Tubing design

vacuum tube physical body metro designIn the previous chapter, subscribeion military ope ration of pipe diameter was found on well performance analysis. In this section, the procedure for selecting render material properties is presented. Selection of material is carried out by considering different forces that act on the furnish during end product and workover operations and so a graphical method is apply to present the subway system essence against material properties.1.1 Forces on undergroundDuring the life of the well, vacuum tube is subjected to various forces from production and workover operations which include* production of hydrocarbon,* tearing of the well,* squeeze cementing, * hydraulic fracturing etceteraThe activities result in alteration in temperature and haul privileged the pipe and casing- pipe doughnut, which preserve defecate a switch in thermionic valve distance ( cut down or leng accordinglying).The convince in continuance often lead s to increase in compression or tensity in tubing and in organic government agency unseating of bagger or misfortune of tubing (Hammerlindl, 1977 and Lubinski et.al, 1962). According to the authors the mixture in atmospheric push inwardly and im disposed(p) of tuning and temperature tush exhaust various printings on tubing* plumbers helper effect(According to Hookes Law),* helical buckling,* pilot and * thermal effect.HOOKES LAW EFFECTSChanges in extort deep down and extraneous the tubing can cause tubing movement out-of-pocket to piston effect. According to Hookes law, transform in length of tubing caused by this effect can be cargonful using the equivalence 4.1.Where is the switch in forces callable to the change in squelchs in spite of appearance ( ) and extracurricular () tubing and can be expressed asWhere, (see Fig. 4.2)DL1= change in length cod to Hookes Law effect, inch,L = length of tubing, inch,F = force acting on tail of tubing, lb.,E= modulus of elasticity,As = cross- sectional world of tubing, inch2,Ai = ara based on internal diameter of tubing, inch2 andAo = area based on outside diameter of tubing, inch2,Ap= area based on diameter of meat packer seal, inch2,= change in military press inside(a) pack at packer (Final Initial), psi and= change in printing press inside tubing at packer (Final Initial), psi.Notes DL, DF, DPi or DPo indicates change from initial packer setting conditions. It is put on Pi = Po when packer is initially set.HELICAL BUCKLINGThe difference in squelch inside tubing and casing-tubing annulus acts on the cross sectional area of packer bore at tubing seal and leads to a decrease in the length of tubing repayable to buckling. This effect is cognise as helical buckling. When the tubing is restricted from movement, a tensile buck is developed. This effect is increased with increase in inside tubing printing press.The change in length caused by helical buckling can be calculated by th e Equation 4.3.where Force causing buckling Ff = Ap (Pi Po) If Ff (a fictitious force) is zero or negative, there is no buckling.Length of tubing buckled n = Ff / w Where,DL2= change in length due to buckling, inch,r= radial clearance mingled with tubing and casing, inch,w = ws + wi wo,ws = saddle of tubing, lb/incn,wi =weight of melted contained inside tubing, lb/in. (density multiply by area based on ID of tubing),wo= weight of annulus gas displaced by bulk volume of tubing, lb/in. (density multiplied by area based on OD of tubing),=tubing outside diameter, inch and=tubing inside diameter, inch.Buckling can be avoided by applying push through annular wardrobe.BALLOONING EFFECTSThe radial pressure inside the tubing causes tubing to increase or decrease in length. When the pressure inside the tubing is greater compared to the pressure inside the casing-tubing annulus, it tends to inflate the tubing, thus shortening the tubing. If the pressure inside the casing-tubing annulus is greater compared to pressure inside the tubing, then the tubing length is increased. This effect is known as ballooning and the change in length caused due to this effect is stipulation by Equation 4.4.Where,DL3=change in length due to ballooning, in. m= Poissons ratio (0.3 for steel) R= tubing OD/tubing IDDri=change in density of fluid inside tubing, lb/in3Dro=change in density of fluid outside tubing, lb/ in3Dpi=change in go up pressure inside tubing, psiDpo=change in go on pressure outside tubing, psid=pressure drop in tubing due to flow, psi/in. (usually considered as d= 0)THERMAL EFFECTSDue to the earths geothermal slope, the temperature of the produced fluids can be high enough to change the tubing length. The effect is opposite (decrease in length) when a cold fluid is injected inside the tubing. It is ideal to take the change in average trace temperature. The change in length due to temperature can be calculated using the Equation 4.5.Where,DL4=change in length, in.L =length of tubing line, in.C=coefficient of expansion of steel per oFDT=temperature change, oF boxer SETTING FORCEThe setting of packer requires forces which whitethorn lead to change in length of tubing.This change in length can be calculated using the Equation 4.6., which is derived based on Equations 4.1 and 4.3.The force on packer should not exceed critical values whereby it can cause standing(prenominal) damage to the tubing. The initial weight on packer whitethorn cause slack off and to check if this role might exist, single could use Equation 4.7.Where, F = set-down force.The tubing can suffer permanent damage if the stress in the tubing exceeds the yield strength of the tubing material. It is therefore advised to determine the safe tubing stresses for a given production or workover operation. The safe tubing stress can be calculated by using the pursual Equations (Allen and Roberts, 1989)The critical values can be calculated using Equations 4.8 and 4.9.Where, Si=stress at inside(a) mole of the tubingSo=stress at outer wall of the tubingFor free-motion packerWhen the packer exerts some force on the tubing, an additive term Ff should be added to Fa and the sign in Equations 4.8 and 4.9 varies in way to maximise the stresses.Example 4.1 An example of tubing Movement calculationThe following operations are to be performed on a well completed with 9,000 ft of 2-7/8 OD (2.441 ID), 6.5 lb/ft tubing. The tubing is sealed with a packer which permits free motion. The packer bore is 3.25. The casing is 32 lb/ft, 7 OD (6.049 ID). Calculate the total movement of the tubing (note billet is used for inch).ConditionsProduction FracCementInitial Fluid12 lb/ congiuslon mud13 lb/gal saltwater8.5 lb/gal oilFinal Fluid metro10 lb/gal oil 11 lb/gal frac fluid15 lb/gal cementAnnulus12 lb/gal mud13 lb/gal saltwater8.5 lb/gal oil Final PressureTubing1500 psi3500 psi5000 psiAnnulus01000 psi1000 psitemporary worker Change+25oF-55oF-25oFSOLUTIONProductionHookes Law kernelAt click smother conditionsDPi = Final pressure inside tubing Initial pressure inside tubingDPo = Final pressure inside annulus initial pressure inside annulus exploitation Eq. (4.2)victimization Eq. (4.1)Helical Buckling EffectUsing Eq. (4.3)Ballooning EffectUsing Eq. (4.4)Temperature EffectUsing Eq. (4.5) list Tubing Movement(Tubing lengthens)FracturingHookes Law EffectAt fall into place hollow conditionsDPi = Final pressure inside tubing Initial pressure inside tubingDPo = Final pressure inside annulus initial pressure inside annulusUsing Eq. (4.2)Using Eq. (4.1)Helical Buckling EffectUsing Eq. (4.3)Ballooning EffectUsing Eq. (4.4)Temperature EffectUsing Eq. (4.5)Total Tubing Movement(Tubing shortens)CementHookes Law EffectAt bottom bunker conditionsDPi = Final pressure inside tubing Initial pressure inside tubingDPo = Final pressure inside annulus initial pressure inside annulusUsing Eq. (4.2)Using Eq. (4.1)Helical Buckling EffectUsing Eq. (4.3)Ballooning Effect Using Eq. (4.4)Temperature EffectUsing Eq. (4.5)Total Tubing Movement(Tubing shortens)1.2 Selection of Tubing MaterialTubing selection should be based on whether or not the tubing can reserve various forces which are caused due to the variations in temperature and pressure. The API has specified tubing based on the steel pasture. Most common grades are H40, J55, K55, C75, L80, N80, C95, P105 and P110. The number following the letter indicates the maximum yield strength of the material in thousands of psi. The failure of the tubing can be attributed to the fill up conditions. There are trey modes of tubing failure which include* get around (pressure due to fluid inside tubing),* interrupt (pressure due to fluid outside tubing) and* tension (due to weight of tubing and tension if restricted from movement).The graphical design of the tubing can be achieved by creating a plot of depth vs pressure. This design is carried out by calculating pressures inside the tubing and casing-tub ing annulus at the bottom fixture and tubing gaffer. The maximum differential pressures at surface and bottom ambuscade are examined using the plot. This maximum condition usually occurs during input signal. When the maximum deductible annular pressure is maintained during stimulation, a considerable amount of reducing in the tubing load can be achieved. The offend pressure load (difference between the pressure inside the tubing and annulus) is closely see in greater magnitude close to the surface but may not necessarily be always true. The go against load lines are plotted followed by plotting give load lines. The collapse loads are calculated with an assumption that a tiresome leak at the bottom hole has depressurized the tubing. This scenario is sometimes expereinced after the fracturing treatment when operators commence kickoff in the first place bleeding off the annular pressure.If the data for pressure testing conditions (usually virtually critical load) is avail able, it should be included in the plot.Along with the collapse and go bad loads, the burst and collapse resistance for different tubing grades (available) are plotted. By observing the plot we can determine which tubing grade to be selected that can withstand the calculated loads.An example of selecting tubing based on graphical design is presented below.Example 4.2 Graphical tubing design ground on the data given below, select a tubing string that will satisfy burst, collapse and tension with safety portions of 1.1, 1.0 and 1.8 respectively.Planning selective in make-upD =9000 ft true depth,f = 2.875 inches, tubing OD,CIBHP = 6280psi, closed-in bottom hole pressure,FBP = 12550psi, formation germinatedown pressure,FPP = 9100psi, fracture propagation pressure,Gpf = 0.4 psi / ft packer fluid gradient,Gf = .48 psi /ft fracturing fluid gradient,g = 0.75 grease-gun gloominess at reservoir,Pann = 1000 psi, maximum allowable annulus pressure,SFB =1.1, safety Factor, rive Condition,S FC =1.0, safety Factor, stop Condition,SFT =1.8, safety Factor, Tensile Load, go and Collapse rate of available tubingsB_L80 =9395 psi,C_L80 =9920 psi,B_J55 =6453 psi,C_J55 =6826 psi,B_H40 =4693 psi andC_H40 =4960psi.SolutionStep 1 Calculate the ratio of bottomhole pressure to surface pressure.Referring table 4.1 in the manual, determine the ratio of surface and BHP at the given reservoir catalyst somberness,At a gas gravity = 0.8 and Depth 9000 ft, the ratio is 0.779At a gas gravity = 0.7 and Depth 9000 ft, the ratio is 0.804At gas gravity 0.75 the ratio of surface pressure to BHP is Table 4.1 Ratio of surface pressure and BHP in gas wells for a range of gas gravities.Depth of Hole louse up Gravity(ft)(m)0.600.650.700.8010003050.9790.9780.9760.97320006100.9590.9560.9530.94630009150.9390.9350.930.92400012190.920.9140.9070.895500015240.9010.8930.8850.87600018300.8830.8730.8540.847700021330.8640.8540.8440.823800024380.8470.8350.8230.801900027430.8290.8160.8040.7791000030480.8120. 7980.7640.7581100033530.7950.780.7660.7371200036600.7790.7630.7470.7171300039620.7630.7460.7290.6971400042670.7470.7290.7120.6781500045720.7320.7130.6950.6591600048760.7170.6970.670.6411700051810.7020.6820.6520.6241800054860.6870.6560.6450.6071900057910.6730.6520.6310.592000060970.6590.6370.6150.574Step 2 Calculate the pertinent pressures for different operational conditions.a) Pressures inside casing-tubing annulusAssuming during the production and wipe outing of well, packer fluid is present inside the casing tubing annulus.For producing situationPressure inside annulus at surface = packer fluid gradient * DepthPkill_prod_surface= = 0.4* 0 = 0 psiPressure inside annulus at bottom hole = packer fluid gradient * DepthPkill_prod = Gpf *D = 0.4* 9000 = 3600 psiFor StimulationPressure inside annulus at surface= Pstim_surf = 1000 psiPressure inside annulus at bottomhole = packer fluid gradient * Depth + (Max Allowable pressure inside annulus)Pstim_bh= Gpf *D + Pann = 0.4*9000 + 1000 = 4600 psib) Pressures inside tubingAt bottom hole, pressure = CIBHPAt surface, pressure = CITHP (closed in tubing head pressure) CITHP = ratio * CIBHP CITHP = 0.792 * 6280 = 4973 psiKILL SITUATIONWhen a well is killed, the bottom hole pressure is given as sum of CIBHP and maximum allowable annulus pressure.At bottom hole, pressure inside tubing during kill situation (BHIP) = CIBHP+PannBHIP =6280 +1000 = 7280psiTubing head pressure during kill situation is calculated by multiplying BHIP with gas gravity.At tubing head kill pressure (THIP) = ratio * BHIP = 0.792*7280 = 5765 psiFORMATION BREAKDOWN SITUATIONDuring stimulation the bottomhole pressure is the formation break down pressure and can be calculated by the density of the fracture fluid .In this problem the break down pressure is specified.At bottomhole, pressure inside tubing during formation breakdown (BHFBP) = FBPBHFBP = 12550 psi The tubing head pressure can be calculated by subtracting the hydro unchanging head generated by the fracturing fluid from the bottomhole pressure.At tubing head, pressure (THFBP) = FBP -Gf* D=12550- 0.48* 9000 = 8230psiFRACTURE PROPAGATIONDuring stimulation (propagation), we take care some pressure drop due to friction. Based on the pumping pass judgment and properties of proppants we can determine the drop in pressure. Assuming a pressure drop of 0.35 psi / ft (usually calculated through properties of fracturing fluid and pumping rate), the bottomhole pressure at fracture propagation (BHFP) can be calculated asDPfr = 0.35 psi/ ftAt bottomhole, BHFP = FPP BHFP =9100 psiAt tubing head, the pressure inside tubing can be calculated asTubing head fracture propagation pressure (THFP) = BHFP + DPfr* D Gf*D= 9100 + 0.35*9000 -0.48*9000 =7930 psiStep 3 Calculate the burst load for different operating conditionsDefining the burst loads fusillade Load pressure = pressure inside tubing pressure in the casing- tubing annulusBurst Load at tubing head for producing conditionsBL _surfac e_prod = CITHP Pkill_prod_surface = 4973 0 = 4973 psiBurst Load at bottomhole for producing conditionsBL _bh_prod = CIBHP Pkill_prod = 6280-3600 = 2680 psiBurst Load at tubing head for cleansing operationBL _surface_kill = THIP Pkill_prod_surface = 5765 -0 = 5765 psiBurst Load at bottomhole for killing operationBL _bh_kill = BHIP Pkill_prod = 7280-3600 = 3680 psiBurst Load at tubing head for formation breakdownBL _surface_fbp = THFBP Pstim_surf = 8230 -1000 = 7230 psiBurst Load at bottomhole for formation breakdownBL _bh_fbp = BHFBP Pstim_bh = 12550 -4600 = 7950 psiBurst Load at tubing head for fracture propagationBL _surface_fbp = THFP Pstim_surf = 7930 -1000 = 6930 psiBurst Load at bottomhole for fracture propagationBL _bh_fbp = BHFP Pstim_bh = 9100 -4600 = 4500 psiStep 4 Calculation of collapse LoadDefining the collapse loads Collapse load pressure = pressure in casing-tubing annulus- pressure inside tubingIn rove to plot critical collapse load conditions (CLL) normall y, we assume that a slow leak in tubing has changed the pressure inside casing-tubing annulus to CITHP and that tubing is empty and depressurized.Step 5 Plot the Load lines.Plot the burst load and collapse load lines for various completion operations, burst and collapse resistance lines for the available tubing grades. The obtained plot is illustrated in Fig. 4.4.It can be observed from plot that formation breakdown situation has the maximum burst pressures. The maximum burst pressure line and collapse line are plotted with the available ratings of tubing. The resulting plot will look like Fig. 4.5. because by inspecting the graph we can come to a conclusion that L-80 grade is the best grade available that can withstand the collapse and burst pressures during various operations. But in other situations we have an option to select multiple grades on tubing which are guided by the estimated loading conditions.Estimation of Tensile LoadMost of the tubing failures are caused due to coup ling leakage and failure. The failure of coupling can be attributed to little design for tension of the tubing.This load being one of the significant and causes most failures compared to failures due to burst and collapse pressures.A higher safety factor is used while designing tubing. The design can be initiated by considering only the weight of tubing on packer. Some companies even throw out buoyancy effects while calculating weight to have a better design.So ideally a tubing design for tension is carried out by calculating the weight of the tubing in air. and then the buoyant weight of the tubing is calculated using the densities of steel and mud. Selecting a grade of casing which can handle the tensile load generated due to the weight of the tubing. An example below illustrates the design of tubing for tension.Example 4.3 emphasis DesignTubing weight 7.2 lb/ftTubing length 12,500 ftPacker fluid 0.38 psi/ft = 54.72 lb/ft3 closeness of steel 490 lb/ft3Win_air = 7.2 x 12,500 = 9 0,000 lbWbuoyant = = 0.89 x 73,600 = 80,100 lb spliff SpecificationsJ55L80EUEHYD CSEUEHYD A95API joint strength (Klb)Design factor Design message (Klb)99.71.855.41001.855.6135.91.875.51501.883.3Tubing Tension Design Considerations1. Requires L80 tubing at surface2. Requires joint strength capability of HYD A95 or equivalent reexamine questions1. When would buckling of tubing above a packer likely to occur?2. A 10,000-ft, high-rate oil well is completed with 5 15.5 lb/ft tubing (wall thickness 0.275). Under producing conditions the flowing temperature gradient is 0.40F/100 ft, and under static conditions the geothermal gradient is 1.8oF/100ft from a mean surface temperature of 40oF. When the well is killed with a large volume of 40oF seawater, the bottom-hole temperature drops to 70oF. If free to move, what tubing movement can be expected from the landing condition to the hot producing and to the cold injection conditions? If a hydraulic packer were to be used and set in 30,000 lb t ension, what would be the tension loading on the packer after killing the well? (Ignore piston, ballooning and buckling effects).3. A 7000-ft well that is to be produced with a object of 15,000 STB/D using 5 tubing encounters 170 ft of oil-bearing formation with a pressure of 3000 psi. What rating of wellhead should be used? If a single grade and weight tubing is to be used, what is the cheapest string that can probably be run, assuming thatGradeWeight(lb/ft)Collapse Strength(psi)Burst Strength(psi)Tensional Strength(1000 lb)Cost likenessJ-55C-75N-8015.517.017.017.020.04040491060706280883048105320725077408990300329423446524CheapestMost expensiveModerately expensiveREFERENCES1. Allen, TO and Roberts, AP, Well point Design- Production Operations-1, 3rd edition, 1989, pp 182-187.1. Hammerlindl, DT, Movement, Forces and Stress Associated with Combination Tubing Strings sure with Packers, JPT, February 1977.2. Lubinski, A, Althouse, WS, Logan, TL, Helical Buckling of Tubing Sealed in Packers, JPT, June 1962.3. Well completion design and practices PE 301-IHRDC EP Manual Series, Boston, MA 02116, USA.