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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 uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
uRecognition
of abnormal uFigs. 15-13 - 15-20, Table 15-1
u
u uInterpretations of fluids within seals
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Figure 15-1. Pressure/depth (of water)
profile, illustrating that pressure at any depth is proportional
to the density of the |
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Figure 15-2. Subsurface pressure in a
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Figure 15-3. Pressure in confined |
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Figure 15-4. The buried bottle model of
a |
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Figure 15-6. Pressure/depth profiles for
simulated strata containing matrix-supported seal and for
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Figure 15-9. Normal |
Text
Pressure 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 case in
which the rock matrix at the base of each of the two seals bears the
entire weight of the overburden, so the fluid pressures start from zero
at these levels. All of the fluid pressures are markedly less than the
normal 45+/- psi per 100 feet from the surface, so the pressures in the
Keyes Field, except those in the shallow beds above the uppermost seal,
are termed underpressures(Figure 15-7).
The
Carpathian Basin in Hungary is an example of rock load being partially
borne by the fluids below a seal. The fluid pressures are normal from
the surface down to the base of the Pliocene clastics but are greater
than normal below a thick series of lava flows which separate the
Pliocene clastics from the Miocene clastics. Wells drilled on the
northern shelf penetrate the normally pressured Pliocene clastics, the
seal in the lava flows and the subseal high-pressured Miocene
formations, whereas wells drilled in the southern basin usually
penetrate only normally pressured Pliocene clastics. The interval rate
of pressure increase with depth in the Miocene section is the same as
the rate of change in the normally pressure Pliocene section (Figure
15-8). This figure and the previous figure illustrating the Keyes
Field demonstrate the field applicability of Pascal's Principle.
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
Pressures
Figures 15-10 to 15-12
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Figure 15-12. Pressure/depth profile in
Shell pressure test well, Baram Field, Offshore Sarawak, East
Malaysia, showing linear transition of |
Text
In 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 Basin, the South Papua
Basin, the outer Gulf of Mexico, and the Canadian Arctic Basin where the
base of the shallow system has apparently never been buried more than
about 4000 to 6000 feet. The shallow hydraulic systems are basinwide in
extent and exhibit normal pressures. The pore water apparently is
free to migrate; however, the usual rate of movement, below the
uppermost few hundred feet, is so slow that motion is surmised rather
than detected. Stable isotope ratios of dissolved solids and gases
appear to indicate widespread invasion of the shallow hydraulic system
by meteoric water in only a few basins.
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-basin shelf deposits and basement rock. The uppermost
noncompartmented layer usually is in rocks which were deposited during
the slowing rate of deposition in late stage in basin filling.
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 basin. However, in some young, foreign basins and in the Copper
River Basin in Alaska, fluidized rock material, mainly shale, and high
pressure water with minor hydrocarbons are being locally ejected upward
from subsurface overpressured compartments, through overlying normally
pressured rocks and venting at the surface. Mud volcanoes may be built
up at the vent sites. The rising, high-pressured mixture may pressure-up
any shallow, permeable beds encountered, thereby locally complicating
recognition of the layered arrangement of hydraulic systems.
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 Basin. The pressures within the
compartments are overpressured or underpressured relative to the
pressures in both the shallower and deeper hydraulic systems. The
compartmented hydraulic systems in currently sinking basins are almost
universally overpressured and are underpressured in many onshore basins
undergoing erosion. The principal source of overpressures appears to be
thermal expansion of confined fluids and the generation of petroleum
during continued sinking and the principal source of underpressures
appears to be thermal contraction of confined fluids as buried rocks
cool during continued uplift and erosion at the surface. Thus, it
appears that the compartments have an amazing longevity as they undergo
a continuum from overpressures through normal appearing pressures to
underpressures as their host basins progress from deposition, to
quiescence, to basin uplift and erosion. Fluid compartments are
important in subsurface geology because oil and gas may be trapped in
external or internal beds where they abut seals or may be in permeable
beds within seals.
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 Basin
appears everywhere to be within the thin Cretaceous Fuson shale.
However, in many basins, the top seal of the compartmented layer is more
complicated. It (1) tends to follow an irregular
sands-over-massive-shale boundary in the Gulf Coast and Niger Delta
basins, (2) it is within thin evaporites in many onshore European and
southwestern U.S. basins, and (3) occurs as horizontal or gently dipping
planes which cut indiscriminately across structures, facies, formations,
and geological time horizons in the Alaska North Slope Basin, in the
northern Cook Inlet Basin, in the Alberta Basin, in the Anadarko Basin,
in the North Sea Basin, and in many Rocky Mountains basins (Figure
15-11). Those top seals which do not follow a specific stratigraphic
horizon generally are restricted to clastics dominated sections. The
planar-topped, compartmented sections are almost universally in basins
which are older than the basins in which the compartmented sections
exhibit much top surface irregularity. Thus, it appears that there is
some process in nature whereby the top seals of compartments in clastics-dominated
sections can smooth themselves over time. The leveling process may be
quite rapid because the tops of the two principal fluid compartments in
the central North Sea Basin are horizontal over distances in excess of
100 miles despite the recent salt-induced structure development in the
area.
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 Basin. No deeper seals have yet been encountered in wells in the graben or in the Ardmore Basin.
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
oil and gas pools. The transition of pressures across the total
thickness of top seals in clastic rocks is linear with increasing depth
wherever data have been obtained (Figure 15-12).
Too few data have been accumulated to determine the patterns of
pressures within lateral seals or within basal seals. The overall rate
of pressure change across seals in shale have been observed to be as
great as 15 psi/foot and 25 psi/foot in seals in sandstone.
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 Basin.
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 oil and gas production. While lateral seals are almost always nearly vertical, continuous planes, there are a few remarkable cases of breaks in seal continuity where individual permeable rock layers extend in hydraulic continuity from a compartment into a neighboring compartment. Those tongues are of particular interest to exploration geologists because they frequently contain oil and gas pools.
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 Basin and in the deep
basin area of the Alberta Basin. Mud losses start at the base of the top
seals in both areas. The mud will reenter the wellbores if the wells are
changed to an underbalanced state. Most fractures are less than 1 inch
long. They generally extend from pore to pore and tend to separate
grains rather than break across grains.
The fractures in the internal volume are, in a few areas, open enough to permit commercial-rate extraction of oil and gas even in the absence of significant matrix porosity and permeability. However, the distribution of open fractures is generally not uniform enough to allow field development without a substantial proportion of dry holes unless the fracture porosity is augmented with matrix porosity and permeability within the internal volume rocks. The matrix rocks, in different areas, may exhibit remarkably different porosity values. For instance, sandstone porosities are in the 20-35% range in the overpressured Cretaceous Tuscaloosa sandstone reservoir in the False River Field in Louisiana and are generally much less than 10% in the Paleozoic Goddard sandstone reservoir in the Fletcher Field in Oklahoma at approximately the same depth and pressure.
Recognition and Indirect Quantification of Abnormal Pressures
Figures 15-13 to 15-20, Table 15-1
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Figure 15-13. Shale resistivity
highlighted on log of Amoco No. 1 S.L. 4427, St. Mary Parish,
Louisiana, to show a section with normal |
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Figure 15-14. Relationship of
resistivity ratio of shales to |
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Figure 15-20. Estimation of |
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Table 15-1. Techniques available to
predict, detect and indirectly quantify abnormal pore |
Text
Overpressures have been known and studied in the Gulf Coast Basin for
many years. Most of the techniques to drill and complete wells safely in
overpressured formations now in use worldwide were developed in the Gulf
Coast. One of the most significant techniques is the use of well logs to
identify and quantify overpressures. The techniques now in use are
modified from those introduced in a paper presented by Hottman and
Johnson in 1965. They reported the coincidence of high fluid pressures
in sands and lower-than-normal electrical resistivities and acoustic
velocities in adjacent shales (Figure 15-13).
The technique using electrical logs involves an empirical relationship
between the resistivity of shales adjacent to sands with fluids at
normal pressures and the resistivity of shales adjacent to sands with
overpressured fluids. The resistivity values for shales are generally
easy to read on electrical logs. The ratios of the resistivity of the
shales in the normally pressured section to the resistivity of the
shales in the overpressured section are plotted on a ratio comparison
chart which yields a pressure/vertical depth ratio value applicable to
the resistivity ratio (Figure 15-14). It is
important to note that the onset of the reduction in shale resistivity
occurs at the depth at which a pressure depth ratio of 61 psi/100
vertical feet of burial is encountered. The relationship actually is
0.61 times the geostatic gradient value at that depth; however,
essentially no error is introduced if 0.61 times the depth is feet is
used in onshore and shallow water wells. Any electrical resistivity log
can be used; however, the author has had the best results using
resistivity ratios from values recorded on induction logs.
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 Basin are very uniform, probably resulting
from their hundreds to thousands of miles transport and mixing in rivers
before deposition. Shales derived from nearby sources, as in many Rocky
Mountain Tertiary formations, tend to be too nonuniform for pressure
analyses by electrical log techniques.
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 oil companies to identify
overpressured shales in wells in the Gulf Coast Basin. He contended that
the magnitudes of pressures may be determined by measuring the
deviations of the densities of shales in overpressured rocks from a
normal compaction trend. In the rush of enthusiasm for a new technique,
porosities and densities were measured in shales from thousands of wells
by many of the companies operating in the Gulf Coast Basin. Amoco
measured those properties in shale from 4000 wells during that period.
Each of the companies developed its own compaction (density-porosity)
comparison standards. Within a few years the technique was generally
abandoned because drillers had developed more reliable indicators of
overpressures in drilling wells and because it was discovered that
overpressures occur in association with both normally compacted and
undercompacted shales. Undercompacted shales were found to be
universally overpressured, but normally compacted shales can be
overpressured, normally pressured, or underpressured. Geological
Research Department Report No. F~2-G-23 deals more extensively with the
relation between pressures and shale compaction in the Gulf Coast
Basin.
The
compaction-pressure technique continues to be applicable in southern
Texas where there is a high degree of correlation between the degrees of
compaction and pressures. Bob Hix of the Houston Region is the company
log analyst most familiar with those techniques; so it would be
advisable for geologists and engineers working with overpressured wells
in South Texas to contact Bob directly.
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 Basin. Similar calibration overlays must be developed for each geological province and/or geological period.
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 oil
or gas. Also, there have been a few serious misinterpretations where gas
occupies a large part of the porosity in shale. Gassy shale generally
exhibits very low interval sonic velocities which can lead to incorrect
interpretations that the shale has higher fluid pressures than in the
adjacent reservoir rock. Conversely, gassy shale generally exhibits high
electrical resistivities which can lead to an incorrect interpretation
of lower pressures in the shale than in the adjacent reservoirs.
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
|
|
Figure 15-21. Pressure/depth profiles,
Ekofisk and Eldfisk fields, offshore Norway, from scout ticket
data (bottomhole shut-in |
|
|
Figure 15-22. Pressure/elevation
profiles, Britoil no. 20/2-3, Ettrick Field, UK North Sea Basin,
from |
|
|
Figure 15-23. Cross section, Ettrick Field, UK North Sea Basin, with fault-bounded compartments. |
|
|
Figure 15-24. Pressure/depth profiles,
Ettrick Field, UK North Sea Basin, showing the different
compartments in Jurassic strata, determined with data from
repeat |
Text
None 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
|
|
Figure 15-25. Pressure/depth profile,
from recorded shut-in |
|
|
Figure 15-26. Pressure/depth profile,
from recorded shut-in |
|
|
Figure 15-27. Pressure/depth profile,
from initial shut-in |
|
|
Figure 15-28. Pressure/depth profiles,
from recorded shut-in |
|
|
Figure 15-29. Pressure/depth profiles,
from recorded shut-in |
|
|
Figure 15-30. Pressure/depth profile,
from recorded shut-in |
|
|
Figure 15-31. Pressure/elevation
profiles, from |
|
|
Figure 15-32. Pressure/elevation
profiles, from |
|
|
|
|
|
Figure 15-34. Pressure/depth profile,
from bottomhole |
|
|
|
|
|
Text
Exploration 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 case of
probable transposition of numbers. Transposition of numbers is
particularly common in data files which were accumulated from scout
check sources, such as Amoco's Well Data I and Well Data II. The
interpreter must be willing to ignore suspect data with the consequent
hazard that accurate data may be discarded.
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
Text
All
prior discussions in this report dealt with water dominated fluids
systems. This discussion deals with gas, condensate, and oil-bearing
reservoirs in normally pressured rocks and in the internal volumes of
fluid compartments (Figure 15-4). The data
accuracy requirements when dealing with petroleum are much greater than
for water systems, and the zone of interest is generally much thinner
when dealing with petroleum.
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 basin or basin sector is
accurate enough to establish the slope of a surface to total depth
pressure/depth profile, but the investigator should be prepared to
accept what his data (rather than his instincts) tell him about local,
restricted depth range water densities. For example, many geologists
find it difficult to accept that quite fresh water may exist at great
depths in deep marine origin rocks. Figure 15-37
illustrates a well in which the well logs warned of low salinities,
which were later verified by the rate of change in pressures measured
with a wireline repeatable formation tester. Note that the in-situ water
density in this well is less than the density of fresh water under
surface conditions due to the effect of thermal expansion of water in a
high temperature environment being greater than the combined effects of
the salt in the water and of the compressibility of water.
Figure 15-38 demonstrates the prominent
reduction in brine densities which occur with increasing temperatures in
constant salinity sodium chloride solutions. Note that the rate of
reduction of density is essentially the same across the whole salinity
range from fresh water to saturated brines. In nature, brine salinities
do not remain constant with increasing depth. Salinities generally
increase downward at a rate which exactly offsets the effects of
temperature and water compressibility, with the result that brines
exhibit a constant density value; i.e., a constant pressure/depth ratio,
from near the surface to great depths in most basins.
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 oil and gas columns.
The
last purpose involves the differences in densities of oil, gas, and
brines. Figure 15-39 presents a graphical
representation of the pressures in a hydrocarbon column vs the pressures
to be expected in laterally adjacent water-bearing rocks in the same
fluid system. It is important to note that the adjacent water-bearing
beds may be normally pressured, overpressured, or underpressured. Oil
and gas columns in permeable zones within seals require special
handling; so the ensuing discussions will first deal with mixed fluid
systems in normally pressured rocks and in the internal volumes of fluid
compartments. Please refer to the discussion of fluids within seals (Pressures
Interpretations of Fluids within Seals).
The
divergence of the oil or gas column pressure/depth profile from the
water pressure/depth profile is due entirely to the differences in
density between petroleum and water. The petroleum and adjacent caprock
water are pressures-separated by a capillary membrane of mixed petroleum
and water in the rock pores with very fine pore throats along the
interface between the petroleum and the water. It is important to note
that the capillary membrane seal is developed only where petroleum abuts
water; i.e., there is no membrane separation of water from water.
Therefore, the water around the petroleum column is assumed to be
pressure connected to the adjacent interconnected water system. The
buoyancy pressure is balanced by the capillary pressure. Some reservoirs
are oil or gas-filled to their full downdip extent; i.e., there is no
connected bottom water. In those reservoirs, the pressures within the
petroleum column are sealed by a continuous capillary membrane from the
pressures in the adjacent water-filled rock system. Pressures measured
high within the hydrocarbon column are not indicative of the downdip
extent of the pool.
Operations geologists and office engineers frequently are called upon to
estimate the greatest potential vertical height of an oil or gas column
over bottom water after oil or gas without water has been recovered in a
well test. The updip limit of a hydrocarbon column cannot be determined
from pressures data alone; however, the pressure at the top of the
petroleum column cannot exceed the local fracture gradient. If the test
recovered oil, there is no reliable method to determine if a gas cap is
present somewhere above the tested interval. Projecting the vertical
height of a hydrocarbon column downward from a test which recovered gas
is subject to uncertainties about whether there is a downdip oil leg. If
an estimate of a hydrocarbon column below the test is to be made on the
assumption that the density of the petroleum recovered in the test is
representative of the hydrocarbons throughout the whole column below the
tested interval a simple mathematical analysis probably will suffice.
(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 oil reservoir at 10,000 feet.
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 oil are highly sensitive to
hydrocarbon composition, temperature, and pressure; so selection of
appropriate hydrocarbon density values applicable to reservoir
conditions requires conversions from densities measured under surface
conditions. The author has found the charts on Figures
15-40, 15-41,
15-42, 15-43,
and 15-44 to be satisfactory for reservoirs
at shallow to intermediate depths but require extrapolations for deep or
high pressure pools. Production Research is currently entering the
composition phase characteristics of crude oil, condensate, and gas
systems under varying temperatures and pressures into a user friendly
computer program called PVT CALC. It will be available in the Regions
within a few weeks following completion of this handbook. It is
suggested that PVT CALC be used in preference to Figures
15-40 through 15-44
where more precise interpretations are required. If very precise
interpretations are required, a sample of the fluids recovered during a
well test collected under rather strict well site procedures should be
submitted to the Research Center for analysis. The well testing, fluids
collection, sample bottling, and shipping procedures will be included in
the lab services handbook, currently being revised by Production
Research.
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 oil or gas
column would look like a greater buoyancy pressure; i.e., a longer
petroleum column, than is really there. Likewise, failure to recognize
the full extent of underpressuring in the bottom water would lead to
actual heights of oil and gas columns being greater than calculated.
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) oil pool in Alberta. The
prevailing hydrogeological concept at that time was that the pressures
in any permeable bed are essentially independent of the pressures in
shallower and deeper permeable beds. Therefore, the recorded pressures
in the shallower (Belly River) sands were believed to have no bearing on
the pressures in the oil column in the Cardium sand. The Cardium
pressure exceeded the expected water pressure/depth value of 44 psi/100
feet from the surface by about 550 psi; so an approximate 5000 feet
downdip oil column was anticipated. If the determination of the water
pressure/depth value had utilized the recorded pressures in the
shallower beds, a 1100 psi over bottom water differential pressure would
have been anticipated with a consequent recognition that the Cardium
continuous oil column extends about 10,000 feet downdip. The “mistake”
would not be made now because fluid compartments and their patterns of
internal pressures are better understood now.
In all cases previously discussed in this report, it was assumed that there is no internal compartmentalization within apparently continuous oil and gas pools. Several of the large pools discovered in recent years, particularly in low permeability sand reservoirs, display evidence of through-going seals dividing large pools into subpools. Determinations of the heights of petroleum columns have been fraught with confusion as interpreters attempted to “push” their data into single petroleum column interpretations. Figure 15-48 displays a subpool (multicompartment) system in an ostensibly continuous large gas pool producing from a single sand. Similar subpools have been noted in the tight gas sand areas in the Rocky Mountains and Alberta and in the downdip Wilcox fields in South Texas.
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 oil in the area is at the gas/oil interface in the Bell Creek
field, and the lowest oil is at the oil/water interface in the downdip
Recluse field. The pressure differential is 2262-1180 = 1082 psi across
3700-430 = 3270 feet, which calculates to 1082 psi/3270 ft = 33.1 psi/100
feet. That indicated density of a static pressure conducting medium
corresponds with the density of the reservoir oil in the two fields.
Thus, a static continuous oil column from Bell Creek to Recluse is
indicated, as illustrated diagrammatically in
Figure 15-52. Alternatively, if a pressure/elevation of head
conversion is made using either a fresh water or formation water
density, the resultant calculated potentiometric surfaces dip strongly
downdip, thus requiring a very fast downdip water flow to account for
the pressure differential between the fields. Inasmuch as there is no
topographically low area within at least a hundred miles to vent water
at an approximate +1500 feet elevation, the moving water pressure
connector from field to field interpretation, while not conclusively
disproved, appears to be very unlikely. The indicated continuous oil
column from Bell Creek to Recluse does not necessarily mean that all of
the intervening area could be made commercially productive. Wells
drilled between the fields have encountered tight reservoir sand or thin
oil columns over water. The oil over water tests indicate that there are
several water ponds held in place by facies changes in the reservoir
sand. There are two small water ponds below the pay within the Bell
Creek Field. It seems likely that there are commercial oil fields
awaiting discovery between Recluse and Bell Creek and possibly downdip
from Recluse.
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 oil despite two large adjacent areas in
which water only was recovered. The diagrammatic map in
Figure 15-54 provides a simplistic
interpretation of the geographic arrangement of the fields and of the
two large water-bearing areas. The pressures in the water ponds indicate
that the pressures are controlled by the pressures in the abutting oil.
It appears likely that there are at least a few undrilled locations in
which oil completions could still be made in the interfields oil column
connectors.
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 oil “pools” had been discovered,
and Amoco had acquired an acreage block in southern Roosevelt County.
Amoco drilled a wildcat well, Amoco State “DO” No.1, which tested the
objective formation and recovered oil and gas cut mud and a large
quantity of salty water. The well was in a structurally low position; so
the well and lease were sold to a Midland junk dealer. The buyer, rather
than salvaging the tubular goods as anticipated, installed a large pump
and started pumping water with an increasing oil cut. The well
eventually stopped producing water and became a commercial oil well. The
well apparently had encountered a closed structural low which had
retained a local water pond (Figure 15-57)
when oil migrated into the trap. The six oil “pools” eventually/became
one large continuous oil field, as the 33.6 psi/100 feet pressure/depth
“pool” to “pool” ratio had indicated.
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, oil,
and water as they were when the seals were complete; therefore,
recognition of seal segments is very important in petroleum exploration.
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 oil and gas pool on the Cement anticline in Oklahoma
occupies an underpressured fluid compartment which leaks at its updip
terminus into adjacent normally pressured rocks (Leak A,
Figure 15-60). The gas pressure at the updip
end of the pool coincides with the adjacent normal pressures (Figure
15-61). The pool probably has leaked as erosion has progressively
removed cover, and thereby reduced the external normal pressures. Note
that the compartment is normally pressured at its updip terminus, but
because gas and oil are less dense than the external water, the pool is
underpressured relative to the external water in its full downdip
extent. The leakage plume over this field has been extensively used by
promoters of geological and geophysical techniques which sense the
chemical changes in rocks due to the continued presence of seepage gas.
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 basin area
of Alberta. Figures 15-63 and
15-64 show two of those pressure/depth
profiles. In the Gulf Coast Basin, there are cases of updip pressure
equalization across a leak with overpressured water in an adjacent fluid
compartment.
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 oil and
gas columns being equal to water pressures in immediately adjacent fluid
compartments that coincidences seem to be very unlikely. During the
discussion of leaky seals, it was tacitly assumed that the pressures
within the leaky compartments had reached stability.
Figure 15-68 demonstrates that the
pressure/depth profiles shown on Figure 15-67
could be point-in-time transient conditions in a continuing blowdown of
a leaky petroleum-bearing fluid compartment.
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
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Figure 15-69. The buried bottle model of
a |
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Figure 15-70. Slope of pressure/depth
profile in seal controlled by nonfluid related factors; slope
above and below seal controlled by density of |
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Figure 15-74. Pressure/depth profiles,
Lanaway area, Alberta, Canada, shows the |
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Figure 15-75. Pressure/depth profile
(Carr City Field, Seminole Sag, Oklahoma) of an extensive
underpressured |
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Figure 15-80. Pressure/elevation profile
for Niobrara Chalk in gas fields, western Kansas, where a
lateral seal separates normal and underpressured |
Text
Earlier
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, oil, or water. Unlike the pressure/depth profiles
in normally pressured rocks and in the internal volumes of fluid
compartments, the pressure/depth profile slopes within seals appear to
be controlled by nonfluid related factors (Figure
15-70).
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 oil pays there are in a few thick sands in the top seal of a
very widespread fluid compartment which extends from onshore eastern
Venezuela, across the Gulf of Paria, across the island of Trinidad, to
the offshore area east of southern Trinidad.
Figure 15-72 shows a U.S. example, in this
case, with a single thick, water-loaded sand in the top seal.
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 oil and a large amount of gas, most of which was
flared. Most of the industry drilling, completion, and production
techniques applicable to underpressured reservoirs were developed there.
The permeable zone pressures in wells exhibited a straight-line rate of
change with increasing depth without regard to whether the permeable
zones contained gas, oil, or water. Very little reliable data are
available regarding the original lengths of the petroleum columns in
individual permeable zones in the seal because many operators set casing
in. the Caney Shale and open-hole completed all deeper formations into a
commingled fluid stream.
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 Basin in Alaska. The
major difference between this figure and Figures
15-75 and 15-76 is that all but one of
the sands in the Cook Inlet seal are water-bearing. One sand is the
reservoir for the deep wet gas pay in the Cook Inlet Field. Whatever
factor it is that forces pressures in permeable layers in top seals of
fluid compartments to change linearly with increasing depth makes no
distinction between the types of fluids in the pore spaces in the
permeable layers.
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 Basin. The
pressure/depth profile across the seal displays a linear increase in
pressure with increasing depth. For several years, California geologists
have been aware of the pressure/depth profile in the Forbes sand, but
they have persistently contended that the linear change of pressures
with increasing depth is unique to the Forbes turbidite deposits. The
laminar nature of the Forbes turbidites is similar to the generally
laminar nature of seals in clastic rocks elsewhere, and the linear
change of pressures with depth nature of the pressure/depth profile in
the Forbes is the same as the profiles in other seals, so the Forbes
seal does not appear to be unique. The Forbes sand at Sycamore has been
gas productive for over 20 years, so the thin depositional laminae there
must be very extensive.
Figure 15-79 portrays the pressure/depth
profiles across the gas and oil productive Lower Tuscaloosa and Dantzler
sands in the Moore-Sams, Schwab, and Morganza fields in Louisiana. Amoco
geologists have described the sands in the seals and in the internal
volumes of the two fluid compartments there as being visually identical.
The bulk of the pay section in the Morganza field is in the top seal of
a fluid compartment, whereas the bulk of the pay section in the Moore-Sams
and Schwab fields are in the internal volume of an adjacent fluid
compartment. The pressure/depth profile across the seal in the Morganza
fluid compartment displays the typical linear rate of change with
increasing depth; this clearly requires that the sand is laminated into
many noncommunicating layers. The straight-line rate of pressure change
also indicates that there is either no buoyancy effect from the lengths
of gas columns or the buoyancy effect is equal in each of the sand
laminae. It seems very unlikely that the lengths of columns are
identical from lamina to lamina in each seal everywhere, so it appears
that we are faced with some new factor which suppresses the buoyancy
effects of petroleum columns in fluid compartment seals. If, in fact,
there is something about seals which suppresses the buoyancy effects of
petroleum columns; we are left without a method of predicting lengths of
petroleum columns in thin permeable layers within seals. The apparent
suppression of buoyancy effects of oil and gas pools within seals is the
most surprising aspect of this study. The author needs further
documented pressures in oil and gas pools in seals anywhere in-the
world, particularly if those pools exhibit discernible buoyancy
effects.
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.
Finale
The
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 Hungary: Oil and Gas Journal, v. 71, no. 21 (May
21), p. 97-100.
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 Oil and Gas, 1973, California oil and gas fields: Volume I, North and east central California: Sacramento, California.
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: Oil and Gas Jounral, November 21, p. 175-176.
Moses P.L., 1986, Engineering applications of phase behavior of crude oil and condensate systems: Journal Petroleum Technology, v. 38, p. 715-723.
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 oil and gas pools in the Gulf Coast Basin: Amoco Geological Research Report F82-G-23.
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: Oil and Gas Journal, September, p. 126-130.
Stuart C.A., 1970, Geopressures: unpublished Shell Oil Company report.
Weagant, F.E., 1972, Grimes gas field, Sacramento Valley, California, in R. E. King, ed., Stratigraphic oil and gas fields: AAPG Memoir 16, p. 428-439.
