ARPO ENI S.p.A. Agip Division 4.8. 4.8.1.
DESIGN CRITERIA Burst
IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 36 OF 230 REVISION 0 Burst loading on the casing is induced when internal pressure exceeds external pressure. To evaluate the burst loading, surface and bottomhole casing burst resistance must first be established according to the company procedure outlined below.
Internal Pressure Surface Casing The wellhead burst pressure limit is arbitrary, and is generally set equal to that of the working pressure rating of the wellhead and BOP equipment 2 but with a minimum of 140kg/cm . See ?BOP selection criteria? in section 9.1. With a subsea wellhead, the wellhead burst pressure limit is taken as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to surface but in any case not less than 2,000psi (140atm). Consideration should be given to the pressure rating of the wellhead and BOP equipment which must always be equal to, or higher than, the pressure rating of the pipe. When an oversize BOP having a capacity greater than that necessary is selected, the wellhead burst pressure limit will be 60% of the calculated surface pressure obtained as difference between the fracture pressure at the casing shoe with a gas column to surface. Methane gas (CH4) with 3 density of 0.3kg/dm is normally used for this calculation. In any case it shall never be considered less than 2,000psi (140atm). The use of methane for this calculation is the ?worst case? when the specific gravity of gas is unknown, as the specific gravities of any gases which may be encountered will usually be greater than that of methane. The bottomhole burst pressure limit is set equal to the predicted fracture gradient of the formation below the casing shoe. Connect the wellhead and bottomhole burst pressure limits with a straight line to obtain the maximum internal burst load verses depth. When taking a gas kick, the pressure from bottom-hole to surface will assume different profiles according to the position of influx into the wellbore. The plotted pressure versus depth will produce a curve. External Pressure In wells with surface wellheads, the external pressure is assumed to be equal to the hydrostatic pressure of a column of drilling mud. In wells with subsea wellheads: At the wellhead - Water Depth x Seawater Density x 0.1 (if atm) At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm) Net Pressure The resultant load, or net pressure, will be obtained by subtracting, at each depth, the external from internal pressure.
ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 Intermediate Casing PAGE 37 OF 230 REVISION 0 Internal Pressure The wellhead burst pressure limit is taken as 60% of the calculated value obtained as difference between the fracture pressure at the casing shoe and the pressure of a gas column to wellhead. In subsea wellheads, the wellhead burst pressure limit is taken as 60% of the value obtained as the difference between the fracture pressure at the casing shoe and the pressure of a gas column to the wellhead minus the seawater pressure The bottom-hole burst pressure limit is equal to that of the predicted fracture gradient of the formation below the casing shoe. Connect the wellhead and bottom-hole burst pressure limits with a straight line to obtain the maximum internal burst pressure External Pressure The external collapse pressure is taken to be equal to that of the formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered. Net Burst Pressure The resultant burst pressure is obtained by subtracting the external from internal pressure versus depth.
ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 38 OF 230 REVISION 0 Production Casing The ?worst case? burst load condition on production casing occurs when a well is shut-in and there is a leak in the top of the tubing, or in the tubing hanger, and this pressure is applied to the top of the packer fluid (i.e. completion fluid) in the tubing-casing annulus. Internal Pressure The wellhead burst limit is obtained as the difference between the pore pressure of the reservoir fluid and the hydrostatic pressure produced by a colum of fluid which is usually gas (density = 3) 0.3kg/dm . Actual gas/oil gradients can be used if information on these are known and available. The bottom-hole pressure burst limit is obtained by adding the wellhead pressure burst limit to the annulus hydrostatic pressure exerted by the completion fluid. Generally the completion fluid density is, equal to or close to, the mud weight in which casing is installed. Note: It is usually assumed that the completion fluid and mud on the outside of the casing remains homogeneous and retain their original density values. However this is not actually the case particularly with heavy fluids but it is also assumed that the two fluids will degrade similarly under the same conditions of pressure and temperature. Connect the wellhead and bottom-hole burst pressure limits with a straight line to obtain the maximum internal burst pressure. Note: If it is foreseen of that stimulation or hydraulic fracturing operations may be necessary in future, therefore the fracture pressure at perforation depth and at the well head pressure minus the hydrostatic 2 head in the casing plus a safety margin of 70kg/cm (1,000psi) will be assumed. External Pressure The external pressure is taken to be equal to that of the formation pressure. With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should be considered. Net Burst Pressure The resultant burst pressure is obtained by subtracting the external from internal pressure at each depth.
ARPO IDENTIFICATION CODE PAGE 39 OF 230 ENI S.p.A. Agip Division REVISION STAP-P-1-M-6100 0 Intermediate Casing and Liner If a drilling liner is to be used in the drilling of a well, the casing above where the liner is suspended must withstand the burst pressure that may occur while drilling below the liner. The design of the intermediate casing string is, therefore, altered slightly. Since the fracture pressure and mud weight may be greater or lower below the liner shoe than casing shoe, these values must be used to design the intermediate casing string as well as the liner. When well testing or producing through a liner, the casing above the liner is part of the production string and must be designed according to this criteria Tie-Back String In a high pressure well, the intermediate casing string above a liner may be unable to withstand a tubing leak at surface pressures according to the production burst criteria. The solution to this problem is to run and tie-back a string of casing from the liner top to surface, isolating the intermediate casing.
4.8.2.
Collapse
Pipe collapse will occur if the external force on a pipe exceeds the combination of the internal force plus the collapse resistance.
The reduced collapse resistance under biaxial stress (tension/collapse) should be considered.
No allowance is given to increased collapse resistance due to cementing. Surface Casing For wells with a surface wellhead, the casing is assumed to be Internal Pressure completely empty. In offshore wells with subsea wellheads, the internal pressure assumes that the mud level drops due to a thief zone In wells with a surface wellhead, the external pressure is assumed to be equal to that of the hydrostatic pressure of a column of drilling mud. In offshore wells with a subsea wellhead, it is calculated: At the wellhead - Water Depth x Seawater Density x 0.1 (if atm). At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm). The resultant collapse pressure is obtained by subtracting the internal pressure from external pressure at each depth.
External Pressure Net Collapse Pressure
ARPO ENI S.p.A. Agip Division IDENTIFICATION CODE STAP-P-1-M-6100 PAGE 40 OF 230 REVISION 0 Internal Pressure Intermediate Casing The ?worst case? collapse loading occurs when a loss of circulation is encountered while drilling the next hole section with the maximum allowable mud weight. This would result in the mud level inside the casing dropping to an equilibrium level where the mud hydrostatic equals the pore pressure of the thief zone (Refer to Errore. L'origine riferimento non è stata trovata.). Consequently it will be assumed the casing is empty to the height (H) calculated as follows: (Hloss-H) x dm = Hloss x Gp H = Hloss (dm - Gp)/dm If Gp = 1.03 (kg/cm /10m) Then H = Hloss (dm-1.03)/dm Hloss = Depth at which circulation loss is expected (m) dm = Mud density expected at Hloss (kg/dm ) 2 2 2 Gp = Pore pressure of thief zone (kg/cm /10m) - usually Normally pressured with 1.03 as gradient. When thief zones cannot be confirmed, or otherwise, during the collapse design, as is the case in exploration wells, Eni-Agip division and associates suggests that on wells with surface wellheads, the casing is assumed to be half empty and the remaining part of the casing full of the heaviest mud planned to drill the next section below the shoe. In wells with subsea wellheads, the mud level inside the casing is assumed to drop to an equilibrium level where the mud hydrostatic pressure equals the pore pressure of the thief zone. External Pressure The pressure acting on the outside of casing is the pressure of mud in which casing is installed. The uniform external pressure exerted by salt on the casing or cement sheath through overburden pressure, should be given a value equal to the true vertical depth of the relative point. Net Collapse Pressure The effective collapse line is obtained by subtracting the internal pressure from external at each depth. Production Casing During the productive life of well, tubing leaks often occur. Also wells may be on artificial lift, or have plugged perforations or very low internal pressure values and, under these circumstances, the production casing string could be partially or completely empty. The ideal solution is to design for zero pressure inside the casing which provides full safety, nevertheless in particular well situations, the Drilling and Completions Manager may consider that the lowest casing internal pressure is the level of a column of the lightest density producible formation fluid. Internal Pressure