Potential of Very Deep Oil and Gas Bearing Deposits

Forecasting the presence of deep hydrocarbon-bearing and, in particular, gas-bearing deposits attracts much attention.

The current investigations show that there is a high content of total organic carbon in the Cenozoic-Lower Paleozoic sedimentary rocks, and an increase in the organic matter bituminization with depth. Some investigators believe that the processes of oil and gas generation at a depth interval of 4.5 to 8.0 km has not been completed in some basins, particularly, in basins in-filled either with salt-bearing strata or with shales having abnormally high pore pressures and low formation temperatures. The most favorable geochemical and lithological conditions for gas and oil generation are associated with young oil- and gas-bearing basins with very thick Cenozoic deposits. One of these basins is the South Caspian Basin.

The South Caspian Basin and the adjacent land area of Eastern Azerbaijan and Western Turkmenistan is characterized by: (1) an exceptionally high rate of sediment accumulation (up to 1.3 km/million years); (2) a very thick (up to 25 km) sedimentary cover, in general, and the Quaternary-Pliocene sediments (up to 10 km), in particular; (3) interbedded sands, silts, and shales; (4) abnormally high pore pressure in shales (average abnormality factor = up to 1.8); (5) low heat flow and low formation temperature (at depths of 6 km the temperature is about 100-110°C); (6) an inverted hydrochemical profile (with depth, calcium chloride and magnesium chloride waters change into sodium bicarbonate type of formation waters); and (7) extensive development of mud volcanism. Argillaceous rocks make up from 50 to 95% of the section thickness and play a key role in the formation of the lithologic, mineralogic, geochemical, and thermo-baric characteristics of the basin.

Petroleum potential of the super-deep deposits, the other factors being equal, depends on two key factors: (1) sealing properties of caprocks, and (2) reservoir-rock properties.

As for the first factor, an important question is as follows: what is the depth limit for hydrocarbon occurrence considering the sealing capabilities of argillaceous rocks due to the preservation of mont-morillonite under given pressure and temperature? Khitarov and Pugin (1966) estimated the occurrence depth for montmorillonite under various conditions. For example, when the geothermal gradient changes from 40 to 10°C/km, the limiting depth of occurrence for montmorillonite changes from 3 to 16 km. Inasmuch as the average geothermal gradient in the Baku Archipelago is 16°C/km, the limiting depth may be 8-9 km. On the basis of the data obtained by Khitarov and Pugin (1966), the writers suggested the following equation relating the depth of montmorillonite occurrence D in km to the geothermal gradient G in °C/km:

Stratigraphic sections with abnormally high pore pressures, however, may have even greater limiting depths. Inasmuch as there is a linear relationship between pressure and depth, the limiting depth, Dlim, can be determined as follows:

Dlim = 261KaG 123

where Ka is a dimensionless factor to account for the pore-pressure anomaly (abnormality factor, which is equal to the ratio of actual (or predicted) pore pressure to the hydrostatic pressure).

Prediction of clay-mineral transformations in the South Caspian Basin at depths exceeding 6.5 km is of great importance. Data obtained from extrapolation and from physical and mathematical simulation (Buryakovsky et al., 1982a) indicate that conditions at depths of 9 km or more in the South Caspian Basin do not favor catagenesis of argillaceous rocks. As shown by Buryakovsky et al. (1982a), the porosity of shales at depths of more than 9 km can be as high as 10%, which indicates the presence of abnormally high pore pressure. Using the equation above, at G = 16°C/km and Ka = 1.8, the limiting depths are found to be 15-17 km in the center of basin. This indicates that the overpressured shales retain their sealing properties because of continuing squeezing-out of pore water.

Usually, for estimating the potential reservoir quality in undrilled areas, one can use a statistical distribution of geological and petro-physical parameters of known deposits in the region. Estimation of reservoir quality is often limited by insufficient information. Primarily, this refers to the South Caspian offshore fields with complex geologic conditions for drilling deep exploratory wells using separate offshore platforms. Productive formations occur at depths of 5-6 km or deeper, and pore pressure and formation temperature exceed 70 MPa and 110-120°C, respectively. While drilling, there are problems with overpressured formations, such as "kicks" and strong gas shows. This results in limitation in core recovery, which, in turn, limits the knowledge of petrophysical properties (mainly porosity and permeability) of reservoir rocks. The collected information on the reservoir-rock quality, both for the Apsheron oil- and gas-bearing region and for the South Caspian Sea areas, is used for estimating reserves.

Grain-size distribution in clastic rocks changes on moving away from the source and further offshore. With progradation of ancient shoreline to the south and southeast of the Apsheron Peninsula, there is a decrease in sand content and an increase in silt-clay content. This change in lithology affects the reservoir-rock properties (mainly porosity and permeability) in more deeply buried anticlinal zones. Smaller grain size and better sediment sorting characterize the silty-clayey rocks in these zones. Thus, there is development of abnormally high pore pressures due to underconsolidation (undercompaction) of sediments in downwarped zones. This explains the relatively high porosity and permeability of rocks (Buryakovsky et al., 1991b).

The lithology of productive strata and pressure-temperature conditions has been taken into consideration for statistical correlations of porosity, permeability and other reservoir properties of rocks in the new deep offshore fields. Data on lithologic and reservoir-rock properties have been evaluated using mathematical statistics (Griffiths, 1971; Harbaugh and Bonham-Carter, 1974; Krumbein and Graybill, 1969; Buryakovsky et al., 1982a, 1990b; Rodionov et al., 1987; Sharapov, 1965).

The following relationships were established:

1. Variation of porosity %) and permeability (k, mD) of sandstones and siltstones with depth (D, km) up to 6 km have been studied. Porosity and permeability at depths ranging from 500 to 6,000 m may be obtained using the following correlations:

These mathematical models enabled prediction of porosity at a depth of 9 km: 8% for sandstones and 6% for siltstones. Permeability at a depth of 9 km was estimated to be 10 mD for sandstones and 8 mD for siltstones.

2. Regression models were established for porosity and permeability versus depth, taking into account clay cement content (Csh,%) and carbonate cement content (Ccarb,%):

^ = 27.91 - 2.66D + 0.00007Csh2 - 0.483lnCcarb k = 597.97 - 164.01D1'2 - 39.76Csh - 31.99Ccarb1/3

Coefficients of correlation are 0.92 and 0.78, whereas standard deviations are 0.03 and 0.09, respectively. The equations are accurate with a confidence level of 0.95, and degrees of freedom of 2 and 172, and 2 and 168, respectively.

The presence of abnormally high formation pressures and relatively low temperatures suggests presence of hydrocarbons. Thus, the South Caspian Basin may have commercial accumulations of oil and gas at depths of 9 km or even deeper.

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