Shale Velocity Research Articles

The effect of pressure on rock properties in the Gulf of Mexico: Comparison between compaction disequilibrium and unloading

We used statistical methods on rock properties derived from more than 480 wells to catalog shale velocity and density trends in different pressure regimes in the Gulf of Mexico and evaluated the reasons for their variations. A detailed evaluation of the density and velocity trends revealed that in the northern part of the Louisiana shelf, unloading is the major mechanism of overpressure. The onset of overpressure occurs at depths around 3000 m where temperatures are normally greater than 70°C. The relationship of the temperature gradient increase and the velocity decrease to the smectite-illite transformation allowed us to believe that inelastic unloading may be the major mechanism for overpressure in this region. On the other hand, in the southern part of the Louisiana shelf, abnormal pore pressure is often caused by compaction disequilibrium where the sediment section has a low sand percentage. In this type of pressure regime, velocity and density values cease to change at the onset of overpressure and essentially remain at the same value below the onset.

The velocity and attenuation anisotropy of shale at ultrasonic frequency

The velocity and attenuation anisotropy of dry and oil-saturated shale were measured at laboratory ultrasonic frequency by using the transmission technique. Our purpose is to find the variation rules of wave velocity and attenuation in different directions as a function of effective pressure in dry and oil-saturated situations, and those intrinsic factors that result in such anisotropy. Using x-ray diffraction techniques and a scanning electron microscope, the causative factors for the velocity anisotropy are found to be mainly due to the alignment of clay mineral and microcracks. The attenuation of P- and S-waves also shows apparent directional dependence, but different from that of velocities. Attenuation anisotropy can be interpreted in terms of grain and pore geometry. For dry shale samples, the dominant attenuation mechanism is phase hysteresis due to static friction. On one hand, the Biot flow plays a key role in causing wave attenuation for the P-wave propagating parallel to bedding for fluid-saturated samples. On the other hand, the fluid-related attenuation is mainly attributed to the mechanisms of squirt flow for the P-wave propagating vertical to bedding.

Anisotropy of elastic wave velocities in deformed shales: Part 2 — Modeling results

This study was devoted to the interpretation of the evolution of elastic wave velocities in anisotropic shales that are subjected to deformation experiments in the laboratory. A micromechanical model was used to describe the macroscopic effective elastic properties and anisotropy of the rock in terms of its microscopic features, such as intrinsic anisotropy and crack/pore geometry. The experimental data (reported in Part 1) were compared quantitatively with the micromechanical model predictions to gain some insight into the microstructural behavior of the rock during deformation. The inversion of the experimental data using the micromechanical model was carried out by means of a numerical minimization of the least-squares distance between data and model in terms of effective compliances. Under isotropic mechanical loading, the overall behavior of the dry shale is consistent with the closure of crack-like pores, which are aligned in theplane of symmetry of the transversely isotropic background matrix. Those cracks represent a low fraction of the total porosity, but they have a strong effect on elastic wave velocities. The data are consistent with an initial (horizontal) crack density of 0.07. Crack closure also is evidenced at early stages of axial loading applied perpendicular to the shale bedding plane, whereas crack density increases significantly as axial stress is increased. Interpretation of the wet experiment is less straightforward, although some preliminary conclusions could be drawn. Under isotropic stress, crack closure also is evidenced, whereas crack density remains constant at the early stages of deviatoric loading. When axial peak stress is approached, crack density increases drastically, which likely indicates onset and development of vertical cracking. Wet experiments probably are more complex because water is likely to be expelled from crack-like pores toward equant pores in response to the mechanical loading.

Analysis of large thermal maturity datasets: Examples from the Canadian Arctic Islands

Abstract This paper describes an approach for verifying thermal maturity data in a large historical dataset from the Canadian Arctic Islands. A compilation of more than 6000 maturity measurements (vitrinite reflectance and Rock-Eval Tmax) collected over the span of three decades involved a rigorous assessment of data quality. Some common anomalies in interpreting thermal maturity dataset include: (i) elevated thermal maturity due to Cretaceous igneous intrusion in the region, (ii) reworking of refractory material from older rocks into younger strata during the Triassic period, (iii) suppression of vitrinite reflectance and Tmax in hydrogen-rich samples, (iv) low maturity values due to cross-contamination by the younger sediments during drilling process (caving), and (v) offset maturity values obtained from different maturity measurements. The study discusses various independent checks to verify the obtained maturity parameters. The comparison between thermal maturity data with the sonic velocity of shale resulted in a satisfactory correlation. While such a correlation may vary in different sedimentary basins, it produces a useful independent assessment of thermal maturity. The results indicate that increased heat flow during the Jurassic–Early Cretaceous rifting of the Canada Basin may have caused the elevated maturity beyond the expected burial level as suggested by the discrepancy between thermal maturity and sonic velocity data. Given the fact that vitrinite reflectance records only the maximum temperature to which the enclosing rocks were exposed, deviation of the collected reflectance values from the current depth of burial serves as an indicator for the amount of geological uplift.

Geological constraints of pore pressure detection in shales from seismic data

ABSTRACTMethods for detection of pore fluid overpressures in shales from seismic data have become widespread in the oil industry. Such methods are largely based on the identification of anomalous seismic velocities, and on subsequent determination of pore pressures through relationships between seismic velocities and the vertical effective stress (VES). Although it is well known that lithology variations and compaction mechanisms should be accounted for in pore pressure evaluation, a systematic approach to evaluation of these factors in seismic pore pressure prediction seems to be absent. We have investigated the influence of lithology variations and compaction mechanism on shale velocities from acoustic logs. This was performed by analyses of 80 wells from the northern North Sea and 24 wells from the Haltenbanken area. The analyses involved identification of large‐scale density and velocity variations that were unrelated to overpressure variations, which served as a basis for the analyses of the resolution of overpressure variations from well log data. The analyses demonstrated that the overpressures in neither area were associated with compaction disequilibrium. A significant correlation between acoustic velocity and fluid overpressure nevertheless exists in the Haltenbanken data, whereas the correlation between these two parameters is weak to non‐existing in the North Sea shales. We do not presently know why acoustic velocities in the two areas respond differently to fluid overpressuring. Smectitic rocks often have low permeabilities, and define the top of overpressures in the northern North Sea when they are buried below 2 km. As smectitic rocks are characterized by low densities and low acoustic velocities, their presence may be identified from seismic data. Smectite identification from seismic data may thus serve as an indirect overpressure indicator in some areas. Our investigations demonstrate the importance of including geological work and process understanding in pore pressure evaluation work. As a response to the lack of documented practice within this area, we suggest a workflow for geological analyses that should be performed and integrated with seismic pore pressure prediction.

Seismic anisotropy in sedimentary rocks, part 2: Laboratory data

Part one of this paper presents a method for measuring seismic velocities and transverse isotropy in rocks using a single core plug. This method saves at least two‐thirds of the time for preparing core samples and measuring velocities in transversely isotropic (TI) rocks. Using this method, we have measured velocity and anisotropy of many shale and reservoir rocks from oil and gas fields around the world. We present some of the data in this paper, which include seismic velocity and anisotropy in 17 brine‐saturated shale samples, 1 gas‐ and brine‐saturated coal sample, 8 brine‐saturated sands, 12 gas‐saturated sands, 32 gas‐saturated carbonate samples, and 25 brine‐saturated carbonate samples. The results show that clays and fine layering in sedimentary rocks are the main causes of seismic anisotropy. Very little intrinsic anisotropy exists in unfractured reservoir rocks such as sands, sandstones, and carbonates under reservoir conditions. In contrast, all shales were found seismically anisotropic: anisotropy ranges from 6% to 33% for P‐waves and from 2% to 55% for S‐waves. The magnitude of shale anisotropy seems to decrease exponentially with increasing porosity. At present, the magnitude of shale anisotropy cannot be predicted accurately from other data without laboratory measurements. This paper also presents some best practices for laboratory measurements of shale velocity and anisotropy.

AVO Analysis of Long Offset Seismic Data Using 3-D Graphical Analysis

P-wave AVO intercept (A) and gradient (B) crossplotting is widely used for detecting anomalous elastic properties that may be indicative of hydrocarbons, but long offset seismic data are starting to become widely available. It is well known that the two-term AVO equation is only an approximation for angles of P-wave incidence less than 30°. However, long-offset seismic data with P-wave angle of incidence much larger than 30o are sometimes used to extract A and B values using a 2-term AVO equation. And then the extracted A and B values are used for AVO crossplotting and hydrocarbon detection. We show how inaccurate A and B values may result if the two-term AVO equation is used for prestack seismic data with large incident angles. A linear Vp–Vs and a Gardner-like Vp–ρ (rho) relationship explain the linear relationship between A and B for typical brine-saturated sandstones and shales, and this line passes through the origin. However, in the Gulf of Mexico (Hilterman, 1990) and Gulf of Thailand (Zhu, 2000), the sand velocity is sometimes larger than the shale velocity, while sand density is smaller than the shale density. As a result, the A–B trend of some brine-saturated sandstones and shales may not pass through the origin or may not be linear in the A–B plane. Nevertheless, a linear Vp–Vs relationship holds and the average Vp across the shale and sand interface does not vary significantly. AVO intercept (A), gradient (B) and curvature (C), which can be extracted from long offset prestack seismic data, are expressible in an equation representing a plane the 3-D A–B–C space. Deviations from this plane suggest abnormal velocities and indicate lithology and fluid variations.

Acoustic wave velocity modelling in sedimentary sequences

Layered-clay shale density increases systematically with increasing depth of burial by progressive expulsion of pore water: ρ(z)= ρ0​+ (ρ∞ − ρ0)(1 − e−kz)Using elastic wave propagation theory, this shale density function can be transformed into a shale velocity prediction. Providing shale and water chemistry remain relatively stable, the progressive reduction in shale porosity and contained water also results in systematic changes to shale resistivity.More general formation (mixed lithology) sonic slowness can be modelled using established log interpretation transforms (the Archie porosity - resistivity and Raymer-Hunt-Gardner porosity - slowness relationships). The difference between measured formation resistivity and predicted shale resistivity is then interpreted in terms of departure of the expected slowness from that of pure shale. When added to the expected shale slowness, the combined slowness shows good agreement with observed sonic log data.This provides a new technique for prediction of formation velocities. The technique can be used to improve the quality of sonic log data, and can be applied where no sonic data were acquired. Numerous technical and commercial applications result.

Quantifying Erosion in Sedimentary Basins from Sonic Velocities in Shales and Sandstones

If it is assumed that sonic velocity in a sedimentary rock decreases with burial-depth according to a known velocity/depth relationship, and that velocity is not reduced by erosion from maximum bur...

Documenting the sand/shale crossover

All types of velocity data, i.e., surface seismic and well log or sonic log data, indicate that velocity in shallow, unconsolidated sands is lower than in associated shales, while velocity in older sands in more consolidated rock sequences is higher than in their associated shales. As the low‐velocity sands compact to become the high‐velocity member in the sand‐shale sequence, sand and shale velocities must become equal or crossover at some age and depth of burial. If the same type of velocity data is used consistently, this crossover occurs at the same depth and age of rocks in the geologic sequence as would be indicated by other types of velocity data, even though the different kinds of velocities would not agree elsewhere. If all rocks in the province are older and compacted, this crossover of sand and shale velocities may not be observed or, if observed, may be very near the surface.

An Interpretation of Vitrinite Reflectance Data From the Southern North Sea Basin

Summary Vitrinite reflectance data for the Carboniferous in 68 Southern North Sea Basin wells have been used to determine a maturity-depth relationship for the basin and to provide an estimate of basement inversion. The derived maturity-depth relationship is comparable with maturity gradients in other Paleozoic coal and gas basins known to have had similar geothermal histories. The earliest onset of gas generation in the Southern North Sea was in the late Jurassic following the accumulation of ± 11700 ft (3500 m) of sediment above the Carboniferous source beds. Estimates of inversion of the Sole Pit area using vitrinite data are similar to those based on shale velocity methods (± 1500 m maximum). In some areas the amount of inversion of the Carboniferous basement apparently exceeds that of the post-Zechstein section which may be attributed to removal of significant amounts of late Carboniferous strata during late Hercynian times; these areas are also associated with the principal gas discoveries in the basin.

Ultrasonic velocities in cretaceous shales from the Williston Basin : Jones, L E A; Wang, H F Geophysics, V46, N3, March 1981, P288–297

Ultrasonic velocities in cretaceous shales from the Williston Basin : Jones, L E A; Wang, H F Geophysics, V46, N3, March 1981, P288–297

Ultrasonic velocities in Cretaceous shales from the Williston basin

Compressional and shear‐wave velocities were measured in the laboratory from 1 bar to 4 kbar confining pressure for wet, undrained samples of Cretaceous shales from depths of 3200 and 5000 ft in the Williston basin, North Dakota. These shales behave as transversely isotropic elastic media, the plane of circular symmetry coinciding with the bedding plane. For compressional waves, the velocity is higher for propagation in the bedding plane than at right angles to it, and the anisotropy is greater for the 5000-ft shale. For shear waves, the SH‐wave perpendicular to bedding and the SV‐wave parallel to bedding propagate with the same speed, which is about 25 percent lower than that for the SH‐wave parallel to bedding. In general, compressional and shear velocities are higher for the indurated 5000-ft shale than for the friable 3200-ft shale. All velocities increase with in‐increasing confining pressure to 4 kbar. The 3200-ft shale exhibits velocity hysteresis as a function of pressure, whereas this effect is almost nonexistent for the 5000-ft shale. Many features of the dependence of velocity on pressure can be explained by consideration of effective pressure and the degree of water saturation. For both shales, laboratory compressional wave velocities are on average 10 percent higher than log‐derived velocities. The discrepancy cannot be explained completely, but likely contributing factors are sampling bias, velocity dispersion, and formation damage in situ.

A Review of Geopressure Evaluation From Well Logs - Louisiana Gulf Coast

Recent Gulf Coast drilling experience and log data reveal irregularities in resistivity trends. Anomalies caused by age boundaries, younger sediments, and other phenomena may make log relationships difficult to apply. The geographic distribution and interpretation techniques for some of these anomalies are presented. Resistivity-trend departure/pressure relationships are examined. Introduction Since the beginning of geopressure drilling in the Louisiana Gulf Coast, attempts have been made to quantify log parameters as an aid in pressure prediction.In 1965, Hottman and Johnson presented an empirical correlation relating abnormal formation pressures to departures from normal shale velocity and resistivity trends observed in Gulf Coast formations. These relationships have been used widely for predicting younger Tertiary abnormal pressures, although both sets predicting younger Tertiary abnormal pressures, although both sets of data were obtained from Miocene-Oligocene sediments.In recent years, other empirical but largely undocumented resistivity relationships, based chiefly on mud-weight observations, have been established and are commonly used offshore. These account for local trend anomalies wherein the Hottman and Johnson resistivity relationship is not suitably accurate. Some of these erratic trends have been found to be systematic either in kind or areal extent and, once recognized, can be interpreted. In 1972, while this study was in progress, Eaton suggested that variations in overburden gradient might be responsible for irregularities in departure trends.Since 1965, drilling activity has moved farther offshore into younger Pleisto-Pliocene sediments. With the onset of production in these newer fields, some 50 additional pressure measurements in virgin geopressured reservoirs have become available. The density log has become the primary porosity log offshore, and the prevalence of density data provides a means to calculate overburden prevalence of density data provides a means to calculate overburden gradients in these fields. It is considered timely to include the new data with those of Hottman and Johnson. Resistivity data are emphasized because the resistivity device often is the only log run over sufficient intervals of borehole. Pressure Estimation Pressure Estimation To estimate formation pressures from logs in the Gulf Coast, the following information is necessary:an established normal log response trend in hydropressured shales,an observed departure from the normal trend, andan empirical relationship between this trend departure and formation pressure gradient. Hydropressured Trends The first trends of sonic and resistivity data for the offshore Miocene-Oligocene were presented by Hottman and Johnson. These trends are averages of early observed data in the Louisiana Gulf Coast. However, since compaction trends probably depend not only on depth but also on rate of compaction, cementation, and overburden, these Miocene-Oligocene data should not necessarily apply to the Pleisto-Pliocene sediments presently being explored. Fig. 1 shows the observed normal pressure resistivity trends superimposed on an age-correlation dip section from Atchafalaya Bay through Vermilion Block 321. Because of sediment age, the Hottman and Johnson trends apply to Atchafalaya Bay and Eugene Island Block 100. JPT P. 963

New Aspects of Quantitative Interpretation of Velocity Data and Their Impact on Geologic Evaluation of Exploration Prospects: ABSTRACT

Studies on elastic wave velocities in rocks have proved increasingly useful in the geologic investigation of sedimentary basins. Velocities of sediments are End_Page 345------------------------------ closely interrelated with their lithology, structure, and fabric, and strongly reflect their alteration through diagenetic processes. Perhaps the most important of these processes, the compaction of clastics, causes progressive and unilateral reduction of pore space and expulsion of fluids. Compaction status--especially of shales--can be measured by interval velocities which increase irreversibly up to the maximum burial depth. In any specific basin, therefore, shale velocities indicate later uplift and thus aid in recalculating the thickness of eroded sediments. Shale velocities, when observed vertically and parallel with the bedding plane, exhibit an anisotropy which probably decreases with growing lateral tectonic stress. Rapidly deposited shales and shales embedded in evaporites, how retarded compaction and consequently delay in velocity increase. Psammites and carbonates have more complicated velocity patterns due to the complexity of their diagenesis. Evaporites show little compaction because of their primary lack of porosity. All these phenomena are reflected in velocities and have been studied in basins where numerous well-velocity data were available (e.g., NW German basin). Seismic velocity data, collected through advanced modern techniques, serve the same purpose. Although their accuracy is still comparatively limited, an almost quantitative interpretation may be reached with the aid of mathematical and statistical treatment of sedimentation models. End_of_Article - Last_Page 346------------

OUTLINING OF SHALE MASSES BY GEOPHYSICAL METHODS

Shale masses are here defined as large bodies of shale at least several hundred feet in thickness. These may be formed either as diapiric masses or as depositional masses. The shale masses are like salt masses and the two are many times combined to form domal masses; they both may form the updip seal for stratigraphic accumulation of oil. The shale masses exhibit the following properties by comparison to the normal section: (1) low velocities—in the range of 6,500 to 8,500 ft/sec with very little increase of velocity with depth, (2) low densities—estimated to be in the range [Formula: see text] to [Formula: see text], (3) low resistivities—approximately 0.5 ohm‐m, and (4) high fluid pressures—about 0.9 overburden pressure. These properties all seem to be caused by the high porosity and low permeability of these large shale masses. Maps and cross sections of an example area block 113, Ship Shoal Area are shown. The low shale velocities were measured by acoustic logs and verified by refraction shooting. The low densities were deduced from gravity maps. The low resistivities are shown on electric logs, and high pressure is evidenced by the drilling difficulties with heaving shales. These physical properties allow the outlining of the shale mass by one or more of the following ways: the gravity method is used to outline the low density material, the seismic reflection method is used to outline the lack of reflection contrast and in some cases map the velocity configuration, the seismic refraction method is used to indicate the velocity of the anomalous mass, thereby differentiating between shale and salt.

Sonic Logging

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 106–114. Abstract The principle, the equipment and field operation of sonic logging are described. The two-receiver system produces logs independent of hole size and mud. Field experience is given and forms the basis for the interpretation of the log. The derivation of porosity values from measured velocities is discussed, according to the type of formations (hard formations, compacted sands, and unconsolidated formations). The time-average equation proposed by M.R.J. Wyllie, A.R. Gregory and L.W. Gardner is used as a basis for the computation of porosity in limestones, cemented sandstones and compacted sands. Variations in the lithologic character of limestones do not seem to change the porosity calibration markedly. The compaction of sands is related to the compaction of shale adjacent to them; and, thus, the shale velocity is used for the establishment of empirical relations for the computation of porosity in unconsolidated formations. Various formulas are tentatively presented to account for shale and fluid content. Field experience demonstrates that considerable attenuation of sonic energy takes place in unconsolidated formations, particularly when gas bearing, and in fractured formations. Unusually large attenuation produces skipped cycles, a feature easily recognized. The application of sonic logging to structural studies is featured, showing its possible integration with the dipmeter. Correlation and its application to the interpretation of seismic surveys are reviewed.The paper is illustrated with field examples. Introduction Sonic logging is the recording of the time required for a sound wave to traverse a definite length of formation. Sonic travel-times are inversely proportional to the speed of sound in the various formations.The speed of sound in subsurface formations depends upon the elastic properties of the rock matrix, the porosity of the formations and their fluid content and pressure. Below the "weathered" or low-velocity layer extending from 50 to 100 ft or so below the surface, sound velocities may range from about 6,000 ft/sec in shallow shales to as much as 24,000 ft/sec in dolomites. In hard formations (well cemented and/or compacted), the sonic log reflects the amount of fluid in the formations; hence, it correlates well with their porosity.

DISCUSSION ON: LATERAL VELOCITY VARIATIONS NEAR BOREHOLES

The discrepancies between regular geophone‐type logs or surveys and continuous velocity surveys have been noted ever since the latter came into use. Hick’s speculations as to the cause of these discrepancies in terms of compositional and structural changes in the rock surrounding the borehole are, therefore, welcome. His description of the actual mechanism of alteration of shale velocity due to shale damage is, however, brief, and some additional and/or alternative causes, which could be considered, are given below.

Influence of Geological Factors on Longitudinal Seismic Velocities

An examination has been made of velocity data obtained from fifty wells located in eight states. There is definite evidence to show that the velocity of shale and sandstone sections increases with the geologic age of the beds. Less reliable evidence points to a similar relationship for limestone velocities. The velocity of calcareous sandstones and shales is substantially higher than that of a normal sand-shale section. The effect of depth on the velocity of a given section is investigated. There is a definite increase in velocity with depth in the case of shale and sand sections. Increase of velocity with age is ascribed to the general increase of the lithification of sediments with age.