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Handbook on Static Pressures*
By
D. E. Powley1
Search and Discovery Article #60007 (2006)
Posted May 1, 2006
*Amoco Production Company Research Department Report F87-G-19, August 3, 1987
1Amoco Production Company, retired, Tulsa, Oklahoma 74136
Introduction
This report was prepared to fulfill the dual objectives of (1) being used as Section 15 in the Amoco training manual “Advanced Formation Evaluation” currently undergoing extensive revisions, and (2) being a report of part of the investigation conducted pursuant to Geological Research Proposal 86-7 “Develop Methods for Estimating Volumes of Sand Bodies and Heights of Hydrocarbon Columns within Overpressured Fluid Compartments.” The format of the report follows the requirements of the Amoco Training Center in Houston. The succession of topics progresses from basic to complex to allow for terminations of training courses anywhere within the text. The report should provide office engineers and operations geologists who are inexperienced in the use of subsurface fluid pressures with a jump-start into semiprofessional level interpretations of static; i.e., nontransient, pressures data. This report will be followed by a companion report which will deal with techniques used mainly by specialists in the interpretation of regional static pressures.
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uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
uRecognition of abnormal pressures uFigs. 15-13 - 15-20, Table 15-1 uPressures interpretations of water uPressures interpretations of petroleum uInterpretations of fluids within seals
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Fluid Pressures - General
TextPressure is the force per unit area which fluids (liquids and gases) exert on the surface of any solid which they contact. Pressure exists at every point in a fluid at rest. The magnitude of the pressure is proportional to the depth below the surface and to the density of the fluid; i.e., the pressure is the same at all points at the same level within a uniform density fluid (Figure 15-1) if the fluid is static; i.e., not in motion. The pressure in a fluid at rest is independent of the shape of the containing vessel and is the same whether the vessel contains a fluid only or contains a fluid and a quantity of solids in grain-to-grain contact; i.e., not a suspension. Thus, in the earth, the pressure in a static subsurface fluid is independent of the shape and size of the rock pores but is dependent upon the density of the fluid and upon the depth below its surface (Figure 15-2). In the earth, the datum water surface usually cannot be seen. However, pressure calculations commonly indicate that the rock pores are fluid-filled and interconnected from the top of the free water in the soil down to at least intermediate depths. Inasmuch as the soil water surface is usually only a few inches to a few feet below the topographic surface, it has become common practice to consider the free water surface and the topographic surface to be the same. In marine areas, the free water surface is considered to be mean sea level. The hydrostatic pressure is that caused by the weight of a freestanding fluid column without any external pressure being applied. If any external pressure is applied to any confined static fluid, the pressure at every point within the fluid is increased by the amount of the external pressure. This statement is known as Pascal's Principle, after the French philosopher who first clearly expressed it. An example of a confined static fluid is the fluid below a piston in a closed cylinder. The pressure in the fluid increases as external pressure is applied and returns to normal when the pressure is removed. Within the confined static fluid, the rate of increase in pressure downward; i.e., the interval pressure gradient, is the same with or without an external pressure (Figure 15-3). In geology, the counterpart to the piston and cylinder walls of Figure 15-3 are any combination of rock layers, faults, and interfaces which completely enclose a body of fluid-bearing rock in a low-permeability envelope. The low-permeability envelope is usually referred to as a seal. A seal is usually thin with respect to both thickness and lateral extent of the enclosed rock body. An abnormally pressured rock body is like a huge bottle (Figure 15-4). It has a thin, essentially impermeable outer seal and an internal volume which exhibits effective internal hydraulic communication. The interval rate of increase in pressure with increasing depth within the internal volume is in direct accordance with the density of the internal fluids (Figure 15-5). The fluid pressures in the internal volume may be greater than, equal to, or less than the pressures in the fluids in the rocks outside of the seal. The magnitude of the internal fluid pressure is dependent on how much of the weight of the superincumbent rock column is borne by the fluids in the enclosed body and how much of the weight is borne by the rock matrix in the enclosed body. The fluid pressure below the top seal at the shallowest point in the enclosed rock body can range from zero, where the rock matrix bears all of the weight of the superincumbent rock, to about 1 psi/foot thickness of overlying rock if the enclosed rock matrix bears none of the weight of the superincumbent rock load (Figure 15-6). The Keyes Field in northwestern Oklahoma is illustrative of the 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 PressuresFigures 15-10 to 15-12
TextIn most deep basins in the world there is a layered arrangement of at least two superimposed hydraulic systems (Figure 15-10). The shallowest hydraulic system can extend to great depths; however, in many basins it extends from the surface down to about 10,000 feet, greatest historical depth of burial, in normal geothermal gradient basins and to slightly greater depths in cool basins. There are a few remarkable deviations, like the central North Sea 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 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 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
TextNone of the foregoing indirect indicators of abnormal pressures or the pressures calculated from indirect indicators are as reliable as a few measured pressures. Until the mid-1970's, the only measured pressures available in overpressured soft rock sections in most wells were pressures measured during initial production tests run after the wells were drilled, cased, and perforated. Open hole drillstem tests have been routinely run in normally pressured and underpressured firm rock sections since 1935; however, the reported shut-in pressures tended to be unreliable because the mud (hydraulic) pressures in the wellbores usually exceeded formation fluid pressures with possible consequent distortions in measurements (supercharging) of shut-in formation fluid pressures prior to opening the tool. The more common problem was that a measurement of static pressure made after the test was completed was distorted by drawdown of pressures during testing (Figure 15-21). There is nothing basically wrong with drillstem test tools or gauges for pressure measurements; the shortcoming is that the usual purposes for using the tool do not include a serious attempt to measure the static pressure in the rock interval being investigated. The usual purposes for using the tool are to determine the type of formation fluid present, to indicate a short term production rate, to record sufficient transient (not static) pressures data to provide a basis for estimating average reservoir permeability within the radius of investigation, and lastly to indicate the extent of wellbore skin damage. Obtaining reliable static pressures can be added to the list if the operator is willing to pay for the extra rig time usually required for shut-in pressures to stabilize. Many of the pre-l975 recorded shut-in pressures are more reliable than data from later tests because early testing engineers generally had more wellsite authority. The commercialization of wireline repeatable formation testers in 1974 ushered in a whole new era in well control and well data interpretation. They can record an unlimited number of pressure measurements during a single trip into a wellbore. Two independent formation fluid samples can also be taken on the same trip. Those test tools are reliable, rugged, and very sensitive to minor differences in pressures. They withdraw such a tiny amount of fluid from the formation being tested that drawdown of pressures is not a problem. Pressures measured with repeat formation testers, like pressures measured with drillstem testers, are subject to distortion by supercharging of low permeability rocks by the pressures in the wellbore mud column. Figure 15-22 portrays the pressures measured with a wireline repeatable formation tester in a field in the North Sea. Note that the fluid compartments portrayed in Figures 15-23 and 15-24 have very small but consistent pressure differences from compartment to compartment. Neither production tests or drillstem tests could have provided pressure data of similar reliability. The only real limitations to the use of wireline repeatable formation testers are (1) that the tester works well only in soft formations, and (2) the tester run must be preceded by some porosity indicator log, such as an electrical log to select the depths at which pressures are to be measured. The pressure values from repeat formation tests should be corrected for temperature effects on the quartz gauges in the test tools. The corrections are supplied by the testing contractors. It is suggested that up to 30 pressure measurements be made in water-bearing porous zones over a depth interval of up to 300 feet above and below each zone of interest to establish a water base line if there is any indication that the zone of interest in a new well is either overpressured or underpressured. Usually, it is also prudent to make several pressure measurements within pay zones to provide data for estimations of drawdown and buildup permeability at precise depths.
Pressures Interpretations of Water in Open Hydraulic Systems
Figures 15-25 to 15-36
TextExploration geologists and well planning engineers have similar problems regarding locating, sorting, and assembling pressure data. Both are required to make interpretations regarding specific sites or specific areas using whatever data are available. Both groups work primarily with water dominated fluids systems. The ensuing discussion, while aimed mainly at well planning engineers, is equally applicable to exploration geologists. Engineers drawing up the operating specifications for wildcat wells are frequently faced with the necessity of anticipating static fluid pressures in underground formations in regions where industry practice has been to run only about one drillstem test somewhere in each well. At first glance, it may seem to be impossible to assemble enough data to do an adequate job of anticipating the pattern of pressures to be encountered by the planned well. Pressures measured in drillstem tests have been labeled “unreliable” earlier in this report; however, large files of unreliable drillstem test data may be used to identify overpressured and underpressured fluid compartments. Amoco's Well Data I and Well Data II computer files contain an enormous quantity of pressures data derived from drillstem tests. When such data from many wells are plotted onto pressure/depth charts, the overall patterns may yield very reliable indications of static pressures. Those patterns can indicate whether abnormal pressures should be anticipated, whether those abnormal pressures are overpressures or underpressures, and the approximate depths at which mud weight control likely will be required. Inasmuch as those data files contain both virgin pressures and pressures drawndown by production, it seems prudent to attempt to avoid being misled by local drawndown pressures. Figure 15-25 illustrates the recorded pressures measured at various times through the life of two fields. Note that the pressures at discovery (the highest pressures), are significant if a wildcat well is being planned and the lower pressures have no significance unless the planned well is to be drilled in, or adjacent to, the field. Figures 15-26, 15-27, 15-28, 15-29, 15-30, 15-31, and 15-32 illustrate the kinds of fluid compartment implications which can be derived from critical examination of large masses of pressure data, even though every data point may be somewhat unreliable. Pressure/depth or pressure/elevation profiles may be constructed on an area basis (Figures 15-25 through 15-30) or on a formation-by-formation basis (Figures 15-31 and 15-32). Duplication of the mud program used in nearby old wells may be sufficient to select an acceptable mud program in a new well; however, mud programs in a few old wells usually cannot be reliably converted into subsurface static pressures in abnormally pressured fluid compartments. Use of mud data from a few old wells is subject to considerable bias ranging from the operator's state of knowledge about pressures at the time the old wells were drilled to how safe-from-blowout the operators of the wells wished to drill their wells. Figure 15-33 illustrates how large files of mud density data from well log headers, converted to equivalent bottomhole pressures, plotted onto pressure/depth charts may be indicative of both the regional top of the top seal (the first kink in the data profile) and the base of the top seal (the second kink in the data profile) in overpressured fluid compartments. A hydrostatic interval pressure/depth gradient line drawn downward from the base of the top seal provides a reasonably reliable indicator of static fluid pressures in deeper rocks within the compartment. The use of large files of mud density data reduces the biases inherent in using mud data from single wells. Some operators drill wells with slightly underbalanced mud columns to attain increased drilling penetration rates. Drilling kicks in such wells may provide accurate indicators of the formation fluids pressure/depth ratios at the depths at which the kicks were experienced. Figure 15-34 shows a well in which the data from only two drilling kicks could have led to a reasonably accurate interpretation of the pressures in two superimposed fluid compartments, providing the interpreter kept in mind that the pressure/depth ratio of the fluids in fluid compartments, like mud in wellbores, cannot exceed the local fracture gradient. The foregoing discussions regarding the use of inaccurate data presumed that the inadequacies are resident in the original data. However, there can be a large error factor introduced by human carelessness all along the line from recording of wellsite data to data introduction into computer files. Transposed numbers; i.e., numbers copied out of sequence, are an ever present menace when making interpretations of subsurface pressures. Figure 15-35 illustrates a typical 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
TextAll 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
TextEarlier in this report, a fluid compartment was described as having “a thin, essentially impermeable outer seal and an internal volume which exhibits effective hydraulic communication.” An analogy was made between a fluid compartment and a buried bottle. The analogy provides an adequate description of the hydraulic conditions within the internal volumes of fluid compartments, and it is functionally correct regarding seals, but it is somewhat misleading regarding the internal structure of seals. Seals, like the glass in bottles, are essentially impermeable across their total thickness but, unlike glass, may exhibit a high order of internal directional permeability parallel to their outer surfaces. Therefore, a fluid compartment may be like a buried bottle which was constructed of some laminated material rather than being like a buried glass bottle. Figure 15-69 is a restatement of Figure 15-4 but portrays a fuller description of the seal. Several figures used earlier in this report depicted pressure/depth profiles across seals with a linear increase or linear decrease in pressures with increasing depth. The linear rates of pressure change across the seals appear to bear no relationship to whether the permeable streaks within the seals contain gas, 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.
FinaleThe level of skills advanced in this report is sufficient for most day-to-day interpretations of local static pressures in underground formations by operations geologists and office engineers. This report will be supplemented with a later report which will advance into more involved techniques of interpretations of static pressures appropriate to specialists in regional pressure studies.
References and Suggested Reading Alliquander, O., 1973, High pressures, temperatures plague deep drilling in 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. |
