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<div class="articledetails article-header clearfix">
<p class="art-type">Research Article</p>
<p class="art-title">Thermal regime and Hydrocarbon generation in the
Apsheron Trough of the South Caspian</p>
<p class="art-author"><?php $authors="Yu I. Galushkin<sup>*</sup>"; echo (stristr($authors,$coauthor))?str_replace($coauthor,"<a href='".$extpath."authors/".$courl."' target='_blank'>".$coauthor."</a>",$authors):$authors; ?></p>
<p class="art-affl">
Lomonosov Moscow State University, Earth Science Museum, Russian Federation, Russia
</p>
<p class="art-aff"><b>*Corresponding author: <?php $corresponding_author="Yu I. Galushkin"; echo ($coauthor!="" && $coauthor==$corresponding_author)?"<a href='".$extpath."authors/".$courl."' target='_blank'>".$coauthor."</a>":$corresponding_author;?></b>, Lomonosov Moscow State University, Earth Science Museum, Russian Federation, Russia, Tel: +74959391594, E-mail: <a href="mailto:yu_gal@mail.ru">yu_gal@mail.ru</a>
</p>
<p class="art-aff"><b>Received:</b> June 9, 2018
<b>Accepted:</b> June 23, 2018
<b>Published:</b> June 28, 2018</p>
<p class="art-aff"><b>Citation: </b> Yu G. Thermal regime and
Hydrocarbon generation in the Apsheron
trough of the South Caspian. <i>Int J Petrochem Res.</i> 2018; 2(1): 150-154. doi: <a href="https://doi.org/10.18689/ijpr-1000126">10.18689/ijpr-1000126</a>
</p>
 <p class="art-aff"><b>Copyright:</b> &copy; 2018 The Author(s). This
work is licensed under a Creative Commons
Attribution 4.0 International License, which
permits unrestricted use, distribution, and
reproduction in any medium, provided the
original work is properly cited.</p>
<p><a href="<?php echo $extpath;?><?php echo $jres['journal_link'];?>/ijpr-1000124.pdf" class="btn btn-danger pull-right" target="_blank">Download PDF</a></p>
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<div class="articlecontent">
<p class="art-subhead">Abstract</p>
<p class="art-para">The earlier modeling helped explain the contradiction between the high thermal
regime of the mantle of the South Caspian Basin and the abnormally low temperatures
of the upper 6 km of its sedimentary blanket. The modeling suggested that the "oil
window" is located at the depths from 4.5 to 9 km in the modern sections of the South
Apsheron Trough and includes the rocks of the Productive and Pontian formations
which are not source rocks in the basin. To solve this problem, we used reconstruction
of the thermal history of the basin to restore numerically the history of realization of
hydrocarbon potential of the Maikop and Diatomaceous formations. Our modeling
shown that the non-steady thermal regime of the mantle in the region and avalanche
sedimentation in the Pliocene-Quaternary have shifted the time of intense hydrocarbon
generation close to the present time. The maximum generation of light oil by the rocks
of the Maikop and Diatomaceous formations occurred for the last 2 to 7 million years
when avalanche sedimentation in the Pliocene-Quaternary time took place in the Basin
and the powerful layers of weakly compacted highly permeable rocks were created. Assuming the possibility of vertical migration through weakly compacted layers to the
horizons with lower temperatures, it can be said that the Upper Maikop and Diatomaceous
rocks are promising for the generation of liquid hydrocarbons (mainly of light oil) and
gas. The modeling presented in this paper help to understand a leading contribution of
the Maikop and Diatomaceous source formations to formation of oil and gas
accumulations, despite these suites in present-day sedimentary section locate deeper
than the "oil generation window".</p>
<p class="art-para"><b>Keywords:</b> South Caspian, heavy and light oil generation, secondary cracking, vitrinite
reflectance</p>
<p class="art-subhead">Introduction</p>
<p class="art-para">The South Caspian basin is the one of the promising oil and gas regions of the
world. The originality of the Basin is huge thickness of the sedimentary cover (over 20
km), the extremely high sedimentation rate in the Pliocene (up to 5 km in million years), and a low degree of compaction of the Pliocene-Quaternary sediments <a href="#1">[1]</a> <a href="#2">[2] </a><a href="#3">[3]</a>. Thermal regime of the basin is also unusual. It is well known that the South Caspian
Basin is characterized by abnormally low temperatures of the rocks in the upper 6 km of
the sedimentary cover <a href="#4">[4] </a><a href="#5">[5] </a><a href="#6">[6] </a><a href="#7">[7]</a>. But at the same time, assessments of deep
temperatures, as well as the study of the upper mantle by electrical and seismic sounding, show that the studied area is one of the most heated areas of the Caspian region along
with the latitudinal belt of the Middle-Caspian <a href="#8">[8] </a><a href="#9">[9]</a> <a href="#10">[10]</a>.</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure1.PNG" class="img-responsive center-block"/></div>
<p class="art-para">Application of the GALO system for basin modeling <a href="#11">[11]</a>
<a href="#12">[12]</a> allowed us to reconstruct the thermal history of
sedimentary blanket of the South Caspian Basin in the South
Apsheron Trough (Figure 1) and explain the contradictions
between high thermal regime of the mantle and the low rock
temperatures in the upper part of the sedimentary cover in
the South Caspian Basin <a href="#13">[13]</a>. Figure 2 demonstrates the part
of general reconstruction of the burial and thermal history of
the Basin for last 20 My. This reconstruction is in agreement
with modern sedimentary section of the basin, established
according to drilling data and seismic profiling <a href="#2">[2] </a><a href="#14">[14]</a> <a href="#15">[15]</a>
and with observed values of deep temperatures (Figure 3a) and vitrinite reflectance (Figure 3b). Analysis of the variations
in the basin tectonic subsidence in <a href="#13">[13]</a> revealed two periods
of intensive stretching of the lithosphere with amplitudes: &beta; &asymp; 1.4 and 1.7. These stretchings explain the intense basement
subsidence during sedimentation in the Oligocene and
Miocene, as well as the avalanche sedimentation in the
Pliocene together</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure2.PNG" class="img-responsive center-block"/></div>
<p class="art-para">with sharp changes in the sea depth in this time <a href="#2">[2] </a><a href="#3">[3]</a>. As
result of the above stretching periods, the total crust thickness
reduced up to 32.4 km at present time, 20 km of which are the
present-day sedimentary section. Therefore, a thickness of
the consolidated crust decreased from initial 35 km to the
present-day value of 12.4 km <a href="#13">[13]</a>. The last value is close to
the geophysical estimates of the thickness of the consolidated
crust in the Basin <a href="#1">[1] </a><a href="#14">[14]</a> <a href="#10">[10]</a>, and is in accordance with
geophysical assessment of thickness of the granitic layer in
the South Caspian lithosphere that admit the thickness of this
layer no more than 2 - 6 km <a href="#2">[2] </a><a href="#3">[3] </a><a href="#8">[8] </a><a href="#10">[10]</a>.</p>
<p class="art-para">Dotted lines in Figure 2 show the isolines of vitrinite
reflectance. In our model, vitrinite reflectance was computed
using the EASY-%Ro model of kinetic spectrum of vitrinite
maturation from <a href="#16">[16]</a>. The model of thermal evolution of the
Basin in figures 2, 3b suggests that the "oil window" (0.50 < Ro < 1.30%) is located at depths from 4.5 to 9 km in the
modern sedimentary sections of the South Apsheron Trough.</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure3.PNG" class="img-responsive center-block"/></div>
<p class="art-para">1- calculated values; 2 (left) - measured deep temperatures
in western half of the South Caspian Basin <a href="#4">[4] </a><a href="#5">[5] </a><a href="#6">[6]</a>. 2 (right) - Ro-values measured in nearest well of the South Apsheron
Trough; 3 - (left) - estimations of deep temperatures according
to extrapolation-interpolation equations in <a href="#7">[7]</a>. 3 (right) -
indirect estimations of %Ro in the area under study by
assessment of oil and gas maturity in <a href="#17">[17]</a> <a href="#18">[18]</a>. </p>
<p class="art-para">This depth interval includes the rocks of the Productive
and Pontian formations (Figure 4). But these rocks are no
source rocks, because they have very low TOC and contain
mainly kerogen of the type III. Source rocks in the Basin are
the deposits of the Diatomaceous and Maikop formations (Figure 4) that are outside the "oil window" according to the
maturity level of organic matter. To explain this contradiction, we use the reconstructions of the thermal history of the
sedimentary strata of the basin described in <a href="#13">[13]</a> to study a
realization of the hydrocarbon potential in the rocks of the
Maikop and Diatomaceous source formations.</p>
<p class="art-para"><b>Hydrocarbon generation by the Maikop and Diatomaceous
source rocks</b>
The Maikop formation of age from 33.9 to 16 My occupies
an interval of depths from 12.3 to 14.3 km in the modern section
of the basin. Present-day content of organic matter is 2%.</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure4.PNG" class="img-responsive center-block"/></div>
<p class="art-para">and initial TOC is estimated in the model as 4.7%. According to modeling, the rocks at base of the formation
reached temperature of about 280&deg;C and maturity level of
3.98% by vitrinite
</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure5.PNG" class="img-responsive center-block"/></div>
<p class="art-para">reflectance, whereas the rocks at top of the formation
reached temperature of about 230&deg;C and maturity level of Ro
= 2.98% (Figure 5). The temperature and maturity level of the
Maikop rocks are rather high and at present time the rocks
can be considered as overmature gas prone source rocks. This
is confirmed by Figure 6 shown that light and heavy oil have
degraded totally to present time due to secondary cracking of
kerogene. In these calculations, it was taken into account that
kerogen of the Maikop shales is presented by mixture 50% marine kerogen of type II with initial potential of HC generation
HI = 611 mg HC/g TOC and 50% kerogen of type III with
initial potential of HC generation HI = 160 mg HC/g TOC, so
that the initial potential of hydrocarbon generation of the
rock is HI = 393.5 mg HC/g TOC. In calculations, we used the
kinetic spectra for cracking of kerogen of types II and III in the
4-fractional model, that was developed in the French Oil
Institute (Paris) and are applied in a widespread modeling
package MATOIL.</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure6.PNG" class="img-responsive center-block"/></div>
<p class="art-para">Situation with Diatomaceous formation can be seen on
Figures 7 and 8. The Diatomaceous formation of age from 16
to 7.2 My occupies an interval of depths from 9.7 to 12.3 km
in the modern section of the basin. Present-day content of
organic matter is 1% and initial TOC is estimated in the model
as 2.4%. According to modeling, the rocks at base of the
formation reached temperature of about 230&degC and maturity
level of Ro=2.98%, whereas the rocks at top of the formation
reached temperature of about 190&deg;C and maturity level of Ro
= 1.74% (Figure 7). The temperature and maturity level of the
Diatomaceous rocks are also rather high and at present time
the rocks can be considered as high mature and gas prone
source rocks. This is partly confirmed by Figure 8 shown that light and heavy oil in the rocks at base of formation have
degraded totally to present time due to secondary cracking of
kerogen (Figure 8). However, in the rocks at top of the
Diatomaceous formation the light oil is degraded only
partially (Figure 8).</p>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure7.PNG" class="img-responsive center-block"/></div>
<div class="art-img">
<img src="<?php echo $imgpath;?>images/IJPR-126-figure8.PNG" class="img-responsive center-block"/></div>
<p class="art-subhead">Discussion</p>
<p class="art-para">Diatomaceous formations in the modern sedimentary
section of the South Caspian Basin are mainly gas-generating. However, it is necessary to remember that the geochemical
modeling in Figures 6 and 8 assumes that the generated
hydrocarbons did not leave the pore space of the source rock. Therefore, only on the basis of present-day situation it cannot
be argued that the prospects for the formation of oil fields
generated by the rocks of the above formations are small. The
fact is that the South Caspian Basin is an unusual sedimentary
basin. Here, the unsteady character of thermal regime of the
mantle <a href="#13">[13]</a> and avalanche sedimentation contributed to the
displacement of the processes of maturation of organic
matter to the present time. Of course, the rocks of the lower
Maikop are mainly gas-generating. But the modeling shows
that the secondary cracking of liquid hydrocarbons in the
Upper Maikop rocks occurred only 5-10 million years ago and
only 2 - 4 million years ago in the Diatomaceous rocks (Figures. 6, 8). Liquid hydrocarbons generated by these rocks
could quite migrate 3-4 km vertically through the relatively
weakly consolidated rocks of the upper layers and reach the
Productive strata with a lower temperature, thereby avoiding
P-T conditions of secondary cracking. Then the upper half of
the Maikop formation can be considered as promising for the generation of both liquid and gas hydrocarbons. The
probability of avoiding hard conditions of secondary cracking
for the Diatomaceous rocks was even more because here
degradation of heavy and light oils occurred during avalanche
sedimentation in the Pliocene-Quaternary time when the
powerful layers of weakly compacted highly permeable rocks
were created <a href="#19">[19]</a>. Assuming the possibility of such vertical
migration through weakly compacted layers to the horizons
with lower temperatures, it can be said that the Diatomaceous
rocks are promising for the generation of liquid hydrocarbons (mainly of light oil) and gas.</p>
<p class="art-subhead">Conclusion</p>
<p class="art-para">The modeling suggests that the "oil window" is located at
depths from 4.5 to 9 km in the modern sections of the Trough
and includes the rocks of the Productive and Pontian
formations. But these rocks are no source rocks, because they
have very low TOC and contain mainly kerogen of the type III. Source rocks in the Basin are the deposits of the Diatomic and
Maikop formations. We explain this contradiction by the fact
that the non-steady thermal regime of the mantle in the
region and avalanche sedimentation in the Pliocene-
Quaternary had a significant influence on the history of
hydrocarbon generation in the basin, shifting the time of
intense hydrocarbon generation to the present time. According to the calculations, the maximum generation of
light oil by the rocks of the Maikop and Diatomic formations
occurred for the last 2 to 7 million years. Such recent
hydrocarbon generation and significant role of vertical
migration of hydrocarbons determine leading contribution of
the Maikop and Diatomaceous suites to formation of oil and
gas accumulations, despite these suites in present-day
sedimentary section locate deeper than "oil generation
window".</p>
<p class="art-para">(2). The height of quartz sand bed was used as a
parameter to control the residence time. With the
increase of the residence time, the influence on the
secondary pyrolysis of primary volatiles gradually
weakened. The heavy components were converted
into light components via contacting with silica sand. Within 1~3 seconds of the residence time, the
cracking of aliphatic hydrocarbons intensified, while
the gas yield increased significantly and mainly
dominated by decomposition reactions. During the 3
to 5 seconds residence time, the yield of VGO
components was significantly reduced. The rapid
enrichment of gas and the presence of steam could
suppress gas generation and this process mainly
dominated by the condensation reactions.</p>
<p class="art-para">(3). The addition of steam had an inhibitory effect on the
polymerization of aromatics. The proportion of SAH
monocyclic aromatics in the aromatic component
after the addition of 20% steam was much higher
than that without steam. This shows that the addition
of steam could well inhibit the condensation of
aromatics. In general, the regulation effect of steam
on the secondary reactions of oil shale pyrolysis
volatiles was not only reflected in the increase in oil
yield but also could improve the content and quality
of light components in oil products, which reduced
the difficulty in the downstream processing of oil
products.</p>
<p class="art-subhead">Acknowledgments</p>
<p class="art-para">The study was conducted with the research programs
financed by National Natural Science Foundation (21406264), National Basic Research Program of China (2014CB744304) and Science Foundation of China University of Petroleum, Beijing (No. 2462018BJC003).</p>
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