is considered a "build as you go" wellhead system that is assembled as the drilling process proceeds. Figure 1--Illustration of a typical land wellhead system and casing program (all figures in this chapter are courtesy of Dril-Quip). The starting casing head (see Figs. 2 and 3) attaches to the surface casing (conductor) by either welding or threading on to the conductor.
Two forms of derivatized cellulose have been found useful in well-cementing applications. The usefulness of the two materials depends on their retardational character and thermal stability limits. This is commonly used at temperatures up to approximately 82 C (180 F) for fluid-loss control, and may be used at temperatures up to approximately 110 C (230 F) BHCT, depending on the co-additives used and slurry viscosity limitations. Above 110 C (230 F), HEC is not thermally stable. HEC is typically used at a concentration of 0.4 to 3.0% by weight of cement (BWOC), densities ranging from 16.0 to 11.0 lbm/gal, and temperatures ranging from 27 to 66 C (80 to 150 F) BHCT to achieve a fluid loss of less than 100 cm3 /30 min.
The unitized wellhead is very different from the spool wellhead system, because it incorporates different design characteristics and features. The unitized wellhead, shown in Figure 1, is a one-piece body that is typically run on 13 3/8 -in. The casing hangers used are threaded and preassembled with a pup joint. This way, the threaded connection can be pressure tested before leaving the factory, ensuring that the assembly will have pressure-containing competence. Gate valves are installed on the external outlet connections of the unitized wellhead to enable annulus access to each of the intermediate and the production casing strings.
The subsea wellhead system (Figure 1) is a pressure-containing vessel that provides a means to hang off and seal off casing used in drilling the well. The wellhead also provides a profile to latch the subsea blowout preventer (BOP) stack and drilling riser back to the floating drilling rig. In this way, access to the wellbore is secure in a pressure-controlled environment. The subsea wellhead system is located on the ocean floor, and must be installed remotely with running tools and drillpipe. Figure 1--Illustration of a typical subsea wellhead system with temporary abandonment cap installed.
Remedial cementing is undertaken to correct issues with the primary cement job of a well. Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs have the potential to force poor decisions and high risk. Good planning and risk assessment is the key to successful remedial cementing. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics.
Most primary cement jobs are performed by pumping the slurry down the casing and up the annulus; however, modified techniques can be used for special situations. Conductor, surface, protection, and production strings are usually cemented by the single-stage method, which is performed by pumping cement slurry through the casing shoe and using top and bottom plugs. There are various types of heads for continuous cementing, as well as special adaptors for rotating or reciprocating casing. Stage-cementing tools, or differential valve (DV) tools, are used to cement multiple sections behind the same casing string, or to cement a critical long section in multistages. Stage cementing may reduce mud contamination and lessens the possibility of high filtrate loss or formation breakdown caused by high hydrostatic pressures, which is often a cause for lost circulation.
From a historic point of view, as jackup drilling vessels drilled in deeper water, the need to transfer the weight of the well to the seabed and provide a disconnect-and-reconnect capability became clearly beneficial. This series of hangers, called mudline suspension equipment, provides landing rings and shoulders to transfer the weight of each casing string to the conductor and the sea bed. Each mudline hanger landing shoulder and landing ring centralizes the hanger body, and establishes concentricity around the center line of the well. Concentricity is important when tying the well back to the surface. In addition, each hanger body stacks down relative to the previously installed hanger for washout efficiency.
Bit- and casing-size selection can mean the difference between a well that must be abandoned before completion and a well that is an economic and engineering success. Improper size selection can result in holes so small that the well must be abandoned because of drilling or completion problems. The drilling engineer (and well planner) is responsible for designing the hole geometry to avoid these problems. However, a successful well is not necessarily an economic success. For example, a well design that allows for satisfactory, trouble-free drilling and completion may be an economic failure, because the drilling costs are greater than the expected return on investment.