Overview of Casing Process

The casing process begins with the design of the casing string, a complex optimization problem that requires careful consideration of many variables, including economics, safety, borehole stability, well completion aspects, and applicable regulations. Prior to beginning the casing design, important information such as fracture gradients, formation pressures, temperature profiles, maximum anticipated surface pressures, and produced fluid composition should be gathered (Hansen, 2013). The design process begins with the selection of the production casing size and depth by a petroleum engineer working alongside a geologist. With the depth and diameter of the production casing known, the borehole size and rock bit diameter are selected. From here, diameter selection of casing strings and boreholes proceeds in a bottom-up approach (Lyons and Plisga, 2005). Proper clearance between the casing stings and borehole must be

maintained to promote good cementing.

With casing diameters determined, the next task is selection of the setting depth for each string. Many parameters influence the setting depth of casing, and most are out of control of the designer. These parameters include formation fluid pressures, fracture gradients, borehole stability problems, regulations, company policy and a company’s experience in the area (Byrom, 2007). After the initial casing plan has been determined, it may be modified as the well is drilled based on measurements and data, such as drill logs, cuttings analysis, and analysis of pressures and drilling loads (API, 2009). Excluding

problem zones and regulations, the primary design criteria are the pore and fracture pressure gradients. While drilling, the drillers must maintain the pressure in the borehole between the formation pressure (also referred to as pore pressure) and fracture pressure, with an added safety margin on each parameter. Although this is explained in more detail in the section on pressure management, it plays an important role in casing design and setting depth.

To illustrate how casing set depth is determined based on pore and fracture pressure gradients, Figure 14 shows pore and fracture pressures verses depth for a theoretical well requiring the use of intermediate casing to reach a total depth of 12,000 ft. Starting at the bottom of the well, a mud density of 1.3 specific gravity (sg) is

sufficient to contain the pore pressure plus the safety margin. However, at a depth of approximately 2,000 ft., a mud of 1.3 sg exceeds the kick margin. Therefore a string of casing must be set at that depth for drilling to continue from 2,000 feet to 12,000 feet. It is worth noting that the majority of wells drilled in the world have simple, linear pore and formation pressure gradients (Byrom, 2007).

Another important aspect of casing design is consideration of the loads applied to the casing and the resultant tri-axial stress. In service, casing will be subjected to burst loads, collapse loads, and tangential loads. Stress within the casing is composed of three principle components: axial stress (longitudinal), hoop stress (tangential) stress, and radial stress. Burst loads are applied when pressure inside the casing is greater than pressure external to the casing, such as during fracturing. Collapse loads are the opposite, and typically occur when the wellbore is empty and at atmospheric pressure. Collapse and burst loads result in hoop and radial stresses within the casing. Axial loads are caused by gravitational, frictional and buoyancy forces acting on the casing. These loads impose axial stress within the casing (Maurer Engineering Inc., 1996). The axial stresses imposed by tensile or compressive loads have an effect on the collapse and burst strength of the casing string. Tensile loads have the effect of increasing burst strength while decreasing collapse strength, compressive loads increase collapse strength while decreasing burst strength. This effect is shown quantitatively in Figure 15 for 7” – 23 lb/ft N-80 casing. In practice, loading calculations for casing are highly complex, and are often performed by computer programs making use of formulas outlined in API Bulletin 5C3.

Figure 15: Interaction of Axial Loads with Collapse and Burst Strength (TH Hill, 2010)

Proper material selection plays a vital role in the maintenance of well integrity, and is therefore a critical step in the design of a casing string. The two most important parameters involved in material selection for casing is the materials yield strength and corrosion resistance. The standard API Material designation encompasses both of these parameters. Casing and wellbore tubular grades are designated by a letter followed by a number, with the letter representing the composition of the steel, and the number

approximate minimum yield strength of the material in ksi (1000 psi). The most common steels for casing include H40, J55, K55, N80-1, N80Q, and P110, with N80 being used most frequently (Renpu, 2011), and a comparison of their mechanical properties is shown in Table 2.

Table 2: Mechanical Properties of API Casing Grades (Adapted from API Spec. 5CT/ISO 11960)

Grade

Yield Strength (ksi) Tensile Strength (ksi) Minimum Total Elongation % Minimum Maximum H-40 40 80 60 0.5 J-55 55 80 75 0.5 K-55 55 80 95 0.5 N-80 80 110 100 0.5 M-65 65 85 85 0.5 L-80 80 95 95 0.5 C-90 90 105 100 0.5 C-95 95 110 105 0.5 T-95 95 110 105 0.5 P-110 110 140 125 0.6 Q-125 125 150 135 0.65

The borehole environment can be extremely hostile to steel, often containing Cl-, HCO3- Mg+, CO2, and H2S, all of which can corrode the cement sheath and the casing, possibly compromising wellbore integrity (Renpu, 2011). Materials have been developed which can resist the effects of some corrosive environments. For example, an L80-13Cr steel is well suited to an environment containing carbon dioxide, while grades like T95 and C95 are suited for environments containing H2S (Renpu, 2011).