3 high pressure pup joint rack drawings made in china

Swivel loop Pup jointis cementing and fracturing equipment delivery High Pressure Fluid Control Products. Widely used in the acidic operating environment (excluding containing CO2, H2S sour gas operating environment) in the high-pressure discharge line, input line, a temporary flow line, well testing, and other high-voltage transmission lines on pipelines.

Pup jointmade of high strength steel, with a special toughening process. It uses Acme threaded connection, making it with the demolition convenient, fast, reliable connection, and reliable. Multiple seal design and high precision, to ensure the sealing performance of Pup joint.

4. Each technical parameters and performances of pup joints conform to standards of API Spec 6A and can be exchanged with like products internationally.

The standard detail drawings below apply to all Site Permit Review (formerly Concurrent Review). They are intended to be used as a guide in the preparation and submittal of plans for private development and city contract projects within the City of Raleigh and the city"s extra-territorial jurisdiction.

All construction shall conform to either these City of Raleigh specifications or to the latest edition of the NCDOT Standard Specifications for Road and Structures. If a required detail is not included on this web page, the North Carolina Department of Transportation (NCDOT) Roadway Standard Drawings shall apply. Any questions regarding the NCDOT Standard Drawings should be directed to the NCDOT, Design Services Unit at 919-250-4128.

This utility model relates to thermal extraction casing head technical field, is that a kind of two-stage hangs thermal extraction casing head；Including flange top connection, hanging pup joint, thread bush, liter dais, body, slips, hanger and tubing nipple, the two-stage that flange top connection internal diameter is up-small and down-big is step-like, the two-stage that the external diameter of thread bush is up-small and down-big is step-like, hanging pup joint is sleeved in flange top connection and top is fixed together with flange top connection, being provided with external screw thread in the middle part of hanging pup joint, thread bush is fixedly mounted on outside hanging pup joint by external screw thread.This utility model reasonable and compact in structure, easy to use, slips is placed in inside hanger, hanger is made to be seated in the second limiting stand of body interior, so make oil pipe be not susceptible to the situations such as deformation, sinking in frequent gas injection process and destroy weld seam, do not easily cause the leakages such as profit, and then pollute environment, stable and reliable in work, i.e. can be used for old well reparation and can also be used for the use of new well.

, popularity is to use note high temperature and high pressure steam exploitation at present, supporting is earth anchor special cementing technology, oil well is after too much alternate water injection gas, existing thermal extraction casing head occurs in that welding position ftractures, the problems such as oil jacket sinking, the fuel-displaced water outlet of well head, the pressure of environmental protection is bigger, prior art is all by the way of slips suspension sleeve, slips well cementation time from gas-injection oil-production time operating mode and stress different, slips stress when gas-injection oil-production is more than stress when cementing the well, for ensureing that slips continues to embrace jail sleeve pipe, slips must move down certain distance and could realize, the most original will stress by the weld seam of welded seal, the impact of welding quality and welding surroundings is difficult to ensure, arise that welding position ftractures, and then drawing crack hanger end plate；Under many wheel high temperature and high pressure gas environment, the intensity of the cement sheath intensity that also can be affected reduces, and then there will be the situation that oil jacket sinks, and then the situations such as fuel-displaced, the water of well head occurs, thus affects environment.

This utility model provides a kind of two-stage and hangs thermal extraction casing head, overcomes the deficiency of above-mentioned prior art, and it can effectively solve the problem that existing thermal extraction casing head occurs in that welding position cracking, oil jacket sink.

nullThe technical solution of the utility model is realized by following measures: a kind of two-stage hangs thermal extraction casing head，Including flange top connection、Hanging pup joint、Thread bush、Rise dais、Body、Slips、Hanger and tubing nipple，In up-narrow and down-wide step-like inside flange top connection，The outside of thread bush is up-narrow and down-wide step-like，Together with in hanging pup joint is sleeved on flange top connection and top is welded and fixed with flange top connection，External screw thread it is provided with in the middle part of hanging pup joint，Thread bush is fixedly mounted on outside hanging pup joint by external screw thread，The top of thread bush is positioned at the bottom of flange top connection，The inside rising dais is wide at the top and narrow at the bottom step-like，Rise dais upper inner and flange top connection lower outside to be threadably secured and link together and rise dais upper end and be welded in flange top connection，Rise dais lower inside and be provided with taper type the first limiting stand wide at the top and narrow at the bottom，The lower shape of thread bush is corresponding with the first limiting stand and seat is on the first limiting stand，Body upper part and liter dais bottom are fixed together，The second limiting stand in frustum wide at the top and narrow at the bottom it is provided with in the middle part of body，The lower shape of hanger is corresponding with the second limiting stand and seat is on the second limiting stand，The slips being fixed together it is provided with hanging pup joint between hanger and hanging pup joint，At least two tubing nipple it is installed with on body below second limiting stand.

Embracing sleeve pipe, complete pre-stress construction, well cementation is waited after coagulating and is rigged down, and Casing-Cutting thereon end face finished edge weld hanging pup joint

null1. a two-stage hangs thermal extraction casing head，It is characterized in that including flange top connection、Hanging pup joint、Thread bush、Rise dais、Body、Slips、Hanger and tubing nipple，In up-narrow and down-wide step-like inside flange top connection，The outside of thread bush is up-narrow and down-wide step-like，Together with in hanging pup joint is sleeved on flange top connection and top is welded and fixed with flange top connection，External screw thread it is provided with in the middle part of hanging pup joint，Thread bush is fixedly mounted on outside hanging pup joint by external screw thread，The top of thread bush is positioned at the bottom of flange top connection，The inside rising dais is wide at the top and narrow at the bottom step-like，Rise dais upper inner and flange top connection lower outside to be threadably secured and link together and rise dais upper end and be welded in flange top connection，Rise dais lower inside and be provided with taper type the first limiting stand wide at the top and narrow at the bottom，The lower shape of thread bush is corresponding with the first limiting stand and seat is on the first limiting stand，Body upper part and liter dais bottom are fixed together，The second limiting stand in frustum wide at the top and narrow at the bottom it is provided with in the middle part of body，The lower shape of hanger is corresponding with the second limiting stand and seat is on the second limiting stand，The slips being fixed together it is provided with hanging pup joint between hanger and hanging pup joint，At least two tubing nipple it is installed with on body below second limiting stand.

Two-stage the most according to claim 1 hangs thermal extraction casing head, it is characterised in that flange top connection is provided with the inner convex platform identical with hanging pup joint diameter.

Two-stage the most according to claim 1 and 2 hangs thermal extraction casing head, it is characterised in that be installed with at least one sealing ring between hanger and hanging pup joint.

Two-stage the most according to claim 3 hangs thermal extraction casing head, it is characterised in that be together by a threaded connection between flange top connection and liter dais.

Two-stage the most according to claim 3 hangs thermal extraction casing head, it is characterised in that rises and is together by a threaded connection between dais and body；Or/and, flange top connection top is provided with steel ring slot and tapped through hole.

830026 science and technology management division, West drilling and Drilling Engineering Institute, No. 326 South Central Road, Urumqi economic and Technological Development Zone, the Xinjiang Uygur Autonomous Region, China

A bicycle, also called a pedal cycle, bike, push-bike or cycle, is a human-powered or motor-powered assisted, pedal-driven, single-track vehicle, having two wheels attached to a frame, one behind the other. A bicycle rider is called a cyclist, or bicyclist.

The first mechanically propelled, two-wheeled vehicle may have been built by Kirkpatrick MacMillan, a Scottish blacksmith, in 1839, although the claim is often disputed.shillings (equivalent to £25 in 2021).

A human traveling on a bicycle at low to medium speeds of around 16–24 km/h (10–15 mph) uses only the power required to walk. Air drag, which is proportional to the square of speed, requires dramatically higher power outputs as speeds increase. If the rider is sitting upright, the rider"s body creates about 75% of the total drag of the bicycle/rider combination. Drag can be reduced by seating the rider in a more aerodynamically streamlined position. Drag can also be reduced by covering the bicycle with an aerodynamic fairing. The fastest recorded unpaced speed on a flat surface is 144.18 km/h (89.59 mph).

The great majority of modern bicycles have a frame with upright seating that looks much like the first chain-driven bike.diamond frame, a truss consisting of two triangles: the front triangle and the rear triangle. The front triangle consists of the head tube, top tube, down tube, and seat tube. The head tube contains the headset, the set of bearings that allows the fork to turn smoothly for steering and balance. The top tube connects the head tube to the seat tube at the top, and the down tube connects the head tube to the bottom bracket. The rear triangle consists of the seat tube and paired chain stays and seat stays. The chain stays run parallel to the chain, connecting the bottom bracket to the rear dropout, where the axle for the rear wheel is held. The seat stays connect the top of the seat tube (at or near the same point as the top tube) to the rear fork ends.

Another style is the recumbent bicycle. These are inherently more aerodynamic than upright versions, as the rider may lean back onto a support and operate pedals that are on about the same level as the seat. The world"s fastest bicycle is a recumbent bicycle but this type was banned from competition in 1934 by the Union Cycliste Internationale.

Historically, materials used in bicycles have followed a similar pattern as in aircraft, the goal being high strength and low weight. Since the late 1930s alloy steels have been used for frame and fork tubes in higher quality machines. By the 1980s aluminum welding techniques had improved to the point that aluminum tube could safely be used in place of steel. Since then aluminum alloy frames and other components have become popular due to their light weight, and most mid-range bikes are now principally aluminum alloy of some kind.carbon fibre due to its significantly lighter weight and profiling ability, allowing designers to make a bike both stiff and compliant by manipulating the lay-up. Virtually all professional racing bicycles now use carbon fibre frames, as they have the best strength to weight ratio. A typical modern carbon fiber frame can weighs less than 1 kilogram (2.2 lb).

Other exotic frame materials include titanium and advanced alloys. Bamboo, a natural composite material with high strength-to-weight ratio and stiffness

The drivetrain begins with pedals which rotate the cranks, which are held in axis by the bottom bracket. Most bicycles use a chain to transmit power to the rear wheel. A very small number of bicycles use a shaft drive to transmit power, or special belts. Hydraulic bicycle transmissions have been built, but they are currently inefficient and complex.

Since cyclists" legs are most efficient over a narrow range of pedaling speeds, or cadence, a variable gear ratio helps a cyclist to maintain an optimum pedalling speed while covering varied terrain. Some, mainly utility, bicycles use hub gears with between 3 and 14 ratios, but most use the generally more efficient dérailleur system, by which the chain is moved between different cogs called chainrings and sprockets to select a ratio. A dérailleur system normally has two dérailleurs, or mechs, one at the front to select the chainring and another at the back to select the sprocket. Most bikes have two or three chainrings, and from 5 to 11 sprockets on the back, with the number of theoretical gears calculated by multiplying front by back. In reality, many gears overlap or require the chain to run diagonally, so the number of usable gears is fewer.

Different gears and ranges of gears are appropriate for different people and styles of cycling. Multi-speed bicycles allow gear selection to suit the circumstances: a cyclist could use a high gear when cycling downhill, a medium gear when cycling on a flat road, and a low gear when cycling uphill. In a lower gear every turn of the pedals leads to fewer rotations of the rear wheel. This allows the energy required to move the same distance to be distributed over more pedal turns, reducing fatigue when riding uphill, with a heavy load, or against strong winds. A higher gear allows a cyclist to make fewer pedal turns to maintain a given speed, but with more effort per turn of the pedals.

With a chain drive transmission, a chainring attached to a crank drives the chain, which in turn rotates the rear wheel via the rear sprocket(s) (cassette or freewheel). There are four gearing options: two-speed hub gear integrated with chain ring, up to 3 chain rings, up to 11 sprockets, hub gear built into rear wheel (3-speed to 14-speed). The most common options are either a rear hub or multiple chain rings combined with multiple sprockets (other combinations of options are possible but less common).

Saddles also vary with rider preference, from the cushioned ones favored by short-distance riders to narrower saddles which allow more room for leg swings. Comfort depends on riding position. With comfort bikes and hybrids, cyclists sit high over the seat, their weight directed down onto the saddle, such that a wider and more cushioned saddle is preferable. For racing bikes where the rider is bent over, weight is more evenly distributed between the handlebars and saddle, the hips are flexed, and a narrower and harder saddle is more efficient. Differing saddle designs exist for male and female cyclists, accommodating the genders" differing anatomies and sit bone width measurements, although bikes typically are sold with saddles most appropriate for men. Suspension seat posts and seat springs provide comfort by absorbing shock but can add to the overall weight of the bicycle.

With hand-operated brakes, force is applied to brake levers mounted on the handlebars and transmitted via Bowden cables or hydraulic lines to the friction pads, which apply pressure to the braking surface, causing friction which slows the bicycle down. A rear hub brake may be either hand-operated or pedal-actuated, as in the back pedal coaster brakes which were popular in North America until the 1960s.

Track bicycles do not have brakes, because all riders ride in the same direction around a track which does not necessitate sharp deceleration. Track riders are still able to slow down because all track bicycles are fixed-gear, meaning that there is no freewheel. Without a freewheel, coasting is impossible, so when the rear wheel is moving, the cranks are moving. To slow down, the rider applies resistance to the pedals, acting as a braking system which can be as effective as a conventional rear wheel brake, but not as effective as a front wheel brake.

Tires vary enormously depending on their intended purpose. Road bicycles use tires 18 to 25 millimeters wide, most often completely smooth, or slick, and inflated to high pressure to roll fast on smooth surfaces. Off-road tires are usually between 38 and 64 mm (1.5 and 2.5 in) wide, and have treads for gripping in muddy conditions or metal studs for ice.

Some components, which are often optional accessories on sports bicycles, are standard features on utility bicycles to enhance their usefulness, comfort, safety and visibility. Fenders with spoilers (mudflaps) protect the cyclist and moving parts from spray when riding through wet areas. In some countries (e.g. Germany, UK), fenders are called mudguards. The chainguards protect clothes from oil on the chain while preventing clothing from being caught between the chain and crankset teeth. Kick stands keep bicycles upright when parked, and bike locks deter theft. Front-mounted baskets, front or rear luggage carriers or racks, and panniers mounted above either or both wheels can be used to carry equipment or cargo. Pegs can be fastened to one, or both of the wheel hubs to either help the rider perform certain tricks, or allow a place for extra riders to stand, or rest.child seats, an auxiliary saddle fitted to the crossbar, or both to transport children. Bicycles can also be fitted with a hitch to tow a trailer for carrying cargo, a child, or both.

Toe-clips and toestraps and clipless pedals help keep the foot locked in the proper pedal position and enable cyclists to pull and push the pedals. Technical accessories include cyclocomputers for measuring speed, distance, heart rate, GPS data etc. Other accessories include lights, reflectors, mirrors, racks, trailers, bags, water bottles and cages, and bell.

The European Committee for Standardization (CEN) also has a specific Technical Committee, TC333, that defines European standards for cycles. Their mandate states that EN cycle standards shall harmonize with ISO standards. Some CEN cycle standards were developed before ISO published their standards, leading to strong European influences in this area. European cycle standards tend to describe minimum safety requirements, while ISO standards have historically harmonized parts geometry.

Many bicycle components are available at several different price/quality points; manufacturers generally try to keep all components on any particular bike at about the same quality level, though at the very cheap end of the market there may be some skimping on less obvious components (e.g. bottom bracket).

The most basic maintenance item is keeping the tires correctly inflated; this can make a noticeable difference as to how the bike feels to ride. Bicycle tires usually have a marking on the sidewall indicating the pressure appropriate for that tire. Bicycles use much higher pressures than cars: car tires are normally in the range of 30 to 40 pounds per square inch (210 to 280 kPa), whereas bicycle tires are normally in the range of 60 to 100 pounds per square inch (410 to 690 kPa).

Over the longer term, tires do wear out, after 2,000 to 5,000 miles (3,200 to 8,000 km); a rash of punctures is often the most visible sign of a worn tire.

Some US companies, notably in the tech sector, are developing both innovative cycle designs and cycle-friendliness in the workplace. Foursquare, whose CEO Dennis Crowley "pedaled to pitch meetings ... [when he] was raising money from venture capitalists" on a two-wheeler, chose a new location for its New York headquarters "based on where biking would be easy". Parking in the office was also integral to HQ planning. Mitchell Moss, who runs the Rudin Center for Transportation Policy & Management at New York University, said in 2012: "Biking has become the mode of choice for the educated high tech worker".

Bicycle poverty reduction is the concept that access to bicycles and the transportation infrastructure to support them can dramatically reduce poverty.Uganda and Tanzania) and Sri Lanka on hundreds of households have shown that a bicycle can increase the income of a poor family by as much as 35%.

Transport, if analyzed for the cost–benefit analysis for rural poverty alleviation, has given one of the best returns in this regard. For example, road investments in India were a staggering 3–10 times more effective than almost all other investments and subsidies in rural economy in the decade of the 1990s. A road can ease transport on a macro level, while bicycle access supports it at the micro level. In that sense, the bicycle can be one of the most effective means to eradicate poverty in poor nations.

In general, U.S. and European cycle manufacturers used to assemble cycles from their own frames and components made by other companies, although very large companies (such as Raleigh) used to make almost every part of a bicycle (including bottom brackets, axles, etc.) In recent years, those bicycle makers have greatly changed their methods of production. Now, almost none of them produce their own frames.

A bicycle wheel remains chained in a bike rack after the rest of the bicycle has been stolen at east campus of Duke University in Durham, North Carolina.

Bulletin des lois de la République française (1873) 12th series, vol. 6, p. 648, patent no. 86,705: "Perfectionnements dans les roues de vélocipèdes" ("Improvements in the wheels of bicycles"), issued 4 August 1869.

Meijaard, J.P.; Papadopoulos, Jim M.; Ruina, Andy; Schwab, A.L. (2007). "Linearized dynamics equations for the balance and steer of a bicycle: a benchmark and review". 463 (2084): 1955–82. Bibcode:2007RSPSA.463.1955M. doi:10.1098/rspa.2007.1857. S2CID 18309860.

Fajans, Joel (July 1738). "Steering in bicycles and motorcycles" (PDF). American Journal of Physics. 68 (7): 654–59. Bibcode:2000AmJPh..68..654F. doi:10.1119/1.19504. Archived from the original (PDF) on 1 September 2006. Retrieved 4 August 2006.

"History Loudly Tells Why The Recumbent Bike Is Popular Today". Recumbent-bikes-truth-for-you.com. 1 April 1934. Archived from the original on 2 August 2003. Retrieved 24 October 2011.

Lakkad; Patel (June 1981). "Mechanical properties of bamboo, a natural composite". Fibre Science and Technology. 14 (4): 319–22. doi:10.1016/0015-0568(81)90023-3.

Patterson, J.M.; Jaggars, M.M.; Boyer, M.I. (2003). "Ulnar and median nerve palsy in long-distance cyclists. A prospective study". The American Journal of Sports Medicine. 31 (4): 585–89. doi:10.1177/03635465030310041801. PMID 12860549. S2CID 22497516.

Bluejay, Michael. "Safety Accessories". Bicycle Accessories. BicycleUniverse.info. Archived from the original on 8 October 2006. Retrieved 13 September 2006.

Shaheen, Susan; Guzman, Stacey; Zhang, Hua (2010). "Bikesharing in Europe, the Americas, and Asia". Transportation Research Record. 2143: 159–67. doi:10.3141/2143-20. S2CID 40770008.

Shaheen, Susan; Zhang, Hua; Martin, Elliot; Guzman, Stacey (2011). "China"s Hangzhou Public Bicycle" (PDF). Transportation Research Record. 2247: 33–41. doi:10.3141/2247-05. S2CID 111120290.

Broekaert, Joel & Kist, Reinier (12 February 2010). "So many bikes, so little space". NRC Handelsblad. Archived from the original on 13 February 2010. Retrieved 13 February 2010.

van Lierop Grimsrud El-Geneidy (2015). "Breaking into bicycle theft: Insights from Montreal, Canada" (PDF). International Journal of Sustainable Transportation. Retrieved 30 September 2015.

A design factor is the specific load rating divided by the specific anticipated load. A design factor less than 1.0 does not necessarily mean the product will fail, and neither does a design factor in excess of 1.0 mean that the product will not fail. As a result, design factors are generally selected on the basis of experience. The designer has the responsibility to select the design factors to suit particular needs and to reflect field experience. The condition of the tubing and the severity of a failure should have a significant effect on the design factors used. Design factors greater than 1.0 are recommended. Table 3.10 contains design factor guidelines.

The internal-yield pressure rating for tubing is based on an API variation of Barlow’ s formula and incorporates a 0.875 factor that compensates for the 12.5% reduction tolerance in wall thickness allowed in manufacturing.

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 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 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 3.11 shows approximate setting depths for various API grades.

A collapse resistance design of 1.1 is suggested. Collapse resistance for tubing is covered in API Bull. 5C3. Fig. 3.2 shows an ellipse of biaxial yield stress.

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. 3.2, 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.

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.

The burst resistance of the tube is increased because of tension loading up to a certain limit. In tubing- and casing-design practice, it is customary to apply the ellipse of plasticity only when a detrimental effect results. For a conservative design, this increase in burst resistance normally is ignored. Compression loads reduce burst resistance and must be considered when they occur. Such a condition can occur near the bottom of the well with a set-down packer and a relatively high internal tubing pressure and a relatively low annulus pressure. A typical design case in burst is to assume that the tubing is full of produced fluid and that the annulus is empty, which is a common situation for pumped wells.

Because tension loading reduces collapse resistance, the biaxial effect should be used to design for problem regions. A common practice in tubing design is to assume that the tubing is empty and that the annulus is full of fluid. Such conditions are common in low-pressure gas wells or oil wells that may be swabbed to bottom. Typically, the highest collapse pressures are near the bottom of the well. For combination tubing-string design, the collapse and tensile loads should be evaluated at the bottom and top of any tubing size, weight, or grade change.

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.

Many operators prefer one uniform weight (constant ID) and API grade tubing from top to bottom. Thus, it is not possible to mix different sections of the tubing during running or pulling operations throughout the life of the well. Most relatively shallow (< 9,000 ft), low-pressure (< 4,000 psi) wells have noncombination strings. As the pressures and depths increase, there comes a point at which a higher grade (stronger) or heavier weight (increased wall thickness) tubing must be used to meet load conditions and achieve acceptable design factors. For the same size diameter tubing, a higher grade normally is preferred over an increase in tubing weight. Such a choice is usually less expensive and maintains a constant internal diameter, which simplifies wireline operation inside the tubing.

Unlike casing design, which often has numerous grades and weights in a combination design, tubing design seldom has more than two different grades or weights. Such restriction may increase the cost of the tubing string but simplifies the running and pulling procedures. Deep and high-pressure wells may require more than two weights, grades, or diameters. When more than one grade or weight are used, each should be easily identifiable. To separate different weights and grades, a pup joint or different collar types may be used. For example, one section could use standard couplings and another could use beveled couplings. Painted and stenciled markings on the outside of the tubing are inadequate once the tubing is used because such markings are often obliterated.

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 OD size on bottom may be necessary because of casing diameter restrictions.

The tubing OD must have adequate clearance with the casing ID. The tubing size selected should permit washover and fishing operations, in case the tubing becomes stuck and requires recovery. A wash pipe must be available that has an outside coupling dimension less than the casing drift diameter and an internal drift diameter that is greater than the tubing coupling OD plus provide a minimum of 1/8-in. clearance for adequate circulation. Also, the tubing OD should permit use of an overshot inside the casing, which limits the tubing OD size and/or the coupling OD. For example, 3 1/2-in. OD tubing with regular API EUE couplings (OD = 4.500 in.) inside 5 1/2-in., 17.00 casing (drift diameter = 4.767 in.) could not be washed over with available wash pipe. Even 3 1/2-in. specialty joint tubing with a joint OD of 3.875 in. would be an impractical, risky washover operation because the couplings would require milling. Nevertheless, special circumstances may require special proprietary tubing in close tolerance applications. Special wash-pipe sizes often can be rented from the tool service companies. The tubing designer should check the success of washover and fishing operations for their particular planned condition and the area of operation.

Multicompletions with parallel tubing strings often result in limiting the tubing and/or coupling size. If two tubing strings are to be run and pulled independently, the sum of the tubing coupling ODs should be less than the casing drift diameter. For example, inside 7-29.00 casing with a drift diameter of 6.059 in., parallel 2 3/8-in. tubing strings with EUE couplings may be planned. In such a case, beveled and special-clearance couplings with an OD of 2.910 in. typically are used. The sum of the two ODs is 5.82 in. Experience shows that if the couplings are beveled (top and bottom), these strings can be run and pulled independently. The auxiliary tubing equipment such as gas lift mandrels and safety valves often cause more clearance problems than the tubing couplings.

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 3 1/2-in. tubing inside 9 5/8-in. casing is another common practice, and tubing OD limitations must be considered in such installations.

Tubing performance properties are found in API Bull. 5C2, Bull. 5C3.Bull. 5C2, includes tables showing minimum tubing performance properties. [Tables shown in printed volume, but removed here because API did not provide permission for their use in PetroWiki.]

Design a tubing string for a 9,000-ft hydropressured vertical well that is relatively straight, that will be used to flow 500 BOPD, and that will be completed inside 4 1/2-11.60-K55 casing. The well is to be completed with compression-set type packer and 9.0 ppg inhibited salt water in annulus. An overpull to free the packer of 15,000 lbf is anticipated. A maximum surface-treating pressure of 3,000 psi is expected.

The minimum collapse pressure without axial stress, pcr, = 8,100 psi (See Minimum Performance Properties of Tubing tables in API Bull. 5C2 Eq. 3.7, pbh = 9,000 ft × (9.0 × 0.052) psi/ft = 4,212 psi.

Check burst at bottom of hole under pumping conditions. Assume tubing filled with 9.0 ppg salt water with 100 psi surface tubing pressure and empty annulus.

Select and order tubing material. Order per API Spec. 5CT : 9,000 ft plus 300 ft of 2 3/8;-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.

Design tubing for relatively deep high-pressure gas well with CO2 and H2S. Assume the following conditions: casing designation = 5 1/2-23.00-L80; measured depth, Dm, = 14,000 ft; true vertical depth, DtV, = 13,000 ft; gas rate = 15 MMcf/D, 10 bbl of condensate per MMcf, 40 ppm hydrogen sulfide resulting in a partial pressure of 0.40 psi for the H2S and a 2% (20,000 ppm) carbon dioxide; pwh = 10,000 psi during stimulation; pbh = 9,000 psi; Tbh = 250°F; Tsf = 125°F; completion fluid weight = 14.0 ppg of inhibited solids free salt water; fluid gradient = 0.728 psi/ft; anticipated drag on tubing when pulling = 5,000 lbf; and packer shear pins setting = overpull = 25,000 lbf.

Because of the anticipated rate of 15 MMcf/D, 2 7/8-in. tubing will permit flow at a significantly higher rate than 2 3/8-in. tubing. The use of 3 1/2-in. tubing is not normally recommended within 5 1/2-in. casing because fishing operations would be difficult. On the basis of experience, the use of 3 1/2-in. tubing rather than 2 7/8-in. tubing would not significantly improve the production rate in this case.

Select the tubing weight and grade. Because surface pressures of 10,000 psi are anticipated, the tubing must have a minimum internal-yield pressure greater than 10,000 psi. With a design factor of 1.25 in burst, the required minimum internal-yield pressure is 12,500 psi (1.25 × 10,000). Because the partial pressure of H2S is 0.40 psi (greater than 0.05 psi), a sour service tubing grade must be used. See NACE MR-01-75. Bull. 5C2 Eq. 3.4 to calculate Fa = Lp × wn = 14,000 ft × 7.9 lbm/ft = 110,600 lbf. Use Eq. 3.7 to find the hydrostatic pressure at depth, pbh = 13,000 × 14 × 0.052 = 9,464 psi. Use Eq. 3.8 to calculate the buoyancy effect in 14 ppg fluid, Fb = Am × pbh = 2.254 in. 2 × 9,464 psi = 21,332 lbf. Use Eq. 3.5 to calculate Ff = Fa – Fb = 110,600 lbf – 21,332 lbf = 89,269 lbf. With Fj = 180,300 lbf, use Eqs. 3.9 and 3.10 to calculate Dt = Fj/Fa = 180,300/110,600 = 1.63, which is an acceptable design factor in tension in air, and Dt = Fj/Ff = 180,300/89,269 = 2.02, which is an acceptable design factor in tension considering buoyancy.

This is the required hook load to unset the packer. Use Eq. 3.12 to calculate Df = Fj/Ps = 180,300/140,600 = 1.28, which is an acceptable design factor in tension.

Check collapse conditions. pcr = 13,890 psi for 2 7/8-7.9-L80 tubing (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 Eq. 3.7 to calculate pbh = DtV × gf = 13,000 ft × (14.0 × 0.052) psi/ft = 9,464 psi, and use Eq. 3.15 to calculate Df = pcr / pbh = 13,890/9,464 = 1.47, which is an acceptable value. Ensure that the surface annulus pressure is kept less than 3,163 psi [ (13,890/1.1) – 9,464] in the event that the tubing pressure is bled off.

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 tubing size. Because of the anticipated flow rate, 3 1/2-in. tubing was selected. There is no clearance problem with 3 1/2-in. tubing inside the 7-in. casing. Smaller tubing sizes would result in high friction losses and loss in production rate. Larger tubing sizes would not increase production rates sufficiently and would result in clearance problems inside the 7-in. casing. EUE tubing with modified couplings (see API SR13 seal ring) are selected to provide adequate leak resistance.

Check collapse on bottom. pcr = 7,400 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 Eq. 3.7 to calculate pbh = DtV × gf = 11,000 ft × 0.572 = 6,292, and use Eq. 3.15 to calculate Dc = pcr / pbh = 7,400/6,292 = 1.176, which is adequate because 1.1 is acceptable.

Check burst at bottom. Assume casing annulus is empty and tubing is full of produced water. This is possible under gas lift conditions if the annulus injection pressure is bled off with tubing full of produced fluid plus surface wellhead pressure. Use Eq. 3.16 to calculate the burst pressure on bottom, 11,000 × 0.465 + 100 = 5,115 + 100 = 5,215 psi. With an internal-yield pressure for 3 1/2-9.30-J55 of 6,980 psi, use Eq. 3.17 to calculate 6,980/5,215 = 1.34, which is adequate because 1.25 is acceptable. With a maximum stimulation burst pressure at surface of 5,000 psi, use Eq. 3.14 to calculate Db = 6,980/5,000 = 1.396, which is adequate for burst.

Check tension loads at surface. For 3 1/2-9.30-J55 or N80 tubing, use Eq. 3.4 to calculate 11,000 ft × 9.3 lb/ft = 102,300 lbf. Use Eqs. 3.7 and 3.8 to calculate the axial buoyancy load, Fb = 2.590 in.2 × (11,000 × 11.0 × 0.052) psi = 16,296 lbf. Use Eq. 3.5 to calculate the weight in 11 ppg fluid, 102,300 – 16,296 = 86,004 lbf. For 3 1/2-9.30-J55 EUE tubing (100% joint efficiency), Fj = 142,500 lbf. Use Eq. 3.9 to calculate the design factor in tension, Dt, for 3 1/2-9.30-J55 EUE tubing in air, 142,500/102,300 = 1.39, which does not account for necessary overpull. The recommended design factor for weight in air is 1.6; therefore, the design factor is not adequate. A higher grade at top must be used for adequate tension design conditions.

Check worst possible tension design case. Pull at surface to overcome drag and shear pins in packer with no buoyancy effect on tubing above packer. Use Eq. 3.4 to calculate Fa, and use Eq. 3.18 to calculate Ft = 11,000 × 9.3 + 50,000 + 0 = 102,300 + 50,000 = 152,300 lbf. Use

to calculate 152,300 × 1.25 = 190,375 lbf. Use Minimum Performance Properties of Tubing tables in API Bull. 5C2 Fj = 207,200 lbf for 3 1/2-9.30-N80 tubing, which is acceptable. Suggest the use of as much J55 as feasible to reduce tubing string cost. For maximum pull load on 3 1/2-9.3-J55, applying the acceptable design factor = 142,500/1.25 = 114,000 lbf. Calculate the maximum feet of 3 1/2-9.30-J55 from

Assume Lp = 6,800 ft for 3 1/2-9.30-J55, and Lp = 11,000 – 6,800 = 4,200 ft for 3 1/2-9.30-N80 tubing. Use Eq. 3.12 to calculate the design factor in tension, Dt, for 3 1/2-9.30-N80, 207,200/152,300 = 1.36, which is acceptable. For Fa = 152,300 lbf, the design factor for 3 1/2-9.30-J55 can be calculated as 142,500/(152,300 – 4,200 × 9.3) = 1.26. Do not exceed the 50,000-lbf overpull load, because this would over load the top of the J55 tubing.

Select and order tubing material. Request that tubing meet API Spec. 5CT. Order 4,400 ft of 3 1/2-9.30-N80 with EUE modified API SR13 beveled couplings and S or EW, range 2; one set of pup joints for 3 1/2-9.30-N80 EUE modified API SR 13 standard couplings; 7,000 ft of 3 1/2-9.30-J55 with EUE modified API SR 13 standard couplings and S or EW, range 2; and 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.

Design tubing for a deep high-pressure gas well. Complete the well with 7-29.00-P110 casing to 13,900 ft and a 5-in. liner (4.031 in. ID) from 13,800 to 16,650 ft. Perforations are to be from 16,530 to 16,570 ft with a permanent packer at 16,500 ft. The bottomhole pressure is estimated to be 14,850 psi with a bottomhole temperature of 340°F and a surface-flowing temperature of 150°F. The well has a surface shut-in pressure of 12,445 psi with a gas gradient, gg, of 0.146 psi/ft. The well initially will produce approximately 10 MMcf/D of gas with a 10 BC/MMcf and 10 BW/MMcf into a 1,000-psia sales system. The gas gravity is 0.7 and contains 1% of nitrogen and 1% carbon dioxide, but the H2S is only 1 ppm. The formation may require acid stimulation with a maximum surface-treating pressure of 10,000 psi. Before perforating, the 17.4 ppg mud will be circulated out and replaced with 10 ppg clean inhibited salt water. After perforating, the well will be killed, the packer and tubing installed, and the annulus filled with 10 ppg clean inhibited salt water. If needed, batch inhibition is planned to protect the tubing from erosion/corrosion.

Select tubing sizes. The type of completion and the size of the tubing string must be selected before making the tubing design. Fig 3.3 shows an inflow performance and outflow performance graph comparing the production with 2 3/8-, 2 7/8-, and 3 1/2-in. tubing strings. This graph shows that a full string of 2 3/8-in. tubing would restrict production significantly; thus, the amount of 2 3/8-in. tubing should be limited. The 2 7/8-in. tubing produces the well near its maximum rate, whereas the use of 3 1/2-in. tubing results in only a small production rate increase and will cost substantially more. The 5-in. liner (4.031 in. ID) will make washover and fishing 2 7/8-in. tubing difficult; therefore, 2 3/8-in. tubing will be used in the liner section of the well. Thus, the top portion of the tubing string will be 2 7/8-in. tubing and the lower portion inside the liner will be 2 3/8-in. tubing.

Select weights and grades. The most common approach in casing and tubing design is to start at the bottom and work your way back to the surface; however, in this high-pressure well, burst is a major consideration. Draw a pressure-depth graph as shown in Fig. 3.4.

To control the shut-in surface tubing pressure of 12,445 psi with a design factor of 1.25, calculate the suggested minimum internal-yield pressure rating required, pyi = 12,445 × 1.25 or 15,556 psi. As the Minimum Performance Properties of Tubing tables in API Bull. 5C2 2S partial pressure is less than 0.05 psi, the nonsour service grade N80 and P110 can be used.

Because tension reduces the collapse rating and collapse reduces the tension rating, start at the bottom where tension is small and collapse is normally high. Actually, at the bottom (because of buoyancy forces), the tubing is in compression when run in fluid. Draw a schematic tubing depth chart as shown in Fig. 3.5.

Check collapse and tension stresses. Start at the bottom of the hole and work to the surface-checking tension and collapse at any size, weight, or grade change. The tensile load increases moving upward, but the collapse differential pressure decreases.

With the annulus full of 10 ppg salt water and assuming that the tubing pressure bled to zero, a 0.52 × 16,500 = 8,580 psi collapse differential would result on the bottom of the hole. The 23/8;-4.70-N80 tubing has a collapse of 11,780 psi, resulting in a design factor 11,780/8,580 = 1.37, which is acceptable. Keep the annulus pressure at the surface to a maximum of 1,500 psi in normal operations to avoid possible collapse if the tubing pressure at bottom is bled down to zero.

From above the top of the liner at 13,800 ft to the permanent packer at 16,500 ft, 2,700 ft of 2 3/8-4.70-N80 tubing is tentatively selected. Use 2,800 ft of 2 3/8-in. tubing to avoid interference with the liner top. At 13,700 ft, the tubing size can be increased safely to 2 7/8 in., which will allow a higher flow rate. To simplify wireline operations, the tubing weight for all 2 7/8-in. tubing is the same.

For burst considerations, the design requires a minimum of 7.9 lbm/ft tubing. There is a –11,188 buoyancy force because of the fluid acting on the bottom tubing area. At 13,700 ft, the 2 3/8-in. tubing will have a load of 4.7 lbm/ft × 2,800 ft = 13,160 lbf; however, the tensile load on the tubing is altered slightly because of the tubing area change at 13,700 ft. This results in an axial load at 13,700 ft of 13,160 – 11,188 + 7,929 – 14,690 = –4,789 lbf; thus, the effect of tension on collapse can be neglected because the tubing is in compression.

Assuming a surface-treating pressure of 10,000 psi, the tubing full of acid (gradient = 0.45 psi/ft), and the annulus full of 10 ppg (gradient = 0.52 psi/ft) salt water, use Eq. 3.22 to calculate a burst differential on bottom of 10,000 + 0.45 × 16,500 – 0.52 × 16,500 = 8,845 psi. The use of a design factor of 1.25 in burst will require an internal-yield pressure of 8,845 × 1.25 = 11,056 psi. The 2 3/8-4.70-N80 tubing has an API internal yield of 11,200 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 Eq. 3.22 to calculate the tubing burst pressure differential during stimulation: 10,000 psi + 0.45 psi/ft × 13,700 ft – 0.52 psi/ft × 13,700 ft = 9,041 psi. The use of a design factor in burst, Db, of 1.25 would require a burst resistance rating of 9,041 psi × 1.25 = 11,301 psi. Thus, at this depth, the 2 3/8, 4.7, N80 tubing is acceptable and 2 7/8, 7.9, N80 tubing is acceptable because it has an API internal pressure rating of 13,440 psi (see Minimum Performance Properties of Tubing tables in API Bull. 5C2 Db, of 1.25, the maximum burst differential for 2 7/8, 7.9, N80 should not exceed 13,440/1.25 = 10,752 psi.

At the surface during stimulation, 2 7/8-in., 7.9, P110 is required as shown previously. The depth of the crossover from P110 to N80 needs to be calculated. This depth is where the burst pressure differential is equal to 10,752 psi for 2 7/8-in., 7.9, N80 tubing. The worst case condition is during shut-in when a surface pressure of 12,445 psi occurs and the tubing is full of 0.146-psi/ft gas.

Using Eq. 3.23, Lp = (12,445 psi – 13,440/1.25 psi)/(0.52 psi/ft – 0.146 psi/ft) = 4,527 ft. Thus, 2 7/8-in., 7.9, P110 tubing is to be used from the surface to 4,527 ft and 2 7/8;-in., 7.9, N80 tubing is to be used from 4,527 to 13,700 ft. Table 3.13 summarizes the sizes, weights and grades selected.

Thus, the limiting condition is for pulling on the 2 7/8, 7.9, N80 tubing, which allows a hook load at the surface of 180,003 lbf. For this string design, an overpull over the weight in fluid would be 180,003 lbf – 103,441 lbf = 76,562 lbf.

Select and order tubing material. Order the tubing to API 5CT specifications, adding a few hundred feet of each type: seamless, range 2, and a proprietary connection integral joint or threaded and coupled with metal-to-metal seals. Also, order a set of grade P110 pup joints for the 2 7/8-in. tubing with the same proprietary connection integral joint. Order an appropriate thread compound. In addition, one special crossover 2 7/8-7.90 to 2 3/8-4.70 in grade N80 is required. (If an MTC connection is used, the crossover can be a pin × pin with a 2 7/8-N80 coupling.)

All auxiliary well equipment should have the same proprietary connection. Tubing should be hydrostatically tested to 80% of yield pressure. Ensure that proper running procedures are used.

Check with the manufacturer on ways to distinguish between the two grades of 2.875-in. OD tubing. Some operators would select 2 7/8-7.90-P110 and no 2 7/8-7.90-N80 tubing to ensure that accidental mixing of the 2.875-in. OD different grade tubing could not occur and to allow a slightly higher overpull value.

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.

where ΔLt = total axial stretch or contraction, in.; F = superimposed tension or compression axial load, lbf; Lp = length of pipe, ft; E = Young ’ s modulus of elasticity for steel = 30 million psi, which is not affected significantly by tubing grade; and Am = cross-section metal area of pipe, in.2 = 0.7854 × (do2 – di2).

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. 3.6. Am = π × (2.8752 – 2.4412)/4 = 1.812 in.2 Use Eq. 3.25 to calculate Lp = ΔLt × E × Am / (12 × F) = 20.0 in. × 30,000,000 psi × 1.812 in.2 /(12 in./ft × 10,000 lbf) = 9,060 ft.

Corrosion/erosion, a major problem with steel tubing, occurs in most high-rate gas-condensate wells in which the gas contains CO2. The CO2 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 CO2 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 CO2 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. 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 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 (H2S) 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 H2S for susceptible materials has been defined as 0.05 psi partial pressure of the H2S gas phase. Carbonate-induced cracking of mild steel can occur in freshwater environments.

Plastic internal coating of a tubing string is sometimes used to deter corrosion or erosion/corrosion in oil and gas wells and may increase tubing life significantly. Such cases may be in high-water-cut oil wells or gas wells with high CO2 partial pressures. These coatings are usually thin wall film applications ( < 0.01 in. thick) that are baked (bonded) onto the inside walls of the tubing string. The film thickness is small enough to allow normal wireline operations. The key to plastic coatings is selecting the correct material and its proper application. Even if the specifications call for "100% holiday free," eventually the coating comes off and holidays occur because of poor application or handling practices, wireline work, caliper surveys, blisters caused by the environment, or other reasons. 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.