A plot of depth vs shale acoustic travel time is effective for monitoring abnormal formation fluid pressure in clastic marine basins. However, factors such as subtle lithological variations, drilling-induced shale alterations, and acoustic-log error can prove to be red herrings. The best way to check the validity of pressure measurements is to refer to other logs and auxiliary drilling data. Introduction Since about 1965, the petroleum industry has developed and used several wireline logging interpretative techniques to monitor fluid pore pressures in subterranean formations. Most of these techniques have been particularly successful in clastic, Tertiary basins where the sediments are marine in origin and where the pore pressures are dependent on the degree of sediment compaction. Good examples of this type of environment would be the U. S. Gulf Coast and the South China Sea. Perhaps the most popular pressure monitoring technique is the use of the acoustic-log shale pressure plot. 2 As the name implies, this technique is simply plot. 2 As the name implies, this technique is simply a depth vs shale acoustic transit time display that when constructed on semilogarithmic paper shows a straight-line trend over the "normally" compacted section. Since pore pressures are dependent on compaction, this straight-line segment also represents the normally" pressured section. Fig. 1 is a U. S. Gulf Coast example of an acoustic-log shale pressure plot for an abnormally pressured well. The top of the overpressure corresponds to the departure from the normal trend to higher transit times at about 7,500 ft. These higher transit times (i.e., slower velocities) are indicating that the shales have not been allowed to compact properly because the contained fluids could not escape with increasing overburden loading. This concept can be used to calculate pore pressures at any desired depth. For example, let us pressures at any desired depth. For example, let us calculate the pore pressure at 10,000 ft in Fig. 1. The pore pressure should be equal to the overburden pore pressure should be equal to the overburden pressure at 10,000 ft less the shale matrix stress at pressure at 10,000 ft less the shale matrix stress at 10,000 ft. Since the 10,000-ft shale has the same transit time as the shale at 3,000 ft, we should expect the matrix stresses to be the same. Therefore, if we know the overburden gradient and hydrostatic gradient for an area, we can determine the matrix stress at any depth in the normally compacted section. For the Gulf Coast, the overburden gradient at 3,000 ft is 0.88 psi/ft and the normal hydrostatic gradient is 0.465 psi/ft. So at 3,000 ft, the matrix stress is (0.88 - 0.465)×3,000 = 1,245 psi. The pore pressure at 10,000 ft then is (0.95)×10,000 - 1,245 = pressure at 10,000 ft then is (0.95)×10,000 - 1,245 = 8,255 psi. Note that the overburden gradient at 10,000 ft is now 0.95 psi/ft. The foregoing is referred to as the "equivalent depth" method. Another method of calculating pore pressure, which was first described by Hottman and Johnson in 1965, is simply to relate the difference in observed transit time and the normal transit time at that depth to a calibration curve like Fig. 2, which was established from actual pressure data. Let us now rework the same Gulf Coast example as before (Fig. 1). At 10,000 ft, we can see about 28 mu sec/ft difference between the observed and normal transit times. This difference would correspond to a pressure gradient of 0.87 psi/ft, or at 10,000 ft, to a pore pressure of 8,700 psi. pressure of 8,700 psi. So from the Hottman and Johnson technique we calculated 445 psi more pressure than from the "equivalent depth" technique previously described. JPT P. 1039
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Feb 1, 2016
Sergey M Martemyanov + 3
Open Access