Geohistory, thermal history and hydrocarbon generation history of the north-west South Caspian basin

Marine and Petroleum Geology, Vol. 14, NO. 4, pp. 363-382, 1997 0 1997 ElsevierScience Ltd

All rights reserved. Printed in Great Britain 0264-8172/97 $17.00+0.00

PII: S0264-6172(96)00063-0 ELSEVIER

Geohistory, thermal history and hydrocarbon generation history of the north-west South Caspian Basin M. F. Tagiyev, R. S. Nadirov and E. 6. Bagirov Geological

Institute

of Azerbaijan,

Azerbaijan

Academy

of Sciences,

Baku, Azerbaijan

I. Lerche* Department USA

Received

of Geological

30 August

Sciences,

1995; revised

University

2 September

of South Carolina,

1996; accepted

Columbia,

5 October

SC 29208,

1996

Both the hydrocarbon potential of, and excess fluid pressure build-up in, the thick (25-30 km) sedimentary pile of the northwestern part of the South Caspian Basin were evaluated using a one-dimensional fluid flow/compaction model. The model consists of three parts: a geohistory model; a thermal history model; and a hydrocarbon generation model. Input data for the model are commonly used depth values of geological parameters: lithofacies, formation thicknesses, strata1 ages, porosity, permeability, pore pressure, temperature, total organic carbon content, type of organic matter, vitrinite reflectance and other maturity indicators. In order to bracket oil generation in terms of timing and depth location, two extreme thermal histories were modeled: paleoheat flow values at one half and twice the present-day values with a linear variation through time to present day measured values. The most intensive oil generation occurs during the last 5.2 My, when the ‘oil window’ is confined to depths between 5-7.5 km in the northwest, 7-10 km in the west (onshore part of the study area), and 8-l 1 km in the central and southwestern parts of the area. Below the ‘oil window’ cracking occurs of oil into gas. Rapid sedimentation, which took place in the middle Pliocene through Quaternary, results in overpressure build-up across all of the study area. Maximum values of excess fluid pressure of 300-400 atm at 6-10 km are reached in the central and southeastern parts of the area, where the sedimentation rate is the highest. Isobaric contours of excess pressure are then at shallow depths compared to the previous history of the area. Because there is a laterally decreasing trend of excess pressure, oriented from the central and western parts of the area to the northeast and, in addition, the sand/shale ratio is increasing in the same direction, inferences that can be drawn on the most probable hydrocarbon migration directions suggest recent flows towards the northeast with hydrocarbon accumulations of gas and light oil likely to be more prevalent in the northeastern sands. 0 1997 Elsevier Science Ltd. Keywords: South Caspian; geohistory; thermal history; hydrocarbon

The purposes of this paper are: (1) To apply a onedimensional fluid-flow model to multiple wells in the South Caspian Basin (SCB) to reconstruct the geohistory, thermal history and hydrocarbon generation history; (2) To show how the model results fit observed data; and (3) To interpret the results to increase our understanding of the petroleum geology in the basin. We use a fluid-flow model, rather than an ‘isostatic’ backstripping model (in which fluid pressure is always at the hydrostatic value), because observations show that a significant degree of overpressuring is present in the SCB at the present-day. The study area occupies about a 200 x 200 km2 region, the northwestern part of the SCB, and contains 12 wells with good quality data (Figure I). The typical spacing between wells is about 15-20 km, large enough so that effects due to lateral fluid-flow are small across the study

generation

area because of spatial variations in lithology (Bredehoeft et al., 1988). In particular, as we shall see, hydrocarbon generation occurs dominantly, but not exclusively, in the last few million years so that the lateral flow of hydrocarbons is also limited. Under these conditions use of a 1-D fluid-flow code at each well site, with contouring of results across the basin, is an appropriate method of understanding the sedimentary evolution, basically because one has available seismic sections, gravity and aeromagnetic surveys, some outcrop information, plus detailed downhole information at a few scattered wells in the basin (Cao et al., 1986).

Description of the fluid-flow/compaction

model

A detailed mathematical description of the model can be found in Cao and Lerche (1987). Here only a brief p&is of the model is given. The fluid-flow model consists of

*Author to whom correspondence should be addressed

363

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Geohistory, thermal history and hydrocarbon

generation history: M. f, Tagiyev et al.

hal-deniz

Bahar-deniz

O\

\

Umid

50

100

kilometers

Figure 1 Study area - north-western part of the South Caspian sedimentary basin with the 12 control wells marked, together with the outlines of hydrocarbon fields

three parts: a geohistory model; a thermal history model; and a hydrocarbon generation model. Because the model simulations are one-dimensional, the input data for the model are those commonly used: geophysical, geological and geochemical data from a single well, which makes the simulation useful both in frontier areas where a few wells are commonly available and also in well-developed basins. Geohistory model The geohistory model reconstructs the burial history, basement subsidence, vertical fluid flow, and the changes in porosity, permeability, pressure and fluid flow rate with both time and depth. Also, the evolution of cementation, dissolution and fracturing caused by abnormally high pore pressure are simulated in terms of the change in formation permeability. The input data required to run the geohistory model are the lithology, depth and age of each formation and the paleowater depth. Thermal history model Based on the burial history created in the geohistory model, the thermal history model reconstructs the thermal history by: (a) comparing predicted thermal indicator values (such as vitrinite reflectance) to measurements down a borehole (Lerche et al., 1984); and (b) adjusting the paleoheat flux to minimize discordances. The outputs are: (i) a heat flow change with time; (ii) a temperature change with time and depth; and (iii) vitrinite reflectance and other maturity indicator changes with time and depth. The input data required to run the thermal history model are the temperature at the sediment-water surface, bottom-hole temperature and some thermal indicator measurements with depth.

Hydrocarbon generation models Hydrocarbon generation models are based on the kinetics of kerogen degradation. While the code contains the freedom to include user-defined hydrocarbon kinetics, due to the paucity of readily available Sl/S2 data in the wells of the South Caspian Basin, here just two mathematical models are used to simulate hydrocarbon generation from kerogen: Tissot’s model (Tissot and Welte, 1978) which simulates the formation of oil from kerogen in six parallel reactions (first stage) and formation of gas from oil in a single reaction (second stage), and a modified model (Cao and Lerche, 1987) which adds the major gaseous products from both kerogen degradation and oil cracking. Based on the burial history and the thermal history models, respectively, the generation models give the absolute amount of hydrocarbons generated (per gram of kerogen) with time and depth. The input data required to run the generation models are the content of different kerogen types of each formation. At each instant of time spatial contouring of results from a number of wells in a study area permits an investigation of temporal and spatial regional studies such as basin subsidence, paleostructure, heat flux, source rock maturity, and hydrocarbon generation, migration and accumulation. Geological information for the study area General From both geological structure and history viewpoints the South Caspian Basin is one of the unique sedimentary and petroleum-bearing basins of the world. The basement of the central part of the basin is a fragment of oceanic crust of the Tethys paleo-ocean, which has undergone

Geohistory, thermal history and hydrocarbon progressive subsidence during the Neogene-Quaternary period due to subduction of the crustal flanks under the edges of adjacent plates (Nadirov, 1985). The process of subsidence was compensated for by rapid sedimentation. As a result, the present day thickness of sedimentary deposits in the South Caspian Basin is an enormous 2& 30 km, as confirmed by geophysical data. The same geophysical data also indicate widespread occurrence of mud diapirism, showing that the roots of the diapirs frequently originate at or near the basement (Gambarov et al., 1993). For instance, on the 12-s two-way travel-time east-west section displayed by Gambarov et al. (1993) all three of the mud-diapirs extend to at least 12 s, corresponding to 25-30 km of sediments. There are many ( -200) mud volcanoes protruding into the waters of the Caspian Sea, and also in the onshore region of Azerbaijan; these mud volcanoes are widespread and are not confined solely to oil and gas fields. Qualitatively observations point to the inter-relation of basin development features tying together hydrocarbon generation and mud volcanism. However, to date, there are no quantitative models reflecting the dynamics of development, both of the basin as a whole and individual phenomena within the basin; use of such quantitative models provides important contributions to the development of basic geology in its own right, and to the regional petroleum geology of Azerbaijan, Iran and Turkmenistan. The study area is a north-western portion of the South Caspian sedimentary basin. Geographically the region is enclosed between latitudes 48”N and 51”N, and longitudes 36”E and 42”E (Figure 1). (A regional map of the area is given in Nadirov et al., 1997.) Specific conditions are determined by a number of geological parameters such as low heat fow (20-50mW me*), high sedimentation rate (to 1.3 km Ma-‘), great thickness of sedimentary cover (2k-30 km), and thick argillaceous lithologies constituting up to 90% of the total section uncovered by drilling. The relatively thin Productive Series can be highly sandy, however. Occurrence of mud volcanoes, and of anomalously high pore and formation pressures are characteristic for many parts of the basin. Numerous oil and gas fields are in production on both the western and eastern flanks of the basin. Economic oil production in Azerbaijan, in particular on the ApsheronBalkhan peninsula, began as early as the 1860s. Total oil production in both onshore and offshore Azerbaijan currently exceeds 1.3 billion tons. The oldest deposits, penetrated by a few boreholes, are of Miocene age. The so-called Productive Series of the Middle Pliocene is the main production formation; underlying lithologies are inferred based on outcrop observations in adjacent locales, while the thicknesses of different sedimentary strata below the Productive Series are known indirectly from seismic data (Gambarov et al., 1993; Nadirov et al., 1997).

Geohistory of the study area

Tectonic setting and structure Three stages can be distinguished in tectonic evolution of the basin as typified by the evolution at the Bulla-deniz well (Figure Za). The first stage began during the Jurassic and lasted until about the Paleogene. During this period a thickness of about 9000m was deposited. The second stage spans the interval corresponding to mid- to late

generation history: M. F. Tagiyev et al.

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-120M)

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Figure 2 Geohistory diagrams for well Bulla-deniz: (a) burial history; (b) subsidence rates; (c) total and tectonic basement subsidence. Abscissae are in units of Ma

Tertiary, also with a low sedimentation rate (Figure 2b). The third stage is the late Cenozoic, where maximum sedimentation rate occurs during the Pliocene (Figure 2b). Cenozoic sediments make up about half of the presentday total thickness of sedimentary cover, with the majority being filled during the Pliocene-Quaternary interval. Figure 2c shows basement subsidence through time at Bulla-deniz, divided into two components: one caused by sediment and water weight on the basement and the other representing tectonic effects. According to Figure 2c, tectonic effects make up about 30% of the total basement subsidence (Nadirov et al., 1997). Figure 2b shows contrasting pictures of the rate of sedimentation and rate of tectonic subsidence at different geological times. Note that all rates are quite small (<75mMa-‘) until the recent deposition of about 5000-8000 m of sediment in the last 5 Ma, when volume accommodation requirements increase tectonic subsidence to a peak of over 400 m Maa’ at Pliocene time, in concert with the sedimentation rate increase to a peak of nearly 1.4 km Ma-‘. Thus, values of total subsidence, tectonic subsidence and sedimentation are about an order of magnitude higher in the Pliocene and Quaternary than at any other geologic time.

Thermal history of the north-western part qf’the SCB Figure 3 illustrates change of temperature with depth, to about 7 km, for the two wells (a) Bulla-deniz, and (b) Bahar-deniz, which are about 40 km apart (Figure I). There is a significant difference in the geothermal gradients with least-squares linear fits yielding values of 1.3”ClOOm- and 2.1”ClOOmat Bulla-deniz and Bahar-deniz, respectively. The corresponding equivalent present-day heat fluxes at the two wells are 0.55 and

366

Geohistory, thermal history and hydrocarbon

generation history: M. F. Tagiyev et al.

Temperature [‘Cl

;:,g!

6000

I-

) \ ,,p-_-I

Figure 3 Temperature variation with depth for wells: (a) Bulladeniz; (b) Bahar-deniz (from Bagir-zadeh et al., 1988)

8

“\?

I

37

0.75 HFU (1 HFU ~42 mW m-‘) respectively. (The heat fluxes are calculated using all the downhole temperature data and so refer to equivalent heat fluxes over the depth range of the temperature measurements.) Both the measured thermal gradients and the calculated heat fluxes are considerably lower than in similar shallow water ( 5 1 km) regions of other sedimentary basins which are under massive recent sedimentation. For example, typical temperature gradients in the Gulf of Mexico shelf near the Mississippi delta are around 2.5-3.5”C loom- with corresponding heat fluxes of around l-l .5 HFU. The inference for hydrocarbon maturation is substantial. As an illustration: if a 100°C isotherm is taken as indicating significant oil onset and 140°C as indicating significant gas onset then, with the present-day water temperature of the South Caspian Sea at about lO”C, it follows that the depth to the current oil window lies between about 6.5 km at Bulla-deniz to 4.3 km at Bahar-deniz; while the current gas window commences at about 9.3 km at Bulladeniz, and at about 6.2 km at Bahar-deniz. Corresponding equivalent present-day heat flux values can be derived for each of the wells and the results contoured as shown in Figure 4. The range is from around 0.5-l .OHFU with a systematically increasing heat flux trend from the center to the north-east of the study area. Further to the west, outside the study area, heat flux also increases towards the Talysh-Vandam buried uplift (Nadirov, 1985). This trend is likely related to the fact

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Figure 5 Contour map of present-day temperature 5000 m depth. Lateral and vertical axes in km

(in “C) at

that the eastern continuation of the Apsheron peninsula shows only a low tectonic depression relative to the region around Bulla-deniz (which is subject to compressive thrusts from the western Talysh-Vandam area and the later erogenic rise of the northern Great Caucasus, with a total massive sedimentation of nearly 30 km arising: (a) in the .Iurassic/Cretaceous (about 10 km) from sediment shedding from the Talysh-Vandam high; and (b) in the Miocene-Recent (15-20 km) with dominantly Caucasus shale deposition (Nadirov, 1985; Nadirov et al., 1997)). From temperature measurements at 5000m depth (Bagir-zadeh et al., 1988), a contour map of temperature (at 5000m) at the present-day can be constructed as shown in Figure 5. Note that there is an obvious trend of increasing temperature to the north-east, and that the southwestern part of the area is at roughly ‘oil window’ generation temperatures today (at 5000m), while the north-eastern section is in the ‘gas window’ generation region today at 5000 m depth. To determine paleoheat flux evolution, so that a more controlled estimate of hydrocarbon timing is available, initially attempts were made to use vitrinite reflectance measurements with depth in order to disentangle paleoheat flux variations with inverse methods (Lerche, 1990a, 1990b). However, from the reflectance data shown in Figure 6 for a well (which is typical of all wells, unfortunately) there is an enormous scatter in reflectance values due to reworking, drill bit heating, and uncertainty on cuttings’ depths. In addition, samples from mud vol-

0.50

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Figure 4 Contour map of present-day heat flow (values in Heat Flow Units, 1 HFU=42 mW m-*1. Lateral and vertical axes in km

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8 * I 8 * - 8 I 8 8 18,

Figure 6 Vitrinite reflectance vs. depth (from Guliev et al., 1991)

Geohistory, thermal history and hydrocarbon

generation history: M. F. Tagiyev et al.

367

2.00

206 Figure 7 Two extreme case

156

104 Time [M.Y.B.P]

52

0

heat flow scenarios for the Bulla-deniz Figure 8 Composition of organic matter in terms of generation potential for different sedimentary groups

cane ejecta, estimated to be from about 7-8 km depth, indicate a broad range of reflectance values from 0.2 to 0.6%. About all that can be said is that there is an absence of any clear trend of vitrinite reflectance with depth. In an attempt to bracket the hydrocarbon onset, two extreme models were used of a paleoheat flux at one half and twice the present-day values at each well site with a linear variation with time from about 200Ma through to the present day, as depicted in Figure 7. While not completely satisfactory, at least such a variation provides an indication of likely ranges of hydrocarbon onset. Further, the slow sedimentary deposition in the Cretaceous, after the 9 km deposition in Jurassic time, followed by the massive Miocene-Pliocene-Quaternary deposition, means that only hydrocarbon generation in the Jurassic and Cretaceous sediments is at all sensitive to paleoheat flux variations, with the majority of the sedimentary pile (deposited in the last 5 Ma) being controlled by heat flux variations which are close to present-day values. Given the uncertainties in hydrocarbon kinetic models, the uncertainties in TOC variations throughout the sedimentary pile, and contributions to local temperature variations due to paleo-overpressure development, it is more than adequate to limit consideration to the two extreme paleoheat flux variations depicted in Figure 7. Hydrocarbon

generation

history

in the north-western

part of the SCB Geochemical studies on organic matter content have been conducted using core samples taken to as deep as 6300 m, and also from mud volcano ejecta which are thought to be from strata in the 8-10 km depth range (Korchagina et al., 1988). As a whole, the Mesozoic-Cenozoic sedimentary formations are characterized by an extremely low TOC content, typically ranging from 0.02% to 0.8%, with an average of around 0.2-0.4Oh, although some few thin beds (N 100 m thick) are known in which TOC content can reach 4% (Korchagina et al., 1988). Compiling all organic data from well bores, mud ejecta and outcrops, based on hydrogen index (HI) variations from pyrolysis measurements, permits a chart to be drawn of Type I, II and III (Tissot and Welte, 1978; Ungerer et al., 1984) compositions for each sedimentary group, in relation to maximum generation potential from pyrolysis studies, as depicted in Figure 8 (Guliev, 1995, personal communication). Prior to Pliocene time, there is a roughly equal mixing percentage of each kerogen Type until Cretaceous time, with Types II and III dominating at earlier

(Jurassic) times. More recently than the Pliocene, the variation has shifted to a dominant mix of Types I and III until Quaternary time when Type II kerogen makes up about 2/3 of the TOC, with Type III material contributing the remaining l/3. These shifts in kerogen fraction with geological time are thought to be tied to the shifts in depocenter supply of sediments, with pre-Paleocene material dominantly arising from the west (the Talysh-Vandam uplift region), Cretaceous through Upper Miocene depositions reflecting both shifts in climate patterns as well as the influence of the Tethys Ocean, and post-Miocene deposition being influenced by the orogenie uplift and compression of the Great Caucasus (Guliev, 1995, personal communication). While the average TOC per unit sediment volume is quite small (-0.2X).4%) compared to, say, the North Sea with its Kimmeridge shale source rock averaging between l&25% TOC, nevertheless the sheer thickness of the disseminated organic material in the SCB makes the basin a major hydrocarbon province. A straight TOC richness x thickness calculation would, at 20 km thickness, put the SCB into the range (4-8) x lo3 (TOC% m) compared to the approximately l/2 km of Kimmeridge which yields (0.5-1.2) x lo3 (TOC% m). Thus, overall, the dissemination of low TOC in the SCB implies a total potential productivity of about ten times that of the North Sea Kimmeridge Clay (Draupne Formation) per unit area of source rock (Gasanov et al., 1988; Guliev et al., 1991; Guliev, 1995, personal communication). In order to illuminate different components of the hydrocarbon generation we first compare the predicted patterns for the Bulla-deniz and Bahar-deniz wells, prior to contouring results for all 12 wells across the study area. All wells were run using both the ‘hotter in the past’ and ‘cooler in the past’ paleoheat flux values depicted in Figure 7, and with the two kinetic models discussed previously (Welte and Yukler, 198 1; Ungerer et al., 1984; Cao and Lerche, 1987). Results for well Bulla-deniz

With the present-day geothermal gradient of about 1.3”C lOOm-’ and equivalent heat flux of 0.55 HFU, the onset of oil generation is bracketed by the two end-member situations to occur between about 190-l 50 Ma and, in that time range, spans the depth range from about 410 km depending on the high or low paleoheat flux (Fig-

368

Geohistory, thermal history and hydrocarbon

we 9a,b). Because sediment deposition slows dramatically from 150 Ma through to Tertiary time at about 65 Ma, the oil generation regime tends to remain in the 4-10 km region, as also shown in Figure 9a,b. By Early Pliocene time, however, when the difference between the two extreme heat flux situations is quite small, the onset of massive avalanche-style sedimentation caused a thermal blanketing of the younger sediments and, as a consequence, drove the oil window to depths of order 7-10 km, corresponding to approximately Paleocene-Eocene sediments today entering the oil window. While the difference in onset of oil hydrocarbons is significant for Jurassic and Cretaceous sediments, depending on the paleoheat flux used, there is very little difference in generation estimates for sediments which are Tertiary and younger in age, due to both the convergence of the two extreme paleoheat flux values towards the present-day and because of the massive, late stage sedimentation. For gas generation the situation is more complex. Early oil generation, as in Figure 9a for the high paleoheat flux case, also implies a rapid conversion of oil to gas from the Jurassic sediments, so that gas onset is at about 180 Ma and at 6000 m at that time as indicated in Figure IOU. The low paleoheat flux case does not provide a sufficiently high temperature for conversion of oil to gas until mid-Cretaceous time at about 100 Ma at 10 km depth (Figure lob). Effectively, because deposition is basically stagnant during the Cretaceous, the sediments hold at nearly fixed sub-surface depth, and it is only the increase in the heat flux with time towards the presentday which raises the sedimentary temperature into the gas generation regime during this period. However, as time progresses closer and closer to the present-day, the delay of conversion of oil to gas in the cool paleoheat flux situation gradually catches up with the early conversion of oil to gas that took place in the high heat flow situation so that, by around Pliocene time, all oil has converted to gas in all pre-Pliocene sediments. The major difference, then, is in where the early generated (Jurassic-Cretaceous) hydrocarbons (oil and/or

generation history: M. F, Tagiyev et al. 0 2ow 4ow 6000 9cal

.___s&?o- Cumulatwa y$$z_

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Figure 10 Cumulative gas generation through time for well Bulladeniz with two thermal history scenarios: (a) ‘hotter in the past’; (b) ‘cooler in the past’

gas) could have accumulated depending on migration and on structural and stratigraphic trapping capabilities at the times of generation. Results for well Bahar-deniz While the burial history for well Bahar-deniz is somewhat similar to that for well Bulla-deniz, the present-day geothermal gradient is higher at 2.l”C lOOm_‘. Thus the paleoheat flux in both the ‘hotter in the past’ and ‘cooler in the past’ scenarios is higher than for well Bulla-deniz. Accordingly, both onset of generation of oil and conversion of oil to gas will be earlier and at shallower depths than for Bulla-deniz. indeed, as shown in Figure lla,b

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generation history: M. F. Tagiyev et al.

Geohistory, thermal history and hydrocarbon 209

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Figure 12 Cumulative gas generation through time for well Bahar-deniz with two thermal history scenarios: (a) ‘hotter in the past’; (b) ‘cooler in the past’

and Figure 12a,b for cumulative oil and gas generation, respectively, for both paleoheat flux scenarios, the initial oil generation phase is in the range 2-9 km at Jurassic time, and by early Pliocene time the oil window range is at 3-7 km. The intense subsidence, which occurs in and after the Pliocene, pushes the oil window deeper by about an extra 2 km, making the Eocene-Oligocene-Miocene sediments (which occupy the current depth range of about 5-8 km) prime generators of oil in the last 5 Ma. For gas generation, as depicted in Figure 12a,b for the two scenarios, cumulative generation commenced around 19&150Ma at 3-9 km, and was at about 5-14 km by Pliocene time, just prior to the massive Pliocene deposition, which has then depressed the top of the gas window to about 6.5 km today, the depth of the Oligocene complex. Thus both earlier and shallower generation of oil and gas is expected in the Bahar-deniz region relative to that occurring in the vicinity of Bulla-deniz, with the principal reason being the 50% increase in heat flux at Bahar-deniz relative to that at Bulla-deniz. As a maximal contrast between the central part of the study area of the SCB and the northeastern section, Figure 13 shows a timing chart of oil hydrocarbon generation for each of the layers used in the burial history analysis for wells Bulla-deniz (Figure 13a) and Neft-dashlary (Figure 13b), while Figure 14 shows a similar timing chart analysis of gas generation for the two wells Bulla-deniz (Figure Z4a) and Neft-dashlary (Figure 146). These timing chart plots are useful in that they enable a quick visual inspection to be made of hydrocarbon generation, without the complexities of a superposed burial history. It is apparent from the timing chart plots that the north-eastern region shows earlier oil generation, together with shallower and earlier gas generation, than occurs in the Bulla-deniz region. The differences in time, depth and amount of oil and gas at each well, and for each horizon, now need to be evaluated across the basin as it evolves.

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Figure 13 Timing chart plots for cumulative Bulla-deniz; (b) at Neft-dashlary

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d

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gas generation:

(a)

370

Geohistory, thermal history and hydrocarbon

Con touring hydrocarbon results across the basin For each of the 12 wells in turn, similar outputs for oil and gas hydrocarbon generation were computed. The dominant generation of gas is post-Early Pliocene, as is the major oil generation phase. Accordingly, a series of contour diagrams at different times and different depths are now presented for the last 5 Ma. The two factors which most dominantly control the variation of cumulative oil and gas generation are the variations in isopachous thicknesses of different formations across the study area of the SCB and the systematic variations of heat flow from low (N 0.5 HFU) in the southern part of the basin to about 1 HFU in the northeast of the basin. Prior to Pliocene time the cumulative generation of both oil and gas is at least an order of magnitude smaller than the amount occurring during and after Pliocene. Accordingly, in order to capture the dominant oil and gas components, contours of cumulative hydrocarbon generation (in mg gg ’ TOC) are reported only from 5.2 Ma and younger. Because the known organic carbon is widely disseminated at an average of about 0.2-0.4% (Guliev et al., 1991; Guliev, 1995, personal communication), total cumulative production can be obtained from the contour maps by multiplying the results by an essentially constant factor of about (0.3 &O.l)O/, multiplied by volume between posted horizons. For example, Figure 1.5aprovides contours across the SCB of cumulative oil generation (in units of mgg-’ TOC) at 5.2 Ma at 6 km depth at that time, indicating oil generation only to a level of 5-10 mg g-’ TOC. At 8 km depth at 5.2Ma, Figure ISb also indicates but little oil generation; even as deep as 10 km at 5.2 Ma (Figure 1.5~) there is oil generation only to about 5 mg gg ’TOC. However, by middle Pliocene time (3.4 Ma) the situation has changed dramatically, as depicted in Figure 16 for the depths of 6 km (Figure 16a), 8 km (Figure 16b) and 10 km (Figure 16~). Oil generation in the northern part of the basin (near the Apsheron peninsula) now reaches of order 80-100 mg gg’ TOC at 6 km depth, but the southern section is still low at about 20 mg gg ’ TOC (Figure 16a). At 8 km depth (Figure 16b), the western part of the basin is reaching lOO-200mgg-’ TOC oil generation, while the north, east and southern parts of the basin are at 4080 mg gg’ TOC. And, at the greater depth of 10 km (Figure I~c), the central part of the basin has a cumulative oil generation of over 200 mg g- ’TOC, with the northern and southern sections ranging from 40-80 mg gg ’ TOC. Roughly, maximum cumulative oil generation at this time is at about 6 km in the northern part of the study area, at 8 km in the western onshore part, and at about 10 km in the south/southeast section of the area. By present-day, cumulative oil generation has diminished across all of the study area with only about 3& 50 mg gg ’ TOC in the northern section at 6 km depth (Figure I7a), and with roughly the same level of generation in the western onshore section at 8 km depth (Figure 17b), and between about 2&40mgg-’ TOC across the whole region at 10 km depth (Figure 17~). The largest contrasting pattern of behavior is, perhaps, that at the 10 km horizon from 3.4 Ma to today. Part of the reason for the massive shift in oil generation during this period is due to the lowering of sedimentation from late Pliocene through the Quaternary, while the major part is due to the conversion of generated oil to gas which outstrips the generation of oil from kerogen during this period. Indeed, cumulative gas generation contours at 6,

generation history: M. F. Tagiyev et al.

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8 and 10 km, at the same time horizons of 5.2 Ma, 3.4 Ma and present-day, reflect precisely this conversion of oil to gas. For example, Figure 18a gives the cumulative gas production (in mgg-’ TOC) at 6 km depth at 5.2 Ma, indicating that the northern section of the basin, around the Apsheron peninsula, is already at 200_300mggTOC. By 8 km depth the northern, middle and southern parts of the basin have all passed the 200mg gg’ TOC level of cumulative gas generation as shown in Figure

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18b, and that pattern is then maintained at greater depths, as indicated in Figure 18c, representing cumulative gas production at 10 km depth at 5.2 Ma. The same general pattern of behavior is seen at 3.4 Ma, after the massive Pliocene deposition, as shown in Figure 19. The high cumulative gas generation at 6 km depth is maintained in the northern section of the basin at lo& 200 mg g-’ TOC, as shown in Figure 29a; the pervasive spread of high gas generation across the whole basin with

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levels of 12WIOOmgg-’ TOC is seen in Figure 19b at 8 km depth, with the exception of the central and westerncentral parts of the basin where cumulative gas generation is only of order 4&80 mg g-’ TOC; by 10 km depth, the whole basin is at about 250mgg-’ TOC or higher of cumulative gas generation (Figure 19~). The cooler central portions of the SCB are mainly responsible for the slightly slower cumulative gas generation at this

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Figure 19 Contour maps of cumulative gas generation at 3.4Ma at different depths: (a) 6 km; (b) 8 km; (c) 10 km. Contours are in mg g-’ TOC

time but, by 10 km depth, major gas generation is widespread. The same pattern of behavior is repeated at the presentday, with high gas (-200mgg-’ TOC) in the northern part of the basin at 6 km depth (Figure 20~); high gas (2 200 mg gg ’TOC) in the southern and northern parts of the basin at 8 km depth, with of order XL-lOOmgg-’ TOC gas generation in the cooler central and western

sections of the basin (Figure 20b); and 25tF450mgg~’ TOC gas generation across the whole basin at 10 km depth (Figure 20~). The rate of generation of gas (in mg g- ’ TOC Ma-‘) from Pliocene to the present-day provides a different way of illustrating the conversion of oil to gas across the study area as paleoheat flux varies both spatially and as the massive Pliocene-Quaternary deposition occurs.

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Figure 21 Contour maps of gas generation rate at 5.2 Ma at different depths: (a) 6 km; (b) 8 km;(c) 10 km. Contours are in mg g-’ TOC

For horizons at 6, 8 and 10 km, Figure Zla,b,c, respectively, provides contours of rate of gas generation at 5.2 Ma, indicating high rates (2 100mg gg’ TOC Ma-‘) of generation in the southern sector of the basin at 6 km depth (Figure 2Za), medium (80mgg-’ TOC Ma-‘) in the central part of the basin at 8 km depth (Figure 21b), and low rates of gas generation ( < 6 mg gg ’TOC Ma-‘) across the whole basin at 10 km depth (Figure 21~).

By 3.4 Ma, massive gas generation (- 100-120 mg g-’ TOCMa-‘) is occurring in the northern sector of the basin at 6 km depth (Figure 22a); massive gas generation (- 100-120 mg gg ’ TOC Ma-‘) in the western onshore region at 8 km depth (Figure 22b); and low (5 30 mg gg ’ TOC Ma-‘) gas generation rate across the whole basin at 10 km depth (Figure 22~). By present-day, only moderate (4&60 mg gg ’ TOC Ma-‘) gas generation is occurring across the basin at 6 km depth (Figure 23a); medium to

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high (8&120mgg-’ TOCMaa’) gas generation is going on in the central and west-central parts of the basin at 8 km depth (Figure 23b), and low (<30mgg-’ TOC Ma-‘) gas generation is occurring throughout the basin at 10 km depth (Figure 23~). The implication is that conversion of oil to gas generally takes place in the last 5Ma or so, that full conversion takes place in the depth range of 6-10 km; and that the cooler central section of the basin is generally

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delayed in time in its gas generation relative to the warmer northern sector of the basin. Excessfluid directions

pressure

and hydrocarbon

migration

The predominance of argillaceous shale and clay material throughout the study area, and estimated (Abasov et al., 1991; Gambarov et al., 1993; Guliev, 1995, personal

Geohistory, thermal history and hydrocarbon 0

200

Pore pressure [atm] 400 600 600 1000

generation history: M. F. Tagiyev et al.

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kglsq.cm Figure 25 Excess fluid Bulla-deniz Figure 24 Pore pressure vs. depth in wells Bulla-deniz, deniz and Neft-dashlary (from Abasov et a/., 1991)

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communication) to occur to as early as the Jurassic, argues for the presence of fluid overpressuring. The competition is between the rate of sedimentation, the low permeability of shales which generally impedes fluid flow, and the rise in overpressure which, if too large, will lead to fracturing of sediments with a concomitant loss of overpressure to below the fracture limit. Most types of sedimentary rocks fracture when the total fluid pressure is a fraction of between about 0.75085 of the total overburden (Jaeger and Cook, 1976) -although extreme situations are known (Bour et al., 1995) where the lateral stress exceeds the overburden load, so that the principal rock failure direction is no longer effectively vertical. In such cases fluid pressure has reached 0.95 of total overburden load. Figure 24 provides in situ pore pressure measurements with depth for the three wells Bulla-deniz, Bahar-deniz, and Neft-dashlary, indicating a lowering of fluid pressure to the north of the study area from about 1OOOatm at 5.5 km depth at the Bulla-deniz well, to about 620 atm at the same depth at Neft-dashlary. The vertical pressure gradient is then from about 0.18 atm m-’ (2 0.9 psi ft-‘) (Bulla-deniz) to about 0.11 atm m-’ (0.55 psi ft-‘) (Neftdashlary). The total distance between Bulla-deniz and Neft-dashlary is about 100 km, so the corresponding horizontal fluid pressure gradient is around 0.35atm km-’ directed from the high pressure region around Bulladeniz towards lower pressure in the northeastern sector of the study area. Across the study area as a whole, the total vertical fluid pressure gradient for the 12 wells has an average of 0.8 psi ft-‘. The rise of overpressure across the basin, together with the massive gas generation, are the two likely main causes for the presence of the observed mud volcanoes, of which more than 200 are recorded in the SCB (Guliev et al., 1991; Guliev, 1995, personal communication). Figure 25 illustrates the excess fluid pressure build-up with time at well Bulla-deniz. The rapid deposition of the Jurassic shales (9 km in about 50 Ma) causes an early build-up of excess pressure to about 250 kg cmp2 (1 kg crnd2g 1.03 atm) at 150 Ma. However, the lack of any significant further deposition during the Cretaceous gives plenty of time for this overpressure build-up to ‘bleed off, reducing undercompaction to more nearly normal behavior. In the Tertiary, the steady deposition of a further 4 km of argillaceous shales from 65 Ma to 3.4 Ma causes a secondary rise in overpressure to a maximum of about 170 kg cmp2 between an overpressure top at 6 km to a basal depth of 14 km. The massive shale deposition from

mid-Pliocene time onward exacerbates the rise of overpressure, yielding a continuously increasing overpressure with time, which rises to as high as around 800 f 50 kg cm-* in the late Pliocene to early Quaternary through to the present-day. The total fluid pressure rises nearly to the fracture point (*O.SS) for typical consolidated, brittle, failure but, given the ductile nature of shales, the deformation of sediments and associated mud volcanoes would seem to be the prevalent path by which massive rock fracture failure is avoided. For each of the 12 wells in the study area, similar developments of evolution with time have been evaluated. In this way contours can be given of excess pressure development with time across the basin at different fixed depths or, alternatively, depth values to a given isobaric level can be drawn, thereby indicating the relative equivalent hydraulic head driving fluid flow across the basin. To provide a basis for evaluating the evolution of the fluid pressure development across the basin in relation to sediment fill, relative to a structural map at base of sedimentary cover (Figure 26a), three major groupings of sediment isopachs are looked at here (Figure 26b,c,6) based on well data and on seismic data when deeper than drilled depths. At the end of the dominant Jurassic deposition, the western, southern and central regions had accumulated about 7-7.5 km of sediments by shedding from the Talysh-Vandam high region, with the Apsheron region receiving less than about 5-6 km, leading to a local high in the Bulla-deniz region of order 2.5 km relative to sediment supplied to Baku (Figure 26b). By late Neogene time, the combined isopach thickness across the section from Cretaceous through Neogene amounted to some 5 km in the region of Bulla-deniz, and about 8-9 km along the Great Caucasus-Apsheron peninsula region, so that the relative high of 2.5 km at Bulladeniz is now reversed to a depression of about 1.5-2.5 km relative to the structural high which follows parallel to sub-parallel to the erogenic development of the Caucasus (Figure 26~). The massive deposition in the mid-Pliocene through Quaternary resulted in a isopach thickness of 5-7 km in the southeastern portion of the area (towards the Turkmenian border) with a thinner section of around 4-5 km across much of the north, parallel to the Great Caucasus. The depression in the central part of the basin is then filled by the extra l-3 km of late Pliocene/Quaternary sediment, with local variations due to transpressive thrust of the Talysh-Vandam wedge under the Great Caucasus plate after Tethys Sea closure in late Miocene/early Pliocene (Figure 266).

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Geohistory, thermal history and hydrocarbon

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Figure 26 (a) Structural map at base of sedimentary pile (from Gasanov et al., 1988); (b) Schematic isopach map of Jurassic deposits (from Bagir-zadeh et al., 1988); (c) Schematic isopach map of Cretaceous-Paleogene-Miocene interval of the sedimentary cover; (d) Schematic isopach map of Pliocene-Quaternary interval of the sedimentary cover. Contours are in km

Fixed depths, variable excess pressure with time

Because the dominant rise in excess fluid pressure is associated with the rapid and massive Pliocene-Quaternary shale sedimentation, we concentrate here on excess pressure evolution across the basin from 5.2 Ma through to the present day. As a basis for comparison, Figure 27a,b,c shows the excess fluid pressure (in atmospheres) across the basin at 23 Ma, at depths of 6, 8 and 10 km respectively. There is an approximate 40atm increase between 6 and 10 km, but the values are typically scattered in the range W-140 atm. By the early Pliocene (5.2 Ma) the extra sediment deposition of about 4 km across the basin has raised the excess pressure values a little as exhibited in Figure 28a,b,c for 6, 8 and 10 km depths, respectively. There is a slight high of excess pressure at all depths in the northeast of the basin (yielding a lateral excess pressure gradient of 0.2 atm km-’ from a northeast high to a southwest low), but the variation with depth in the 610 km range is again limited to 20-40 atm. By middle Pliocene time (3.4 Ma) the massive deposition across the basin, with the central part of the basin receiving about 4 km more recent sediments than the flanks, creates a major center of overpressure in the central and west-central parts of the basin, rising to about 300-330 atm at 6 km depth (Figure 29~) to 330-360 atm at 8 km depth (Figure 29b), and 390-

410atm at 10 km depth (Figure 29~); meanwhile the northeastern sector of the basin has an overpressure of only around 180atm at 6 km depth, 2lOatm at 8 km depth, and 240atm at 10 km depth, so that a northeastward trending lateral gradient of around 1.2 atm km-’ is developed from the central excess pressure high around the Bulla-deniz region. By 1.8 Ma, this pattern of excess pressure development has intensified in magnitude but not changed in shape. As shown in Figure 30a,b,c, drawn for depths of 6,8 and 10 km respectively, the excess pressure high in the central basin continues to strengthen, with lateral pressure gradients to the northeast, northwest and southwest, but with the highest pressure contrast in the northeasterly direction. This strengthening of the overpressure pattern throughout the basin continues to the present-day as even more Quaternary and Holocene shale-like sediments are added to the basin. Figure 3la,b,c, drawn for depths of 6, 8 and 10 km at the present-day, illustrates this total pattern of development. As well as the horizontal gradient of excess pressure, the vertical gradient is now increased to around 50 atm km-’ between 6 to 10 km i.e. around 0.25-0.3 psi ftt’ of excess fluid pressure, which when added to the hydrostatic pressure gradient of about 0.5 psift-‘, yields an estimated vertical fluid pressure

Geohistory, thermal history and hydrocarbon

generation history: M. F. Tagiyev et al.

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gradient of 0.75-0.8 psi ftt’ - as is generally observed in wells in the study area at 6-8 km depth. Isobaric pressures, variable depths with time An appreciation of which formations are most likely to be responsive (in terms of fluid flow) to applied excess pressure can be attained by constructing depth contours with time across the basin at which a fixed isobaric total fluid pressure is reached. A constant depth across the study area would indicate no lateral pressure gradient.

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Thus the difference in elevations across the basin in order to reach a prescribed isobaric value gives an idea of the differential hydraulic head driving fluid migration. Shown in Figure 32a-j, is the development of contours of depth elevation to reach total isobaric pressures of 900atm and 1200atm, respectively, at 23 Ma, 5.2Ma, 3.4 Ma, 1.8 Ma and present-day, respectively. Note from the Miocene (23 Ma) and early Pliocene (Figure 32u-6) that there is not much change in the depth elevations, with 900atm being reached around 8.&

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Figure 30 Contour maps of excess fluid pressure at 1.8Ma at depths: (a) 6 km; (b) 8 km; (c) 10 km. Contours are in atmospheres

8.6 km, and 1200 atm being reached around 11.0-l 1.6 km in both cases. However, following the massive deposition and associated increase in overpressure during the Pliocene the situation changes markedly. Shown in Figure 32efare the depth elevations to reach 900 atm and 1200 atm, respectively, at 3.4Ma. Note the considerable shallowing to around 6.3 km in the central part of the basin to reach 900atm, with the northeastern part equivalent depth being around 7.5 km. Thus there is an equivalent

hydraulic head of about 1.2 km at the 900 atm isobar, as shown on Figure 32e, which drives fluids northeastward from the central part of the basin. The same phenomenon is recorded at the 1200 atm isobar (Figure 32f), where the central part of the basin and the west-central part have equivalent head depths of 9 km, while the north-east is at around 10.5 km, again corresponding to a northeastward-directed hydraulic head of around 1.5 km. By 1.8 Ma, the 900 atm isobar is now reached at between 5-5.6 km across the basin, with a slight north-

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379

reduced to 0.2-0.6 km to the northeast from the central part of the basin at 900atm, and to about 1 km head at 1200 atm; with northwesterly and southwesterly head drives of around 040.6 km at the 1200 atm isobar value, and O-O.4km head at the 900 atm isobar value. The dominant conclusion is that the massive deposition in the Pliocene forces lateral pressure gradients to be mainly directed to the northeast from the central portion of the basin, with secondary drives to the northwest and southwest. The prevailing drives slacken by around 1.8 Ma to present, in concert with the lessening sedimentary deposition, so that the major push for hydrocarbon migration is between about 3-l Ma, but migration occurs prior to and past that intensive phase of overpressure build-up. In addition to the excess pressure development as the driving force, lateral and vertical migration of fluids (in particular hydrocarbons) can occur most easily when the formational permeabilities are as high as possible. Thus, the frequency of interbedding of sandy and shaley lithologies, and the large-scale connectivity of high permeability pathways through the basin, are the main components indicating likely flow of fluids, once an excess pressure field is established which varies both vertically and across the study area. Characteristic descriptors of likely trends for hydrocarbon migration pathways are the sand/shale ratios in the wells, together with the shale porosity with depth with respect to basinal position. Buryakovsky and Djevanshir (1983) have compiled average sand/shale ratios for wells in the study area and grouped them into three sub-areas, called Areas I, II and III respectively, as shown on Figure 33. To the typical well depth of around 5-6 km, the average sand/shale ratio is around 50:50 in Area 1, around 30:70 in Area II, and around lo:90 in Area III. These domains are precisely those with the highest overpressure today (Area III, as typified by Bulla-den@, medium overpressure today (Area II, as typified by Bahar-deniz), and low overpressure today (Area I, as typified by Neft-dashlary), and are in accord with the estimated directions of lateral fluid pressure gradients since Pliocene time. In addition, data on shale porosity variations with depth have been compiled in the wells by Bredehoeft et al. (1988) and, as depicted in Table I for the average values from wells in each of the sub-areas, there is a systematic tendency for shale porosity to be retained to a higher degree in Area III than in Area II, and retained more in Area II than in Area I, again indicative of the direction of recent fluid flow from the central part of the basin to the northeast.

218

Figure31 Contour maps of excess fluid pressure at present-day at depths: (a) 6 km; (b) 8 km; (c) 10 km. Contours are in atmospheres

Table 1 Shale porosity vs. depth for Areas Bredehoeft et al., 1988)

Depth (m)

eastern fluid driving tendency of around 0.2-0.6 km equivalent hydraulic head, as shown in Figure 32g. The driving head at the 1200 atm isobar at this time still maintains about a 1 km differential from the central part of the basin to the northeast, and about a 0.5-0.8 km head to the northwest, indicative of the longer time it takes fluid pressure to ‘bleed off from depth compared to shallower formations (Figure 32h). By present-day, as shown on Figure 32i (900atm isobar) and Figure 32j (1200 atm isobar), the driving head is

750 1250 1750 2250 2750 3250 3750 4250 4750 5250

I, II and III (from

Area I

Porosity (%) Area II

Area Ill

27.0 21.5 16.0 12.0 8.5 7.0 5.5 4.5 3.0 -

29.0 23.5 19.0 14.0 13.0 12.0 10.4 9.5 8.5 -

31.0 26.0 22.0 20.0 18.5 16.5 16.0 16.0 13.5 12.3

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Figure 32 Isobaric depth contour maps across the area for 900 atm and 1200 atm total fluid pressure values at 23 Ma, 5.2 Ma, 3.4 Ma, 1.8 Ma and present-day, respectively. Contours are in metres

Discussion and conclusions In this application to the South Caspian Basin, checks were made on pressure but not on permeability because of lack of data. Even without considering the effects of faults and mud diapir movement, the distribution of hydrocarbons reservoired in the Productive Series of the Pliocene in the SCB reflects a fairly good relation to the paleostructure highs, the fairways of regional fluid flow, and the trends in porosity and pressure, indicating that all these conditions play an important role in controlling the hydrocarbon migration and accumulation in the SCB. Further studies on the basin evolution, hydrocarbon generation, migration and accumulation in the SCB are recommended such as: Use more wells and ties to more seismic profiles in order to reconstruct a more complete basin evolution history; Use porosity, permeability and pressure data, with well log data, to study cementation, dissolution and fracture evolution, and their effects on hydrocarbon generation, migration and accumulation; Use better quality-controlled thermal indicators and

tomography history.

to reconstruct a more accurate thermal

The following two major conclusions can be derived from this study: The Jurassic is a minor contributor to present-day hydrocarbons in the SCB, and is post-mature in most areas of the basin. Peak oil generation for the Miocene-Oligocene complex was reached during Pliocene and Holocene. Peak gas generation by cracking of oil occurred during the last 3 Ma (from Late Pliocene to present). Peak oil migration in the SCB probably happened during mid- to late Pliocene. The paleostructure highs, the fairways of regional fluid flow, and the trends of excess pressure, porosity and permeability during peak oil and gas migration time, played important roles in controlling the hydrocarbon migration pathways and accumulation sites in the South Caspian Basin. Tectonic faulting and mud diapir evolution also have roles to play in controlling hydrocarbon accumulation sites, both of which processes will be considered in a future communication.

Geohistory, thermal history and hydrocarbon

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generation history: A4 F. Tagiyev et al.

381

382

Geohistory, thermal history and hydrocarbon

generation history: M. F. Tagiyev et al.

Neft-dashlaty

Kalamaddin

AREA 3

Figure 33 Three sub-areas

delimited

by various

average

sand/shale

Acknowledgements The work reported here was supported by the Industrial Associates of the Basin Modeling Group at USC, by the Azerbaijan Academy of Sciences, and by grant number MVY 000 from the International Science Foundation.

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