Parke A. Dickey

Possible Primary Migration of Oil from Source Rock in Oil Phase: GEOLOGIC NOTES

It is now generally believed that most petroleum is generated at temperatures between 60 and 150°C, corresponding to depths of burial of 1,500 to 4,500 m. At these depths shale source rocks have lost most of their water and practically all their permeability. If a good source rock still contains 500 ppm hydrocarbon, it probably has expelled a similar amount. If such a rock was subjected to a porosity loss of 10 percent during the time that it gave up 500 ppm by weight, the ratio of hydrocarbons to hydrocarbons plus liquid is 12,000 ppm, or 1.2 percent by volume of the liquid. There is no possibility of dissolving this much oil in water, even with the aid of solubilizers. Much of the shale surface may be wetted by oil, so that the saturation at which oil will flow as a continuous phase may be less than 10 percent. Furthermore, much of the water in the pores is structured and may behave like a solid. For fluid flow it might be considered as part of the solid matrix, and oil then would form a large fraction of the pore liquid. The relative permeability of the shale to oil then would become greater than to water. As compaction of the source rocks proceeds, shales might expel oil preferentially to water.

Increasing concentration of subsurface brines with depth

Abstract The concentration of deep subsurface brines of the chloride-calcium chemical type normally increases with depth. In many areas the increase is linear over thousands of feet vertically. The rate of increase ranges between 15,000 and 100,000 p.p.m. 1,000 ft. (50–300 mg/l/m). In the Gulf Coast this relationship reverses at great depths. Here, however, the presence of abnormal fluid pressures indicates that processes of compaction and diagenesis are not yet complete. Any hypothesis to account for the chemical composition of these brines must explain the linear nature of the increase in concentration with depth.

Geology and Geochemistry of Crude Oils, Bolivar Coastal Fields, Venezuela

The Bolivar Coastal Fields (BCF) are located on the eastern margin of Lake Maracaibo, Venezuela. They form the largest oil field outside of the Middle East and contain oil which is mostly heavy with a gravity less than 22° API. Lake Maracaibo is now in an intermontane basin enclosed on three sides by the Andes Mountains. The area has a complex history and tectonic movement continues today. In the Cretaceous, the area was part of the platform of a large geosyncline, but by the Eocene it was near a coast where a series of large sandy deltas was deposited, with terrestrial sediments on the south and thick marine shales on the north. At this time, conditions for oil generation in the shales and migration to the sands were established, but the subsequent Oligocene faultin , uplift, and erosion may have allowed meteoric water to penetrate into reservoirs. During the Miocene and Pliocene, the basin was tilted first west and then south, and filled with continental sediments from the rising Andes. Tilting is still continuing and oil is moving up along the Oligocene unconformity, forming surface seeps. Most oil fields are located in sands above the unconformity or in fault blocks immediately below it. Thirty crude oils from the BCF were collected along two parallel and generally southwest-northeast trends. These oils were characterized by their API gravity, percent saturates, aromatics, NSO and asphaltic compounds, gas chromatograms for whole oils, C4-C7 fractions, and aromatics. Also, 24 associated waters were sampled and analyzed for Ca++, Mg++, Na+, HCO3-, CO3=, SO4=, pH, and total dissolved solids (TDS). The oils show the classic sequence of biodegradation and range from green, 40° API oils with a full suite of n-alkanes and isoprenoids, to black, heavy oils with a gas chromatogram that is an unresolved hump. In many respects the oils are chemically simi ar and appear related, possibly sharing the same source rock. The Miocene L-5 reservoir contained two oil types which did not appear to fit the main trend. One type is depleted in n-alkanes in the range C8-C14, whereas the other type is depleted in n-alkanes above C17. Benzene and toluene values for these oils were normal. In general, oils in the Eocene reservoirs below the unconformity are less degraded than those in the Miocene sands above it. The formation waters range from very salty (62,000 mg/L), to quite dilute (3,000 mg/L). Those associated with the degraded oils are typically meteoric in chemical composition with considerable bicarbonate (20 to 90 meq/L), small quantities of chloride (2 to 25 meq/L), and extremely low amounts of magnesium and calcium (mostly less than 1 meq/L). If the amount of bicarbonate is taken as an indicator of the meteoric character of the water, then the more meteoric the water, the more degraded the oil. The presence of at least four classes of waters with different compositions in the area of the BCF suggests that there is no through-going flow at present. Many of the fields have oil-water contacts descending toward the south, showing that continued tilting southward occurred during the Mio ene and Pliocene after the oil was emplaced in the reservoir. It seems likely that there was large scale secondary migration of oil from south to north, probably along the unconformity surface, which still leaks oil where it is exposed. In the shallower Miocene reservoirs along the northeast margin of the field, heavy asphaltic oil overlies lighter oil downdip to the west and south. This suggests that the oil became more degraded the farther it moved, finally becoming viscous and asphaltic, possibly even gelled. In this immobilized form it acted as a seal trapping the less degraded oil which followed.

Patterns of Chemical Composition in Deep Subsurface Waters: GEOLOGICAL NOTES

Stagnant connate waters associated with oil fields are similar in ratios of ions and cations. The principal ion is chloride--nearly always 99 percent. The principal cations are sodium, calcium and magnesium, and the usual Ca/Mg ratio is 5 to 1 (in equivalent weights). The concentration ranges from about 50,000 to 350,000 ppm. There is a general tendency for this type of water to increase in concentration with depth. In artesian situations the compositions of oil field waters is different. They range in concentration from 5,000 to 15,000 ppm. Sodium is the predominant cation, 85 to 100 percent and calcium and magnesium are rare or absent. These waters are classified into two types by their anions: (1) those without SO 4 and HCO 3 from 3 to 85 percent and (2) those with more than 50 percent SO 4 .

Oil and Gas in Reservoirs with Subnormal Pressures

Oil and gas are common in stratigraphic traps in structural basins, both deep down near the bottom, and also along the flanks. In many of these traps initial reservoir pressures were subnormal, indicating a lack of permeable connection to the outcrop. Some maps drawn on the potentiometric (piezometric) surface using pressure data from drill-stem tests show clearly the location of the stratigraphic barriers which have trapped the oil; these maps should be used in prospecting. Many giant gas fields with abnormally low initial reservoir pressures are low on the flanks of structural basins. The geologic factors favoring this type of accumulation are not understood. The cause of the low pressures may be related to removal of overburden, which has resulted in a dilation of the pore volume in the rocks, and a decrease in reservoir temperature.

Modern Evaporite Deposition in Peru

Gypsum and halite are being precipitated in the saline environment which prevails in the uppermost reaches of a restricted marine estuary, the Bocana de Virrila, in the arid Sechura region on the northwest coast of Peru.

Chemical Composition of Deep Formation Waters in Southwestern Louisiana

Forty-one formation-water samples from gas fields near Lafayette in southwestern Louisiana were analyzed by the U.S. Bureau of Mines to determine whether there is any difference in chemical composition between waters in normally pressured and abnormally pressured geologic intervals. The analytic data plus associated geologic data indicate that the concentration of dissolved solids in the waters is related to the degree of compaction of the adjacent shale, and that most of the samples taken from high-pressure zones are less concentrated in dissolved solids than those taken from normally pressured zones.

Subsurface Temperature in South Louisiana

Many subsurface temperature observations from South Louisiana were obtained from the Federal Power Commission. Most of the measurements were made with calibrated maximum thermometers long after the wells had been completed. Temperature-depth curves could be obtained for 123 fields. The temperature gradients ranged from 18 to 36° C/km of depth; most were between 22 and 24° C/km. At a depth of 3,048 m (10,000 ft) there is a belt of high temperature near the present coastline. This hot belt is located approximately where the sedimentary strata are believed to be of maximum thickness, which is estimated to be about 15,000 m. It is suggested that metamorphism and recrystallization already have begun in the lowest part of the sedimentary section, and the consequent increased thermal conductivity may account for the high temperatures along the belt of maximum thickness.

Stratigraphy of Intermontane, Lacustrine Delta, Catatumbo River, Lake Maracaibo, Venezuela

Lake Maracaibo, Venezuela, including the Catatumbo River delta, is an excellent analog to the ancient, intermontane basins that occupied the North American Rocky Mountains and other major mountain systems. These basins are of considerable interest because of their proved oil and gas potential and because of recent interest in oil shales and coals. The Maracaibo basin has been rapidly subsiding during the Cenozoic, and Catatumbo River has been a significant source of Holocene sediments. Each distributary has a middle-ground bar orifice caused by the similarity between effluent and ambient water densities. The coarse bed load is spread over a relatively wide area and down to the delta front, which is steep (5°) but lacks large-scale subaqueous landslide features. The stratigraphic column of the Catatumbo River delta is a sequence which coarsens upward but differs from many other deltaic sequences in that it lacks slump deposits at its base and overlying tidal deposits. There are relatively few current-oriented sedimentary structures. Grain-flow deposits and, less commonly, turbidites occur at the base of the slope. The proximal to distal sedimentation is characterized by an increasing ratio of mudstone to sandstone. Lenses of transported coal are present from the orifice basinward, and extensive coals occur in the freshwater swamps. It is suggested that the Fort Union Formation, which was deposited in the Paleocene Waltman Lake of the Wind River basin of Wyoming, was formed, in part, by several loci of deltaic sedimentation prograding into the lake from the southwest in a manner analogous to the progradation of the modern Catatumbo River into Lake Maracaibo. The reservoir quality of Waltman Lake deltaic bar-finger sands and other similarly deposited intermontane, lacustrine deltaic sands should be excellent.

Hydrocarbon Habitat in Main Producing Areas, Saudi Arabia: DISCUSSION

Most petroleum geologists have wondered why the Persian (Arabian) Gulf area contained such enormous volumes of petroleum. Saudi Arabia alone has produced 44.1 billion barrels of oil, and remaining reserves are estimated at 177.2 billion bbl. Previous studies concluded the Jurassic Callovian to Oxforidan organic-rich carbonates were the only rocks considered rich enough to be the likely source for Saudi Arabias vast reserves. These authors believed the unique size of the accumulations reflected the scale of the system, with large volumes of petroleum-generating rocks coupled efficiently to large traps. It was argued that the type of organic matter generally associated with carbonates was algal-rich, oil prone, and a more efficient generator compared with the organic matter in clastics. It was concluded that the previously identified source rocks only partly answer the question of the unique size of oil accumulations in the part of the Middle East.