There are a number of ways to anticipate, detect and evaluate overpressured zones.
These range from qualitative indicators, which serve primarily as warning signs, to quantitative methods that we can use in selecting mud weights, designing casing strings, planning cement jobs and specifying completion requirements.
Pressure prediction involves the talents of geophysicists, geologists and engineers, and should be part of an integrated, team approach to well planning and operations.
Most prediction techniques are based on finding the relatively low bulk densities and high pore volumes characteristic of overpressured zones. They include:
seismic methods
well log analysis
mud logging
measurement-while-drilling (MWD)
drilling equations
Pressure transient tests, which are performed during the well testing and completion stages, can also provide valuable information for future drilling.
Geophysical predictions of abnormal pressure are based on reflection seismic principles, which in the simplest sense involve
generating acoustic energy at the surface
measuring the interval transit time for this energy to reflect back from a subsurface horizon
plotting this transit time as a function of depth
With other factors being equal, the velocity of sound through a subsurface horizon increases with increasing rock density (i.e., decreasing porosity). To put it another way, the interval transit time (which is the reciprocal of sonic velocity) decreases. In a normal pressure environment, where porosity decreases with depth, we should see a corresponding decrease in interval transit time ( Figure 1 , Normal pressure trend line for interval transit time, base on seismic data survey from US gulf coast).
Figure 1
It follows that in an overpressured formation, where porosities are abnormally high, we should see interval transit times that are above normal ( Figure 2 , Interval transit time plot indicating abnormal pressure trend, based on seismic data from south Texas Frio trend).
Figure 2
While this is a qualitative indication of abnormal pressure, we can arrive at quantitiative presure estimates by analyzing seismic data in more detail.
We can also obtain interval transit times from sonic logs. A major benefit of seismic techniques, however, is that they provide "pre-spud" data, which can be used during the early stages of well planning.
As with seismic interpretation, the objective of log analysis is to detect the high porosities characteristic of abnormally pressured formations. We can do this by obtaining electrical (resistivity/conductivity), sonic, density and other measurements from open-hole or cased-hole tools. With the exception of measurement-while-drilling (MWD) data, well logs are used for "post-measurement-while-drilling" evaluations.
Because water has lower electrical resistivity (i.e., higher conductivity) than rock matrix particles, an increase in the fluid-filled pore volume due to overpressuring should result in a resistivity decrease. Figure 3 (Generalized shale resistivity plot) illustrates this deviation from the normal, linear shale resistivity trend.
Figure 3
(Note that since the abnormal pressures originally developed in shale sections, only resistivities of clean shales are used in constructing resistivity plots. )
To estimate formation pressure from resistivity measurements, Hottman and Johnson (1965) recommend determining the ratio between observed and normal rock
resistivities. using an empirical correlation ( Figure 4 , Empirical correlation of reservoir fluid pressure gradients versus ratio of noremal to observed shale resistivities) and the following three-step procedure:
1.
Figure 4
Plot the shale resistivity versus depth on semi-log paper to establish a normal resistivity trend.
2. Note the depth at which the plotted points deviate from the established trend. This indicates the top of the overpressured zone.
3. Determine the pressure gradient at the depth of interest.
a. Extrapolate the trend line to determine the "normal" resistivity at that depth.
b. Calculate the ratio of the observed resistivity to the extrapolated resistivity.
c. Use Figure 4 to determine the formation pressure.
Example 1: Abnormal pressure prediction using resistivity data (from Adams, 1985):
Given the resistivity data in Table 1, below, determine:
(a) the top of the abnormal pressure zone
(b) the formation pressure at a depth of 11,600 ft
Resistivity, -m Depth, ft Resistivity, -m Depth, ft
0.54 4,000 0.80 10,400
0.64 4,600 0.76 10,700
0.60 5,600 0.58 10,900
0.70 6,000 0.45 11,000
0.76 6400 0.36 11,100
0.60 7,000 0.30 11,300
0.70 7,500 0.28 11,600
0.74 8,000 0.29 11,900
0.76 8,500 0.27 12,300
0.82 9,000 0.28 12,500
0.90 9,700 0.29 12,700
0.84 10,100 0.30 12,900
Solution:
These data are plotted in Figure 5 .
Figure 5
The deviation from the normal pressure trend occurs at about 9,700 ft. Extrapolated
"normal" resistivity at 11,600 ft. is 1.23 -m, while the observed resistivity is 0.28
-m. The ratio of these resistivities is (1.23/0.28) = 4.39. Hottman and Johnson's correlation ( Figure 4 ) gives a formation pressure corresponding to about 17.1 ppg EMW, or 10,314 psi.
Overlay plots, consisting of parallel lines that represent formation pressure in terms of mud weight, are available for resistivity or conductivity curves, as well as for sonic logs. ( Figure 6 , Shale resistivity overlay).
Figure 6
By shifting overlays horizontally, we can correlate normal resistivity or conductivity trends with normal pressure lines. We need to make sure that overlay scales are consistent with those of the plotted curves, that the curves are correlated with the depth marks and guide lines on the overlays, and that conductivity curves are not used with resistivity overlays (or vice-versa).
The Hottman and Johnson technique assumes that:
porosity is the only formation variable affecting pore pressure
temperature gradients are constant
resistivity measurements are made in water-filled shale
water salinity is constant
Where formation water salinities vary, we can apply techniques such as those developed by Foster and Whalen (1965).
We can also use sonic or density logs to plot normal versus observed trends and, in conjunction with empirical correlations, determine reservoir pressure. For a sonic log, the measured parameter is travel time in shale (tsh). In an abnormal pressure environment, tsh is greater than it would be in a normally pressured rock matrix (similar to the trend shown in Figure 1 and Figure 2 ).
Operators have for many years used drilled cuttings and mud returns to detect abnormal pressure. Their main drawback is that they provide information on a
"delayed" basis, because it takes time for the mud to travel from the bottom of the hole to the shale shaker. They nevertheless are useful pressure indicators because of the amount and variety of information they provide.
Mud logs can give the following indications of abnormal pressure:
Paleontology If offset well data indicate that certain fossils are characteristic of an overpressured formation, then the presence of these same fossils may indicate that we have encountered that formation.
Penetration Rate Increase ("drilling break") A steady increase in penetration rate could result from increasing porosity and a consequent lowering of differential pressure. Note, however, that there may be other reasons for higher drilling rates, such as lithology changes.
Cuttings size increase Increased cuttings sizes may mean that the wellbore differential pressure has decreased, and cuttings are not being held on bottom, where they experience grinding and re-grinding. If the mud weight has not changed, it is likely that the formation pressure is increasing.
Flowline temperature increase Because water does not conduct heat as effectively as clay, a water-filled pore space tends to be hotter than its surrounding rock matrix. Mud returns from an overpressured formation having abnormally high porosity should therefore be hotter than returns from a formation having normal porosity.
Mud gas analysis Three general classifications of mud gas are:
-- background gas the total gas concentration in the mud returns during drilling -- connection gas the increase in gas concentration due to the
swabbing action of the drill string when pulling up to make connections
-- trip gas the increased gas circulated out of the hole after tripping pipe.
Increased gas concentrations have commonly been interpreted as signs of abnormal pressure. There are, however, a number of other factors contributing to these increases, which compromise their reliability as pressure indicators. (Adams, 1980).
Mud resistivity and chloride content Changes in these parameters may serve as secondary indicators of increasing porosity and, therefore, abnormal pressure. For mud resistivity to serve as an indicator, the mud salinity must be measurably different from that of the formation fluid.
Shale density Normally, shale density should increase with increasing depth.
By measuring the bulk density of the drilled cuttings, the mud logger can detect deviations from this trend.
These tools, once at the frontiers of technology, have become integral to many drilling operations.
They offer the advantage of real time (i.e., instantaneously transmitted) data, including resistivity and formation conductivity, lithology (from gamma ray measurements), annular temperature, and other abnormal pressure indicators.
Defining the relationship between penetration rate and various rig parameters (e.g., weight-on-bit, rotary speed, mud properties) is a basic goal of drilling research. The models and correlations developed for this purpose are mainly empirical, and range from "rule-of-thumb" field calculations to sophisticated computer simulations.
Perhaps the most well-known drilling model used in the industry is the dc exponent, developed from Bingham's drilling rate equation (Bingham, 1965):
(1)
where = penetration rate, ft/hour
a = formation drillability constant (dimensionless) W = weight-on-bit, 1000 lbf
dB = bit diameter, inches
b = bit weight exponent (dimensionless) N = rotary speed, revolutions/minute (RPM)
Jordan and Shirley (1966) simplified and modified this relationship, assigning a value of "1" to the formation drillability constant and replacing Bingham's bit weight constant with a d-exponent:
(2)
Assuming constant mud weights and normally-pressured formations, a plot of d versus depth typically shows increasing d-exponent values with increasing depth . In abnormally pressured formations, d should increase at a slower rate, or even begin to decrease, with depth.
Rehm and McLendon (1971) took into account the effect of increasing mud weight by modifying the d-exponent:
(3)
where EMWn = Equivalent mud weight of normally pressured formation.
We may plot dcexponents as a function of depth on semi-log paper, and then use overlays to determine formation pressures ( Figure 7 , Typical dc-exponent plot).
Figure 7