Nathan Stein
Sans Co.
Boston
A new set of equations helps estimate formation fluid pressures and minimum fracture pressures in liquid-filled, overpressured, soft rock areas before any wells are drilled in the area.
The calculation method uses reflection seismic data to make the estimates which should be helpful for the initial design of mud weight and casing programs.
These equations are suited for soft rock areas containing layers of shale and friable sands, such as those in the Gulf Coast or offshore West Africa.
Standard seismic interpretation procedures are used to obtain the data. The equations assume that the stronger reflection signals occur where sand bodies exist and are based on the mechanical behavior of uncemented sand.
The equations are part of another theory to estimate the porosity of water-bearing sands. 1 After the theory was reported, the author was provided with data to determine the accuracy of porosity estimates when applied to known water-bearing sands in the Gulf Coast area, and this additional information helped determine the calculation method.
Reflection seismic data were analyzed according to techniques described by Waters.2 The values of acoustical wave velocities were related to depths. One or more different velocity values were reported at specific depths; however, multiple velocity values tended to cluster when the signal-to-noise ratios were 3. The inverse of each average value of clustered velocities was used in the calculations.
Three values are required for each calculation set: The average compressional acoustic wave velocity where the signal-to-noise ratio is 3, the depth corresponding to the reflection, and sea depth.
DYNAMIC FORMATION PROPERTIES
It was assumed that the stronger signals reflected the properties of the solid grains in sands rather than the compressible structures of grains in shales. If this were true, there should be a linear relationship between effective vertical stress and the dynamic combined modulus at each signal depth .3 Modulus values for friable sands can be calculated from Equation 1.
For uncemented sand, 2.06 g/cc is a reasonable value for the bulk density, p. The compressional acoustic wave travel time, At, is the inverse of velocity.
With the assumption that the values represent liquid-filled sands, the modulus relation with vertical stress as derived from the seismic data is a linear relationship (Equation 2). This equation is almost the same relationship as that found by Stein for liquid-filled friable sands in a different location. 3
In Equation 2, u is the overburden pressure minus the fluid pressure. It is assumed that the effects of other stresses, such as tectonic stresses, are negligible.
Equation 3 provides a practical value for overburden pressure.
There was no direct proof that the strong reflection signals were caused by the presence of sand bodies. However, two observations lend confidence to the use of strong seismic reflections as measures of sand properties:
- Sand bodies were identified from values of logs run in a well drilled at the location of the seismic data. Sands were found at the approximate depths corresponding to depths for strong reflections.
- Mud pressures while the well was logged were between the estimated values of formation fluid pressure and the minimum possible fracture pressure. A plot of these pressures indicates mud weights used during well logging were correct (Fig. 1). Such plots equate to the well bore stability during logging.
These observations provided confidence in the porosity research. The second observation shows promise for a means to estimate formation fluid pressures and minimum fracture pressures of liquid-filled formations in any new soft rock area.
PRESSURE CALCULATIONS
The formation fluid pressures may be estimated from Equation 4. Seismic data at the test well location were used in Equation 4 to determine the formation fluid pressure plot in Fig. 1. The mud pressure should be kept above this value to help control fluid influx.
The minimum possible fracture pressure corresponds to the vertical fracture of an uncemented sand. Higher fracture pressures would be expected for shale formations, cemented sands, or horizontal fractures. The mud pressure should be kept below the minimum possible fracture pressure.
The vertical fracture pressures of uncemented sands can be estimated from Equation 5.4 These values for the test well location are also plotted in Fig. 1.
In this equation, u, Poisson's ratio, is 0.3 for uncemented sand.
The mud pressure values plotted in Fig. 1 were calculated from Equation 6.
This method for using reflection seismic data to help design casing and mud weight programs based on predicted formation pressures has potential for applications in overpressured soft rock areas made up of friable sands and shales.
ACKNOWLEDGMENT
The author thanks Exxon Co. U.S.A., Corpus Christi Oil & Gas Co., and the Weston Observatory in Boston College's Department of Geology and Geophysics for their assistance.
REFERENCES
- Stein, N., "Porosity of Friable Sand Using Acoustic Wave Velocity," presented at the Third International symposium on Borehole Geophysics for Minerals, Geotechnical and Ground Water Applications, Las Vegas, Oct. 2-5, 1989.
- Waters, K.H., Reflection Seismology, John Wiley & Sons Inc., 1981.
- Stein, N., "Mechanical Properties of Friable Sands from Conventional Log Data," journal of Petroleum Technology, July 1976.
- Stein, N., "How to Calculate Fracture Pressures from Well Logs," Petroleum Engineer International, August 1988.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
