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Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles
Volume 74, 2019
Article Number 74
Number of page(s) 8
DOI https://doi.org/10.2516/ogst/2019046
Published online 18 September 2019

© A.A. Feyzullayev & I. Lerche, published by IFP Energies nouvelles, 2019

Licence Creative CommonsThis is an Open Access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/4.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

1 Introduction

The widespread occurrence of sedimentary rocks together with modern sediments lining the bottom of the world’s oceans and terrigenous basins form a cover of the Earth. The thickness of the cover varies widely from 0 to 20–30 km. The total volume of sedimentary cover rocks is estimated at 1.1 × 109 million km3, which is about 11% of the Earth’s crust [1]. Current concepts suggest that all voids in sedimentary rocks (except for hydrocarbon deposits) are filled with water below the groundwater level. According to available estimates [2], about 3.0 × 1023 g water is contained in the sedimentary cover. In the South Caspian Basin (SCB), the volume of these waters is estimated at about 5.3 × 1020 g. Groundwater is represented both in free and bound (adsorbed) forms. Vernadskiy [3] pointed out the important role of water in geological processes and noted that the water composition is a function of the long evolution of the water–rock–gas–OM system.

The fundamental property of this system is its equilibrium–nonequilibrium state [3–6]. Water is in continuous interaction with the mineral skeleton of the rocks, maximal in finely dispersed (clay) rocks that form about 70% of the total sedimentary rock volume. Water–rock interaction processes (ion exchange, dissolution and precipitation) are responsible for the chemical aspects of mineral diagenesis [7–10].

Understanding these processes is extremely important in the petroleum industry because they lead to major increases or decreases in the porosity and permeability of reservoir rocks.

Water at all stages of interaction with rocks continuously concentrates some elements and dissipates others, as manifested by regular changes in the composition of the aqueous solution.

Removal of mobile mineral and Organic Matter (OM) from the rocks is accompanied by a gradual increase in their concentration in the pore waters.

Water-soluble OM can be inherited not only from connate waters, but also includes OM that has passed into the groundwater from rocks during lithogenesis. Altovskiy et al. [11] showed that transitions of OM in the water–rock system are determined by the ratio of their concentrations and the sorption capacity of the rocks. At the same time, the enrichment of rocks with dispersed OM has a significant influence on the value of the DOM content in underground waters [12, 13]. The total amount of OM in groundwater is dependent on the amount of OM in many natural processes and second only to its content in sedimentary rocks [2].

Theoretical and experimental studies [11, 14, 15] made it possible to establish an identical distribution of OM in the formation water and in the water-bearing rock system. These studies served as the original basis for the concept of participation of OM and DOM in oil and gas generation [11, 16]. The content of DOM, like OM of rocks, is regulated mainly by such factors as the evolution of the sedimentary basin, the intensity of the OM introduced from the surrounding land by water flow, the sedimentation environment, lithogenetic processes, etc. Enrichment of rocks with OM has a significant influence on the value of the DOM content in underground waters [12] (Tab. 1).

Table 1

The dependence of the content of Corg in water from enrichment rocks with organic matter [12].

This article is not particularly concerned directly with commercial interests but rather, based on the example of the SCB, shows that DOM plays a secondary role in the formation of oil and gas fields and participates in the process of hydrocarbon generation together with the source rocks. One major point should, perhaps, be emphasized to minimize potential confusion. This article demonstrates that DOM in the SCB can be a source of oil and/or gas. While the amount of hydrocarbons produced by DOM may not play a dominant role in the formation of oil and gas fields, nevertheless one needs to be somewhat circumspect when comparing hydrocarbons produced by OM in rocks and those produced by DOM. The point is that flowing water carries DOM with it unlike OM in rocks. Thus the relative locations of hydrocarbons produced by DOM compared to those produced by OM in rocks depend on the total fluid history of the basin, where and when the OM was converted into hydrocarbons and the subsequent history of those hydrocarbons flowing either on their own or in water solution. By way of contrast one has a similar problem for DOM in water solution and when any of the DOM was converted to hydrocarbons and their subsequent history. A direct comparison of DOM and OM does not include such a development and can lead one to dismiss DOM as a potential contributor to hydrocarbon involvement because it ignores the later locations of produced hydrocarbons from both DOM and OM. There is also the concern that present-day measurements of DOM and OM do not represent produced hydrocarbons but rather represent the future potential of DOM and OM for producing hydrocarbons. The amount of hydrocarbons that has been produced through to the present-day is not given by such estimates. In short one needs to have a complete history including production, migration and accumulation and a way of estimating whether hydrocarbons so produced in the past are still retained in the accumulation sites or whether they have leaked away with time.

As a consequence only the fundamental aspect of this problem is considered here. The results show that not only the rocks but also the water contained in them participate in the hydrocarbon generation process. Our task is not a quantitative comparison of the two likely sources of hydrocarbons (including a complete basin analysis of the timing of production, later motion and locations after production [something that is well beyond the scope of the present article]) but rather use of available data in the SCB to discuss the present-day patterns of DOM and OM with depth and basin location. As shown throughout there are both interesting differences and similarities between DOM and OM which can be used to suggest the histories of both in a qualitative fashion in the absence of a detailed basin analysis.

For the eastern part of the Azov-Kuban and western parts of the Middle Caspian oil and gas basins Bars et al. [17] have established the apparent positive dependence of the DOM concentration in groundwater on the OM concentration in the water-bearing rocks, based on analysis of more than 1500 different parameters of the OM composition in waters and about 3000 determinations of the OM composition in the rocks (Fig. 1).

thumbnail Fig. 1

The content of Corg in the waters and rocks of Ciscaucasia: 1, Azov-Kuban Basin; 2, Middle-Caspian Basin as inferred from organic carbon measurements [17].

The SCB is one of the oldest and well studied oil and gas basins. However, specific studies on the analysis of regional regularities of the OM distribution in groundwater, their connection with OM of rocks, the role of the DOM in oil and gas generation have not yet been given. Generalizations and analyses are given of the data accumulated to date on the content of OM in formation waters of various stratigraphic complexes, as well as of mud volcanoes, and the correlation with OM in SCB sedimentary rocks.

2 Database and methods

Results are based on about 300 analyses of formation waters and waters of mud volcanoes, as well as more than 400 analyses on the content of OM in rocks of the SCB. The stratigraphic interval covers the period from the Lower Pliocene to the Jurassic, and depth interval from 73 m to 6043 m. The Total Organic Carbon (TOC) content in rocks was determined by the direct combustion method: crushed shale samples were acid treated in a filtering crucible to remove carbonate, combusted at about 1000 °C, and analyzed as carbon dioxide. This TOC is taken to represent OM in rocks although there is always the uncertainty of knowing aliphatic and aromatic relative contributions. Pyrolysis data of rocks, made on a Rock-Eval device, was also used. In total about 400 values of TOC and rock pyrolysis were used obtained from outcrops and wells from both onshore and offshore petroleum fields.

Determination of Dissolved Organic Matter (DOM) consists in preliminary processing of a water sample by hydrochloric acid, removal of carbon dioxide formed from carbonates and hydrocarbonates, oxidation of the organic carbon compounds in the sample at temperature from 550 °C up to 1000 °C in the presence of oxygen or oxygen-containing gas, catalysis to carbon dioxide and subsequent determination of the total carbon with use of an infrared radiation detector.

3 Results and discussion

The SCB occupies a vast depression area of the Earth’s crust, including the southern part of the Kura intermountain trough, the West Turkmen depression and the deep-sea basin of the Southern Caspian located between them. Hydrogeologically the SCB is a classical connate basin [18]. The content of OM in the rocks of the sedimentary complex of the SCB has been previously studied primarily on natural outcrops of different stratigraphic ages [19–21]. According to these studies, the rocks of the Miocene-Oligocene deposits, which are referred to as oil source deposits [21–24] have the highest values of TOC. The TOC values, averaged over individual stratigraphic complexes, show an uneven distribution [25]. The maximum OM contents were distinctive for Maikop (Oligocene-Lower Miocene) sediments. Jurassic rocks are also distinguished by elevated TOC values (Fig. 2).

thumbnail Fig. 2

Stratigraphic control of variations in average values of TOC in rocks and DOM in the South Caspian Basin [25].

DOM varied from 4.1 mg/L to 271.2 mg/L. The average value for 219 analyses was 48.9 mg/L, which agrees well with estimates for other basins for which dissolved OM in underground aquifers of oil and gas basins does not exceed 50 mg/L [26, 27]. The change in average values of DOM is in good agreement with the TOC change in rocks. A deviation towards higher values of OM in the waters in comparison with the rocks is noted only for the Eocene-Pliocene interval of the section. The OM variation in formation waters of the various stratigraphic complexes of the SCB is more clearly demonstrated by the distribution histograms of Figure 3. The histograms showed that in water as well as in rocks the highest values are characteristic for oil-source Paleogene-Miocene and Jurassic deposits. The lowest concentrations of OM are for mud volcano waters.

thumbnail Fig. 3

Corg distribution histograms in SCB formation waters for various stratigraphic intervals: (a) Pliocene; (b) upper-middle Miocene; (c) low Miocene-Oligocene (Maykop); (d) Eocene-Paleocene; (e) Cretaceous-Jurassic; (f) mud volcanoes.

The correlation between OM in waters and their surrounding rocks permits the conclusion that a dynamic equilibrium is established between the rock and water that are constituent parts of a single rock–fluid system and are in continuous interaction over geological time. Accordingly, Cai et al. [28] supposed that very negative δD values and positive δ 18O values in the oilfield waters of the Cambrian–Ordovician system in the Tarim Basin resulted from hydrocarbon–water and water–rock interactions.

Moreover, as shown by Schimmelmann and Mastalerz [29], the dynamic equilibrium is also seen in the relationship between the isotope composition of hydrogen (D/H) in oil (various fractions) and neighboring formation waters (Fig. 4).

thumbnail Fig. 4

Isotopic composition of hydrogen in formation waters and in various oil fractions [29].

With depth there are changes in physical conditions (temperature and pressure), chemical composition of formation waters, lithofacies (the density of rocks and their reservoir properties) and other associated processes (oil and gas formation, clay dehydration, etc.). Accordingly, of interest is to analyze DOM with hypsometric depth. Figure 5a shows that a sharp increase in the DOM values at a depth of approximately 3.3 km. is common for various stratigraphic intervals. A similar feature is noted in the change with the depth of TOC in source rocks (Fig. 5b).

thumbnail Fig. 5

Change with depth of (a) DOM and (b) TOC for various stratigraphic intervals in the SCB.

Likely, these observed increases are due to the transition of the rock–water system from a diagenesis stage (where relatively low temperatures are not sufficient for thermal decomposition of OM) to the catagenetic stage, where favorable temperature conditions exist for the thermal transformation of OM into hydrocarbons. Given the relatively higher migration potential of oil and gas in comparison with their ancestral OM in the zone of catagenesis, the flow from rocks into water is accompanied by an increase of the organic component in the water and of bitumen.

The nature of the dependence of DOM on the carbon content of bitumen (Cbit) favors this conclusion. Figure 6 shows that high contents of Corg, observed at a depth greater than 3 km (see Fig. 5a), are characterized by high values of Cbit (Fig. 6a), a derivative of the thermal transformation of Corg. A similar feature is observed in the S1 indicator (milligrams of hydrocarbon per gram of rock) during the pyrolysis of source rocks (Fig. 6b), indicating free hydrocarbons (gas and oil) in the sample [30].

thumbnail Fig. 6

Dependence of generated hydrocarbons (in water: Cbit; in rock; free hydrocarbons-S1) vs. (a) total Dissolved Organic Matter (DOM) in water and (b) Total Organic Carbon (TOC) in rock.

Kartsev et al. [31] also consider that sedimentary waters dissolve hydrocarbons as a result of catagenesis and move with them to reservoir rocks. Additionally, when moving through reservoirs groundwater can dissolve more hydrocarbons and other organic compounds in the reservoir rocks. Studies conducted by Shvets [32] found that the content of DOM depends on the chemical composition of the waters. However, according to other studies [33], mineralization and chemical composition of waters can have an ambiguous effect on OM.

In this study the hydrochemical composition of the formation waters of the SCB data on the well-studied Productive Series (low Pliocene) was used. From Figure 7 one notes a pattern in the ratio of chlorine ion to the bicarbonate ion similar to the change with the depth of DOM. At approximately the same depth (3.5 km), a jump is observed in the Cl−/HCO3 − ratio. Hence there is a relationship between the chemical composition of water and OM.

thumbnail Fig. 7

Chlorine ion to bicarbonate ion ratio values vs. depth.

The salinity dependence of the OM content in waters is also known. For instance, investigation of DOM in the Michigan Basin (USA) established the dependence of the OM content in the formation waters on salinity [34]. There is a negative relationship between the content of DOM and the salinity of the water [35]. To study this dependence in the SCB a corresponding graph was constructed (Fig. 8).

thumbnail Fig. 8

DOM (mg/L) in formation waters of various stratigraphic intervals and mud volcano waters vs. mineralization of waters (g/L) in the SCB.

Figure 8 shows that SCB formation waters containing high concentrations of DOM (more than 70 mg/L) are characterized by relatively low mineralization (less than 50 g/L). In waters with a salinity of more than 60 g/L, the content of DOM is low and varies within the limits of 25–70 mg/L. At the same time, formation waters with low DOM values (less than 20 mg/L) and low salinity are also encountered. The same behavior was established in the Michigan Basin [34]. Such waters are also characteristic for mud volcanoes. Data from 24 analyses yields DOM in mud volcano waters varying from 7.9 mg/L to 108.5 mg/L (average 28.6 mg/L), while water salinity ranges from 4.1 g/L to 58.7 g/L (24.2 g/L). The same behavior was also found in the study of mud volcano waters in the Taman Peninsula [36].

Low mineralization and low content of OM in some formation waters and mud volcano waters are likely due to their condensation genesis as confirmed by the low mineralization of formation waters that are directly connected to oil in comparison with the high mineralization waters as shown by the examples of the Neftchala and Khilly fields of the SCB (Fig. 9). Taking into account that the oil in the Productive Series is epigenetic, this pattern can be associated with phase transitions caused by changes in the thermobaric conditions during the subvertical migration of the water–oil solution. Smirnova [37] found that gas-condensate waters and those of oil-bearing deposits are characterized by very high concentrations of hydrocarbons.

thumbnail Fig. 9

Change in mineralization of formation waters with depth within and outside the oil-bearing zone on (1) Khilly and (2) Neftchala petroleum fields in the SCB [38].

4 Conclusion

The interaction processes between water and host rock leads to the establishment of a dynamic equilibrium in the system during geological evolution. This result explains: (1) the good convergence of the distribution of OM in rocks and formation waters of the SCB; (2) the relationship between the content of OM in waters and their chemical composition and mineralization; and (3) the nature of changes with depth.

The results of the studies show that underground water, as one of the components of a single rock–water system of the Earth’s sedimentary cover and together with the rocks, participates in the processes of hydrocarbon generation and migration. This fundamental conclusion is important in order to obtain a complete understanding of the processes of hydrocarbon generation. Such an understanding can come only with the application of a quantitative basin analysis evaluation, well beyond the scope of the present paper.

It is also important to note factors due to prior investigations of OM in waters. Several articles [39–43] have substantiated the possibility of discovering oil and gas accumulations in the subsurface based on hydrochemical criteria. For instance, Sahay [42] notes that “Appropriate mapping of these indicators with geological and geophysical information will prove useful in the location of oil and gas”.

This aspect is not considered here but additional sources of literature are provided that confirm the effectiveness of the hydrochemical criteria for hydrocarbon (HC) searches (including OM as a direct indicator of the presence of HC accumulations).

Acknowledgments

All analyses were made at the Institute of Geology and Geophysics of Azerbaijan National Academy of Sciences and we are grateful to all who took part in field and analytical investigations in particular G. Ismaylov, R. Gurbanova, Ch. Aliyev, Z. Guseynova, R. Efendiyeva, and G. Ismaylova.

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All Tables

Table 1

The dependence of the content of Corg in water from enrichment rocks with organic matter [12].

In the text

All Figures

thumbnail Fig. 1

The content of Corg in the waters and rocks of Ciscaucasia: 1, Azov-Kuban Basin; 2, Middle-Caspian Basin as inferred from organic carbon measurements [17].
In the text
thumbnail Fig. 2

Stratigraphic control of variations in average values of TOC in rocks and DOM in the South Caspian Basin [25].
In the text
thumbnail Fig. 3

Corg distribution histograms in SCB formation waters for various stratigraphic intervals: (a) Pliocene; (b) upper-middle Miocene; (c) low Miocene-Oligocene (Maykop); (d) Eocene-Paleocene; (e) Cretaceous-Jurassic; (f) mud volcanoes.
In the text
thumbnail Fig. 4

Isotopic composition of hydrogen in formation waters and in various oil fractions [29].
In the text
thumbnail Fig. 5

Change with depth of (a) DOM and (b) TOC for various stratigraphic intervals in the SCB.
In the text
thumbnail Fig. 6

Dependence of generated hydrocarbons (in water: Cbit; in rock; free hydrocarbons-S1) vs. (a) total Dissolved Organic Matter (DOM) in water and (b) Total Organic Carbon (TOC) in rock.
In the text
thumbnail Fig. 7

Chlorine ion to bicarbonate ion ratio values vs. depth.
In the text
thumbnail Fig. 8

DOM (mg/L) in formation waters of various stratigraphic intervals and mud volcano waters vs. mineralization of waters (g/L) in the SCB.
In the text
thumbnail Fig. 9

Change in mineralization of formation waters with depth within and outside the oil-bearing zone on (1) Khilly and (2) Neftchala petroleum fields in the SCB [38].
In the text

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