Spatial variations in fluid compositions within reservoirs have been reported in fields in many parts of the world. Production problems in some well-investigated large reservoirs have given new information about spatial and temporal variations in fluid properties in recent years.
The focus of petroleum geochemists has moved away from exploration and increasingly towards production and reservoir-related problems. The recent information about the short-time-scale variations of petroleum fluids from Eugene Island Block 3301 in the US Gulf of Mexico demonstrates the complexity of intrareservoir processes and different consequences on the variability in fluid composition.
Petroleum geochemistry gives a great selection of the processes that provide variations in the composition of petroleum including changes in source rocks, thermal maturity, migration, and in-reservoir alternation.
In-reservoir alternation processes such as biodegradation, evaporative fractionation, water washing, and gravity segregation have often been overpowered by the process of gas washing. These are cases when the oil saturated reservoirs may have been equilibrated, or washed, with a great volume of upward-moving gas and associated oil.
Gas generation and migration is considered as the second stage after oil generation, and this process must be widely distributed in sedimentary basins. In-reservoir mixing of different-maturity petroleums, including gas, is a cause of asphaltene precipitation and increasing the oil density in an oil leg.2 The North Caspian and South Caspian basins give good examples of the geochemical consequences of the two-stage reservoir infilling by oil and later by gas.
Astrakhan gas field
Three giant hydrocarbon accumulations in the North Caspian basin—Astrakhan, Karachaganak, and Tengiz—present the full range of the phase systems: gas, gas with oil, and oil (Table 1). The position of these systems on the phase diagram is shown on Fig. 1.
Astrakhan gas field is located in the southwestern North Caspian basin and is considered the world's largest sour gas field. The hydrogen sulfide content in the gas varies from 16% to 31%. The subsalt carbonate reservoir consists of broad, thick packages of porous, shallow-water platform limestones deposited during the Middle Carboniferous.
The hydrocarbons at Astrakhan field are structurally trapped in the dome of the Astrakhan arch. The field is approximately 110 km long by 40 km wide with a reservoir thickness of 225 m. Seismic data indicate that the height of the Astrakhan arch is more than 1,000 m, but the reservoir filling is 15-20% of the common volume of the trap. The principal source of the gas is located in the rift zone, situated to the north, where the subsalt formations are below 8,000 m.
The seal of the principal gas accumulation is the Lower Permian bituminous shale, up to 200 m thick.
Above the Permian seal two small oil accumulations have been discovered in basal anhydrites of the Kungurian salt formation (Fig. 2). The first reservoir is 3-6 m thick, and the second one is 14-20 m thick. Oil accumulations in these reservoirs are very limited, and flow rates decrease rapidly. Oil indices are presented in the Kungurian salts, but there are no indications of the presence of H2S even though many lenses with brine have been encountered during the penetration of salt rocks.
Some very small oil accumulations have been discovered in Mesozoic deposits in the upper part of the sedimentary section. In these oil accumulations the absence of direct and indirect indices of H2S is remarkable. The principal sour gas reservoir is overpressured, with formation pressure of 60 MPa at depths of 4,000 m.
Oil, gas, and solid bitumen distributions within the sedimentary section provide the most important data on the history of hydrocarbon accumulation. Sakhibgareev and Kuryshev3 carried out a detailed investigation of solid bitumen and oil patches distribution in the productive gas reservoir (Fig. 3). An explanation of this situation in distribution of oil, bitumen, and gas along the stratigraphic section is as follows (Fig. 4):
In the first stage, a relatively small oil accumulation formed in the Middle Carboniferous (C2) subsalt reservoir, and some oil migrated through the Lower Permian seal to the basal anhydrite of Kungurian salt and postsalt sediments. As a result pores and fissures in the Permian shales became saturated with oil; some small oil accumulations formed in the basal anhydrite, and oil inclusions traced the migration pathways in salt.
In the second stage, sour gas invasion in the main subsalt reservoir formed the gas accumulation and an oil rim, which descended concurrently with reservoir filling by gas. Light hydrocarbons of oil were transformed into condensate. Heavy components of oil and bitumen were smeared in the reservoir.
Pulse invasions of gas were marked by relatively continuous periods of constant oil-water contacts with abundant bitumen precipitation. Vertical gas migration through the Permian oil saturated shale led to bitumen precipitation in the pores, fissures, and interlayer spaces, forming a perfect seal.
In the third stage, sour gas filled the trap, and oil was divided into condensate and solid bitumen. Isolated oil accumulations in the basal anhydrite above the main reservoir existed since the first state.
This model can explain the principal features of gas, oil, and bitumen distribution in the subsalt rock sequence at Astrakhan field. These data prove that the holding capacity of a seal for gas may be changed by incorporation of bitumen in shale.
Sour gas entered in the oil-saturated shale played an active role to form the most perfect seal for the great gas accumulation. Two-stage hydrocarbon saturation within the seal (oil, and later gas) accompanied by de-asphalting and bitumen precipitation in shales is the most probable process to form a perfect seal above the principal gas reservoir.
Karachaganak field
Comparative study of Tengiz oilfield and Karachaganak gas-oil field, two giant petroleum accumulations in the North Caspian basin, shows the dramatic difference between oil properties distribution within reservoirs of these fields: similar oil properties within an unsaturated oil column at Tengiz and wide variations in oil properties at Karachganak.
Karachaganak field is on the northern margin of the basin and was discovered in 1979. The main hydrocarbon accumulation is in Upper Paleozoic carbonate formations of reef origin.
The productive reservoir is 16 by 29 km in area and 1,700 m in height. The top of the reservoir has been found at 3,526 mss, the gas-oil contact at 4,950 mss, and oil-water contact at 5,150 mss (Fig. 5).
The hydrocarbon-bearing reservoir is sealed either by Kungurian salt or by Upper Permian shale and salt (Kazanian). Cap-rock leakage is proved by the existence of small oil and gas fields in the carbonate layers inside Lower Permian salt
The position of the gas-oil contact has been estimated at 4,900 mss, but according to some authors gas-oil contact may be increased to the level of 4,450 mss. We can postulate from the different sources that there is an extensive transition zone between the gas and the real oil rim. PVT experiments4 show that there is a wide transition zone with the gas and liquid phases existence postulated by visual observing the system with graduated changing the state from a bottom to a top of the PVT chamber.
Fig. 6 shows the distribution of formation pressures in relation to depth for the Karachaganak reservoir. There is the principal difference between the gas and oil zones: the wide variations of pressure potential in the gas zone and the small potential dispersion in the oil rim zone.
According to PVT experiments, gas densities in the reservoir vary from 433 to 450 kg/cu m, whereas the oil densities vary from 480 to 671 kg/cu m depending on the oil quality and gas/oil ratios. The average in-reservoir fluid density according to the plot (Fig. 5) is 480 kg/cu m for the gas-condensate portion and 800 kg/cu m for the oil portion.
The excess of fluid densities in comparison with PVT experiments may be explained by the wide distribution of patches of liquid hydrocarbons in the gas zone and formation waters in the oil zone. But the great dispersion of fluid potential in the gas zone demands also another explanation, namely, the unsteady state of the fluid system. To understand how the system works we have to take into account the temperature factor and migration of new portions of hydrocarbons in the main reservoir.
The Karachaganak reservoir is saturated by gas with a great content of condensate from the top to the level of 4,950 mss and oil with a great content of gas from 4,950 mss to 5,150 mss. The average content of condensates in gases varies from 486 g/cu m in the Permian part of the pool to 644 g/cu m in the Carboniferous part. This is near the condensate point, the condensate pressure varies from 49.7 MPa to 57 MPa in comparison with formation pressure variations from 50 to 60 MPa (Fig. 6).
The gas saturation pressure is close to the boiling point at the gas-oil contact and is reduced to the oil-water contact. Condensate content is the highest at the gas-oil contact and is reduced to the top of the reservoir.
The highest gas-oil ratio is found near gas-oil contact, 800 cu m/cu m, and below GOR declines to 300 cu m/cu m. Condensate density also is increased to the gas-oil contact, reducing to the top from 820 to 780 kg/cu m (Fig. 7).
Density of crude oils is changed with depth from 820-830 kg/cu m near the gas-oil contact to 880-890 kg/cu m near the oil-water contact. Additionally, heavy oils dominate at the southwest part of the oil accumulation in comparison with the northeast part (Fig. 7). Experiments of the gas pumping through oil samples show the effect of increasing oil density related to volume of pumping gas (Fig. 9).
Two types of formation waters are present in the reservoir: condensate waters with very low salinity (about 1 g/l) in the gas part of the reservoir, and formation waters with salinity from 114 g/l to 159 g/l below the oil-water contact. Hydrochemical data show a strong regularity in variation in water salinity.
Concentrations of dissolved salt decrease from the southwest to the east. The salinity of formation waters north of Karachaganak field always exceeds in 240 g/l, and salinity reduction to 114 g/l can be resulted by the influence of condensate waters from the productive part of reservoir. Minimum salinity has been marked in the eastern part of the reservoir.
Filling, phase transition
In the case of Forties field in the North Sea, the variations in fluid composition are often inherited from one side migration into a structure, where the most mature source rock kitchen is offset to one side of the reservoir.5
The main oil source rock in the Karachaganak zone is Devonian terrigenous formations, which are situated below and to the south of the main reservoir. Oil accumulation with overpressure has been discovered in Middle Devonian strata at depths of 5,647-5,754 m. This accumulation may be a source of new portions of hydrocarbons to maintain the convective regime in the main reservoir.
Gas migrated from Devonian strata to the oil rim extracts the light fractions of oil and brings them to the gas-condensate zone. As a result, the density of oil increases in those parts of oil rim, i.e., in the southwest, where gas pumping through the oil is active (Figs. 8 and 9). Falling condensate with condensate water decreases the oil density on the east part of the oil rim and decreases the salinity of formation waters in the same part of reservoir.
Fractionation during in-reservoir migration, where gas containing an oil phase (i.e., condensate) leaves the oil zone to migrate in a decreasing temperature and pressure regime, will result in at least one gas and one oil system. The fate of the liquid phase is to fall down to the oil rim or to be delayed in the different "pockets" in the upper parts of reservoir. It may need a long time to stand the phase equilibria in such a huge and complex reservoir. The reservoir works as a machine by heating of some its parts and distributing new portions of fluids from the oil window zone between oil and gas.
The difference between the thermal conductivity of the salt and surrounding sediments results in the temperature difference of underlying rocks. Below the bottom of the salt layer in the Karachaganak reservoir a difference of approximately 10° C. is maintained for all subsalt sediments, independent of their depth and lithology.
The positive temperature anomaly creates the effect of density gradient and the vertical movement of enriched gas-condensate system. The gas-phase migration to the top of reservoir is accompanied by the condensate separation and origin of the partially isolated zones with liquid hydrocarbons. The reservoir heterogeneity is favorable for preservation of these zones (Fig. 10).
Gas washing, or equilibration of reservoired oils with migrating gas that have passed through a particular oil and consequent evaporative fractionation, is considered as the principal process for oil alteration in deep reservoirs. This process tends to concentrate high-molecular-weight constituents in the residual oil according to relative volumes of gas and oil involved.
Volume of gas also has a significant influence on parameters of the retrograde condensation of the different liquids that occurs in the vicinity of the K-point. Prediction of phase behavior of gas-containing systems can be based on the ternary hydrocarbon mixtures experiments.6
For the more complex systems we can rely only on the database of fluid composition for different natural systems, i.e. oilfields. Nevertheless, the presence of some liquid phases in the liquid-vapor systems can create gravity segregation within productive reservoirs.
Regular alterations in oil density along the oil column can be observed for some oilfields. These data show a great possibility for the close cooperation between specialists in physical chemistry and petroleum geochemistry for this area.
South Caspian washing
The Azerbaijan sector of the South Caspian basin is known as the world's oldest oil province with a very high oil reserve density, where to date more than 1.2 billion tons of crude oil and condensate have been produced.
The sedimentary section thickness reaches 25 km in the southern Caspian. The principal productive section comprises the large delta complex to be post-Mesozoic in age, alternating shales, fine-grained silts, siltstones, and sand. The massive volume of rocks suggests the great potential for oil and gas generation. Most of the structures are elongated ridges with shale diapirism, products of which are the numerous "mud volcanoes."
The problems of mud diapirism activity and associated oil and gas presence has long been of interest to petroleum geologists. Mud volcano activity involves large volumes of gas, water, and mud. And just a few volcanoes emit pure oil through their gryphons.7
Diapir models explain the small content of oil in diapir bodies by the flow rates of every fluid. The first to arrive at a diapir is gas, because of its low viscosity and buoyancy. Then water arrives, followed by oil. The oil mostly remains at the flanks of a diapir and does not enter the diapir.
On the other hand, seismic data show that the sources of mud volcanoes are very deep, in fact 10 km or more, and are attributed to the Jurassic section, but younger shales could be involved as well. At this depth, gas generation is dominant and the present-day diapir activity can be considered as the recent stage of gas penetration in the petroleum system. Oil accumulations could be formed early in the undisturbed anticlinal structures.
Many oil reservoirs in the Apsheron Peninsula contained small gas accumulations near the diapir body. Usually this free-phase gas was extracted at the beginning of field development. In this period many wells yield oil with a high gas content, and later the gas-oil ratio decreases. Associated gas consists of mainly CH4, 91-94%, with a heavy hydrocarbon gas content of 3-4%. This is unusual in comparison with other petroleum provinces.
Apsheron crude oils are characterized by the low content of sulfur (up to 0.4%) but wide variations in density, paraffin, and resins. Temporal changes in oil properties, mainly increasing oil density during the field development, have been marked in some works.8
Formation waters of the productive series have variations in salinity from 150 g/l in the upper part of the section to 12 g/l in the lower part. Water salinity decreases also near the body of mud volcanoes. There is a strong correlation between water salinity and oil density: Light oils are accompanied by high salinity waters, and heavy oils are accompanied by low salinity waters.
High concentration of naphthenic acids is the most outstanding feature of Apsheron formation waters. The concentration may be as much as 3-4 g/l. Most authors have proposed that crude-oil degradation by moving formation water in the Apsheron oilfields is the microbiological oxidation by sulfate ions. Extremely low content of sulfur in the Apsheron oils, even in the heavy oils, proves that the washing processes are preferable to explain many cases of alteration in the oil composition.
Water washing and gas washing are used now to explain many cases of the petroleum fluid variations in the different oil and gas-bearing basins. In the case of oil domination in the system, in oil-water and oil-gas contact regions, for example, we can say about oil washing relating to gas and water properties. Then, modeling of three-phase "oil-gas-water" system increases the potential of employing geochemical methods for source and reservoir process characterization.
References
- Whelan, J., Eglinton, L., Kennicutt, M., and Qian Y., "Short-time-scale (year) variations of petroleum fluids from the U.S. Gulf Coast," Geochimica et Cosmochimica Acta, Vol. 65, No. 20, 2001, pp. 3,529-55.
- Wilhelm, A., and Larter, S., "Overview of the geochemistry of some tar mats from the North Sea and USA: implication for tar mat origin," in Cubitt, J., and England, W., eds., "The Geochemistry of Reservoirs," Geological Society, London, Special Publication 86, 1995, pp. 87-101.
- Sakhibgareev, R.S., and Kuryshev, A.D., "Alteration of reservoir rocks of the Astrakhan gas/condensate field during hydrocarbon accumulation," in Sakhibgareev, R.S., and Kapchenko, L.N., eds., "Secondary alteration of rocks during accumulation and destruction of hydrocarbon pools and their significance to improve exploration process," VNIGRI, Leningrad, 1990, pp. 97-102 (in Russian).
- Martos, V.N., Lapshin, V.I., Bylinkin, G.P., and Kuvandykin, N.S., "Peculiarities of the phase state of formation fluid systems with high content of liquid hydrocarbons," Geologia Nefti i Gaza, No. 10, 1990, pp. 27-28 (in Russian).
- England, W., Muggeridge, A., Clifford, P., and Tang, Z., "Modelling density-driven mixing rates in petroleum reservoirs on geological time-scale, with application to the detection of barriers in the Forties Field (UKCS)," in Cubitt, J., and England, W., eds., "The Geochemisry of Reservoirs, Geological Society, London, Special Publication 86, 1995, pp. 185-201.
- Gregorowicz, J., Smits, P., de Loos, Th., and de Swaan, Arons J., "Liquid-liquid-vapor phase equilibria in the system methane+ethane+eicosane: retrograde behaviour of the heavy liquid phase," Fluid Phase Equilibria, Vol. 85, 1993, pp. 225-238.
- Bagirov, E., and Lerche, I., "Impact of natural hazards on oil and gas extraction: the South Caspian Basin," Plenum Press, New York, 1999.
- Bashirov, Y., "Alteration of the oil property in the Balakhan Series, south part of the Fatmai-Zykh anticlinal zone," Izvestiya Azerbaijan Academy of Science, No. 1, 164, pp. 19-25 (in Russian).
The authors
Leonid Anissimov (vmorneft@ vlink.ru) was a chief of the hydrogeology department at the petroleum research institute VolgogradNIPIneft, where he had been working since 1963. Later he was professor and head of the hydrogeology, engineering geology, and geoecology department at Saratov State University from 1984. He returned to LUKOIL-VolgogradNIPImorneft in 2000 as a chief researcher. He has a doctoral of science degree in geochemistry from Grozny Petroleum Institute.
Gennady Bylinkin (gennady@ mail.saratov.ru) is a chief of the regional analytical center at Nizhnevolzhsky Research Institute of Geology and Geophysics (NV NIIGG), Saratov, Russia. He is a specialist in PVT investigations and consults with several oil companies. He worked with Vietsovpetro in Vietnam in 1991-95. He has a doctor of science degree in petroleum geology from Saratov State University.