Page 135 - Practical Well Planning and Drilling Manual

Section 1 revised 11/00/bc 1/17/01 2:56 PM Page 111

Directional Design [ ]
1.5.2

ed wellbore” in Section 1.4.13, Calculating Axial Loads.) This tension
will pull the drillpipe into the inside of the curve and force the drillpipe
against the casing. Of course, you will be tripping and rotating while
operations continue, which will cause wear on the casing. The higher
the dogleg severity, the more the sideforce generated and the greater
the wear.
Tool joint damage. This sideforce also imposes a lateral loading
on the tool joints that can cause damage; Lubinski suggested a limit
of 2000 lbs lateral force to avoid damage to the tool joints. The dog-
leg severity for a given lateral force and drillstring tension can be
calculated by:
108,000 F
c = —————
pLT

where c is dogleg severity in ˚/100 ft, F is the lateral force, L is half
the length of a joint of drillpipe in inches and T is the drillstring ten-
sion at the depth of interest. Using a maximum lateral force of 2000 lbs
as suggested by Lubinski and assuming 31 ft joints of drillpipe, the DLS
causing this lateral force would be (108,000 x 2000) ÷ (3.142 x 186 x
180,000) = 2.05˚/100 ft. From this, it can be seen that our initial
assumption about the desirable dogleg severity is ambitious and is like-
ly to cause tool joint damage. We can also calculate the lateral force for
the initially planned dogleg severity by turning the above equation
round, so that:

p x L x T x c
F = —————------
108,000

and for a DLS of 3˚, the lateral force F would be 2922 lbs.

In examining these limiting factors, a practical point must also be
made. We run directional surveys while drilling, but these surveys
inevitably give an average dogleg severity over the interval between
survey points. The most common method of calculating the wellpath

111