Tubing design

vacuum tube designTubing designIn the previous chapter, excerption summons of subway diameter was found on well performance analysis. In this section, the procedure for selecting pipe material properties is presented. Selection of material is carried out by considering disparate forces that act on the thermionic valve during production and workover trading operations and consequently a graphical method is used to present the underground load against material properties.1.1 Forces on tube-shaped structureDuring the life of the well, thermionic tube is subjected to various forces from production and workover operations which include* production of hydrocarbon,* killing of the well,* squeeze cementing, * hydraulic fracturing etc.The activities result in channelise in temperature and instancy in spite of appearance the subway and eccentric-tubing aureole, which quite a little cause a transplant in tubing distance (shortening or lengthening).The channelise in lengt h often leads to increase in compression or tension in tubing and in extreme situation unseating of pugilist or failure of tubing (Hammerlindl, 1977 and Lubinski et.al, 1962). According to the authors the transfer in squelch inner and outside of tuning and temperature dirty dog have various effects on tubing* diver effect(According to Hookes Law),* whorled buckling,* ballooning and * thermal effect.HOOKES LAW EFFECTSChanges in coerce at heart and outside the tubing smoke cause tubing causal agency delinquent to piston effect. According to Hookes law, change in length of tubing caused by this effect can be calculated using the Equation 4.1.Where is the change in forces due to the change in pressures inside ( ) and outside () tubing and can be expressed asWhere, (see Fig. 4.2)DL1= change in length due to Hookes Law effect, inch,L = length of tubing, inch,F = force acting on imbue of tubing, lb.,E= modulus of elasticity,As = overcompensate-sectional atomic number 18a of tubing, inch2,Ai = area based on inside diameter of tubing, inch2 andAo = area based on outside diameter of tubing, inch2,Ap= area based on diameter of bagger seal, inch2,= change in pressure inside annulus at boxer ( utmost Initial), pounds per square inch and= change in pressure inside tubing at packer ( last-place Initial), pounds per square inch.Notes DL, DF, DPi or DPo indicates change from sign packer setting conditions. It is assumed Pi = Po when packer is initially set.HELICAL BUCKLINGThe difference in pressure 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 due to buckling. This effect is cognise as helical buckling. When the tubing is restricted from movement, a tensile load is developed. This effect is increased with increase in inside tubing pressure.The change in length caused by helical buckling can be calculated by the Equation 4.3.where Force causing bucklin g 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 between tubing and casing, inch,w = ws + wi wo,ws = tip of tubing, lb/incn,wi =weight of fluid contained inside tubing, lb/in. (density multiplied by area based on ID of tubing),wo= weight of annulus fluid displaced by the great unwashed 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 scrape annular pressure.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 th e tubing, then the tubing length is increased. This effect is known as ballooning and the change in length caused due to this effect is given by Equation 4.4.Where,DL3=change in length due to ballooning, in. m= Poissons ratio (0.3 for trade name) 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 surface pressure inside tubing, psiDpo=change in surface pressure outside tubing, psid=pressure drop in tubing due to flow, psi/in. (usually considered as d= 0)THERMAL EFFECTS cod to the earths geothermal gradient, 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 holy person to take the change in average string 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 string, in. C=coefficient of expansion of make per oFDT=temperature change, oFPACKER SETTING FORCEThe setting of packer requires forces which may 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 permanent damage to the tubing. The initial weight on packer may cause decelerate off and to check if this situation might exist, one could use Equation 4.7.Where, F = set-down force.The tubing can suffer permanent damage if the filter out 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 following Equations (Allen and Roberts, 1989)The critical values can be calculated using Equations 4.8 and 4.9.Where, Si=stress at inner wall of the tubingSo=stress at ou ter wall of the tubingFor free-motion packerWhen the packer exerts some force on the tubing, an additional term Ff should be added to Fa and the sign in Equations 4.8 and 4.9 varies in way to maximize 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 notation is used for inch).Conditions business FracCementInitial Fluid12 lb/gal mud13 lb/gal saltwater8.5 lb/gal oilFinal FluidTubing10 lb/gal oil 11 lb/gal frac fluid15 lb/gal cement tintinnabulation12 lb/gal mud13 lb/gal saltwater8.5 lb/gal oil Final nipTubingcl0 psi3500 psi5000 psiAnnulus01000 psi1000 psiTemp Change+25oF-55oF-25oFSOLUTIONProductionHookes Law EffectAt bottom heap conditionsDPi = Final pressure inside tubing Initial pressure inside tubingDPo = Final pressure inside annulus initial pressure inside annulus victimisation Eq. (4.2)Using Eq. (4.1) whorled Buckling EffectUsing Eq. (4.3)Ballooning EffectUsing Eq. (4.4)Temperature EffectUsing Eq. (4.5)Total Tubing Movement(Tubing lengthens)FracturingHookes Law EffectAt bottom hole 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 hole 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)1.2 S election of Tubing MaterialTubing selection should be based on whether or not the tubing can withstand various forces which are caused due to the variations in temperature and pressure. The API has specified tubing based on the steel straddle. 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 loading conditions. There are three modes of tubing failure which include* reveal (pressure due to fluid inside tubing),* clangour (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 mend of depth vs pressure. This design is carried out by calculating pressures inside the tubing and casing-tubing annulus at the bottom hole and tubing soul. The maximum differential pressures at surface and bottom hole are examined using the plot. This maximum condition usually occurs during stimulation. When the maximum allowable annular pressure is maintained during stimulation, a broad amount of reduction in the tubing load can be achieved. The burst pressure load (difference between the pressure inside the tubing and annulus) is generally experienced in greater magnitude close to the surface but may not necessarily be always true. The burst load accounts are plotted followed by plotting divulge load lines. The collapse loads are calculated with an assumption that a slow leak at the bottom hole has depressurized the tubing. This scenario is sometimes expereinced after the fracturing treatment when operators commence kickoff before bleeding off the annular pressure.If the data for pressure testing conditions (usually most critical load) is available, it should be included in the plot.Along with the collapse and burst loads, the burst and collapse resistance for different tub ing 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 graphic tubing designBased on the data given below, select a tubing string that will satisfy burst, collapse and tension with rubber eraser factors of 1.1, 1.0 and 1.8 respectively.Planning DataD =9000 ft true depth,f = 2.875 inches, tubing OD,CIBHP = 6280psi, closed-in bottom hole pressure,FBP = 12550psi, formation breakdown pressure,FPP = 9100psi, shot propagation pressure,Gpf = 0.4 psi / ft packer fluid gradient,Gf = .48 psi /ft fracturing fluid gradient,g = 0.75 gas gravity at reservoir,Pann = 1000 psi, maximum allowable annulus pressure,SFB =1.1, safety Factor, rupture Condition,SFC =1.0, safety Factor, Collapse Condition,SFT =1.8, safety Factor, Tensile Load, die and Collapse rating 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.Solution grade 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 gas gravity,At a gas gravity = 0.8 and profoundness 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 balance of surface pressure and BHP in gas wells for a range of gas gravities.Depth of HoleGas Gravity(ft)(m)0.600.650.700.8010003050.9790.9780.9760.97320006100.9590.9560.9530.94630009150.9390.9350.930.92400012190.920.9140.9070.895500015240.9010.8930.8850.87600018300.8830.8730.8540.847700021330.8640.8540.8440.823800024380.8470.8350.8230.801900027430.8290.8160.8040.7791000030480.8120.7980.7640.7581100033530.7950.780.7660.7371200036600.7790.7630.7470.7171300039620.7630.7460.7290.6971400042670.7470.7290.7120.6781500045720.7320.7130.6950.65916000 48760.7170.6970.670.6411700051810.7020.6820.6520.6241800054860.6870.6560.6450.6071900057910.6730.6520.6310.592000060970.6590.6370.6150.574Step 2 Calculate the pertinent pressures for different operating conditions.a) Pressures inside casing-tubing annulusAssuming during the production and killing 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 * 628 0 = 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 hydrostatic 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 experience some pressure drop due to friction. Based on the pumping rates 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 conditionsshaping the burst loads Burst Load pressure = pressure inside tubing pressure in the casing- tubing annulusBurst Load at tubing head for producing conditionsBL _surface_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 ki lling 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 order to plot critical collapse load conditions (CLL) normally, 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 secret plan the Load lines.Plot the burs t 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.Then 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 eightfold grades on tubing which are guided by the estimated loading conditions.Estimation of Tensile LoadMost of the tubing failures are caused due to coupling effluence and failure. The failure of coupling can be attributed to inadequate design for tension of the tubing.This load being one of the significant and causes most failures compar ed 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 ignore 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. 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 focus DesignTubing weight 7.2 lb/ftTubing length 12,500 ftPacker fluid 0.38 psi/ft = 54.72 lb/ft3Density of steel 490 lb/ft3Win_air = 7.2 x 12,500 = 90,000 lbWbuoyant = = 0.89 x 73,600 = 80,100 lbJoint SpecificationsJ55L80EUEHYD CSEUEHYD A95API joint strength (Klb)Design factor Design capacity (Klb)99.71.855.41001.855.6135.91.875.51501.883.3Tubi ng Tension Design Considerations1. Requires L80 tubing at surface2. Requires joint strength capability of HYD A95 or equivalentReview 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 tension, 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 aspire of 15,000 STB/D us ing 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 ComparisonJ-55C-75N-8015.517.017.017.020.04040491060706280883048105320725077408990300329423446524CheapestMost expensiveModerately expensiveREFERENCES1. Allen, TO and Roberts, AP, Well Completion Design- Production Operations-1, 3rd edition, 1989, pp 182-187.1. Hammerlindl, DT, Movement, Forces and assay Associated with Combination Tubing Strings Sealed 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.