Temperature is the most sensitive parameter in hydrocarbon generation. Thus, reconstruction of temperature history is essential when evaluating petroleum prospects. No measurable parameter can be directly converted to paleotemperature. Maturation indices such as vitrinite reflectance, Tmax from Rock-Eval pyrolysis, spore coloration, Thermal Alteration Index (TAI), or concentration of biological markers offer an indirect approach. All these indices are a function of the thermal history through rather complex kinetics, frequently influenced by the type of organic matter. Their significance and validity are reviewed. Besides the problems of identification (e.g., vitrinite) and interlaboratory calibration, it is important to simultaneously interpret kerogen type and maturation and to avoid difficult conversions from one index to another. Geodynamic models, where structural and thermal histories are connected, are another approach to temper ture reconstruction which could be calibrated against the present distribution of temperature and the present value of maturation indices. Kinetics of kerogen decomposition controls the amount and composition of hydrocarbons generated. An empirical time-temperature index (TTI), originally introduced by Lopatin, does not allow such a quantitative evaluation. Due to several limitations (no provision for different types of kerogen and different rates of reactions, poor calibration on vitrinite reflectance), it is of limited interest unless one has no access to a desk-top computer. Kinetic models, based on a specific calibration made on actual source rock samples, can simulate the evolution of all types of organic matter and can provide a quantitative evaluation of oil and gas generated. Examples from the Jurassic source rocks of the Paris basin, Monterey Formation of California, Green River shales of Utah, Paleozoic source eds of the Algerian Sahara, and Miocene rocks of the Mahakam Delta, Indonesia, illustrate various aspects of the discussion. Geological/geochemical models are the most efficient way to integrate geological, seismic, and geochemical data, and they should greatly help to reduce the risk in exploration.

Thermal History of Sedimentary Basins, Maturation Indices, and Kinetics of Oil and Gas Generation

Overpressure can be produced by the following processes: (1) increase of compressive stress, (2) changes in the volume of the pore fluid or rock matrix, and (3) fluid movement or buoyancy. Loading during burial can generate considerable overpressure due to disequilibrium compaction, particularly during the rapid subsidence of low- permeability sediments. Horizontal stress changes can rapidly generate and dissipate large amounts of overpressure in tectonically active areas. Overpressure mechanisms involving change in volume must be well sealed to be effective. Fluid volume increases associated with aquathermal expansion and clay dehydration are too small to generate significant overpressure unless perfect sealing occurs. Hydrocarbon generation and cracking to gas could possibly produce overpressure, depending upon the kerogen type, abundance of organic matter, temperature history, and rock permeability; however, these processes may be self-limiting in a sealed system because buildup of pressure could inhibit further organic metamorphism. The potential for generating overpressure by hydrocarbon generation and cracking must be regarded as unproven at present. Fluid movement due to a hydraulic head can generate significant overpressure in shallowly buried, "well-plumbed" basins. Calculations indicate that hydrocarbon buoyancy and osmosis can generate only small amounts of localized overpressure. The upward movement of gas in an incompressible fluid also could generate ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received October 17, 1995; revised manuscript received September 4, 1996; final acceptance January 20, 1997. 2Department of Geological Sciences, Durham University, South Road, Durham DH1 3LE, United Kingdom. Osborne e-mail: M.J.Osborne@ durham.ac.uk; GeoPOP web site http://www.dur.ac.uk/~dgl0zz7/ We wish to thank the companies that support the Geosciences Project on Overpressure (GeoPOP) at the universities of Durham, Newcastle, and Heriot-Watt: Agip, Amerada Hess, Amoco, ARCO, Chevron, Conoco, Elf Exploration, Mobil, Norsk Hydro, Phillips Petroleum UK Company Limited, Statoil, and Total. We also thank Neil Goulty (Durham) for commenting on an earlier draft of this paper. Osborne thanks Gordon Macleod (Newcastle) for help with geochemical modeling.

Mechanisms for Generating Overpressure in Sedimentary Basins: A Reevaluation

Subsurface samples of shales ranging in age from Pleistocene to Eocene obtained from five Gulf Coast oil wells were examined mineralogically and chemically to determine the nature and extent of burial diagenesis in pelitic sediments. Illite/montmorillonite dominates the mineralogy and undergoes a monotonic decrease in expandability from about 80 to a limit of 20 per cent montmorillonite layers with increasing depth. The interstratification changes from random to ordered at about 35 per cent expanded layers. Discrete illite and kaolinite phases are ubiquitous and judged detrital. The discrete illite (mica) content of the whole rock decreases with depth, while the kaolinite shows no systematic variation. Chlorite occurs in appreciable amounts in only one well and there only in samples from the shallow water facies. This chlorite is also considered detrital.

Burial Diagenesis in Gulf Coast Pelitic Sediments

Clay swelling — A challenge in the oilfield

Aromatic components of coal: relation of distribution pattern to rank

The writer has established reference intervals in the subsurface on the basis of apparent systematic interlayer water loss of swelling clay minerals. The intervals are used in much the same manner as the familiar indicators for metamorphism, but are present at sufficiently shallow depths to be evident within oil-bearing strata of the Gulf Coast. The resulting conclusion is that clay-mineral diagenesis indicators may prove to be important petroleum-evaluation markers as well as fundamental properties of sedimentary basins. Sedimentary basins are viewed as combinations of gases, liquids, and semisolids distributed through a solid matrix. During geologic development the interstitial components segregate by migration and produce various commercially exploitable concentrations. Water, the principal fluid component of the sedimentary section, is thought to migrate in three separate stages. Initially, pore water and excessive (more than two) clay-water interlayers are removed by the action of overburden pressure. This initial water flow (which is essentially completed after the first few thousand feet of burial) reduces the water content of the sediment to about 30 percent, most of which is in the semi-solid interlayer form. A second stage of dehydration is thought to occur when the heat absorbed by the burie sediment becomes sufficiently great to mobilize the next-to-last water interlayer in an M(H2O)x + ^DgrHr = 1 + XH2O fashion. The final stage of sediment dehydration which extracts the last remaining water monolayer from clay lattices is apparently very slow, even by geologic standards, requiring tens or possibly hundreds of millions of years depending upon the geothermal and burial history of the sediment. Petroleum hydrocarbons which are distributed throughout the matrices of potential source beds in normal frequencies of 300-3,000 ppm are thought to be too sparse to initiate continuous fluid flow. In normal marine sediments, however, the water associated with clay minerals is present to a considerable depth in the order of 200,000 ppm, and therefore it is reasoned that this phase forms the connection between petroleum source and reservoir beds. The first and last dehydration stages are probably unimportant in Gulf Coast oil migration, inasmuch as they occur, respectively, at levels too shallow and too deep to intersect the interval of maximum liquid petroleum availability. The amount of water in movement during the second stage, at a level which does intersect this interval, is 10-15 percent of the compacted bulk volume and represents a significant fluid displacement capable of redistributing any mobile subsurface component. A measure of the degree to which the second-stage interlayer water has been discharged into the system can be noted on X-ray diffractograms. The movement appears to occur in a relatively restricted, depth-dependent temperature zone in which the average dehydration temperature of the points measured is 22 °F. With the use of an empirically derived P/T curve and a geothermal-gradient map, a set of regional subsurface dehydration contours can be constructed. A plot of 5,368 liquid petroleum production depths referenced to this dehydration "surface" shows an almost perfect Gaussian distribution. It seems significant that, although the dehydration depths range from 4,000 to 16,000 ft, hydrocarbon production depths are distributed in a statistically consistent relation to the calculated clay-dehydration contour surface.

John Frederick Burst

Papers

Diagenesis of Gulf Coast Clayey Sediments and Its Possible Relation to Petroleum Migration

Glauconite pellets; their mineral nature and applications to stratigraphic interpretations