Estimation of Formation Pressures from Log-Derived Shale Properties

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Abstract
Fluid pressure within the pore space of shales can be determined by using data obtained tram both acoustic and resistivity logs. The method involves establishing relationships between the common logarithm of shale transit time or shale resistivity and depth for hydrostatic-pressure formations. On a plot of transit time vs depth, a linear relationship is generally observed, whereas on a plot of resistivity vs depth, a nonlinear trend exists. Divergence at observed transit time or resistivity values from those obtained from established normal compaction trends under hydrostatic pressure conditions is a measure of the pore fluid pressure in the shale and, thus, in adjacent isolated permeable formations. This relationship has been empirically established with actual pressure measurements in adjacent permeable formations. The use of these data and this method permits the interpretation of fluid pressure from acoustic and resistivity measurements with an accuracy of approximately 0.04 psi/ft, or about 400 psi at 10,000 ft. The standard deviation for the resistivity method is 0.022 psi/ft, and for the acoustic method 0.020 psi/ft. Knowledge of the first occurrence of overpressures, and of the precise pressure-depth relationship in a geologic province, enables improvements in drilling techniques, casing programs, completion methods and reservoir evaluations. INTRODUCTION: GENERAL STATEMENT: Operators engaged in the search for and production of hydrocarbon reserves in Tertiary basins are more and more frequently confronted with complications associated with overpressured (abnormally high fluid pressure) formations. This is particularly true in the Texas-Louisiana Gulf Coast area. The problems associated with these formations are of direct concern to the combined activities of all phases of operations, i.e., geophysical, drilling, geological and petroleum engineering.1–2 Knowledge of the pressure distribution of a given area of operations would greatly reduce the magnitude of many of these complexities and in some cases would completely eliminate specific problems. This paper presents techniques developed for estimating formation pressures from interpretations of acoustic and electric log data. Specifically, the acoustical and electrical properties of shales, reflected by conventional acoustic and electrical surveys, can be used to infer certain reservoir properties, such as formation pressure, at any level in a well. It has been possible to develop these techniques because of a firm understanding of the basic principles that govern and apply to such overpressured provinces. NORMAL PRESSURES: Normal pressures refer to formation pressures which are approximately equal to the hydrostatic head of a column of water of equal depth. If the formations were opened to the atmosphere, a column of water from the ground surface to the subsurface formation depth would balance the formation pressure. On the Gulf Coast, the shallow, predominantly sand formations contain fluids which are under hydrostatic pressure. These formations are said to be normally pressured or to have a normal pressure gradient.* Experience has shown that the normal pressure gradient on the Gulf Coast is approximately 0.465 psi/ft of depth. OVERPRESSURES: Formations with pressures higher than hydrostatic are encountered at varying depths in many areas. These formations are referred to as being abnormally pressured, abnormally high pressured, or overpressured. Formation pressures up to twice the hydrostatic pressure have been observed. These formations require extreme care and much expense to drill and to exploit. COMPACTION-FLUID PRESSURE RELATIONS THEORY: The generation of overpressured formations in Tertiary sections of the Gulf Coast and several other Tertiary sedimentary basins is, in general terms, considered to be primarily the result of compaction phenomena.1 This portion of the paper presents a brief review of the theory which associates compaction and fluid pressure relations, and should thus provide the necessary background for an understanding of the techniques presented. See Hubbert and Rubey4 for a more comprehensive treatment of this subject. GENERAL STATEMENT: Operators engaged in the search for and production of hydrocarbon reserves in Tertiary basins are more and more frequently confronted with complications associated with overpressured (abnormally high fluid pressure) formations. This is particularly true in the Texas-Louisiana Gulf Coast area. The problems associated with these formations are of direct concern to the combined activities of all phases of operations, i.e., geophysical, drilling, geological and petroleum engineering.1–2 Knowledge of the pressure distribution of a given area of operations would greatly reduce the magnitude of many of these complexities and in some cases would completely eliminate specific problems. This paper presents techniques developed for estimating formation pressures from interpretations of acoustic and electric log data. Specifically, the acoustical and electrical properties of shales, reflected by conventional acoustic and electrical surveys, can be used to infer certain reservoir properties, such as formation pressure, at any level in a well. It has been possible to develop these techniques because of a firm understanding of the basic principles that govern and apply to such overpressured provinces. NORMAL PRESSURES: Normal pressures refer to formation pressures which are approximately equal to the hydrostatic head of a column of water of equal depth. If the formations were opened to the atmosphere, a column of water from the ground surface to the subsurface formation depth would balance the formation pressure. On the Gulf Coast, the shallow, predominantly sand formations contain fluids which are under hydrostatic pressure. These formations are said to be normally pressured or to have a normal pressure gradient.* Experience has shown that the normal pressure...

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