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In general, these values should not be exceeded in operation. To be on the safe side, a minimum design factor of 1.25 based on the internal-yield pressure rating is suggested; however, some operators use different values. | In general, these values should not be exceeded in operation. To be on the safe side, a minimum design factor of 1.25 based on the internal-yield pressure rating is suggested; however, some operators use different values. | ||
In medium to high pressure wells, especially in sour service when L80, C90, and T95 API grades are used, the general stress level in the tubing should not exceed the minimum yield strength for L80 or the sulfide stress corrosion cracking (SSC) threshold stress (generally 80% of the minimum yield strength) for C90 and T95 grades. | In medium to high pressure wells, especially in sour service when L80, C90, and T95 API grades are used, the general stress level in the tubing should not exceed the minimum [[Glossary:Yield strength|yield strength]] for L80 or the sulfide stress corrosion cracking (SSC) threshold stress (generally 80% of the minimum yield strength) for C90 and T95 grades. | ||
The joint or body yield strength for the tension design factor varies widely in practice. A simple approach is to assume a relatively high design factor of 1.6 based on the tubing weight in air and ignore other loading conditions. The calculations for loads in tension are usually for static conditions and ignore dynamic loads that may occur in running and pulling the tubing. They also may ignore collapse loads that reduce tension strengths. The pulling or drag loads are not commonly known. These may be relatively high in directional wells. Typically, the highest loads in tension occur in unsetting the packer during pulling operations. In some cases, shear pins in packers result in substantial loads in unsetting that should be accounted for in design. | The joint or body [[Glossary:Yield strength|yield strength]] for the tension design factor varies widely in practice. A simple approach is to assume a relatively high design factor of 1.6 based on the tubing weight in air and ignore other loading conditions. The calculations for loads in tension are usually for static conditions and ignore dynamic loads that may occur in running and pulling the tubing. They also may ignore collapse loads that reduce tension strengths. The pulling or drag loads are not commonly known. These may be relatively high in directional wells. Typically, the highest loads in tension occur in unsetting the packer during pulling operations. In some cases, shear pins in packers result in substantial loads in unsetting that should be accounted for in design. | ||
The condition of the tubing after several years of service in the well is another unknown that needs to be compensated for either in design or by use of a higher tension design factor. When considering all these factors and making adjustments for drag, shear pins, and collapse pressures, a minimum design factor of 1.25 in tension for pulling is suggested. However, field experience has shown, in general, that tubing in new condition (meets API minimum requirements) can be loaded in tension to its minimum yield joint strength during pulling operations without a tension failure. Tension failures during pulling operations should be avoided because the results usually are costly. It is better to cut or back off the tubing rather than have a tension failure. '''Table 2''' shows approximate setting depths for various API grades. | The condition of the tubing after several years of service in the well is another unknown that needs to be compensated for either in design or by use of a higher tension design factor. When considering all these factors and making adjustments for drag, shear pins, and collapse pressures, a minimum design factor of 1.25 in tension for pulling is suggested. However, field experience has shown, in general, that tubing in new condition (meets API minimum requirements) can be loaded in tension to its minimum yield joint strength during pulling operations without a tension failure. Tension failures during pulling operations should be avoided because the results usually are costly. It is better to cut or back off the tubing rather than have a tension failure. '''Table 2''' shows approximate setting depths for various API grades. | ||
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File:Vol4 Page 117 Image 0001.png|'''Fig. 1—Ellipse of biaxal yield stress.''' | File:Vol4 Page 117 Image 0001.png|'''Fig. 1—Ellipse of biaxal yield stress.''' | ||
</gallery> | </gallery> | ||
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==Design considerations== | ==Design considerations== | ||
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A reasonable approach must be taken to prevent overdesign. The design need not prevent worst-case scenario failures but rather for all cases that have a reasonable probability of occurring. For instance, assume that there is a shallow tubing leak in which the shut-in tubing pressure is applied in the casing annulus on top of a column of heavy annulus fluid and, subsequently, that the tubing pressure at bottom is reduced quickly to a low value. This event would require tubing with a very high collapse pressure rating. If such a condition is considered to have a reasonable probability of occurring, the tubing string should be designed accordingly or adequate steps should be taken to prevent such a series of events. | A reasonable approach must be taken to prevent overdesign. The design need not prevent worst-case scenario failures but rather for all cases that have a reasonable probability of occurring. For instance, assume that there is a shallow tubing leak in which the shut-in tubing pressure is applied in the casing annulus on top of a column of heavy annulus fluid and, subsequently, that the tubing pressure at bottom is reduced quickly to a low value. This event would require tubing with a very high collapse pressure rating. If such a condition is considered to have a reasonable probability of occurring, the tubing string should be designed accordingly or adequate steps should be taken to prevent such a series of events. | ||
The highest tensile loads normally occur at or near the top (surface) of the well. Collapse loads reduce the permitted tension loads, as shown by the biaxial graph in '''Fig. 1''', and should be considered when applicable. Fortunately, the casing annulus pressure is normally low at the surface; thus, collapse pressure effects at the surface often can be ignored, but not in all cases. Buoyancy, which reduces the tensile loads, is sometimes ignored on shallow wells, but it should be considered on deeper wells. A condition that frequently determines the required tension yield strength of the tubing occurs when unsetting a partially stuck packer or using a shear-pin-release type packer in wells in which buoyancy is not applicable. | The highest tensile loads normally occur at or near the top (surface) of the well. Collapse loads reduce the permitted tension loads, as shown by the biaxial graph in '''Fig. 1''', and should be considered when applicable. Fortunately, the casing annulus pressure is normally low at the surface; thus, collapse pressure effects at the surface often can be ignored, but not in all cases. Buoyancy, which reduces the tensile loads, is sometimes ignored on shallow wells, but it should be considered on deeper wells. A condition that frequently determines the required tension [[Glossary:Yield strength|yield strength]] of the tubing occurs when unsetting a partially stuck packer or using a shear-pin-release type packer in wells in which buoyancy is not applicable. | ||
High-burst tubing loads typically occur near the surface with little or no annulus pressure under shut-in tubing conditions or during well stimulation treatments down the tubing. High-burst conditions also may occur deep in the hole with high surface pressures imposed on top of relatively high-density tubing fluid and when the annulus is empty or contains a light-density annulus fluid. Both of these conditions must be evaluated during the design of a tubing string for a specific well. | High-burst tubing loads typically occur near the surface with little or no annulus pressure under shut-in tubing conditions or during well stimulation treatments down the tubing. High-burst conditions also may occur deep in the hole with high surface pressures imposed on top of relatively high-density tubing fluid and when the annulus is empty or contains a light-density annulus fluid. Both of these conditions must be evaluated during the design of a tubing string for a specific well. | ||
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In directional wells, the effect of the wellbore curvature and vertical deviation angle on the axial stress on the tubing body and couplings/joints must be considered in the tubing design. Current design practice considers the detrimental effects of tubing bending, but the favorable effect (friction while running) is neglected. Wall friction, which is unfavorable for upward pipe movement, generally is compensated for by addition of an acceptable overpull to the free-hanging axial tension. Overpull values are best obtained from field experience but can be calculated with available commercial software computer programs. | In directional wells, the effect of the wellbore curvature and vertical deviation angle on the axial stress on the tubing body and couplings/joints must be considered in the tubing design. Current design practice considers the detrimental effects of tubing bending, but the favorable effect (friction while running) is neglected. Wall friction, which is unfavorable for upward pipe movement, generally is compensated for by addition of an acceptable overpull to the free-hanging axial tension. Overpull values are best obtained from field experience but can be calculated with available commercial software computer programs. | ||
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===Single and combination/tapered tubing design=== | ===Single and combination/tapered tubing design=== | ||
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The use of two or three different diameter sizes is sometimes advantageous. The larger tubing size may have high-joint-yield strength and permit a higher flow rate. The largest diameter is run on the top and a smaller tubing size on bottom. In such cases, the surface wellhead valves often are sized to permit wireline work in the larger tubing to prevent operational problems. A smaller tubing outside diameter (OD) size on bottom may be necessary because of casing diameter restrictions. | The use of two or three different diameter sizes is sometimes advantageous. The larger tubing size may have high-joint-yield strength and permit a higher flow rate. The largest diameter is run on the top and a smaller tubing size on bottom. In such cases, the surface wellhead valves often are sized to permit wireline work in the larger tubing to prevent operational problems. A smaller tubing outside diameter (OD) size on bottom may be necessary because of casing diameter restrictions. | ||
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==Outside diameter limitations== | ==Outside diameter limitations== | ||
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If two tubing strings are to be run clamped together, then the sum of the smaller tubing body OD and the OD of the coupling of the second or larger string must be less than the casing drift diameter. In these cases, a full-size drawing of the cross sections of the tubulars used may be helpful. The actual clearance may depend on the clamp design. The use of parallel strings of 3½-in. tubing inside 9 <sup>5</sup>/<sub>8</sub>-in. casing is another common practice, and tubing OD limitations must be considered in such installations. | If two tubing strings are to be run clamped together, then the sum of the smaller tubing body OD and the OD of the coupling of the second or larger string must be less than the casing drift diameter. In these cases, a full-size drawing of the cross sections of the tubulars used may be helpful. The actual clearance may depend on the clamp design. The use of parallel strings of 3½-in. tubing inside 9 <sup>5</sup>/<sub>8</sub>-in. casing is another common practice, and tubing OD limitations must be considered in such installations. | ||
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==Minimum performance properties== | ==Minimum performance properties== | ||
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Select and order tubing material. Order per API ''Spec. 5CT'' : 9,000 ft plus 300 ft of 2 <sup>3</sup>/<sub>8</sub>;-4.70-J55 EUE-8R, range 2, seamless or electric weld, and one set of pups with standard EUE couplings. In addition, order one container of API-modified thread compound and specify delivery date and shipping instructions. | Select and order tubing material. Order per API ''Spec. 5CT'' : 9,000 ft plus 300 ft of 2 <sup>3</sup>/<sub>8</sub>;-4.70-J55 EUE-8R, range 2, seamless or electric weld, and one set of pups with standard EUE couplings. In addition, order one container of API-modified thread compound and specify delivery date and shipping instructions. | ||
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==Example 2== | ==Example 2== | ||
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Select and order the tubing material. Request that the tubing meet API ''Spec. 5CT''. Order 14,500 ft of 2 7/8-7.90-L80 Type 13 Cr, Range 2, seamless tubing with a proprietary connection and one set of pup joints with same type connections as tubing. In addition, order all accessories with the same connection and an appropriate thread lubricant. State the required delivery and follow API ''RP 5C1'' on tubing handling. | Select and order the tubing material. Request that the tubing meet API ''Spec. 5CT''. Order 14,500 ft of 2 7/8-7.90-L80 Type 13 Cr, Range 2, seamless tubing with a proprietary connection and one set of pup joints with same type connections as tubing. In addition, order all accessories with the same connection and an appropriate thread lubricant. State the required delivery and follow API ''RP 5C1'' on tubing handling. | ||
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==Example 3== | ==Example 3== | ||
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*7,000 ft of 3 1/2-9.30-J55 with EUE modified API ''SR 13'' standard couplings and S or EW, range 2 | *7,000 ft of 3 1/2-9.30-J55 with EUE modified API ''SR 13'' standard couplings and S or EW, range 2 | ||
*One container of API modified thread compound as per API ''RP 5A3''. Specify delivery date and shipping instructions. Some operators might prefer to use L80 rather than N80 3 1/2 tubing and to heat-treat the J55 after upsetting. Both these options increase the cost of the tubing string but may increase the operating life. | *One container of API modified thread compound as per API ''RP 5A3''. Specify delivery date and shipping instructions. Some operators might prefer to use L80 rather than N80 3 1/2 tubing and to heat-treat the J55 after upsetting. Both these options increase the cost of the tubing string but may increase the operating life. | ||
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==Example 4== | ==Example 4== | ||
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If pressures are greater than 7,000 psi and the depth is greater than 13,000 ft, a pipe-body load analysis should be performed. In sour service for L80, C90, and T95, triaxial stress intensity should be checked and a design factor greater than 1.25 maintained. See ''ISO 13679'' Sec. B.5.2. <ref name="r4" /> | If pressures are greater than 7,000 psi and the depth is greater than 13,000 ft, a pipe-body load analysis should be performed. In sour service for L80, C90, and T95, triaxial stress intensity should be checked and a design factor greater than 1.25 maintained. See ''ISO 13679'' Sec. B.5.2. <ref name="r4" /> | ||
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==Stretch in tubing== | ==Stretch in tubing== | ||
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[[File:Vol4 page 0133 eq 002.png]]....................(24) | [[File:Vol4 page 0133 eq 002.png]]....................(24) | ||
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==Example 5== | ==Example 5== | ||
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''Solution.'' With a block-hook load of 60,000 lbf, mark the tubing at the top of rotary table. An additional 10,000-lbf load was picked up and the measured increase in length (stretch) is 20.0 in. Calculate the tubing cross-section area with '''Eq. 5'''. ''A''<sub>''m''</sub> = π × (2.875<sup>2</sup> – 2.441<sup>2</sup>)/4 = 1.812 in.<sup>2</sup> Use '''Eq. 3.25''' to calculate ''L''<sub>''p''</sub> = Δ''L''<sub>''t''</sub> × ''E'' × ''A''<sub>''m''</sub> / (12 × ''F'') = 20.0 in. × 30,000,000 psi × 1.812 in.<sup>2</sup> /(12 in./ft × 10,000 lbf) = 9,060 ft. | ''Solution.'' With a block-hook load of 60,000 lbf, mark the tubing at the top of rotary table. An additional 10,000-lbf load was picked up and the measured increase in length (stretch) is 20.0 in. Calculate the tubing cross-section area with '''Eq. 5'''. ''A''<sub>''m''</sub> = π × (2.875<sup>2</sup> – 2.441<sup>2</sup>)/4 = 1.812 in.<sup>2</sup> Use '''Eq. 3.25''' to calculate ''L''<sub>''p''</sub> = Δ''L''<sub>''t''</sub> × ''E'' × ''A''<sub>''m''</sub> / (12 × ''F'') = 20.0 in. × 30,000,000 psi × 1.812 in.<sup>2</sup> /(12 in./ft × 10,000 lbf) = 9,060 ft. | ||
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== Buckling == | == Buckling == | ||
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Tubing selection for corrosive environments is a critical design responsibility. Both the inside and outside of the tubing can be damaged by corrosion. Weight-loss corrosion may be a serious problem with conventional tubing strings in wells producing salt water, especially when the water becomes the wetting phase. Acidity caused by the presence of acid gases (CO<sub>2</sub> and H<sub>2</sub>S) normally increases the corrosion rate. When corrosion is minor, the common practice is to use standard API grades and to start batch inhibition when corrosion becomes a problem. | Tubing selection for corrosive environments is a critical design responsibility. Both the inside and outside of the tubing can be damaged by corrosion. Weight-loss corrosion may be a serious problem with conventional tubing strings in wells producing salt water, especially when the water becomes the wetting phase. Acidity caused by the presence of acid gases (CO<sub>2</sub> and H<sub>2</sub>S) normally increases the corrosion rate. When corrosion is minor, the common practice is to use standard API grades and to start batch inhibition when corrosion becomes a problem. | ||
Corrosion/erosion, a major problem with steel tubing, occurs in most high-rate gas-condensate wells in which the gas contains CO<sub>2</sub>. The CO<sub>2</sub> attacks the steel tubing, which creates an iron carbonate film (corrosion product); it is removed from the wall by erosion (impingement of well fluids). Rapid deep pit failure may occur from corrosion/erosion. Increasing fluid velocities and CO<sub>2</sub> partial pressure are highly detrimental, as are increasing temperature or increasing brine production. There may be a region of conditions in which frequent batch or continuous inhibition is necessary. | [[Glossary:Corrosion|Corrosion]]/[[Glossary:Erosion|erosion]], a major problem with steel tubing, occurs in most high-rate gas-condensate wells in which the gas contains CO<sub>2</sub>. The CO<sub>2</sub> attacks the steel tubing, which creates an iron carbonate film (corrosion product); it is removed from the wall by erosion (impingement of well fluids). Rapid deep pit failure may occur from corrosion/erosion. Increasing fluid velocities and CO<sub>2</sub> partial pressure are highly detrimental, as are increasing temperature or increasing brine production. There may be a region of conditions in which frequent batch or continuous inhibition is necessary. | ||
Gas wells with CO<sub>2</sub> contents higher than 30 psi partial pressure and gas velocities greater than 40 fps normally require continuous or frequent batch inhibition to protect the steel tubing. Corrosion Resistant Alloy (CRA) material is often the most cost-effective means of combatting erosion/corrosion. Some CRA material is subject to failure in brine water environments. | Gas wells with CO<sub>2</sub> contents higher than 30 psi partial pressure and gas velocities greater than 40 fps normally require continuous or frequent batch inhibition to protect the steel tubing. Corrosion Resistant Alloy (CRA) material is often the most cost-effective means of combatting erosion/corrosion. Some CRA material is subject to failure in brine water environments. | ||
A different type of tubing design problem is sulfide stress corrosion cracking (SSC). SSC and/or hydrogen embrittlement causes a brittle-type failure in susceptible materials at stresses less than the tubing yield strength. SSC is a cracking phenomenon encountered with high-strength steels in sour (H<sub>2</sub>S) aqueous environment. | A different type of tubing design problem is sulfide stress corrosion cracking (SSC). SSC and/or hydrogen embrittlement causes a brittle-type failure in susceptible materials at stresses less than the tubing [[Glossary:Yield strength|yield strength]]. SSC is a cracking phenomenon encountered with high-strength steels in sour (H<sub>2</sub>S) aqueous environment. | ||
Cracking also occurs in austenitic stainless steels in caustic or chloride solutions and mild steel in caustic or nitrate solutions. Susceptibility to attack of most low-alloy steels is roughly proportional to its strength. In terms of hardness, most steels are not subject to SSC failure if the hardness is less than 241 Brinell Hardness number or 23 Hardness-Rockwell C. The potential harmful level of H<sub>2</sub>S for susceptible materials has been defined as 0.05 psi partial pressure of the H<sub>2</sub>S gas phase. Carbonate-induced cracking of mild steel can occur in freshwater environments. | Cracking also occurs in [[Glossary:Austenitic steel|austenitic]] stainless steels in caustic or chloride solutions and mild steel in caustic or nitrate solutions. Susceptibility to attack of most low-alloy steels is roughly proportional to its strength. In terms of hardness, most steels are not subject to SSC failure if the hardness is less than 241 Brinell Hardness number or 23 Hardness-Rockwell C. The potential harmful level of H<sub>2</sub>S for susceptible materials has been defined as 0.05 psi partial pressure of the H<sub>2</sub>S gas phase. Carbonate-induced cracking of mild steel can occur in freshwater environments. | ||
Use of inhibition to prevent SSC is not completely reliable because 100% effective coverage of metal surface generally is not achieved. The best solution for tubulars subject to SSC is to use materials that are not subject to SSC failures. In general, follow NACE guidelines. <ref name="r3" /> | Use of inhibition to prevent SSC is not completely reliable because 100% effective coverage of metal surface generally is not achieved. The best solution for tubulars subject to SSC is to use materials that are not subject to SSC failures. In general, follow NACE guidelines. <ref name="r3" /> | ||
Dissimilar metals close to each other can influence corrosion. Because corrosion can result from many causes and influences and can take different forms, no simple or universal remedy exists for its control. Each tubing well problem must be treated individually, and the solution must be attempted in light of known factors and operating conditions. | Dissimilar metals close to each other can influence corrosion. Because corrosion can result from many causes and influences and can take different forms, no simple or universal remedy exists for its control. Each tubing well problem must be treated individually, and the solution must be attempted in light of known factors and operating conditions. | ||
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== Internal coatings == | == Internal coatings == | ||
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Coating should not be expected to stop all weight-loss corrosion over the life of the well. Typically, a few holes may develop in time but the bulk of the tubing stays intact. In such cases, workover costs are usually lowered because the tubing often can be retrieved without major fishing operations. Because such coatings increase the smoothness, they reduce pressure drop slightly in high-rate wells and, in some cases, may be helpful in reducing paraffin and scale problems. Besides thin wall film coatings, there are other kinds of interior coating or liners for tubing that have special application. Plastic liners and cement lining have been used successfully when the reduction in ID is not a major problem, primarily for water and carbon dioxide injection tubing or for sour service production. | Coating should not be expected to stop all weight-loss corrosion over the life of the well. Typically, a few holes may develop in time but the bulk of the tubing stays intact. In such cases, workover costs are usually lowered because the tubing often can be retrieved without major fishing operations. Because such coatings increase the smoothness, they reduce pressure drop slightly in high-rate wells and, in some cases, may be helpful in reducing paraffin and scale problems. Besides thin wall film coatings, there are other kinds of interior coating or liners for tubing that have special application. Plastic liners and cement lining have been used successfully when the reduction in ID is not a major problem, primarily for water and carbon dioxide injection tubing or for sour service production. | ||
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== Nomenclature == | == Nomenclature == | ||
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|total axial stretch or contraction, L, in. | |total axial stretch or contraction, L, in. | ||
|} | |} | ||
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==References== | ==References== | ||
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[[Tubing]] | [[Tubing]] | ||
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[[PEH:Tubing Selection, Design, and Installation]] | [[PEH:Tubing Selection, Design, and Installation]] | ||
[[PEH:Casing Design]] | [[PEH:Casing Design]] | ||
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