Page 392 - Air and Gas Drilling Manual

Chapter 8: Air, Gas, and Unstable Foam Drilling 8-75
pump and the air compressors are alternately allowed to force packages of water slugs
or compressed air into the top of the drill string. After a series of slugs have been
injected into the top of the drill string and these slugs have passed into the annulus,
the well water column in the annulus will begin to be lifted (or unloaded) to the
surface. To create these slugs, it is necessary for operational personnel at the drilling
location to rapidly turn on and off the mud pump and compressors in a sequence that
will produce slugs of water and air inside the drill string. Thus, this procedure
creates high transient pressures in the mud pump, compressors, and surface line
piping to the drill rig. These transient pressures are not generally predictable and,
therefore, pose a safety hazard to personnel and equipment. Therefore, this procedure
is not recommended for use.
8.7 Field Comparisons
The following case histories of vertical drilling operations demonstrate the
accuracy of the planning calculation procedures discussed earlier that utilize complete
major and minor friction loss terms [23].
Case History No. 1 This was a sidetrack re-drill of an existing 17,000 ft deep gas
well in West Texas (Ellenberger formation). The casing and openhole profile for this
well was 9 5/8 inch casing from surface to 8,900 ft, 7 5/8 inch liner from 8,900 ft to
12,000 ft, 5 1/2 inch liner from 12,000 ft to 15,900 ft, and a 4 1/2 inch openhole
from 15,900 ft to 17,000 ft TD. The drill string profile (while drilling at 17,000 ft)
for this well was 4 1/2 inch drill pipe from surface to 7,900 ft, 3 1/2 inch drill pipe
from 7,900 ft to 10,500 ft, and 2 7/8 inch drill pipe from 10,500 ft to 17,000 ft.
The drilling gas was inert atmospheric air (specific gravity of approximately 0.95)
with a volumetric flow rate to the well of approximately 2,300 scfm (surface
elevation location of approximately 3,300 ft). No water and additives were being
injected. The predicted surface injection pressure was 1,245 psig and the actual
injected pressure was approximately 1,000 to 1,300 psig. The predicted bottomhole
pressure was 576 psig.
Case History No. 2 This was another sidetrack re-drill of an existing West Texas
gas well (Ellenberger formation). The well was drilled to 14,900 ft. The casing and
openhole profile for this well was 5 1/2 inch casing set from surface to 13,200 ft,
and a 4 1/2 inch openhole from 13,200 ft to 14,900 ft TD. The drill string profile
(while drilling at 14,900 ft) for this well was 2 3/8 inch drilling tubing from surface
to 14,480 ft, 2 3/8 inch drill pipe from 14,480 ft to 14,600 ft, and 3 1/8 inch drill
collars from 14,600 ft to 14,900 ft. The circulation fluid was natural gas with a
specific gravity of 0.86. The natural gas volumetric flow rate to the well was
approximately 1,400 acfm (at a surface elevation location of approximately 3,300 ft
atmospheric temperature approximately 60˚F). No water and additives were being
injected. The predicted surface injection pressure was 659 psig and the actual
injected pressure was approximately 700 psig. The predicted bottomhole pressure
was 218 psig.
The above two case histories show clearly the reduction in bottomhole pressures
that can be attained when a slim drill sting is used to drill deep boreholes with small
casing and openhole profiles. This reduction in bottomhole pressure is a very
important issue when drilling into low pore pressure mature gas or oil fields. Air or