BAKER HUGHES - Drilling Fluids Reference Manual

PRESSURE PREDICTION AND CONTROL
Pressure
Gradient in
Equivalent
Fluid Weight
(lb m /gal
9.0
9.5
10.0
10.5
11.0
11.5
12.0
12.5
13.0
13.5
14.0
14.5
15.0
15.5
16.0
16.5
17.0
17.5
18.0
U.S. GULF
COAST
Miocene-
Oligocene
to - tn
2.5
5.0
6.5
8.0
10.5
13.0
15.0
17.0
19.0
21.0
24.5
28.0
33.0
38.0
43.0
48.0
FRIO
FORMATION
S. Texas
Gulf Coast
to - tn
10.7
13.0
15.4
17.7
20.0
22.5
25.0
27.8
30.3
33.0
36.0
39.25
42.50
46.25
52.0
WILCOX
FORMATION
S. Texas
Gulf Coast
to - tn
9.2
11.6
14.0
16.4
8.8
21.3
23.8
26.4
29.0
31.8
34.5
37.5
40.5
44.5
48.5
WEST-
TEXAS
to - tn
4.0
6.0
8.0
10.0
12.0
15.5
19.0
22.0
25.0
28.0
32.0
36.0
40.0
45.0
50.0
54.5
59.0
63.0
67.0
NORTH
SEA
to - tn
2.0
7.0
9.5
13.3
17.0
21.0
25.0
29.5
34.0
41.0
48.0
51.0
54.0
57.0
NOTE: Plot observed shale travel time on 3-cycle semi-log paper.
Table 12 - 2 Predicted Pressure Gradient vs. Sonic Log Departure (At Observed-
At Normal)
Example
SOUTH
CHINA SEA
to - tn
3.0
7.0
11.0
15.0
19.0
22.5
26.0
29.0
32.0
34.5
37.0
39.5
42.0
Figure 12-6 indicates a departure from extrapolated normal travel time of approximately 35
sec/ft at 13,000 feet. Utilizing the Miocene-Oligocene column of Table 12-2, a pore pressure
equivalent to 15.8 lb m /gal drilling fluid density is predicted.
As mentioned, abrupt changes in salinity of pore water in shales can lead to erroneous pressure
prediction when using resistivity or conductivity logs. Other variables which may affect logs
are noted in Table 12-3.
Some suggestions for selecting the shale data points to be used in formation pressure prediction
are:
• Select clean shales in intervals of low spontaneous potential (SP) deflection and uniform
conductivity or sonic readings.
• Shales selected for data points should be at least 20 feet thick with points obtained from the
center of section, if possible.
• The most reliable shale readings are usually the higher conductivity values midway between sand
intervals.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 12-9