PRESSURE-DAMPENING CASING TO REDUCE STRESS LOAD ON CEMENT SHEATH BACKGROUND [0001] Fluids are typically produced from a reservoir in a formation by drilling a wellbore into the formation, establishing a flow path between the reservoir and the wellbore, and conveying the fluids from the reservoir to the surface through the wellbore. Typically, a section of the wellbore is drilled at a time; then a casing is lowered into the wellbore and cemented before drilling the next section. [0002] A casing profile includes multiple casing strings, such as conductor casing, surface casing, intermediate casing and production casing. Furthermore, each casing string undergoes a cement job. The large-diameter conductor casing protects shallow formations from contamination by drilling fluid and helps prevent washouts involving unconsolidated topsoil and sediments. Surface casing, the second string, has a smaller diameter, maintains borehole integrity and prevents contamination of shallow groundwater by hydrocarbons, subterranean brines and drilling fluids. The intermediate casing isolates hydrocarbon-bearing, abnormally pressured, fractured and lost circulation zones, providing well control as engineers drill deeper. Multiple strings of intermediate casing may be required to reach the target producing zone. The production casing, or liner, is the last and smallest tubular element in the well. It isolates the zones above and within the production zone and withstands all of the anticipated loads throughout the well’s life. [0003] With the wellbore lined with a casing, cement operations may be conducted. Cement operations include the process of mixing a slurry of cement, cement additives and water and pumping it down through casing to critical points in the annulus around the casing or in the open hole below the casing string. Cement supports and protects well casings and helps achieve zonal isolation. Critical to safer, environmentally sound, and profitable wells, zonal isolation is created and maintained in the wellbore by the cementing process. The cement is deigned based on various well parameters, e.g., depth, wellbore geometry, temperature, pressure, and formation composition. [0004] If the cement fails to achieve zonal isolation, the failure may cause several potential risks such as a surface blowout, sustain casing pressure event, and/or downhole communication between zones. There are several factors that may result in a cement failure such as cyclic loads that are imposed on the cement. The increase in cyclic loads on the cement may be driven from hydraulic fracturing operations. Additionally, temperature cycling due to different fluid being injected or produced within the wellbore may also cause cement failure. If repeated loads with high magnitudes are exposed to the cement sheath, the cement may crack. To mitigate cementing crack, the cement mechanical properties may be enhanced. However, enhancing the cement mechanical properties is limited by the brittleness of the cement. SUMMARY [0005] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. [0006] In one aspect, embodiments disclosed herein relate to a casing having a tubular body formed by a wall extending axially from a first end to a second end, the tubular body having a bore therein throughout. The wall may radially extend from an inner surface of the tubular body to an outer surface of the tubular body. The wall may include a base layer and one or more secondary layers attached to the base layer. The one or more secondary layers may be a rubber or smart foam. [0007] In another aspect, embodiments disclosed herein relate to a casing string. The casing string may include a first casing coupled to a second casing, with the first casing is axially below the second casing. The first casing may include a first tubular body formed by a first wall extending axially from a first end to a second end, the first tubular body having a first bore therein throughout. The first wall may radially extend from a first inner surface of the first tubular body to a first outer surface of the first tubular body. The first wall may include a first base layer and one or more first secondary layers attached to the first base layer. The one or more first secondary layers may be a rubber or smart foam. The second casing may include a second tubular body formed by a second wall extending axially from a third end to a fourth end, the second tubular body having a second bore therein throughout. The second wall may radially extend from a second inner surface of the second tubular body to a second outer surface of the second tubular body. The second wall may include a second base layer and one or more second secondary layers attached to the second base layer. The one or more second secondary layers may be a rubber or smart foam. Additionally, the casing string may include a collar or coupling configured to couple the second end of the first casing to the third end of the second casing [0008] In yet another aspect, embodiments disclosed herein relate to a method. The method may include forming a base layer of a tubular body extending axially from a first end to a second end. The method may also include providing one or more voids within the base layer. The one or more voids may be an empty space extending a radially distance between a first interior surface of the base layer and a second interior surface of the base layer. The method may further include embedding one or more secondary layers within the one or more voids, the one or more secondary layers may be a rubber or smart foam. [0009] Other aspects and advantages of the invention will be apparent from the following description and the appended claims. BRIEF DESCRIPTION OF DRAWINGS [0010] The following is a description of the figures in the accompanying drawings. In the drawings, identical reference numbers identify similar elements or acts. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the elements and have been solely selected for ease of recognition in the drawing. [0011] FIG. 1A is a schematic diagram of a casing in accordance with one or more embodiments disclosed herein. [0012] FIG. 1B is a schematic diagram of a casing within a wellbore in accordance with one or more embodiments disclosed herein. [0013] FIGs. 2A-2D are various cross-sectional views of casing of FIG. 1A in accordance with one or more embodiments disclosed herein. [0014] FIGs. 3A-3D are various cross-sectional views of casing of FIG. 1A in accordance with one or more embodiments disclosed herein. [0015] FIGs. 4A-4G are various cross-sectional views of casing of FIG. 1A in accordance with one or more embodiments disclosed herein. [0016] FIGs. 5A-5F are various cross-sectional views of casing of FIG. 1A in accordance with one or more embodiments disclosed herein. [0017] FIG. 6 is a cross-sectional view of casing of FIG. 1A in accordance with one or more embodiments disclosed herein. [0018] FIG. 7 is a flow chart of a method in accordance with one or more embodiments disclosed herein. DETAILED DESCRIPTION [0019] In the following detailed description, certain specific details are set forth to provide a thorough understanding of various disclosed implementations and embodiments. However, one skilled in the relevant art will recognize that implementations and embodiments may be practiced without one or more of these specific details, or with other methods, components, materials, and so forth. For the sake of continuity, and in the interest of conciseness, same or similar reference characters may be used for same or similar objects in multiple figures. As used herein, the term “coupled” or “coupled to” or “connected” or “connected to” “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such. As used herein, fluids may refer to slurries, liquids, gases, and/or mixtures thereof. It is to be further understood that the various embodiments described herein may be used in various stages of a well (land and/or offshore), such as rig site preparation, drilling, completion, abandonment etc., and in other environments, such as work-over rigs, fracking installation, well-testing installation, oil and gas production installation, without departing from the scope of the present disclosure. Further, embodiments disclosed herein are described with terms designating orientation in reference to a vertical wellbore, but any terms designating orientation should not be deemed to limit the scope of the disclosure. For example, embodiments of the disclosure may be made with reference to a horizontal wellbore. It is to be further understood that the various embodiments described herein may be used in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in other environments, such as sub-sea, without departing from the scope of the present disclosure. The embodiments are described merely as examples of useful applications, which are not limited to any specific details of the embodiments herein. [0020] Embodiments disclosed herein are described with designated terms in reference to a tubular, but any designated terms should not be deemed to limit the scope of the disclosure. For example, the tubular string is made up of numerous tubular pipes joined end-to-end, and each of the tubular pipes might be about twenty to forty feet in length. Further, the tubular pipes are hollow and thus provide a continuous channel of communication between the drill rig and the bottom of the wellbore, down through which a suitable fluid can be introduced to any region required within the well. It is to be further understood that the various embodiments described herein may be used with various types of tubulars, including but not limited to casing, without departing from the scope of the present disclosure. A casing generally refers to a large-diameter pipe that is lowered into an openhole and cemented in place. [0021] More specifically, embodiments disclosed herein are directed to a casing with one or more secondary layers. The one or more secondary layers may be referred to interchangeably as one or more protective layers. The one or more protective layers may be selected based on an annular clearness in a well design and casing rating requirements in a casing string. The different embodiments described herein may provide a casing with one or more secondary layers exhibiting elastic properties that plays a valuable and useful role in the life of a well. By using the casing with the one or more secondary layers having elastic properties, the casing may stretch without damaging the cement and dampen an effect of surface pressure on the casing. It is further envisioned that software simulations may be used to determine the number of secondary layers to dampen effects of pressure cyclic events on the casing. One skilled in the art will appreciate how the casing with the one or more secondary layers may be provided in a portion of a casing string that is exposed to pressure cyclic events during the life of a well. Further, a configuration and arrangement of the one or more secondary layers to provide a shield for the cement from an expansion and contraction of the casing may provide a cost-effective alternative to conventional systems used in cement operations. For example, one or more embodiments described herein may reduce a transition of a stress load to cement from the casing and eliminate cement cracking. The casing with the one or more secondary layers may increase a well-life of the cement in a wellbore. Additionally, the casing with the one or more secondary layers may provide better and longer well integrity by decreasing the chance of having non-productive time (NPT) and increase zonal isolation in the wellbore. Further, the casing with the one or more secondary layers may also insulate temperature transitions in the cement. Overall, the casing with the one or more secondary layers may minimize product engineering, risk associated with well blowouts, reduction of NPT, hardware cost reduction, and weight and envelope reduction. Thus, the disclosed casing improves safety on site and reduces cost associated with cement operations. The embodiments are described merely as examples of useful applications, which are not limited to any specific details of the embodiments herein. [0022] Referring to FIG. 1A, a casing 100 in accordance with embodiments disclosed herein is illustrated. The casing 100 may have a tubular body 101 extending axially a length L from a first end 102 to a second end 103. The tubular body 101 may include a bore 104 extending therein from the first end 102 to the second end 103 about an axis A. By including the bore 104, the tubular body 101 may have a wall 105 with a thickness T extending radially between an outer diameter (OD) of the tubular body 101 and an inner diameter (ID) of the tubular body 101. The wall 105 may be delimited in an axial plane Y by the first end 102 and the second end 103 and delimited in a radial plane X by an outer surface 106 of the tubular body 101 and an inner surface 107 of the tubular body 101. Additionally, the first end 102 may include a first joint connection 102a and the second end 103 may include a second joint connection 103a. In a non-limiting example, the joint connections 102a, 103a may be a threaded connection to connect the casing 100 to a second casing (not shown) to form a casing string. In some embodiments, the threads of each joint connections 102a, 103a may be male threads. The threads may be a buttress thread or a round thread or a specialty thread. A collar or coupling (not shown), formed by a short cylindrical pipe that is slightly larger than the outer diameter OD of the casing 100, may include female threads to connect to the male threads of one casing to another casing. It is further envisioned that one of the joint connections 102a, 103a may be used to connect the casing 100 to a linear hangar or wellhead. [0023] In one or more embodiments, the tubular body 101 a second length L’ extending between the joint connections 102a, 103a. The second length L’ may be shorter than the length L. Additionally, the outer surface 106 of the tubular body 101 between the joint connections 102a, 103a may be exposed to cement and a formation within a wellbore. As shown by FIG. 1B, the casing 100 may be lowered into a wellbore 110 drilled within a formation 110a. In some embodiment, cement 111 may be pumped into the wellbore 110 to form a cement layer between the casing 100 and the formation 110a. The cement 111 may cement the outer surface 106 of the casing 100 to the wellbore 110. The casing and the cement 111 may apply various forces (see arrows F) on each other through the life of the well. While it is noted that a gap is shown between the casing 100 and the cement 111, this gap is merely shown to easily illustrate the arrows F between the casing 100 and the cement 111, and this gap may or may not exist without departing from the scope of the present disclosure. [0024] In one or more embodiments, within the second length L’, the tubular body 101 may include one or more secondary layers as described in the various embodiments of FIGs. 2A-6. While it is noted that FIGs. 2A-6 illustrate various embodiments, the various embodiments may be used in any combination with each other without departing from the scope of the present disclosure. [0025] In FIG. 2A, a cross-sectional view taken along a radial plane X in FIG. 1A is illustrated in accordance with a first embodiment. In other words, FIG. 2A shows a top view of the casing of FIG. 1A. As shown, the wall 105 may include a base layer 200 extending a thickness Tb radially outward from the inner surface 107 of the tubular body 101. The base layer 200 forms the bore 104. The base layer 200 may be made from a material selected from iron, steel, stainless steel, metal alloy, plastic (e.g., polyvinyl chloride (PVC)), or any material suitable for downhole conditions in a well. Additionally, the wall 105 may include a secondary layer 201 extending a thickness Ts radially outward from the base layer 200 to the outer surface 106. The thickness Tb and the thickness Ts added together form the thickness T of the wall 105. In some embodiments, the thickness Tb may be equal to, less than, or more than the thickness Ts. It is further envisioned that a thickness ratio between the thickness Tb and the thickness Ts may be selected based software simulations. The software simulations may run simulations of cement operations in a well to optimize the thickness ratio based on an available clearness in the well and cyclic loads on the casing 100. [0026] In one or more embodiments, the secondary layer 201 may be attached to the base layer 200 through any suitable manufacturing process, such as coating films, painting, blasting, chemically reacting/bonding, or other additive manufacturing processes, or any combination thereof. The secondary layer 201 may be made from a material selected from rubber or smart foam or a combination thereof. The rubber may be a fluoropolymer (e.g., AFLAS® or Viton ®), a synthetic polymer (e.g., Butyl or Hypalon rubber), nitrile rubber, any type of rubber suitable for downhole conditions in a well, or a combination thereof. The smart foam may be a foam cement, Polyethylene (PE), Polyurethane (PU), or a combination thereof. It is further envisioned that insulation material may be added to the secondary layer 201. [0027] In FIG. 2B, a cross-sectional view taken along an axial plane Y in FIG. 1A is illustrated in accordance with the first embodiment. Thus, FIG. 2B is a side view of the casing of FIG. 1A. The joint connections 102a, 103a may be integral part of the base layer 200 such that the secondary layer 201 extends axially between the first joint connection 102a and the second joint connection 103a. [0028] Referring to Figure 2C, a close-up cross-sectional view of a first casing 100 connected to a second casing 100a is illustrated. Both the first casing 100 and the second casing 100a may be configured as described in FIGs. 2A and 2B. Additionally, the first casing 100 may be axially below the second casing 100a. For example, the first joint connection 102a of the first casing 100 may be connected to a second joint connection 103b of the second casing 100a. To connect the two joint connections 102, 103b together, a collar or coupling 108 may be used. The collar or coupling 108 may be a short cylindrical pipe with an inner connection surface 108a. The short cylindrical pipe may have a protective layer 108b. The protective layer 108b may be similar to the secondary layer 201 of the casings 100, 100a. The inner connection surface 108a may be threaded such that the inner connection surface 108a is coupled to the first joint connection 102a of the first casing 100 and the second joint connection 103b of the second casing 100a. For example, the collar or coupling 108 may first be installed on the first joint connection 102a of the first casing 100; then the first joint connection 102a of the first casing 100 may be coupled to the collar or coupling 108 until the first casing 100 and the second casing 100a are flush against each other forming a seal 109. [0029] Still referring to FIG. 2C, the secondary layer 201 may be spaced a distance D from the first joint connection 102a such that the secondary layer 201 does not impede the collar or coupling 108. [0030] Now referring to FIG. 2D, a close-up cross-sectional view of the casing 100 as described in FIGs. 2A and 2B in a wellbore 110 of a formation 110a is illustrated. Additionally, cement 111 may be pumped into the wellbore 110 once the casing 100 in downhole. The cement 111 is pumped in an annulus space between the wellbore 110 and the casing 100. As shown by FIG. 2D, the secondary layer 201 of the casing 100 is between the cement 111 and the base layer 200 of the casing 100. With the secondary layer 201 between the base layer 200 and the cement 111, the secondary layer 201 may dampen a pressure or temperature exerted on the cement 111. [0031] Referring now to FIGs. 3A-3D, a second embodiment of the casing 100 according to embodiments herein is illustrated, where like numerals represent like parts. FIGs. 3A-3D show an embodiment in which the secondary layer 201 is disposed internally, behind the base layer 200 of the casing. This is in contrast to the embodiment of FIG. 2A-2D, in which the secondary layer 201 is disposed externally, between the base layer 200 of the casing and the cement layer. In the second embodiment of FIGs. 3A-3D, the base layer 200 extends a thickness Tb radially inward from the outer surface 106 of the tubular body 101. Additionally, the secondary layer 201 extends a thickness Ts radially inward from the base layer 200 to the inner surface 107 of the tubular body 101. As shown in FIG. 3D, the base layer 200 is between the cement 111 and the secondary layer 201. With the secondary layer 201 behind the base layer 200, the secondary layer 201 may absorb and dampen internal pressure or temperature within the casing 100 before the pressure or temperature is transferred to the cement 111 through the base layer 200. [0032] Referring now to FIGs. 4A-4D, a third embodiment of the casing 100 according to embodiments herein is illustrated, where like numerals represent like parts. The third embodiment of FIGs. 4A-4D is similar to that of the first embodiment of FIGs. 2A-2D. However, in the third embodiment, the base layer 200 extends a thickness Tb radially outwardly from the inner surface 107 to the outer surface 106 of the tubular body 101. Additionally, the secondary layer 201 may be embedded within the casing. More specifically, the secondary layer 201 may be embedded within the base layer 200 of the casing to have a thickness Ts less than the thickness Tb. [0033] In the third embodiment, the base layer 200 may include a void 400 for the secondary layer 201 to be embedded within. The void 400 may extend an axial length to stop a distance D before the first joint connection 102a, as shown in FIG. 4C. For illustration purposes only, FIG. 4E illustrates the base layer 200 without the secondary layer 201 to better show the void 400. The void 400 may be an empty space that is formed between a first interior surface 401 and a second interior surface 402 in the base layer 200. The first interior surface 401 may be spaced from the second interior surface 402 a radial distance RD. The first interior surface 401 may be approximate to the inner surface 107 while the second interior surface 402 may be approximate to the outer surface 106. The first interior surface 401 and the second interior surface 402 may be coated or textured to improve attachment with the secondary layer 201 being inserted into the void 400. The radial distance RD may be equal to or greater than the thickness Ts of the secondary layer 201. [0034] As shown by FIG. 4A, the secondary layer 201 may be inserted in the void 400 and attached to both the first interior surface 401 and the second interior surface 402 (see FIG. 4A). With the secondary layer 201 attached to both the first interior surface 401 and the second interior surface 402, the secondary layer 201 may fill the void 400 to allow absorption of pressure and temperature in the secondary layer 201 from the base layer 200. Additionally, the secondary layer 200 may prevent the base layer 200 from being permanently deformed. [0035] In FIG. 4F, a first variation of FIG. 4A is illustrated. The thickness Ts of the secondary layer 201 is less than the radial distance RD such that the secondary layer 201 may be attached to the first interior surface 401. With the secondary layer 201 attached to the first interior surface 401, a gap may be formed between the secondary layer 201 and the second interior surface 402 to allow for expansion and contraction of either the secondary layer 201 or the base layer 200. [0036] In FIG. 4G, a second variation of FIG. 4A is illustrated. The thickness Ts of the secondary layer 201 is less than the radial distance RD such that the secondary layer 201 may be attached to the second interior surface 402. With the secondary layer 201 attached to the second interior surface 402, a gap may be formed between the secondary layer 201 and the first interior surface 401 to allow for expansion and contraction of either the secondary layer 201 or the base layer 200. [0037] Referring now to FIGs. 5A-5D, a fourth embodiment of the casing 100 according to embodiments herein is illustrated, where like numerals represent like parts. The fourth embodiment of FIGs. 5A-5D is similar to that of the third embodiment of FIGs. 4A-4D. However, in the fourth embodiment, the base layer 200 may include a plurality of secondary layers 201 embedded within a corresponding void 400. For example, each secondary layer 201 may have a corresponding void 400 separate from, each other. In some embodiments, two more secondary layers 201 may be one void 400. Each of the plurality of secondary layers 201 may have the same thickness Ts and be uniformly radially spaced from each other. [0038] For illustration purposes only, FIG. 5E illustrates the base layer 200 without the secondary layer 201 to better show the corresponding voids 400. Each of the voids 400 may have a radial thickness Tr equal to or greater than the thickness Ts of each secondary layer 201. FIG. 5F illustrates a first variation of FIG. 5A; however, the base layer 100 may only have one void 400 (similar to that of FIG. 4A). In the one void 400, the plurality of secondary layers 201 may be embedded and attached to the first interior surface 401 and the second interior surface 402. [0039] Referring now to FIG. 6, a fifth embodiment of the casing 100 according to embodiments herein is illustrated, where like numerals represent like parts. FIG. 6 shows an embodiment in which any combination of the embodiments FIGs. 2A-5F may be used for two or more secondary layer 201a-201d attached to or embedded within the base layer 200. For example, a first secondary layer 201a may be disposed externally, between the base layer 200 of the casing and the cement layer and a second secondary layer 201b may be disposed internally, behind the base layer 200 of the casing. Additionally, a first void 400a may be provided within the base layer 200 with a third secondary layer 201c embedded in the void 400. Further, a second plurality of voids 400d may be provided within the base layer 200. Each void 400d may have a fourth second layer 201d embedded therein. [0040] Now referring to FIG. 7, in one or more embodiments, FIG. 7 is a flowchart showing a method of manufacturing and using the casing 100 of FIGs. 2A-6. While the various blocks in FIG. 7 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively. [0041] In Block 700, a base layer of the casing may be formed. The base layer may be formed by a wall of a tubular body extending axially a length from a first end to a second end. The wall may radially extend from an inner surface of the tubular body to an outer surface of the tubular body. Additionally, the tubular body may have a bore and be a seamless pipe. Further, the base layer of the casing may be formed by various manufacturing process such as mandrel mill process, plug mill process, forged pipe process, extrusion pipe process, or other types of pipe manufacturing. It is further envisioned, the base layer may be made from a material selected from iron, steel, stainless steel, metal alloy, plastic (e.g., polyvinyl chloride (PVC)), or any material suitable for downhole conditions in a well. [0042] In some embodiments, the base layer may be formed with a void. The void may be an empty space within the base layer extending a radial distance between the inner surface of the tubular body and the outer surface of the tubular body. By including the void, the base layer may have a first interior surface and a second interior surface to delimit the empty space. In some embodiments, a plurality of voids may be provided within the base layer. [0043] In Block 701, one or more secondary layers may be added to the base layer, thereby making up the wall of the casing. For example, the one or more secondary layers may be added to the outer surface and/or the inner surface of the base layer, or embedded within the void of the base layer, or a combination thereof. In some embodiments, the one or more secondary layers may be attached to the first interior surface and/or the second interior surface such that the one or more secondary layers is embedded within the base layer. It is further envisioned that simulations may be run to optimize a thickness ration between the base layer and the one or more secondary layers. [0044] The one or more secondary layers may be added through any various manufacturing process, such as coating films, painting, blasting, chemically reacting/bonding, or other additive manufacturing processes, or any combination thereof. The one or more secondary layers may be made from a material selected from rubber or smart foam or a combination thereof. The rubber may be a fluoropolymer (e.g., AFLAS® or Viton ®), a synthetic polymer (e.g., Butyl or Hypalon rubber), nitrile rubber, any type of rubber suitable for downhole conditions in a well, or a combination thereof. The smart foam may be a foam cement, Polyethylene (PE), Polyurethane (PU), or a combination thereof. With the one or more secondary layers added, an inner diameter and an outer diameter of the casing may be formed. [0045] With the base layer and the one or more secondary layers formed, connection ends may be formed on the casing, as shown by Block 702. The connection ends may be provided at the first end and the second end of the casing. In addition, the connection ends may be provided on a portion of the base layer that does not have the one or more secondary layers. For example, the one or more secondary layers may stop a distance before the connection ends such that a gap may be formed between the one or more secondary layers and the connection ends. In one or more embodiments, the connection ends may be formed by a threading process such that threads are provided on the connection ends. The threads may be a buttress or round thread any type of thread. In some embodiments, the threads may be male threads such that both connection ends are male connections. Additionally, a collar or coupling may be threaded on one of the male connections. With connection ends formed, the casing may be transported to a well site. [0046] At the wellsite, the casing may be lowered into the wellbore, as shown by Block 703. For example, the end of the casing without the collar or coupling may be at lower-most end to enter the wellbore first. Next, a second casing may be lowered onto the end of the casing with the collar or coupling. The second casing may be threaded onto the collar or coupling to form a seal with the casing. With the casing and the second casing coupled together, a casing string may be formed within the wellbore, as shown by Block 704. Furthermore, an upper most casing in the casing string may be hung from a wellhead via a linear hangar. With the casing string formed within the wellbore, cement operations may be conducted to cement the casing string to the wellbore. [0047] In addition to the benefits described above, the casing described herein may provide further advantages such as a reduction in pressure magnitude transition to cement, thus, the casing may be a pressure dampening casing. Further, the casing described herein may also provide a reduction in temperature magnitude transition to cement, thus, the casing may be an insulator casing. By providing the casing with one or more secondary layers, a well-life of cement in a wellbore may be increased as the one or more secondary layers shields the cement from an expansion and contraction of the casing. With the one or more secondary layers attached to and/or embedded within a wall of the casing, the one or more secondary layers may act as a protective layer, a mechanical insulator, and a fluid barrier for the casing. Further, the one or more secondary layers may have an elasticity to allow deformation and absorption based on external or and/or internal forces on the casing. One skilled in the art will appreciate how the one or more secondary layers may be integral to the casing in all embodiments described herein. [0048] While the method and apparatus have been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope as disclosed herein. Accordingly, the scope should be limited only by the attached claims.