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Drilling Engineering 1 Course (2nd Ed.)

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1. Hydraulic IntroductionA. Hydrostatic Pressure

a. Calculation for Incompressible Fluids

b. Calculation for Compressible Fluids

c. Buoyancy

B. Drillstring Designa. Length of Drill Collars; Neutral Point Calculation

1. Drillstring designA. Maximum Tensile Force

a. tapered drill pipe

B. Maximum Torque

C. Internal (Burst) and External (Collapse) Pressures

Design for Tensile Force, Torque, Burst, and CollapseOnce the length of the drill collars and the total

weight of the drillstring had been determined, we must check if

the drillstring will be able to resist the loadings it will be submitted during normal and special operations.

The drill pipe section may be composed by one or several types of drill pipes (diameter, linear weight, and steel grade). We must check for maximum tensile strength, maximum

torque, maximum burst, and collapse pressure. In addition, since these loadings very likely occur

simultaneously (for example, tension and torque), the conjoined strength must be determined.

Spring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 5

Design consideration

During normal operation, the maximum tensile force

occurs at the top of the drill pipe section during pick–ups. Since this point has

(normally) the smallest section area, it is also the point of maximum stress.

In addition to static load (the buoyed weight of the drillstring), inertial effects

(the force to accelerate the drillstring),

friction effects between

the drillstring and the borehole wall, and

viscous effects must be considered.

Also, in the event of stuck pipe, the drillstring must be able to support the overpull applied during pipe freeing operations.A stuck pipe is the situation

in which the force required to move, or the torque required to rotate the drillstring is larger that its strength.


safety factors, yield stress, minimum yield strength, tensile strengthDue to several

uncertainties involved in the calculation ofthe various loadings, relative large safety factors must be used. It is practice

to use 125% of the static load as the design parameter (25% of overpull.)

In addition, it is important to note that the API defines yield stress as the stress that will cause a

certain permanent (plastic) deformation.

Based on this, the minimum yield strength of a pipe is defined. The minimum yield

strength is the minimum axial tensile load that will cause the yield of the material.

Normally we want to avoid any plastic deformation of the drill pipes. Therefore, only a fraction

(normally 90%) of the minimum yield strength is allowed during drilling operations. This figure is called tensile strength of the pipe.


The margin of overpull

The margin of overpull (MOP) is defined as the excess of the tensile load capacity of the drillstring to

the normal tensile load for normal operations.

Knowing the MOP is important in case of stuck pipe.

In practice, the determined MOP must not be exceeded since the drillpipe would fail.

Typical values of MOP requirements for drillpipe selections are in the range from 50,000 to 100,000 lbf.


minimum yield strength

Calculate the minimum yield strength required for the drill pipe of the previous example.The drillstring buoyed weight is 291000 lbf

using nominal 5in, 19.5 lb/ft DP (actual 22.28 lb/ft)


minimum tensile strength, minimum yield stress

The drillstring buoyed weight is 291000 lbf, and 125% of this value (25% of overpull) is 1.25 x 291000 lbf = 363750 lbf. The minimum tensile strength required is

If a new 5 in, 19.5 lb/ft (nominal) is used, the minimum yield stress is:

Therefore, a X–95 grade pipe is required (Fy = 501087 lbf).


minimum yield strength

The minimum yield strength in the example is obtained from drill pipe tables,

or calculated from the pipe parameters:

where Ys is the yield strength of the material. For the example above we have:


minimum yield strength for premium pipes

This figure is for new pipe dimensions.

For premium pipes (every new pipe is re–classified

to premium in the first time it goes to operation), it should be considered that the wall thickness is reduced to 80% of the original wall thickness.

Normally, the worst scenario is used and, in this case, we assume that the thickness reduction occurred in the outside diameter (external wear).


minimum yield strength for premium pipes (Cont.)

Therefore, the new dimensions are: (ID = 4.276 in)

Therefore, for premium DP, the minimum yield strength is:

Note that if a premium DP is considered in the example, the X-95, a premium pipe can not be used in the operation.


tapered drill pipe section

Situations like the example suggest the use of tapered drill pipe section. In tapered drill pipe sections, the segment with

the lowest capacity is placed right above the drill collar section (or HWDP when used), and the maximum length for that pipe is calculated.

Then a higher capacity drill pipe is used and the maximum length for this drill pipe is calculated.

The process is repeated until the expected total length (the maximum depth for that drillstring) is reached.

For a multi diameter, multi weight, or multi grade drillstring, the topmost joint of each section must be checked for tension.


tapered drill pipe section

Calculate the drillstring for the previous example data using premium drill pipes of 5 in–19.5 lb/ft and

grades E-75, X-95, and G-105.

The drillstring buoyed weight is 291000 lbf

the length of drill collar with 147 lb/ft is 933 ft


Margin of overpull

This problem is simplified by the fact that the total weight of the drillstring is the same,

no matter the grade and length of the drillpipe.

Using 25% of the buoyed weight, the MOP isMOP = 25% × 291000 = 72750 lbf .

It is important to realize that any overpull applied to the top of the drillstring

will manifest in every element of the drillstring

(assuming that the stuck point is in the bit).


maximum tensile load

The minimum yield strength and maximum tensile load for 5 in–19.5 lbf/ft (actual 22.28 lbf/ft) drill pipes for the various grades, and using a maximum of 90% as operational limits are:

E-75:

X-95:

G-105:


length of drill pipes

Starting with E–75 (on top of the drill collars), the maximum length for this grade is

The maximum length is 933 + 4705 = 5638 ft, and the partial weight is


length of drill pipes (Cont.)

Continuing with the next grade (X–95):

The maximum length is 5638 + 3912 = 9550 ft, and the partial weight is 241978 + 3912 × 22.28 = 329137 lbf

Continuing with the next grade (G–105):

The maximum length is 9550 + 1956 = 11506 ft, enough to reach the depth of 10000 ft.


Notes

Note that if different DP diameters or different linear weights are used, the final weight of the drillstring is not known

before it has been designed,

and the MOP cannot be imposed directly (and an iterative process will be needed).

In this case, we can set the MOP absolutely, based,

for example in the worst scenario (heaviest DP) or using field experience.


Torque source

The torque applied to the drillstring is the reaction due to the bit action on the bottom of the borehole, and due to friction forces

between the drillstring elements and the borehole wall.

In vertical wells, most of the torque comes from the bottom hole assembly (bit, stabilizers, etc.).

For directional wells, the torque is distributed

along the borehole trajectory below the kick-off point (the point of the trajectory where the borehole leaves the vertical).

In any case, the torque accumulates and the point of higher torque is

always at the top of the drillstring.


torsional yield strength

The torsional yield strength of a pipe is:

Ty is the torsional yield strength,

J is the polar moment of inertia of the circular section, for circular pipes is:

r is the outside diameter of the section.

The coefficient 0.577 ≈1

3comes from the von Mises–Henckydistortion energy theory of failure of ductile materials, which determines

the shear yield strength based on the tensile yield strength.

For Ty in ft · lbf, the expression for the torsional yield strength is:


the torsional yield strength

Calculate the torsional yield strength for a new and for a premium 5 in–19.5 lbf/ft, grade E–75 drill pipe.


the torsional yield strength

New:

Premium:

Note that the calculation of the torsional yield strength for a premium DP uses the worst scenario for the wall thickness reduction.

The figures can be found in (API RP7G) Tables

Although these values represent the maximum torque allowed in the body of the drill pipe, the maximum should not exceed

the actual make–up torque of the connection.


New Drill Pipe Torsional and Tensile Data. (API RP7G)


Premium Drill Pipe Torsional and Tensile Data. (API RP7G)


internal pressure strength

The API criteria for internal pressure strength (burst resistance) assumes that drill pipes are thin–walled pipes.

Since API accepts pipes with a minimum of 87.5% of the nominal wall thickness, the formula for the internal

pressure for new pipes (and also for casing) is:

If thick–wall and von Misses–Hencky theories are used, the formula is:

Note that in this formula, the allowed wall reduction to 87.5% has not been considered.

Data for internal pressure strength for new and premium drill pipes are shown in API RP7G.


New Drill Pipe Collapse and Internal Pressure Data. (API RP7G)


Premium Drill Pipe Collapse and Internal Pressure Data. (API RP7G)


net external (collapse) pressure

In operations like drill stem testing, the drill pipe may be

subjected to external pressure higher than the internal pressure. The most critical point is

the lower end of the drill pipe section.

The net collapse pressure is determined by the depth of the fluid

inside the pipe, the depth of the lower end

of the drillstring section, and the density of the fluids

in the annular and inside the drill pipe.

The expression for the net external pressure is:

pext is the external net pressure,

D is the depth of the lower end of the drill pipe section,

d is the depth of the fluid surface inside the pipe (make d = D if d > D),

ρo and ρi are the densities of the fluid in the annular and inside the drill pipe.

A safety factor of 1.125 is normally used for collapse pressure.


the collapse resistance corrected for tension loadingCollapse pressure is

detrimentally affected by tensile force in the drill pipe

(the beneficial effect in burst resistance is neglected).

the combined effect of tensile load to collapse resistance is obtained using the biaxial (σr = 0) expression of the von Misses failure theory:

The equality holds when for a given axial stress σz, an effective tangential yield stress 𝑌𝑠′ occurs. Then we have:

Solving for the appropriate 𝑌𝑠′ (tangential stress is compressive for collapse) results in:


the collapse resistance

Determine the collapse resistance corrected for tension loading for a premium 5 in–19.5 lbf/ft,

grade E–75 drill pipe

subjected to a tensile load of 50,000 lbf.


the collapse resistance

The outside and inside diameters of the DP are 4.8552 in and 4.276 in respectively (premium DP). so:

and the axial stress is:

The ratio of the equivalent yield stress to the nominal yield stress is:

The minimum collapse resistance for the premium pipe is 7041 psi (from Table), and the corrected collapse pressure is 7041 × 0.9100 = 6407 psi


Drillstring Elongation

Due to the weight of the drillstring and the elastic characteristic of the steel (and many other metals and alloys), an elongation occurs when the drillstring is suspended inside the borehole.

In addition, if an additional force acts at the bottom end (be it tensile or compressive) additional elongation (or shortening) occurs.

The expression for the total elongation of a submerged drillstring of length L is:


1. Jorge H.B. Sampaio Jr. “Drilling Engineering Fundamentals.” Master of Petroleum Engineering. Curtin University of Technology, 2007. Chapter 5

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