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Handbook on Static Pressures*
By
D. E. Powley1
Search and Discovery Article #60007 (2006)
Posted May 1, 2006
*Amoco Production Company Research Department Report F87-G-19, August 3, 1987
1Amoco Production Company, retired, Tulsa, Oklahoma 74136
Introduction
This report was prepared to fulfill the dual objectives of (1) being used as Section 15 in the Amoco training manual “Advanced Formation Evaluation” currently undergoing extensive revisions, and (2) being a report of part of the investigation conducted pursuant to Geological Research Proposal 86-7 “Develop Methods for Estimating Volumes of Sand Bodies and Heights of Hydrocarbon Columns within Overpressured Fluid Compartments.” The format of the report follows the requirements of the Amoco Training Center in Houston. The succession of topics progresses from basic to complex to allow for terminations of training courses anywhere within the text. The report should provide office engineers and operations geologists who are inexperienced in the use of subsurface fluid pressures with a jump-start into semiprofessional level interpretations of static; i.e., nontransient, pressures data. This report will be followed by a companion report which will deal with techniques used mainly by specialists in the interpretation of regional static pressures.
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uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
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Fluid Pressures - General
TextPressure is the force per unit area which fluids (liquids and gases) exert on the surface of any solid which they contact. Pressure exists at every point in a fluid at rest. The magnitude of the pressure is proportional to the depth below the surface and to the density of the fluid; i.e., the pressure is the same at all points at the same level within a uniform density fluid (Figure 15-1) if the fluid is static; i.e., not in motion. The pressure in a fluid at rest is independent of the shape of the containing vessel and is the same whether the vessel contains a fluid only or contains a fluid and a quantity of solids in grain-to-grain contact; i.e., not a suspension. Thus, in the earth, the pressure in a static subsurface fluid is independent of the shape and size of the rock pores but is dependent upon the density of the fluid and upon the depth below its surface (Figure 15-2). In the earth, the datum water surface usually cannot be seen. However, pressure calculations commonly indicate that the rock pores are fluid-filled and interconnected from the top of the free water in the soil down to at least intermediate depths. Inasmuch as the soil water surface is usually only a few inches to a few feet below the topographic surface, it has become common practice to consider the free water surface and the topographic surface to be the same. In marine areas, the free water surface is considered to be mean sea level. The hydrostatic pressure is that caused by the weight of a freestanding fluid column without any external pressure being applied. If any external pressure is applied to any confined static fluid, the pressure at every point within the fluid is increased by the amount of the external pressure. This statement is known as Pascal's Principle, after the French philosopher who first clearly expressed it. An example of a confined static fluid is the fluid below a piston in a closed cylinder. The pressure in the fluid increases as external pressure is applied and returns to normal when the pressure is removed. Within the confined static fluid, the rate of increase in pressure downward; i.e., the interval pressure gradient, is the same with or without an external pressure (Figure 15-3). In geology, the counterpart to the piston and cylinder walls of Figure 15-3 are any combination of rock layers, faults, and interfaces which completely enclose a body of fluid-bearing rock in a low-permeability envelope. The low-permeability envelope is usually referred to as a seal. A seal is usually thin with respect to both thickness and lateral extent of the enclosed rock body. An abnormally pressured rock body is like a huge bottle (Figure 15-4). It has a thin, essentially impermeable outer seal and an internal volume which exhibits effective internal hydraulic communication. The interval rate of increase in pressure with increasing depth within the internal volume is in direct accordance with the density of the internal fluids (Figure 15-5). The fluid pressures in the internal volume may be greater than, equal to, or less than the pressures in the fluids in the rocks outside of the seal. The magnitude of the internal fluid pressure is dependent on how much of the weight of the superincumbent rock column is borne by the fluids in the enclosed body and how much of the weight is borne by the rock matrix in the enclosed body. The fluid pressure below the top seal at the shallowest point in the enclosed rock body can range from zero, where the rock matrix bears all of the weight of the superincumbent rock, to about 1 psi/foot thickness of overlying rock if the enclosed rock matrix bears none of the weight of the superincumbent rock load (Figure 15-6). The
Keyes Field in northwestern Oklahoma is illustrative of the The
Carpathian Pressures which are less than can be attributed to a freestanding water column to the surface were termed underpressures during the discussion of the Keyes field. Likewise, pressures which are greater than can be attributed to a freestanding water column to the surface are termed overpressures. Underpressures and overpressures together compromise the well-known classification, abnormal pressures (Figure 15-9).
Geology of Abnormal PressuresFigures 15-10 to 15-12
TextIn most
deep basins in the world there is a layered arrangement of at least two
superimposed hydraulic systems (Figure 15-10).
The shallowest hydraulic system can extend to great depths; however, in
many basins it extends from the surface down to about 10,000 feet,
greatest historical depth of burial, in normal geothermal gradient
basins and to slightly greater depths in cool basins. There are a few
remarkable deviations, like the central North Sea The
deeper hydraulic systems usually are not basinwide in extent and exhibit
abnormal pressures. They generally consist of a layer of individual
fluid compartments which are sealed off from each other and from the
overlying system. In some basins, mainly in the onshore U.S., there is
an even deeper, near normally pressured, noncompartmented section (Figure
15-11). The compartmented layer in those basins generally is
in the sequence of rocks which were deposited during the period of most
rapid deposition. The underlying noncompartmented layer, where present,
usually is in pre-
Recognition of the layered arrangement of hydraulic systems generally is
quite easy. Only a few widely spaced, well-documented deep wells with
several tests run over perforated intervals or several pressure readings
from repeat formation testers in scattered wells generally are
sufficient to outline the overall arrangement of hydraulic systems in
each The
individual compartments in the compartmented layer may be very
extensive, as in some of the Rocky Mountains basins, or may be only a
few miles across, as in the Gulf Coast In
those basins with three layers of hydraulic systems, the seal between
the middle compartmented layer and the underlying noncompartmented layer
usually follows a single stratigraphic horizon. For instance, the basal
seal of the compartmented section in the central Powder River Planar
seals may occur within, as well as on the top of the compartmented
layer. For instance, the shallowest seal in the Mill Creek graben in
southern Oklahoma is everywhere within the thin Marmaton shale; the next
deeper seal is horizontal (-10,400 to -11,500 feet elevation), cuts
through many Paleozoic formations across the graben and even extends, at
the same elevation, across the adjacent Ardmore Earlier
in this chapter it was pointed out that the individual compartments in
the compartmented layer are like huge bottles with thin bounding seals
and huge fluid-communicating internal volumes. Seals are particularly
annoying to work with because they do not have consistent lithologic
properties other than extremely low across-the-seal permeability. In the
absence of unique lithologic properties, recognition must be
accomplished from indirect evidence, such as well log indicators,
measured pressures in local reservoirs encased in seal rock and often
only from the requirement that they must be there separating reservoirs
which, from measured pressure data, are obviously hydraulically
separated from each other. Seals may have thin internal permeable rock
layers (like bubbles in the glass of glass bottles), which may contain
In some areas, seals may be recognized by calcite and/or silica mineralization within the seals or in the lower pressured rocks exterior to the seals, probably resultant from dissolved minerals being precipitated as water seeps through the seals. The mineral infill of porosity and fractures may be so readily recognizable that it becomes an identifier of present or past seals. For instance, calcite infill is so ubiquitous within seals and in adjacent beds in southwestern Louisiana that it has been given the name “Al's Cap,” named for Al Boatman, a local geologist, who first publicly drew attention to the phenomenon there. Silica infill may be recognizable on the basis of drastically reduced rates of drilling penetration across a seal. For instance, it took 24 hours to cut a 60-foot core in a silica-enriched seal in chalk in the Shell-Esso 30/6-2 well in the North Sea. Chalk normally cores very rapidly, unless the bit becomes clogged. Top
seals in clastics dominated sections range in thickness from 150 feet to
over 3000 feet; however, the majority are uniformly near 600 feet. Seals
in carbonate-evaporite sections are generally somewhat thinner; in fact,
some salt and anhydrite beds as thin as 10 feet form effective seals. An
example of the latter is the Devonian Davidson evaporite which, except
for a small area in central Saskatchewan, is about 20 feet thick but
forms a regional seal over almost the entire extent of the Williston
Lateral
seals appear to be generally vertical or very nearly vertical. They
range in thickness from less than 1/8 of a mile (within the distance
between wells on 10 acre spacing) to about six miles, with the majority
being 1/8 of a mile or less in width. They tend to be quite straight,
which suggests that they may tend to follow fault trends. There has not
been any satisfactory suggested geochemical mechanism which could create
impermeable walls over thousands of feet of vertical extent through
rocks of many lithologies. Where wells have penetrated lateral seals,
the rocks have generally been found to be slightly fractured and the
fractures infilled with calcite and/or silica. In a few localities, some
of the fractures are locally open and can yield limited The
rocks in the internal volumes within the compartments, like the seals,
do not have a unique lithology. The most unique property is the
pervasiveness of fractures observed in cores and indirectly indicated by
the apparent hydraulic continuity; i.e., reservoir to reservoir
continuity of interval pressure-depth profiles, within the internal
volumes. A few authors, most notably Narr and Currie (1982), have
attempted to explain a genetic mechanism for the fractures; however,
none of the explanations to date have been particularly
convincing. The fractures in underpressured through slightly
overpressured Cretaceous and older rocks are generally nearly closed in
most basins; however, they are generally open enough to cause prominent
reductions in overall interval sonic velocities in overpressured rocks.
The fractures are open enough to take large quantities of whole drilling
mud if the mud columns in drilling wells are slightly overbalanced in
underpressured fluid compartments in the Hanna The
fractures in the internal volume are, in a few areas, open enough to
permit commercial-rate extraction of
Recognition and Indirect Quantification of Abnormal PressuresFigures 15-13 to 15-20, Table 15-1
Text
Overpressures have been known and studied in the Gulf Coast An
example calculation utilizing Figures 15-15,
15-16, 15-17,
and 15-18 should be made at this point to
ensure that the technique is understood. This example calculation is
somewhat misleading inasmuch as the accuracy obtained is better than
that which can be routinely derived from average quality well logs. The
importance of the foregoing well-log interpretation technique is that it
is possible to construct pressure-depth profiles for overpressured
sections without requiring downhole pressure measurements.Geologists and
engineers are now able to know more about the pressures in overpressured
rocks than they generally know about normally pressured or
underpressured rocks provided the shales have uniform characteristics.
The shales in the Gulf Coast A similar technique, also introduced by Hottman and Johnson (1965), involving interval sonic velocities derived from sonic logs has been used widely. The sonic log is fundamentally different than the resistivity log inasmuch as sonic velocities are affected by fluid pressures across the whole possible pressure/depth range; i.e., there is no onset value in sonic velocities. Therefore, in overpressured sections, the sonic log will start to respond at the first increase in pressure/depth ratio, but the electrical log will not respond until an onset value of 61 psi/l00 feet depth is encountered. Sonic logs have great utility in underpressured sections, but all underpressured sections have a pressure/depth value below the onset value for electrical logs, so electrical logs do not respond to underpressures. It has been the author's experience that sonic log data are excellent for picking the tops and bases of both overpressures and underpressures and tops and bottoms of fluid compartment seals but deriving actual pressure values is very uncertain because so many lithology effects and rock porosity effects are involved in the interval velocities in shales. In some Rocky Mountains and Alaska basins, sonic logs provide the only reliable log indicators of pressures because the lithology effects and water salinity effects tend to overwhelm resistivity logs. In west Texas, sonic logs are difficult to work with because it is hard to find a “valid” shale. Most shale travel time/depth plots as received from logging companies use a logarithmic Dt scale. Interpretations are feasible using logarithmic scales in low velocity shales; however, the logarithmic scale frequently is not as usable as a linear time scale in high velocity shales. Several authors have noted that high pressures are frequently accompanied by higher-than-normal geothermal gradient values. Interval geothermal gradients in overpressured rocks in which pressure/depth ratios are greater than 75 psi/l00 vertical feet of burial depth usually are about 1.4 to 1.5 times as great as the geothermal gradient values in rocks/of similar lithology in which the pressure/depth ratios are less than 75 psi/l00 vertical feet (Figure 15-19). Geothermal gradients are much more difficult to work with than electrical logs because there usually are only a few temperature measurements in each well. Despite the frustrations of basing interpretations on skimpy temperature data, pressure/depth graphs derived from a combination of electrical log data, sonic log data, and temperature data can be quite accurate in overpressured sections. Hottman
and Johnson (1965) contended that porosity in shale is abnormally high
relative to its depth if the fluid pressure is abnormally high. That
statement led to a flood of measurements of porosity and density of Gulf
Coast shales. In 1966 Rogers described how profiles of the density of
shales were then being used by some The
compaction-pressure technique continues to be applicable in southern
Texas where there is a high degree of Drilling rate is a function of weight on the bit, rotary speed (rpm), bit type and size, hydraulics, drilling fluid, pore pressures, rock stresses, and rock characteristics. Under controlled conditions of constant bit weight, rotary speed, bit type and hydraulics, the drilling penetration rate in shales decreases uniformly with depth in normally pressured formations. This is due mainly to progressive loss of porosity; i.e., compaction, in all rocks with depth. However, in overpressured formations the penetration rate generally increases because some of those intervals are not as well compacted, the rock in overpressured compartments may be fractured, and because the differential pressures between wall rock fluids and the mud column may be great enough to lead to rockbursts into the wellbore. Slower penetration rates have been observed in seals because the pores in seals are to some degree infilled with calcite or silica. Penetration rate should be plotted in 5 to 10 feet increments in slow-drilling formations or in 30 to 50 feet increments in fast-drilling intervals. However, plotting such data points should not lag more than twice the plotted depth increment behind the well drilling depth. Drilling rate recorders are available which automatically plot feet per hour vs depth. Regardless of how the rate of penetration is recorded, a normal drilling rate trend should be established while drilling shales in normal pressure environments for comparison with faster drilling overpressured shales. Complications can arise due to bit dulling, which may mask any penetration rate change due to overpressures. The penetration rate even may decrease if the rotary torque fluctuates and if the drilling bit action on the bottom of the borehole becomes erratic. Since it is not always possible and/or feasible to maintain bit weight and rotary speed constant, an improved method has been developed which allows plotting of a normalized penetration rate (d-exponent) vs depth. Normalized drilling rate correlations take into account the rotating speed of the bit, the mud weight, the weight on the bit, the bit size, and the actual penetration rate to detect the entrance into an abnormally pressured zone. These relationships are used to determine the weight of mud to hold the fluids in the abnormally pressured zones. The normalized drilling model is defined by:
Log R/(60 N) = Log K + b Log (12 W) /dB (1)
where: R = bit penetration rate, ft/hr
N = rotary speed, rpm
W = bit weight, M lbs
dB = bit diameter, inches
b = bit weight exponent = Log R/(60 NK) Log (12 W)/ dB
K = formation drillability constant
In 1966, Jorden and Shirley proposed simplifying the normalized drilling model to normalize penetration rate data for the effect of changes in weight on bit, rotary speed and bit diameter through the calculation of a “d-exponent” defined by:
d = Log R/(60 N) (2) Log (12 W)/ (1000 dB)
Equation (2) is not a rigorous solution for the “d-exponent” of Equation (1) in that: (1) the formation drillability constant, K, was assigned a value of unity, and (2) scaling constants were introduced. Jorden and Shirley (1966) felt that this simplification would be permissible in the Gulf Coast area for a single rock type since in this area there are “few significant variations in rock properties other than variations due to increased compaction with depth.” The “d” of Jorden and Shirley replaces the exponent “b” in the normalized drilling model. In 1971, Rehm and McClendon proposed modifying the “d-exponent” to correct for the effect of drilling fluid density changes as well as changes in weight on bit, bit diameter and rotary speed. After an empirical study, Rehm and McClendon computed a “modified d-exponent” using the following equation:
d = d Gpn / Gcd (3)
where: dc = “corrected or modified d-exponent”
d = “d-exponent” defined by Equation (2)
Gpn = normal pore pressure gradient for the area, expressed as equivalent drilling fluid density, lb/gal
Gcd = equivalent drilling fluid circulating density at the bit while drilling, lb/gal
Figure 15-20 is a plot of the calculated
modified “d-exponent” values vs depth. Also, overprinted on this plot is
a calibration overlay used to measure the abnormal pressure in terms of
equivalent mud weight (the straight lines on
Figure 15-20) in the Gulf Coast The overlay and “d” equation plot is probably the most accurate method available to on-site drilling engineers to use for the determination of bottomho1e pressure from drilling rates in regions with an abundance of soft shale. It is limited, however, to good data collection facilities and to consistently good drilling practices. Its effective use is also limited to wells which are drilled nearly in balance, particularly in soft shale formations. Artificially induced pore pressures from excess mud weight can be transmitted into the rocks being drilled, making most drilling responses, including drilling exponent, unreliable indicators of country rock pore pressures. The ability to correlate drilling rates with lithology and pore pressures to establish a standard for drilling rates is the key to accurate interpretations. The
reader should note that most of the techniques to indirectly quantify
pressures in underground reservoirs involve making observations or
measurements in adjacent water-shale. This is based on a commonly
accepted assumption that there is a close coupling of pressures from
reservoir rocks, particularly sandstones, to overlying and underlying
shales. The assumption has not been seriously challenged where both the
reservoir rock and the adjacent shale are water-filled; however, there
have been interpretation problems where the reservoir rock contains There are many indirect pressure indicators not discussed in this chapter. Table 15-1 lists most of those methods, several of which are specialized techniques applicable to on-site drilling engineers. The material discussed in this chapter is considered to be the minimum level of knowledge about indirect quantification of pressures required by exploitation geologists and office engineers dealing with records of wells drilled into abnormally pressured formations.
Direct Quantification of Pressures
Figures 15-21 to 15-24
TextNone of the foregoing indirect indicators of abnormal pressures or the pressures calculated from indirect indicators are as reliable as a few measured pressures. Until the mid-1970's, the only measured pressures available in overpressured soft rock sections in most wells were pressures measured during initial production tests run after the wells were drilled, cased, and perforated. Open hole drillstem tests have been routinely run in normally pressured and underpressured firm rock sections since 1935; however, the reported shut-in pressures tended to be unreliable because the mud (hydraulic) pressures in the wellbores usually exceeded formation fluid pressures with possible consequent distortions in measurements (supercharging) of shut-in formation fluid pressures prior to opening the tool. The more common problem was that a measurement of static pressure made after the test was completed was distorted by drawdown of pressures during testing (Figure 15-21). There is nothing basically wrong with drillstem test tools or gauges for pressure measurements; the shortcoming is that the usual purposes for using the tool do not include a serious attempt to measure the static pressure in the rock interval being investigated. The usual purposes for using the tool are to determine the type of formation fluid present, to indicate a short term production rate, to record sufficient transient (not static) pressures data to provide a basis for estimating average reservoir permeability within the radius of investigation, and lastly to indicate the extent of wellbore skin damage. Obtaining reliable static pressures can be added to the list if the operator is willing to pay for the extra rig time usually required for shut-in pressures to stabilize. Many of the pre-l975 recorded shut-in pressures are more reliable than data from later tests because early testing engineers generally had more wellsite authority. The commercialization of wireline repeatable formation testers in 1974 ushered in a whole new era in well control and well data interpretation. They can record an unlimited number of pressure measurements during a single trip into a wellbore. Two independent formation fluid samples can also be taken on the same trip. Those test tools are reliable, rugged, and very sensitive to minor differences in pressures. They withdraw such a tiny amount of fluid from the formation being tested that drawdown of pressures is not a problem. Pressures measured with repeat formation testers, like pressures measured with drillstem testers, are subject to distortion by supercharging of low permeability rocks by the pressures in the wellbore mud column. Figure 15-22 portrays the pressures measured with a wireline repeatable formation tester in a field in the North Sea. Note that the fluid compartments portrayed in Figures 15-23 and 15-24 have very small but consistent pressure differences from compartment to compartment. Neither production tests or drillstem tests could have provided pressure data of similar reliability. The only real limitations to the use of wireline repeatable formation testers are (1) that the tester works well only in soft formations, and (2) the tester run must be preceded by some porosity indicator log, such as an electrical log to select the depths at which pressures are to be measured. The pressure values from repeat formation tests should be corrected for temperature effects on the quartz gauges in the test tools. The corrections are supplied by the testing contractors. It is suggested that up to 30 pressure measurements be made in water-bearing porous zones over a depth interval of up to 300 feet above and below each zone of interest to establish a water base line if there is any indication that the zone of interest in a new well is either overpressured or underpressured. Usually, it is also prudent to make several pressure measurements within pay zones to provide data for estimations of drawdown and buildup permeability at precise depths.
Pressures Interpretations of Water in Open Hydraulic Systems
Figures 15-25 to 15-36
TextExploration geologists and well planning engineers have similar problems regarding locating, sorting, and assembling pressure data. Both are required to make interpretations regarding specific sites or specific areas using whatever data are available. Both groups work primarily with water dominated fluids systems. The ensuing discussion, while aimed mainly at well planning engineers, is equally applicable to exploration geologists. Engineers drawing up the operating specifications for wildcat wells are frequently faced with the necessity of anticipating static fluid pressures in underground formations in regions where industry practice has been to run only about one drillstem test somewhere in each well. At first glance, it may seem to be impossible to assemble enough data to do an adequate job of anticipating the pattern of pressures to be encountered by the planned well. Pressures measured in drillstem tests have been labeled “unreliable” earlier in this report; however, large files of unreliable drillstem test data may be used to identify overpressured and underpressured fluid compartments. Amoco's Well Data I and Well Data II computer files contain an enormous quantity of pressures data derived from drillstem tests. When such data from many wells are plotted onto pressure/depth charts, the overall patterns may yield very reliable indications of static pressures. Those patterns can indicate whether abnormal pressures should be anticipated, whether those abnormal pressures are overpressures or underpressures, and the approximate depths at which mud weight control likely will be required. Inasmuch as those data files contain both virgin pressures and pressures drawndown by production, it seems prudent to attempt to avoid being misled by local drawndown pressures. Figure 15-25 illustrates the recorded pressures measured at various times through the life of two fields. Note that the pressures at discovery (the highest pressures), are significant if a wildcat well is being planned and the lower pressures have no significance unless the planned well is to be drilled in, or adjacent to, the field. Figures 15-26, 15-27, 15-28, 15-29, 15-30, 15-31, and 15-32 illustrate the kinds of fluid compartment implications which can be derived from critical examination of large masses of pressure data, even though every data point may be somewhat unreliable. Pressure/depth or pressure/elevation profiles may be constructed on an area basis (Figures 15-25 through 15-30) or on a formation-by-formation basis (Figures 15-31 and 15-32). Duplication of the mud program used in nearby old wells may be sufficient to select an acceptable mud program in a new well; however, mud programs in a few old wells usually cannot be reliably converted into subsurface static pressures in abnormally pressured fluid compartments. Use of mud data from a few old wells is subject to considerable bias ranging from the operator's state of knowledge about pressures at the time the old wells were drilled to how safe-from-blowout the operators of the wells wished to drill their wells. Figure 15-33 illustrates how large files of mud density data from well log headers, converted to equivalent bottomhole pressures, plotted onto pressure/depth charts may be indicative of both the regional top of the top seal (the first kink in the data profile) and the base of the top seal (the second kink in the data profile) in overpressured fluid compartments. A hydrostatic interval pressure/depth gradient line drawn downward from the base of the top seal provides a reasonably reliable indicator of static fluid pressures in deeper rocks within the compartment. The use of large files of mud density data reduces the biases inherent in using mud data from single wells. Some operators drill wells with slightly underbalanced mud columns to attain increased drilling penetration rates. Drilling kicks in such wells may provide accurate indicators of the formation fluids pressure/depth ratios at the depths at which the kicks were experienced. Figure 15-34 shows a well in which the data from only two drilling kicks could have led to a reasonably accurate interpretation of the pressures in two superimposed fluid compartments, providing the interpreter kept in mind that the pressure/depth ratio of the fluids in fluid compartments, like mud in wellbores, cannot exceed the local fracture gradient. The
foregoing discussions regarding the use of inaccurate data presumed that
the inadequacies are resident in the original data. However, there can
be a large error factor introduced by human carelessness all along the
line from recording of wellsite data to data introduction into computer
files. Transposed numbers; i.e., numbers copied out of sequence, are an
ever present menace when making interpretations of subsurface pressures.
Figure 15-35 illustrates a typical Some data sources are much more reliable than others. The author has found the data submitted in sworn-to submissions of data in public hearings before the various state and provincial industry regulatory bodies to be a consistently reliable source of data and highly recommends its use where applicable. Figure 15-36 is an example of the data derived from submissions to the Oklahoma Corporation Commission. Note that the data exhibits little scatter, so the inclusion of transposed numbers or guesses instead of real measurements seems to be unlikely.
Pressures Interpretations of Petroleum in Open Hydraulic Systems
Figures 15-37 to 15-68
TextAll
prior discussions in this report dealt with water dominated fluids
systems. This discussion deals with gas, condensate, and Petroleum reservoirs almost invariably contain or abut some water; so the first step in pressure interpretations of petroleum is construction of a surface to total depth pressure/depth profile and a short interval of interest pressure/depth profile, both using water pressures only. The author has found that a vertical (depth) scale of 1 inch equals 2000 feet matched with a horizontal scale of 1 inch equals 2000 psi works quite well for the surface to total depth profile. One inch equals 100 feet vertical scale matched with 1 inch equals 100 psi horizontal scale works well for most detailed work. It is also important to consistently use the same depth-pressure scale proportions to be able to readily recognize various fluids and similar pressure-depth gradient patterns. It is important to retain a wide horizontal scale. The horizontal scale in use in some of Amoco's offices is so narrow that important details cannot be readily recognized.
Usually, the average water density for a whole The
usual purposes of surface to total depth pressure/depth profiles are (1)
to recognize and outline abnormally pressured fluid compartments for
drilling well control purposes, (2) to better understand seismic
velocities, (3) to map fluid compartment seals in pursuit of
stratigraphic traps, and (4) to provide water pressure/depth baseline
profiles for more detailed investigations of The
last purpose involves the differences in densities of The
divergence of the
Operations geologists and office engineers frequently are called upon to
estimate the greatest potential vertical height of an
(pp – pw) / (Dw-Dp) = vertical height of the hydrocarbon column in feet
where:
pp is a recorded pressure within the petroleum column stated in psi.
pw is the regional pressure in water-bearing rocks at the same depth stated in psi.
Dw is the density of the regional water stated in pounds per square inch per foot.
Dp is the density of the petroleum at reservoir conditions stated in pounds per square inch per foot.
Example: a
normally pressured Gulf Coast pp = 4800 psi pw = 4650 psi Dw = 0.465 psi/foot Dp = 0.331 psi/foot (4800 - 4650) / (0.465 - 0.331) = 1112 feet of column below the test
The
densities of gas, condensate, and
Construction of a pressure/depth profile of a petroleum column is much
simpler after several pressures have been recorded because the profile
of recorded pressures directly indicates the density of the petroleum.
Figure 15-45 illustrates the pressure/depth
profiles within two separate gas columns where the bottom water is
normally pressured. Figure 15-46 illustrates
an essentially identical construction in a gas pool where the bottom
water is overpressured. In both cases, the local pressure/depth profile
of the bottom water must be precisely determined from overlying and
underlying water-bearing rocks. Where there are errors in determining
the water pressure in fluid compartments, the errors tend toward the
deviations from normal pressure being greater than recognized. Thus, in
an overpressured fluid compartment, the likely error would be that the
full extent of overpressuring in the bottom water might not be
recognized and a recorded pressure in a newly discovered
Figure 15-47 illustrates the importance of
accurate determinations of the pressures in the bottom water. The
pressures data shown were in Amoco's files in 1955 when there was an
opportunity to acquire an interest in additional acreage downdip from
the newly discovered Pembina (Cardium)
In all
cases previously discussed in this report, it was assumed that there is
no internal compartmentalization within apparently continuous Figure 15-49 illustrates the pressure/depth profiles in several gas pools offshore Britain. The pressure/depth differentials from pool-to-pool are about the same as at Wattenberg, but there are large nonproductive areas between the pools; so the interpreter should be cautious in suggesting that subpools in a continuously productive area have been discovered when the only evidence is that the pressure/depth differentials from petroleum test to petroleum test are not very great. Nearly all development geologists and office engineers will, at some time, encounter at least one petroleum pool with one or more ponds of formation water located well above the base of the petroleum column. Those occurrences of ponded water; i.e., water which was not forced out when petroleum moved into the trap, were called perched water in old geological and engineering literature. Figure 15-50 illustrates the pressures measured in a gas column in northeastern British Columbia, Canada. One test recovered salty water more than 1000 feet above the deepest gas recovery. The ponded water displays a pressure which is being imposed by the adjacent gas. The water probably occupies a local lens of porosity which was not swept of its water when gas entered the field trap. Bottom water has not yet been encountered in the field. The
Recluse to Bell Creek cross-section, shown in
Figure 15-51, demonstrates a simple examination of alternative
techniques to determine if a continuous static petroleum column extends
from one discovery to another, even in the presence of water ponds. The
highest The
discovery pressures (Figure 15-53) in three
old fields producing from a buried river valley sand reservoir in the
Glenrock area of Wyoming clearly indicate that the pressure-transmitting
medium from field to field is
Figures 15-55, 15-56,
and 15-57 deal with an area of more
historical significance to Amoco. Figure 15-55
illustrates the pressure/depth data available in the mid 1960's in an
area in southeastern New Mexico. Six Figure 15-58, taken from a training slide used in the petrophysics training program, illustrates how ponds of water trapped in structural roll-overs between petroleum pools and sealing faults may exhibit the pressure profiles of the abutting petroleum. Figure 15-59 portrays a well offshore Trinidad which encountered water pond in several sands adjacent to a sealing fault. The pressure/depth profile in the water exactly matches the pressure/depth profile in the adjacent Poui field. If the well had been drilled prior to the discovery of the field, the pressures in the water ponds could have led to further drilling and eventually discovery of the field. Up to
now, we have been dealing with fluid compartments and normally pressured
rocks as if the seals have always been there and have always been
intact. There are several recognized compartments in which the bounding
seals have been permanently ruptured by erosion or faulting or were
breached by natural hydraulic fracturing without subsequent healing. The
remaining seal segments apparently are still as impervious to gas, Pressures within a newly ruptured compartment will progressively change toward equilibrium with the pressures in the external water through fluid leakage into or out of the compartment at the point of rupture. When pressure equilibrium is reached at the elevation of the rupture, there is no pressure differential to move fluids further. If the rupture is large or if the adjacent rocks are very permeable, there may continue to be gravitationally driven fluid movement; i.e., water may trickle into a gas-filled compartment, and the gas may bubble out even if the water and gas pressures are equal. During the in or out movement of fluids, the internal pressure at the elevation of the rupture remains equivalent to the external water pressure. If the rupture is very small or if the adjacent rocks have low permeability, the internal and external fluid systems may laterally coexist for a long time after attainment of pressure equilibrium. If the external pressure is decreased, generally through progressive erosion of cover, the fluids within the compartment will seep out to maintain pressure equilibrium. For illustrative purposes, three positions of pressure-equalizing leaks in a seal bounding a fluid compartment (Figure 15-60) will be discussed. The
giant Medrano The giant Milk River gas field in Alberta fills an underpressured fluid compartment which, like the Medrano pool, is pressure equalized near its updip terminus with exterior fluids (Leak A, Figure 15-60). There is some uncertainty about whether the leak is into normally pressured updip rocks to the south or into a near normally pressured fluid compartment to the west (Figure 15-62). The pressure/depth profile of the field exhibits the typical “hanging down” appearance of pressure equalization of a petroleum column with an updip water system. There
are several gas-filled fluid compartments with updip pressure
equalization into water-filled fluid compartments in the deep Figures 15-65 and 15-66 take another look at the Bough “C” compartment within a compartment previously shown (Figures 15-55, 15-56, and 15-57). The pressure/depth profile in the filled internal compartment crosses the pressure/depth profile of the large, mainly water-filled surrounding compartment at about -5400 feet elevation. Thus, if there is a leak between the compartments, it must be near that elevation (Leak B, Figure 15-60).
Figure 15-67 illustrates the pressure/depth
profiles relative to the regional water gradient to be expected within a
fluid compartment with a pressure-equalizing leak at each of the three
locations shown in Figure 15-60. It should
be noted that the pressure equalization through a leak in the seal
explanation may not be correct. Some or all of the cases could be
coincidences; however, there are so many cases of pressures in Operation geologists should become familiar with pressure/depth profiles in petroleum-filled fluid compartments because such familiarity may lead to development of petroleum columns further downdip than usual petroleum overlying normally pressured bottom water interpretations would allow. For example, Figure 15-50 could be interpreted as a gas column overlying normally pressured bottom water a few feet downdip from the deepest gas recovery or, alternatively, it could be interpreted as a fluid compartment with extension of the petroleum column downdip possibly as far as the downdip limit of the compartment. The downdip limit of the petroleum column could be thousands of feet below the petroleum/bottom water contact anticipated by the usual petroleum over normally pressured water interpretation. A fluid compartment interpretation probably is the more likely if there are other fluid compartments in the area because fluid compartments rarely occur singly. Pressures Interpretations of Fluids within Seals
Figures 15-69 to 15-80
TextEarlier in this report, a fluid compartment was described as having “a thin, essentially impermeable outer seal and an internal volume which exhibits effective hydraulic communication.” An analogy was made between a fluid compartment and a buried bottle. The analogy provides an adequate description of the hydraulic conditions within the internal volumes of fluid compartments, and it is functionally correct regarding seals, but it is somewhat misleading regarding the internal structure of seals. Seals, like the glass in bottles, are essentially impermeable across their total thickness but, unlike glass, may exhibit a high order of internal directional permeability parallel to their outer surfaces. Therefore, a fluid compartment may be like a buried bottle which was constructed of some laminated material rather than being like a buried glass bottle. Figure 15-69 is a restatement of Figure 15-4 but portrays a fuller description of the seal. Several
figures used earlier in this report depicted pressure/depth profiles
across seals with a linear increase or linear decrease in pressures with
increasing depth. The linear rates of pressure change across the seals
appear to bear no relationship to whether the permeable streaks within
the seals contain gas, Figure 15-71 carries the reader downward across the page through a progression from two superimposed ordinary fluid compartments through a single fluid compartment with an extra thick top seal which has thick internal permeable layers to an ordinary fluid compartment with a top seal which consists of a layered sequence of microcompartments. The figure is introduced to support the author's contention that many seals, particularly in clastic rocks, seems to be a stacked assemblage of many very thin, but widespread, microcompartments. The individual microseals bounding the microcompartments may be discrete depositional rock layers, like turbidite shale beds, or may be paper-thin microstylolitization zones or mineral-filled zones which cut across the depositional layers. The
middle diagram shown on Figure 15-71
portrays an arrangement which is rather rare in the United States but is
common in a few foreign countries, particularly in Trinidad. Most of the
commercial Figure 15-73 is an example of the diagram at the bottom of the page in Figure 15-71. There are several thin, but very extensive, permeable layers in a strata-bound top seal. The pressures shown on Figure 15-73 are from a single site. Figure 15-74 shows the pressures in the same permeable layers along a traverse from six miles updip to six miles downdip from the site shown in Figure 15-73. Note that each permeable layer exhibits internal hydraulic continuity, but each permeable layer is hydraulically isolated from overlying and underlying permeable layers. The pressures, from permeable layer to permeable layer, exhibit a straight line rate of change with increasing depth in any well in the area.
Figure 15-75 shows an early recognition of
the pressures-with-depth situation in what was later recognized to be
the top seal in an underpressured fluid compartment covering the whole
of the Seminole Sag, a graben in Paleozoic rocks in east-central
Oklahoma. The permeable zones in the top seal produced nearly one
billion barrels of Figure 15-76 portrays pressures measured in an old well in a tight gas sand area in Wyoming. The pressures from sand to sand in the top seal of the large fluid compartment there follow a straight-line rate of change with increasing depth. Every tested sand in the seal yielded gas without water. The differences in pressures from sand-to-sand preclude sand-to-sand communication. The straight-line rate of change of pressure with increasing depth essentially demands that the buoyancy pressures from the gas columns in the sands must be the same in every sand or else, in some unrecognized manner, petroleum columns in permeable zones in seals do not exhibit buoyancy effects.
Figure 15-77 portrays a similar linear
increase of pressure with increasing depth in thin sands in the top seal
of a large fluid compartment in the Cook Inlet
Figure 15-78 is a pressure depth/profile
through the Sycamore gas field in California. The most prolific
production comes from the mid-Forbes turbidite sands. The Forbes sand is
a thinly bedded sequence of hundreds of repetitions of fining-upwards
sands capped by shale laminae. The whole Forbes sand interval is the
intermediate seal of a large two-tiered fluid compartment, which
occupies the western one-half of the Sacramento
Figure 15-79 portrays the pressure/depth
profiles across the gas and Figure 15-80 portrays static pressures along a traverse of fields in a single formation. The traverse extends across a lateral seal between a normally pressured area and an underpressured fluid compartment. The profile is the same as one which would be obtained if it were possible to drill a westerly slanting wellbore staying in the single formation. The lateral seal appears to exhibit a linear rate of pressure change across the seal so lateral seals and top seals may be similar in that regard.
FinaleThe level of skills advanced in this report is sufficient for most day-to-day interpretations of local static pressures in underground formations by operations geologists and office engineers. This report will be supplemented with a later report which will advance into more involved techniques of interpretations of static pressures appropriate to specialists in regional pressure studies.
References and Suggested Reading
Alliquander, O., 1973, High pressures, temperatures
plague deep drilling in Bradley, J.S., 1975, Abnormal formation pressure: AAPG Bulletin, v. 59, p. 957-973. Bradley, J.S., 1976, Abnormal formation pressure: Reply: AAPG Bulletin, v. 60, p. 1127-1128.
California Division of Daines, S.R., 1982, Prediction of fracture pressure for wildcat wells: Journal Petroleum Technology, v. 34, p. 863-874. Debrandes, R., and J. Gauldron, 1987, In situ rock-wettability determination with formation pressure data (in press): SPWLA. Erdle, J.C., 1987, How to get more for your money from drill stem tests: Petroleum Engineers International, v. 59, p. 51-54. Gunter, J.M., and C.V., 1987, Improved use of wireline testers for reservoir evaluation: Journal Petroleum Technology, v. 39, p. 635-644. Higgs, N.G., and J.S. Bradley, 1984, Stress state and fracture development during sedimentary burial from theory and microstructural finite element models: Amoco Geological Research Report F84-G-18. Hottman, C.E., and R.K. Johnson, 1965, Estimation of formation pressures from log-derived properties: Journal Petroleum Technology, v. 17, p. 717-720. Jorden, J.R., and O.J. Shirley, 1966, Application of drilling performance data to overpressure detection: Journal Petroleum Technology, v. 18, p. 1387-1394.
Guerrero, E.T., 1966, How to find bottom hole pressure
from gas well surface-pressure measurement:
Moses P.L., 1986, Engineering applications of phase
behavior of crude Moses, P.L., 1987, Author’s reply: Journal Petroleum Technology, v. 39, p. 235. Narr, W., and J.B. Currie, 1982, Origin of fracture porosity – example from Altamont Field, Utah: AAPG Bulletin, v. 66, p. 1231-1247. Be careful with this publication. It contains a few errors in mathematics, which lead to an incorrect formula for lateral effective stress under conditions of zero lateral strain. Phelps, G.D., G. Stewart, and J.M. Peden, 1984, The effect of filtrate invasion and formation wettability on repeat formation tester measurements: SPE paper 12962, European Petroleum Conference, London, October 1984. Podio, A.L., S.G. Weeks, and J.N. McCoy, 1984, Low cost wellsite determination of bottomhole pressure from acoustic surveys in high pressure wells: Paper 13,254, SPE Meeting, Houston, September, 1984.
Powley, D.E., 1982, The relationship of shale compaction
to Powley, D.E., 1983, Subsurface fluid compartments: Amoco Geological Research Report F83-G-23. Powley, D.E., 1985, Subsurface temperatures: Amoco Geological Research Report F85-G-5. Rehm, B., and R. McClendon, 1971, Measurement of formation pressure from drilling data: Paper 3601, SPE Meeting, New Orleans, October, 1971, 11 p.
Rogers, L., 1966, Shale-density log helps detect
overpressures:
Stuart C.A., 1970, Geopressures: unpublished Shell
Weagant, F.E.,
1972, Grimes gas field, Sacramento Valley, California, in R. E.
King, ed., Stratigraphic |
