Colin Barker

Aquathermal Pressuring--Role of Temperature in Development of Abnormal-Pressure Zones: GEOLOGICAL NOTES

Zones of abnormal subsurface pressures, both above and below hydrostatic, have been described in many areas. The very abrupt changes in pressures and salinities, together with the undercompacted nature of the high-pressure zones, indicate that they are effectively isolated from their surroundings. If this isolation occurred at a shallower depth than the present one, the isolated volume would have been subjected to increasing temperatures as it moved downward. The P-T-density diagram for water shows that, for any geothermal gradient greater than about 15°C/km, the pressure in an isolated volume increases with increasing temperature more rapidly than that in the surrounding fluids. This mechanism for producing excess pressures will operate in addition to most of the ot er processes that have been suggested, but the overall influence in any given area will depend on how well the system remains isolated. If a normally pressured system becomes isolated and is then subjected to a decrease in temperature (for example, if erosion removes considerable quantities of overburden) the pressure in the system will fall below the external hydrostatic pressure. This may have happened in some areas which now have abnormally low pressures.

Calculated Volume and Pressure Changes During the Thermal Cracking of Oil to Gas in Reservoirs (1)

The rising temperature that accompanies increasing burial depth converts oil in a reservoir into thermal gas. A consideration of hydrogen balance during this cracking shows that approximately 3000 cubic ft (85 cubic meters) of gas (at standard temperature and pressure) is generated from each barrel of oil. In addition, a graphitic residue is precipitated. If the volume relationships among oil, thermal gas, and the graphitic residue are combined with data for gas solubility in pore water and gas nonideality (Z factor), then pressure can be calculated for any degree of thermal cracking. These calculations show that in an effectively isolated system, pressures would become very high and could considerably exceed the rock load, so that fracturing must occur causing pressure b eed off and loss of gas. The lithostatic gradient (1.0 psi/ft or 22.6 kPa/m) is reached after only about 1.0% of the oil is cracked. If the reservoir system remains open (i.e., at hydrostatic pressure) and is initially filled with oil that is subsequently cracked to gas, then roughly 75% of the gas will be lost or the reservoir volume must effectively increase in size, for example, by moving the gas-water contact downward.

Effect of Water Washing on Crude Oil Compositions

Crude oils from Venezuela, Oklahoma, and New Mexico were water washed in the laboratory at temperatures from room temperature to 80°C, and with water salinities from 0 to 300,000 mg/L in experiments lasting from 7 to 338 hours. The effects of water washing were determined by gas chromatographic and gas chromatography-mass spectrometric analysis of the residual oil. These experiments show that water washing is particularly effective for the C15- fraction and hydrocarbons are removed in the sequence aromatics, then n-alkanes, then naphthenes. In the C15+ fraction, no loss of pristane, phytane, steranes, or terpanes occurs, but some aromatics and sulfur compounds, especially dibenzothiophene, are depleted. Although water washing reduces API gravity water washing is unlikely to produce tar layers. The effects of water washing were simulated with a numerical model based on the equation of diffusion. Predicted oil-water ratios were in good agreement with the experimental values for the light ends, and the model suggests that water washing is very fast in the subsurface. Comparison of oils that appeared to have been water washed in nature with the equivalent unwashed oils showed the expected compositional trends. Water washing is probably the dominant process affecting crude oil composition in the subsurface when water flows past oils under conditions where bacterial degradation is precluded by temperature (> 80°C) or by lack of dissolved oxygen, and the temperatures are too low for thermal cracking.

Gas adsorption on crushed quartz and basalt

Abstract The new surfaces generated by crushing rocks and minerals adsorb gases. Different gases are adsorbed to different extents so that both the total amount and composition of the released gases are changed. This affects the interpretation of the composition of the gases obtained by vacuum crushing lunar basalts, meteorites and minerals with fluid inclusions.

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.

Programmed-temperature pyrolysis of vitrinites of various rank

Abstract Nine vitrinites separated from coals of various rank (69–93% carbon, daf) were studied by programmed-temperature pyrolysis. Samples were heated at 11°C/min in a stream of helium which swept the pyrolysis products into a flame-ionization detector. With the experimental system used this responds only to hydrocarbons below C 10 . For all the vitrinites the curve of detector response as a function of temperature showed a single maximum and the temperature of the peak maximum was found to be located at higher temperatures for the higher-rank samples. The temperature of the peak maximum was not very sensitive to rank between 70% and about 90% carbon but varied rapidly outside this range. This suggests that the mechanism which generates low-molecular-weight hydrocarbons from coal changes above approximately 90% carbon.

Stability of Natural Gas in the Deep Subsurface: Thermodynamic Calculation of Equilibrium Compositions

The deepest hole in a sedimentary section is currently 31,441 ft (9,583 m), but the deepest production is only 26,536 ft (8,088 m); the depth gap between deepest hole and deepest producer is the largest in the history of the petroleum industry. This prompts a critical reevaluation of methane stability in deep potential reservoirs. We developed a computer program to calculate the equilibrium composition of gases in deep reservoirs of various lithologies. The program establishes the assemblage with minimum free energy for specified conditions of temperature and pressure corresponding to conditions down to 40,000 ft (12,192 m) and can handle up to 70 components, 25 elements, and 20 phases. It does not assume ideal gas behavior but does assume ideal mixing. Calculations have been made for average, high, and low geothermal gradients; hydrostatic and lithostatic pressures; and with and without graphite. Calculated equilibrium compositions show that methane alone in an inert reservoir has considerable stability, and 99.4% survives to 40,000 ft (12,192 m). Even in the geologically more realistic system with water, 99.1 survives. The full capability of the program is demonstrated for a sandstone reservoir with graphite, calcite cement, and a range of minor minerals. There, methane shows considerable stability for average geothermal gradients with both normal and abnormal pressures. For high geothermal gradients, part of the methane is lost by reaction, and significant amounts of carbon dioxide are added to give a gas composition at 40,000 ft (12,192 m) that contains only 9% methane. The program shows that, in general, temperature is much more important than pressure in controlling gas composition, crude oil is not thermodynamically stable at any depth, and a few percent of hydrogen is frequently present in deep gases.

Development of Abnormal and Subnormal Pressures in Reservoirs Containing Bacterially Generated Gas

Burial of reservoirs containing a bacterially generated gas phase may lead to pressures that are above, equal to, or below hydrostatic. The pressures that develop depend on the way in which the gas-bearing volume is connected to, or isolated from, its surroundings. Where a noncompacting volume is totally isolated, subnormal pressures will develop. This approximates the situation in chalks, which have high porosities but low permeabilities and often contain underpressured gas. Low pressures develop because the thermal pressuring of the gas with depth occurs at a lower rate than the increase in hydrostatic pressure and because the gas dissolves in the water. When the gas-bearing volume is freely connected to surrounding, normally pressured sediments, the gas pressures remai hydrostatic, but the volume of gas steadily diminishes as it dissolves in the pore water. If gas occupies 40% of the pore volume at 1,000 ft (305 m), it will all be in solution by 4,600 ft (1,402 m) and a gas phase will no longer exist. Water must flow in to replace the dissolving gas or the rock must compact. This is the situation for normally compacting shales. When the gas is in an isolated but variable volume system (such as a compacting shale), pressure rises above hydrostatic due to sediment loading. This mechanism likely has produced many of the shallow sands charged with high-pressure gas that are a drilling hazard in many offshore areas.

Mass Spectrometric Analysis of the Volatiles Released by Heating or Crushing Rocks

The volatiles trapped in rocks can be released either by heating or by crushing. Unfortunately crushing generates new, clean surfaces which adsorb chemically active gases and thus change both the amount and composition ofthe evolved gases. For quantitative analysis the volatiles were released by heating 0.1-g samples in fused silica tubes at temperatures up to 1200°C. The evolved volatiles were separated into two fractions by fractional freezing. Volatiles which were not condensed in a liquid nitrogen-cooled trap (hydrogen, carbon monoxide, methane, nitrogen, helium, etc.) were mixed with a known amount of argon internal standard and leaked into a calibrated E.A.I. QUAD 1110 mass spectrometer for analysis. The condensable volatiles (water, carbon dioxide, higher hydrocarbons) were subsequently evaporated and analyzed in the same way. The analog output from the mass spectrometer was fed to a digital integrator which printed the areas of the peaks on a teletype and simultaneously punched a paper tape. The tape was later transmitted over a telephone line to a time-shared computer for data processing.

Kinetic study of bitumen release from heated shale

Abstract With rising temperature shales evolve hydrocarbons discontinuously. At low temperatures, bitumens are thermally distilled (Peak 1) while at higher temperatures kerogen is pyrolyzed to lower molecular weight products (Peak 2). Hydrocarbon release occurring between these two peaks is less well understood. We have studied the kinetics of thermal bitumen release (Peak 1) from samples of the Excello and Woodford Shales and find that they are second order with activation energies of 19,000 cals/mole and 17,048 cals/ mole, respectively. The thermal release of nC26 adsorbed on a siliceous support also followed second order kinetics. Activation energies, along with the determined Arrhenius A factor, permits the calculation of Peak 1 shape so that its contribution can be subtracted from the total hydrocarbon release. The residual curve shows two smaller peaks between the bitumen and kerogen peaks. These are tentatively assigned to adsorption on the mineral matrix and adsorption on kerogen. An important consequence of second order kinetics is that the temperature for the Peak 1 maximum varies with the amount of bitumen in the rock.