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Calculating Overburden
Pressure
Integrating
the density log versus depth or estimating the average rock density
profile and integrating will calculate this pressure: WHERE:
Overburden
pressure gradient is: A
literature search will turn up some relationships for (PO/D) for
specific areas, such as this one for the North Sea: In
this equation, depth is in meters.
For a real rock sequence, these values may be integrated over each lithologic interval, or can be used to replace density log data over bad hole or missing log intervals. If the density log is in porosity units, use the appropriate transforms to build a density log. The log below shows the type of editing that might be needed on a density log before integration.
Calculating Normal Pore Pressure Formation
pore pressure gradient is: WHERE:
NOTE: All depths must be true vertical depths. Formation pore pressure (Pp) is the pore pressure used fracture pressure equations. The best source of pore pressure data is the drill stem test (DST) or repeat formation tester (RFT) extrapolated formation pressures from many zones in many wells, plotted versus depth. Commercial databases containing this information are available, or the data can be tabulated from well history files. The slope (Pp/D) of a series of best fit straight lines drawn through the data points will provide the pressure gradient required. The hydrocarbon content will give lower gradients: oil gives a Pp/D between 0.30 and 0.43 psi/ft (6.78 to 9.81 KPa/m). Gas zones will have gradients from 0.05 to 0.30 psi/ft (2.26 to 6.78 KPa/m). Partially depleted reservoirs may have abnormally low pore pressure if there is no active aquifer, water injection, or gas injection to support the reservoir pressure.
Some engineering problems require the initial formation pressure, before any production has occurred. The pore pressure needed for fracture pressure calculations is the current pore pressure at the time the frac is to be performed. Since reservoir pressure depends on the past history of production from all wells in the pool, local pressure anomalies may be present. The best pressure to use is the actual, measured, extrapolated shut in pressure for the zone and well to be fractured. If no measured formation pressures exist, the mud weight hydrostatic pressure can be taken as the upper limit for the pore pressure. A lower limit would be the mud weight during a gas kick.
Calculating Abnormal Pore Pressure Some gas sands are naturally underpressured due to burial at depth with subsequent formation expansion after surface erosion. There is also some suspicion that glaciation may have pressured then relaxed these zones. Measured pressures are the only source of pressure data for such zones. Where overpressure data is sparse, a log analysis technique is sometimes helpful. It relies on fitting lines to semilog plots of sonic travel time in shale versus depth. First,
we need to run a simplified log analysis, just to see where the
shales are: You can substitute a more sophisticated log analysis model if desired. It is used for displaying shale, porosity, and lithology on the depth plot to aid in choosing the normal shale trend line on the sonic log. Find
DTCsh points for the depth plot: Fit
a best fit or eyeball line to the DTCsh data points (ignoring
all zero or null data) above the overpressure zone  this is the
normal pressure trend line: DTCsh0 is the DTCnorm at zero depth and DTCsh1 is the DTCnorm at DEPTH1 on the best fit trend line. DTCdiff is only needed for the depth plot of results. Calculate
overburden pressure gradient from an area specific transform or
by integrating the density log: NOTE: All depths must be true vertical depths. Calculate
pore pressure gradient: This equation is very sensitive to the choice of the normal trend line. The exponent 3 in the equation may also need adjustment.
CONVERting Pressure TO A
"HEAD OF WATER" To
convert DST or RFT data to a head of water, rearrange equation
16 to read: The Pp values from log analysis can be compared to DST or RFT pressures and adjustments made to the best fit lines if needed. There is no good reason to believe that the pressure in a reservoir will be equal to the pressure in the shale above it. However, if a calculated Pp in a shale is less than a measured Pp in a deeper reservoir, then we would expect the formation to leak hydrocarbons or water upward into shallower formations, or even to the surface. To
convert DST or RFT data to a head of water, rearrange equation
10 to read:
EXAMPLE OF
OVERPRESSURE LOG ANALYSIS

