НЕФТЬ И ГАЗ 641. I. Guliyev, A. Feyzullayev, D. Huseynov, M. Tagiyev, H.-M. Aliyev

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1 НЕФТЬ И ГАЗ 641 I. Guliyev, A. Feyzullayev, D. Huseynov, M. Tagiyev, H.-M. Aliyev Chapter 4. GEOCHEMISTRY OF ORGANIC MATTER AND HYDROCARBON FLUIDS AND BASIN MODELLING Source rocks A stratigraphic range from Middle Jurassic to Lower Pliocene in the South Caspian Basin (SCB) has been covered by source rock studies. Analyses were performed on over 500 rock samples collected from over 50 localities, including outcrops, mud volcanoes (ejecta) and boreholes. The bulk of samples were taken at outcrops (37 localities). The deposits of Maykop Series (Oligocene-Lower Miocene) and Diatom Suite were the most extensively studied, whereas the Chokrak unit was represented by relatively few analyses. Lower Eocene, Lower Jurassic and Pontian were among inadequately studied stratigraphic units. Organic geochemical study of the Lower Pliocene unit has been conducted mostly using core samples collected from offshore oilfields, with a few samples from outcrops. Sampling was selective with regard to lithological character of the particular section and aimed to make the most coverage of argillaceous intervals differing in colour and thickness. The number of samples taken from one outcrop varied between 5 and 56. To minimize the impact of exogenous factors on samples, they were collected after removal of an upper cm layer of rock. The laboratory studies of organic matter (OM) included optical examination, pyrolysis, determination of total organic carbon (TOC) content, carbon isotopic composition of kerogen and individual fractions of the OM extract. Optical data included measurements of vitrinite reflectance, TAI (thermal alteration index) and SCI (spore colour index). TOC was determined on a LECO CS444 device using the decarbonated residue of powdered samples. Programmed pyrolysis was performed on powdered whole rock samples using a LECO THA-200 device. This technique provides the following parameters: S 1 (mg of free and adsorbed hydrocarbons per gram of rock), S 2 (mg of hy-

2 642 ГЕОЛОГИЯ АЗЕРБАЙДЖАНА drocarbons per gram of rock, obtained by thermal decomposition of kerogen), T max - (the temperature corresponding to maximum rate of S 2 yield), and the hydrogen index (HI), a measure of hydrocarbon generative potential of kerogen and its preservation state (mg S 2 /g TOC). The isotopic composition of kerogen and individual fractions of extracts were analyzed using a VG 602C and CJS Sigma mass-spectrometers. Vitrinite reflectance measurements were made on polished surfaces of whole rock samples. The data on source properties of rocks produced through pyrolysis indicate that among different age units of the SCB the Oligocene-Miocene has the highest potential for petroleum generation. A considerable amount of data has been summarized to provide a quantitative notion of the distribution and variation range of geochemical parameters. Geochemical study of sedimentary rocks of the SCB suggests that the source rocks are characterized by moderate genetic HC potential. However, in the thick section comprising many stratigraphic units there are horizons with good and excellent oil source properties. They are particularly frequent in the Oligocene and Miocene deposits (Table). In this connection, as well as allowing for their great thickness, predominantly argillaceous content and the tendency for an improving of source facies down the regional dip of these strata under the thick Pliocene-Quaternary complex, where major hydrocarbon resources are concentrated, they can be considered as a key source sequence in the SCB. Summing up the results of the pyrolysis study it should be noted that, as a whole, none of the considered sedimentary units can be placed into a source rock category based only on average geochemical parameters. However, oil generative horizons with high TOC and HI values are most frequent in the Oligocene-Miocene interval. On the whole the relatively modest source potential of the sediments in the SCB is compensated for by their great thickness and predominant clayey content (up to 90%), as well as by the high oil expulsion efficiency due to formation of large volumes of gas concur-rent with oil generation. These circumstances appear to explain the large hydrocarbon re-sources discovered here. There is a clear differentiation between the carbon isotope compositions of pre- Diatom and Diatom OM. Kerogen from the Diatom sediments contains considerably heavier δ 13 C (less negative) than the respective values for older parts of the sedimentary section. A number of maturity indicators (T max, Ro, TAI and SCI), were used for detailed evaluation of OM thermal conversion. The largest dataset was of T max (N=272), though Ro (110), TAI and SCI (92) determinations were represented in considerable number as well. All intervals, except for the Jurassic, have undergone thermal stress inadequate for decomposition of OM. It should be noted that Jurassic samples came from outcrops on the north slope of the Greater Caucasus, Pre-Caspian - Guba foredeep, a geological province outside the limits of the SCB. The younger sediments were sampled within the Shamakhy-Gobustan superimposed trough. Vitrinite reflectance versus depth profiles were examined on core samples collected from the Miocene interval of two fields, West Duvanny and Solakhay (located near the coastline). They indicate an immature state of the sediments down to as deep as 4500 m and probably deeper with respect to oil generation. In the penetrated offshore Productive Series section R o value of 0.6% was found to be at 5300 m.

3 Minimu m Mean Maxi mum Std.Dev. НЕФТЬ И ГАЗ 643 Statistical summary for pyrolysis-derived geochemical parameters for the stratigraphic intervals of the South Caspian Basin Table 1 Number of samples TOC (wt.%) HI (mghc/g TOC) Productive Se- S1 (mghc/g rock) ries (L.Plio.) S2 (mghc/g rock) Tmax ( o C) Ro (%) TOC HI Diatom S (M.-U. Mio.) S Tmax Ro TOC HI Chokrak S (M. Mio.) S Tmax Ro TOC HI Maykop (Oligo.- S L.Mio.) S Tmax Ro TOC HI S Eocene S Tmax Ro TOC HI S Cretaceous S Tmax Ro TOC HI S Jurassic S Tmax Ro Thermal conditions favourable for realization of the genetic hydrocarbon potential of the assumed Oligocene and particularly Miocene oil source rocks are thought to be present in the central most subsided part of the basin.

4 644 ГЕОЛОГИЯ АЗЕРБАЙДЖАНА Geochemistry of oils Reservoired oils were studied at 53 fields located in the Absheron, Yevlakh- Aghjabedi, Shamakhy-Gobustan and Lower-Kura oil and gas bearing regions, in the Baku and Absheron archipelagos and in the interfluve of the Kura and Gabyrry rivers, comprising reservoirs from Upper Cretaceous to Upper Absheron levels. Table 2 displays average values for a number of common biomarker parameters characterizing the studied oils. The isotope composition of 20 natural oil seeps associated with mud volcanoes of the Absheron, Shamakhy-Gobustan and Lower Kura regions received a study as well. As a result of the study of the isotope composition of carbon (δ 13 C) of oils there have been identified two main groups of oils: 1) isotopically light - with δ 13 C values of o / oo to o / oo for the total carbon and o / oo to o / oo for the carbon of the alkane fraction and 2) isotopically heavy, with values of o / oo to o / oo and o / oo to o / oo for the total carbon and the alkane fractions, respectively. Oils of the second group are quanti-tatively dominant (around 65% of the examined samples). The first group includes oils generated by Maykop series and Pre-Maykop deposits. The second group consists of oils generated by the Diatom (Middle and Upper Miocene) complexes. The oil seeps associated with mud volcanoes have been isotopically differentiated into two groups: oils with a typical Paleogene Lower Miocene carbon isotopic signature and those representing mixed oils generated from both Paleogene-Lower Miocene and Diatom sources. About half of the mud volcanoes have been ascertained to release Paleogene - Lower Miocene sourced oils. Some 17% of the seeps are sourced from the Diatom complex, and the remaining 33% is a mixture of oils from the Paleogene - Lower Miocene and Diatom sources. All of the studied oils appear to derive from source rocks deposited in nearshore - marine and deltaic conditions. The Pr/Ph ratio exhibits mostly low values, only a few of them falling in range. Sulphur content does not exceed 0.4%. These results and isotope data suggest that the initial organic matter had a mixed terrestrialmarine composition, with a predominant sapropelic input. These conclusions are confirmed by the C 27 :C 28 :C 29 normal steranes and isosteranes ratios (33:35:32 and 31:36:33, respectively). The relatively high values of the oleanane index suggest a substantial input of terrestrial organic matter into the paleobasin, whilst the moderate values of the gammacerane index points to a saline water environment. The available geochemical data indicate that the oils reservoired in the Lower Pliocene are not syngenetic and migrated up from the Pre-Pliocene deposits. The Pliocene basin was likely to be a closed freshwater basin with intensive input of organic debris carried along with terrigenous clastic material. The occurrence in the Pliocene reservoirs of both isotopically light and isotopically heavy oils, with 3-4 difference on δ 13 C values, suggests their having been generated from at least two different sources: Pre-Miocene interval and the Diatom unit. Contributions to oil charge from different stratigraphic levels are variable from one part of the basin to another: towards the central deep-buried part the share of oils supplied from the Diatom Suite becomes greater, whereas in flank zones charge from the Lower Miocene is higher. The general trend is that from land to sea the oils grow isotopically heavier. Buried under seaward thickening Pliocene-Quaternary strata Diatom deposits are gradually lowered down to around 10 km depth, and become increasingly involved in oil generation zone. Accordingly, the Diatom contribution to oil pools in the PS increases in the same direction, while underlying deposits (including Maykop strata) appear to generate mainly gas and gas condensate. This suggestion based on the geological and temperature conditions of source rock occurrence and basin-modelling results is well con-firmed by the study of the carbon isotope composition (ICC) of organic matter and oils.

5 НЕФТЬ И ГАЗ 645 Based on the isotopic composition of the oils, Paleogene-Lower Miocene and Diatom source rocks appear to have contributed approximately equally to the oils in the Pliocene reservoirs of the Absheron peninsula. In the Pliocene reservoirs of Shamakhy-Gobustan region and Baku archipelago oil charge from the Diatom complex are prevalent. Approximately 3/4 part of the oils in the Lower Kura region were derived from Paleogene-Lower Miocene source rocks. 2/3 part of the oils in the Absheron archipelago Pliocene reservoirs is suggested to come from the Diatom suite. Analysis of ICC in PS oils suggests that in formation of accumulations there have been two major subvertical migration phases. The first migration phase is associated with the intensive transformation of the Maykop OM, with the Diatom being in immature state. In this period oil of relatively light ICC fills up traps in the PS lower division. The second migration phase took place when Diatom deposits became adequately subsided to start intensive generation of oil. Now traps of the PS upper division receive oil charge with relatively heavy carbon signature. Analysis of biomarker ratios of sterane isomerization {ααα C 29 (20S/S+R)} and monoaromatic sterane aromatization {C 28 triarom. sterane / (C 28 triarom. + C 29 monoarom. Sterane)} suggests that the most mature oils among those from various regions of the South Caspian megadepression occur in reservoirs of the Middle Kura depression. Maturity of the oils collected from the Lower Pliocene reservoirs varies from 0.45 to 0.67 %R o. The relatively mature oils occur in oilfields of Lower Kura depression, Baku and Absheron archipelagos (R o =0.62%). Maturity of the mud volcano seep oils based on monoaromatic sterane aromatization suggests low transformation degree, which expressed in vitrinite reflectance equivalence corresponds to the range of R eq %. The studies, briefly outlined above, allows suggesting that further exploration ac-tivities in the deep-water South Caspian will result in discovery of more mature liquid and large gas (gas-condensate) accumulations. Average values of main geochemical parameters of South Caspian oils Table 2 C Pr/ Ph/ Reservoir age Normal steranes,% Isosteranes,% Diasteranes,% Steranes δ Cwhole δ Calk δ Carom n-c 17 n-c 18 C27 C28 C29 iso-c 27 iso-c 28 iso-c 29 dia-c 27 dia-c 28 dia-c 29 20S/S+R Pliocene 32,31 33,94 33,74 28,55 36,36 35,08 25,14 45,97 28,90 0,383-25,76-26,31-25,41 5,44 4,64 Miocene, 31,13 37,16 31,71 24,25 36,66 39,09 0,267-25,38-25,40-23,70 1,02 Diatom Miocene, 30,28 37,58 32,15 27,67 37,00 35,33 0,345-27,31-27,87-27,37 Chokrak Oligo.-Mio., 30,79 36,30 32,91 27,00 36,38 36,62 27,00 44,23 28,77 0,328-27,63-28,01-27,33 5,05 4,10 Maykop Eocene 32,07 33,65 34,28 28,17 35,54 36,23 26,63 44,81 28,57 0,452-27,86-28,33-27,42 ** ** U.Cretaceous 31,85 36,6 31,6 28,0 35,8 36,2 27,7 46,7 25,6 0,358-28,00-28,15-27,05 ** **

6 646 ГЕОЛОГИЯ АЗЕРБАЙДЖАНА Geochemistry of gases Azerbaijan is called as Land of fires. Within its territory there are 10 burning dry gas outcrops, over 400 mud volcanoes with gas manifestation, 12 solid gas manifesta-tions as gas -hydrate on the Caspian Sea bottom, over 15 gas manifestations related with mineral sources. 75 fields of natural gas are developed in Azerbaijan depths. From them there are 6 gas fields, 8 condensate fields, 18 oil fields with gas caps, 30 fields with gas dissolved in oil. The consistent transition from oil to oil-and-gas and gas-condensate fields is observed towards the submersion of the productive series deposits of the main oil-and-gas bearing suite. The greatest reserves of gas are re-lated with gas-condensate deposits. The mentioned manifestations of gas are pointed on map Natural gases of Azerbaijan. (Fig ) According to data of numerous tests there had been studied the chemical, isotopic composition of gases and physical parameters of water-dissolved gases. Chemical composition of gas is expressed by the following components and the limits of their content: 1 hydrocarbonaceous components: methane - from 51,0 to 99,0 %, ethane - from 0,14 to 11,0 %, propane - from 0,04 to 4,4 %, butane - from 0,04 to 3,8 %, pentane - from 0,04 to 3,3 %; 2 - noncombustible gases: - carbon dioxide - from 0 to 46,0 %; nitrogen from 0,01 to 9,0 %, argon from 0,001 to 0,04 %; 3 traces: helium from 0,0002 to 0,03 %; hydrogen sulphide - from 0 to 0,5 %. Isotopic composition of methane carbon (δс 13 СН 4 ) varies from 37,2 to 60,3, on average 45,0, ethane carbon from 21,0 to 40,3, on average 28,9, propane from 10,5, to -33,7, on average -23,7, isobutene from -21,5, to - 35,8, on average -27,0, normal butane from -14,8 to -30,8, on average -23,5, butane from -18,0 to -32,6, on average -25,3, isotopic composition of methane hydrogen δдсн 4 varies from 101,0 to -277, on average The regularities of change of the chemical and isotopic composition of gas depending upon the different geologic -geochemical factors had been determined. Thus, according to methane content, the increase of percentage content of the mentioned component is observed from Absheron stage to the productive series, and the decrease from productive series to foraminifera deposit; by sum of heavy hydrocarbons the reduction of their content is observed from Absheron stage to productive series, and the increase from the productive series to foraminifera deposits. The values of ratio of normal butane to isobutene and normal pentane to isopentane increase naturally from top to bottom along the section of the Tertiary and Mesozoic deposits. The gradual increase of methane content and sum of its homologues towards the submersion of the productive series and reduction of weight of isotope of methane carbon, ethane, propane and butane had been determined. The change of isotopic composition of gas depending upon the stratigraphic age of rocks, depth and along the field of oil-and-gas bearing suite is observed. Results of chemical and isotopic investigations allowed determining the correspondence of gases to different zones of forming: biogenic, main phase of oil-and-gas forming, upper zone of gas-forming, as well as zones of mixed and migration gases. Gases associated / not associated with oil, forming due to oil cracking and organic matter of the sedimentary rocks had been studied. The main volume of gases of the productive series had formed together with generation of liquid hydrocarbons, i.e. as the associated gases. This is corresponded not only to gases of oil but gascondensate fields. The coincidence of main gas-chemical zones of Azerbaijan on methane, carbon dioxide and nitrogen with boundaries of structures of the first order, as well as with the changes of depths of occurrence of the crystalline basement are of definite interest. Chemical composition of water-dissolved gas is hydrocarbonaceous with small admixture of noncombustible components and hydrogen sulfide. Gas saturation of water varies from 0,3 to 40 m 3 /m 3. Change of gas-saturation of formation water depends upon

7 НЕФТЬ И ГАЗ 647 the depth of occurrence. Waters of the western flank of the depression, including Absheron, Gobustan, Lower-Kura oil-and-gas bearing regions and Baku archipelago has the gas-saturation to 3,1 m 3 /m 3. Water of more submerged zones of the productive se-ries are characterized by gas-saturation from 3,1 to 5 m 3 /m 3. Waters with gas-saturation 5-6 m 3 /m 3 and more locate in the deep part of the South-Caspian depression. Basin modelling Over two decades has passed since first basin modelling studies were carried out in Azerbaijan. In at the Geology Institute of Azerbaijan Academy of Sciences (GIA) a procedure for evaluation of hydrocarbon potential of deep-laid strata was developed and respective software elaborated to conduct computations on a computer. Using this, formation of oil and gas at different stratigraphic levels of the SCB was quantitatively described and maps were drawn to display hydrocarbon generation density (per area unit). Based on kinetic modelling total amounts of oil and gas generated by different sedimentary complexes in SCB were calculated (Tagiyev, 1989, 1994). Since mid-1990 s a number of joint basin modelling studies were undertaken by scientific, educational and industrial organizations in Azerbaijan in collaboration with foreign energy companies and scientific centres to reconstruct hydrocarbon (HC) generation and migration processes and predict their accumulations in SCB. A wide range of geological processes were simulated by group of GIA researchers under supervision of prof. I.Lerche of the University of South Carolina in (I.Lerche et al., 1996). Studies on evaluation of physical nature of lithospheric plate, hydrocarbon generation and migration in sedimentary package of the SCB, geometrical evolution of mud diapirs and adjacent layers allowed broadening knowledge about the processes occurring in the basin. Significant results were also obtained on the extent of hydrocarbon generation and migration, occurrence of oil window in depth and time, distribution of overpressure etc. On a 270-km long seismic line across the west central and central parts of the SCB an inverse flexural plate method was used to recover original unloaded plate pa-rameters (Nadirov et al., 1997). Several findings of this study indicate that elastic flex-ure has played a major role in the tectonic development of the SCB. Comparative analysis of the flexural rigidity, bending moment, compressive stress and dip angle in particular provides insight into the flexural/tectonic forces acting in the region. The value of plate rigidity is comparable to estimated oceanic crust values, in line with the suspected Tethys oceanic fragment below the sediments. 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 SCB were evaluated using a one-dimensional fluid flow / compaction model (Tagiyev et al., 1997). The most intensive oil gen-eration in the area occurred during the last 5.2 My, when the oil window is confined to depths between km in the northwest, 7-10 km in the west (onshore part of the study area), and 8-11 km in the central and southwestern parts of the area (offshore). Below the oil window cracking occurs of oil into gas. Rapid sedimentation, which took place in the middle Pliocene through Quaternary, results in overpressure buildup across all of the study 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. Other areas of Azerbaijan, among them the Lower Kura depression and Yev-lakh- Aghjabedi Depression have received basin modelling studies as well. Differing geological settings gave rise to distinct petroleum systems in these areas. According to modelling results in the Lower Kura depression Oligocene-Lower Miocene deposits are marginally mature to mature depending on locality and genera-

8 648 ГЕОЛОГИЯ АЗЕРБАЙДЖАНА tion commenced less than 2 MYBP and continues at present at depths between 6 and 12 km (Inan et al., 1997). Currently younger strata of Upper Miocene and basal Lower Pliocene are estimated to occur in the upper oil window. In Yevlakh-Aghjabedi Depression peak oil generation for normal marine source rocks occurs at depths between 4 and 6 km within the last 3 million years (Klosterman et al., 1997). Only a small proportion of Eocene to Oligo-Miocene potential source interval has been buried deeply enough to reach thermal maturity, resulting in relatively low volumes of generated oil in the area. A fluid flow simulation (Mudford et al., 1997) along the line connecting Shahdeniz at the deeper offshore part of the SCB with the oilfields of Absheron peninsula revealed that the major fault situated between Bahar and Gum-deniz oilfields acted as a barrier, thus was responsible for considerable overpressure difference between onshore and offshore fields. Earlier, possibility of regional scale fluid flow within the SCB was mathematically analysed by Bredehoeft et al. (1988), who came to conclusion that hydraulically isolated sands are major lateral fairways for fluids expelled from overlying and underlying compacting shales. Based on geochemical evidence and basin modelling Abrams et al. (1997) suggested multi-stage hydrocarbon emplacement into evolving structural traps in the SCB. The first phase of emplacement occurred in the Middle Pliocene when tectonic move-ment and increased subsidence initiated early trap/reservoir formation, hydrocarbon generation, and migration. Late rapid subsidence from Quaternary tectonic activity produced additional hydrocarbons to replenish older, depleted traps and charge newly formed traps. Joint basin modelling study by GIA and Japan National Oil Company (JNOC) was aimed to assess hydrocarbon generation, migration and accumulation processes in the deep-water part of SCB. Four regional seismic lines involving lithologic, source rock and thermal data from known onshore and offshore fields served as geologic basis for two-dimensional basin analysis with the use of SIGMA-2D software package. Maturation of potential source rocks, expulsion of HCs and their entrapment in structural highs were simulated according to suggested geological scenarios. Thermal maturation of potential source rocks at individual locations of Pri- Caspian-Guba region was a subject of one-dimensional modelling (GIA & Collinson Jones Co.). Borehole temperature measurements, thermal properties of rocks and vitrinite reflectance data were employed to calibrate models. Both constant and variable heat flux scenarios were computed. The results suggest that in the studied region the depth interval of oil and gas generation brackets a broad stratigraphic range from Jurassic to lower Pliocene and is characterized with variation over the area. In conclusion it should be noted that the features of HC generation and migration revealed through basin modelling are of vital importance for elucidation of formation mechanism of oil and gas fields, evaluation of prospects for HC presence and planning of exploration works. Experience leads us to conclude that efficiency of basin modelling in the SCB is determined in many respects by how complete our knowledge about the geo-logical processes occurring in deep sedimentary strata is. Conventional basin modelling software producing reasonable results for normal basins in the case of unusual basins like SCB encounter challenges. The most substantial one is thought to be mud diapirism / volcanism processes accompanied by anomalous overpressure and mass convection effects. These processes leading to noticeable change in the structure of the sedimentary cover and having much impact on fluid movement are beyond the scope of conventional basin modelling software. The future development of this direction necessitates construction of 3-D models involving wider spectrum of geological processes and allowing their more reasonable reconstruction.