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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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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 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 The
Keyes Field in northwestern Oklahoma is illustrative of the case in
which the rock matrix at the base of each of the two 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). Return to
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 The
deeper
Recognition of the layered arrangement of 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 In
those basins with three layers of Planar
Earlier
in this chapter it was pointed out that the individual compartments in
the compartmented layer are like huge bottles with thin bounding In some
areas,
Lateral
The
rocks in the internal volumes within the compartments, like the 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. Return to
Recognition and Indirect Quantification of Abnormal PressuresFigures 15-13 to 15-20, Table 15-1
TextOverpressures 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 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 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. Return to
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 ( 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
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Figure 15-31. Pressure/elevation profiles, from pressures in the Cotton Valley Lime, East Texas. |
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Figure 15-32. Pressure/elevation profiles, from pressures in the Collton Valley sand, East Texas. |
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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
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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.
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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.
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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 fluid compartment, with a more complete description of the seal than in Figure 15-4. |
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Figure 15-71. Pressure/depth profiles
progressing from two compartments with thick |
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Figure 15-72. Pressure/depth profile,
Fordoche Field, Louisiana, where a single thick, water-loaded
sand is in the |
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Figure 15-73. Pressure/depth profile,
Lanaway area, Alberta, Canada, as an example of the lowest
diagram in Figure 15-71, shows thin, but very extensive,
permeable layers in the |
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Figure 15-74. Pressure/depth profiles, Lanaway area, Alberta, Canada, shows the pressures in same permeable layers along traverse six miles updip and six miles downdip from site illustrated in Figure 15-73. |
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Figure 15-76. Pressure/depth profile,
Pinedale Field, Wyoming, with |
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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.
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