A Guide to the Criteria to be considered when selecting Casing and Tubing for Oil and Gas Wells - Term Paper Example

A Guide to the Criteria Name A Report Submitted by You Institution Course Date A Guide to the Criteria to be considered when selecting Casing and Tubing for Oil and Gas Wells Introduction The following essay is a guide showing the criteria to be considered when selecting casing and tubing for oil and gas wells. The aim of the guide is to assist readers in understanding the factors to consider in selecting casing and tubing materials used in oil and gas wells. Through the analysis and discussions on the topic of material and corrosion, the essay would provide the answers to the thesis question which is, “how important is the criteria of casing and tubing material selection in the production process?” After extensive research and learning, I came into a conclusion that several factors must be considered by engineers, extraction companies and geologist in their oil extraction planning and mining process. The factors identified include: i. The economic factor, which is the cost of the materials and equipments to be used ii. The well to be drilled and the site of the drilling process iii. The potential hazards and problems that might occur in the extraction process iv. The five levels of casing to be undertaken. v. Corrosion control options used in tubing. The five primary factors together with the functions of the casing and tubing equipment provide criteria that help one make a selection of the suitable materials and equipments. Oil and gas play a vital role in the enhancement and advancement of humankind. Since their discovery during the pre-colonial period, oil and gas products seem to be extremely useful in everyday life of human beings. Hardly a day goes by without one using the product. For example, oil products such as petroleum and diesel are used in running machines, in industries, and also in vehicles. Gas is used in cooking and warming up houses during cold seasons among other things. The use of oil as fuel has resulted into a high demand of the product worldwide. In order to meet the demands for this product, oil production has increased over the years. Oil production is carried out through the mining process since crude oil is located in reservoirs under the ground. The crude oil and natural gas production involves the operation of bringing hydrocarbons to the surface and preparing them for processing activities. The production process begins after the drilling of wells in oil reservoirs area. After completion of the first step, operations such as bringing the oil, water and gas mixture to the surface, purifying, measuring and testing are then carried out. The first factor to be considered before beginning the drilling process is the cost to be incurred. Mobley (2001, p.46) states that the economy has a key part in the engineering of all well drilling and installation process. Considering casing and tubing materials, however, lower costs of the material and equipments do not mean least durability or efficiency. Likewise, the most expensive products do not always yield the best results. There should be optimum balance between price and design requires knowledge of the conditions pertaining the well and comparison of the available products. For example, the required well life is one of the analyses to guide in choosing the products. Therefore, the purchasing cost of casing and tubing equipments, the maintenance and handling cost together with the transportation cost should be calculated fully. Additionally, when purchasing the equipments, the vendor must consider the manufacturer of the equipments. It is advisable to purchase the goods from suppliers or manufactures that are reliable at all time trustworthy and have a solid reputation in the petroleum industry. This would prevent the purchase of substandard products that may lead to loss experienced by the extraction company. After the purchase of equipments, the next stage is the drilling process. During the process of natural gas or oil well drilling, the well must be finished in-turn, to allow the flow of petroleum or natural gas. Well completion gets done after verifications of the existence of commercially feasible quantities of petroleum and natural gas to be extracted. This process involves strengthening the well hole through casing, evaluating the temperature and pressure of the formation and installing the proper equipments for efficient flow. There are two main types of conventional gas well. They include natural gas condensate and natural gas wells. In addition to the conventional, natural gas wells, there are oil wells that have associated natural gases. In these wells, natural gas is used to add pressure to the well and boost the extraction process. Sometimes, oil can be extracted together with associated natural gas but only if the gas exists in large enough quantities. Petroleum engineers usually have to put into consideration many elements or units before the extraction process begins. One of the elements to be considered is the well type to be used in the production process. The choice of the well type depends on the extracted resources and would require different casing and tubing equipments. For example, if engineers identify a location with more natural gas and less oil, they would drill natural gas-specific wells. On the other hand, condensate wells are used for extracting natural gas and liquid condensate. The condensate is usually a liquid hydrocarbon mixture that gets separated from natural gas during the processing stage. Completing a well consists of several steps. These steps include well casing installation, well completion, wellhead installation and installation of lifting equipment or formation treatment. Well casing installation is a fundamental part of the drilling together with the completion process. This installation consists of a series of installed metal tubes in drilled holes. The main purposes of casing are strengthening the sides of the well hole and ensuring that no gas or oil seeps out of the well hole. Additionally, casing prevents the seeping of other fluids or gases into the formation through the well. Therefore, a good deal of planning is necessary in ensuring proper well casing installation (Mobley, 2001). Potential hazards and problems, which might occur during the extraction process, provide another criterion to be considered while selecting the casing and tubing of oil wells. By identifying the probable hazards which might occur, Azar and Samuel (2007, p.91) argue that one is in a better position of establishing which equipments would be the most efficient in the process. First and foremost, I will discuss the mechanical forces that bring disruptions and destructions. Casing and tubing are designed to withstand three main mechanical forces that tend to disrupt or destroy tubular sections. The three forces include tension that results from longitudinal loading, collapse from unbalanced external pressure and bursting, which originates from unbalanced internal pressure. In addition, other factors that pose as challenges involve leakage through the threaded connections, crushing which occurs through slips and tongs, wear from drill pipes, tubing, wire lines or rods, erosion as a result of high velocity fluids, buckling which can be from mechanical forces or internal pressure, and torsion. Miscellaneous problems, which also pose as a challenge, may arise from field welding of casing, mishandling of equipments and shot perforating casing. Furthermore, there is the electro chemical or the chemical factor identified as corrosion. All these factors should be put into consideration by engineering when selecting the most appropriate materials to be used in the extraction process. Since both well casing and tubing experience, pretty much the same challenges, the two elements would be considered concurrently. When selecting the appropriate casing, it is advisable for engineers to consider the factors that lead to inefficiency in the operation of the mining process. In the tension case, it is better considering the various factors that lead to tension loading in a string of casing. One factor that brings tension is the weight of the casing itself that hangs onto the coupling. To curb this problem, engineers must properly calculate the tension loads without neglecting buoyancy and assuming that the string is hanging in the air. The other factor causing tension is the shock load that occurs while running the casing. Sometimes an unexpected sudden slipping may occur through a tight spot and might build up a momentarily and unwittingly high-tension load. Axial tension load from casing strings combined with external pressure may lead to the collapse strength of casing. It is, therefore, extremely beneficial to consider the forces of tension when selecting and designing casing strings. Through this criterion, engineers establish a casing design that meets the calculated properties of casing strings. For example, for long casing strings to withstand the string load, they require higher strength materials on the upper part of the string. On the other hand, lower string portions may be assembled with greater wall thickness casing so as to withstand the extreme pressures from depth. Through calculating the body yield strength of the casing by establishing the wall thickness and diameter from nominal wall, the burst pressure, the joint formula for tensional forces and the collapse pressure with zero axial load, engineers can develop a casing string, which can withstand, the tension forces for a long period (Mobley 2001, p. 89). The other mechanical force to be considered as elaborated by Smith (1999, p.67) should be the collapsing force that results from external unbalanced pressure. During the drilling process, external pressure from the ground may result the caving in of the well top. In order to prevent the caving in, materials used in well casing should be of ample strength. Usually, an assembled length of a configured steel pipe is used in suiting a particularly different wellbore. A well casing identified as conductor casing curbs the problem of caving. Conductor casing is the first installation done prior to the drilling ring arrival. The hole for conductor casing is usually drilled with a tiny auger drill. This casing measures no more than 20 to 50 feet long. Its installation prevents the well's top from caving in and helps in the circulation of the drilled fluid up from the well’s bottom. The size of the casing used depends on whether the well construction is taking place onshore or offshore. If it is onshore, the diameter of the casing should be 16 to 20 inches. On the other hand, if it is offshore the casing usually measures 30 to 42 inches. In addition, the conductor casing gets cemented into place before drilling begins. Therefore, one needs to consider the site of the well whether onshore or offshore so as to pursue with conductor casing. Bursting force is the other mechanical force that may arise due to internal unbalanced pressures. The pipes used in both casing and tubing should have mechanical properties that enable them to be resistant to bursting pressure, collapse pressure among others. Usually, many drilling engineers go for carbon steel pipes when choosing a casing material. Carbon steel material exhibits immense strength and through tinkering different amounts of carbon in the alloy, variables such as hardness, density and malleability can be adjusted. The nature of casing ad-tubing pipes used in extraction is vital in the efficiency of the extraction. Through proper calculations of expected, the pressure exerted on the inside, and outside the pipe walls, oil spillage disasters could be prevented. The other criterion used when considering the selection of casing and tubing materials and equipments is the various levels involved in the processes. Let us start by analyzing the different levels in well casing. Up to date, there are only five varieties of well casing that are used. The first type is known to be conductor casing. As discussed earlier, this is the first casing to be installed. The size of the conductor casing ranges from 20 to 50 feet long, but the diameter of the casing differs according to the site of the drilling process. This casing usually supports the well during the drilling operation by preventing loose soil from collapsing (Smith 1999, p. 156). After the completion of the conductor casing, surface casing is then installed. The installation of the surface casing can be anywhere from a few hundred to two thousand feet long. Surface casing is smaller in diameter compared to conductor casing. During installation, the surface casing must fit inside the pinnacle of the conductor casing. The main function of this casing is to prevent the contamination of fresh water deposits near the well surface by leaking saltwater and hydrocarbons. It is also a conduit for mud returning to the ground. Just like conductor casing, surface casing is also a cemented place. Regulations often dictate the cement thickness to be used as a means of ensuring that the possibility of freshwater contamination is little if not none (Smith 1999, p. 157). Intermediate casing is the other casing type and is usually the longest section that is found in a well. The primary purpose of this casing is to minimize the hazards brought along with subsurface formations. These hazards include underground shale, abnormal underground pressure zones, and underground saltwater deposits among others. Intermediate casing, acts as insurance against possible contamination of the well by such formations. Instead of intermediate casing, linear strings may be used now and then. These strings commonly run from the bottom of a different casing to another type of casing at the open well area. Linear strings tend to be attached to other casings through hangers, instead of cement in the area. Although effective, this casing method is less permanent than the immediate casing. Lastly, there is the production casing. It is also known as a long string or oil string, and its installation is the last and the deepest. It provides a conduit that runs from the surface of the well to the petroleum produced formation. Depending on a number of considerations, the size of this casing differs. These considerations include the number of completions required, possibility of deepening the well later in time and the lifting equipment to be used. For example, if later in time, the well is expected to be deepened, the production casing should be wide enough for the later passage of a drill bit (Azar and Samuel 2007, p. 159). From the five casing types identified above, it is clear that depending on which type to be installed different equipments would be used. In addition, the size of the casing would also vary and again the material used would vary. These criteria provide a wide variety of selection considerations. The casing type used depends on various factors such as the well’s subsurface characteristics. The characteristics involve the diameter of the well and the pressures as well as temperatures experienced throughout the well. The well hole diameter depends on the width of the drill bit to be used. In most wells, the deeper it is drilled, smaller the diameter of the well hole becomes. This leads into a conical shape that must be accounted when installing casing. Production tubing refers to the conduit through which fluids get transported from the reservoirs to the surface equipments. The main purpose of the tubing is to provide protection to the wellbore casing from wear and tear, corrosion and product deposits. Among other components, which constitute the production string, the tubing provides a continuous bore that runs from the production zone to the well surface. For this reasons, Azar and Samuel (2007, p.48) argue that tubing are often designed to enable efficient, quick and safe installation whether in the removal, installation or the reinstallation process. The tubing must withstand corrosion from any aqueous phase that results from hydrocarbons, and contains dissolved acid gases such as CO2 and H2S and salts such as chloride ions. Corrosion control is essential especially for maintaining production and avoiding loss of well control risk. Materials to be used for down hole must meet the criteria for corrosion resistance and mechanical requirements (Azar and Samuel 2007, p.49). Through the incorporation analysis of the environment, final material selection and corrosion rate calculations, a logical series of steps for material selection could be established. Majority of production tubing according to general specification tend to be made from low alloy steel. For corrosion to take place in these tubes, water must be in contact with the metal surface. Oil wells analysis of the flow regime show that there is no direct water wetting of steel surface and, therefore, no corrosion. In gas wells, condensation of water occurs when there is a fall in the gas temperature that is below the dew point temperature. This dew point temperature may be at any specified height in the tubing depending with the temperature profile. Liquid full tubing, which contains oil and water mixtures, usually has free water that is within an oil emulsion. The free water would not give rise to corrosion as long as there is sufficient flow rate that entrains the water. Therefore, through the multiphase conditions, water-wetting behaviors that might lead to corrosion depend strongly on the flow regime. Production rates, angle of inclination and gas/liquid ratio influence the flow regime in the tubing. This means for one to choose an appropriate tubing material he/she should consider the corrosion risk that arises through water wetting (Azar and Samuel 2007, p.96). Carbon dioxide gas is another factor that brings about corrosion risks. In considering the viability of using carbon steel, the potential corrosion rate by carbon dioxide gas has to be calculated. Several methods of predicting carbon dioxide corrosion rate of low alloy and carbon steels have been identified. Engineers nowadays design production tubing that precludes the use of corrosion allowance to be given up over the life of the project. This is done since it would increase the tubing string weight. Thus, where the calculated corrosion rate is anticipated to be too high to allow carbon steel use, consideration must be given to inhibitor injection to reduce the selection or the rate of a tubing material. Corrosion of metallic materials can also result from the presence of H2S (Smith 1999, p.118). Such corrosion leads to hydrogen production and subsequently lead to catastrophic failure due to hydrogen induced embrittlement and cracking. Pitting corrosion may also occur in low alloy steels under conditions of flow rate, temperature and CO2 to H2S ratio. Carbon and low alloy steels resistance to sulphide stress corrosion cracking (SSC) depends on H2S pH2S partial pressure and also the pH of the environment. For corrosion resistant alloys that might fail in H2S service through a combination of mechanisms, no simple cutoff in H2S partial pressure can be used to show the limits of cracking risk. This means each alloy type has to be considered separately. Controlling corrosion of tubing, brought about by the three factors discussed above, provides a criteria for selecting tubing and casing materials, which best fit the corrosion control options. There are five ways of preventing corrosion from happening in tubing. They include corrosion inhibition of carbon steel; fibre reinforced plastic, solid corrosion resistance alloys, internal plastic coating and corrosion resistant alloy cladding or lining. Corrosion inhibition involves the injection of inhibitors into a well stream, and it is most effective in low temperature, low pressure and low water level oil wells (Smith 1999, p.206). This form of control is not recommended for wells that tend to be hostile. Internal plastic coating, on the other hand, is particularly used in conditions that are more aggressive although this control method has a short lifespan. This form of control is not effective in deep wells since 15% of the coated tubing would be blistered after only an approximated time of 30 days. The development of reinforced fibre plastic has proved to be more effective than the plastic coating technique. Fibreglass tends to be more favorable as a tubing material due to its high corrosion resistance property. This tubing type works efficiently where internal pressures are below 1000 lb in-2. Low alloy steel tubing lined with glass reinforced epoxy does not have pressure limitation although they are limited by temperature. This property makes it unsuitable for their use in HP/HT wells. Use of corrosion resistance alloys is the other preventive measure. The alloys used in making such tubing include AISI 410 stainless steel (13Cr), alloy 28, alloy 825, duplex stainless steels, C276, and alloy G3. The shift from one alloy to the other is made according to the performance guidelines of these materials in environments with increasing severity (Smith 1999, p.207). Correctly, selected CRAs should exhibit negligible general corrosion. Additionally, it should show no localized corrosion or cracking tendency in the expected service conditions. The main aim of the corrosion engineer is to choose the most cost effective alloy based on an analysis of the corrosion risks given the environmental conditions. CRAs tend to be the most appropriate control option for hostile wells. Lastly, corrosion resistance alloy cladding is a method of control, which involves full metallurgical bonding between backing steel and CRAs. Clad or lined pipe products are best suited for downhole production tubing application due to the backing steel's mechanical properties (Smith 1999, p.208). In conclusion, it is evident that the criteria of casing and tubing material selection are extremely relevant for efficient and successful oil extraction. Factors such as cost, well design, casing levels, corrosion control methods and probable problem occurrence in the extraction process all provide the basis in which to select the materials and equipments. References List Azar, J. J. and Samuel, G. R., 2007. Drilling engineering. Tulsa, Okla.: PennWell Corp.. Mobley, R. K., 2001. Plant engineer's handbook. Boston: Butterworth-Heinemann. Smith, I., 1999. Control of corrosion in oil and gas production tubing. British Corrosion Journal, 34(4), p.253. Read More