Changes

During Aptian time, a new transgression flooded the erosional surface carbonate deposition which prevailed. Two sequences beginning with a transgression and ending with a shallowing upward character deposited. These two sequences, one in the Cenomanian, and the other in the Coniacian to Early Maestrichtian, have source rock potential.

During Aptian time, a new transgression flooded the erosional surface carbonate deposition which prevailed. Two sequences beginning with a transgression and ending with a shallowing upward character deposited. These two sequences, one in the Cenomanian, and the other in the Coniacian to Early Maestrichtian, have source rock potential.

The first sequence is divided into four facies types and numbered D1 through D4. All levels contain rich organic matter except D1. Main kerogen type is mainly Type II, but Type III is also present. Maturation varies from mature to a little overmature. The southern part of the region is mature, but northern areas are pre-overmature. This unit has TOC values 0.09–2.28.<ref name=Soylu_1988 /> <ref name=Sengunduzandsoylu_1990 /> <ref name=Coruhetal_1997 /> Distribution of rich TOC values may reflect paleotopographic irregularities. Maturation is tied to thickness of the sediment due to tectonic loading under the thrust.<ref name=Sengunduzandsoylu_1990 /> It has Type II kerogen and Tmax values are >435°C especially in the middle of the region (between Adiyaman and Şanliurfa trending NE-SW direction). According to Şengündüz and Soylu,<ref name=Sengunduzandsoylu_1992 /> oil generation started in Early Miocene. Oil has migrated toward the Pre-Miocene structures.

The first sequence is divided into four facies types and numbered D1 through D4. All levels contain rich organic matter except D1. Main kerogen type is mainly Type II, but Type III is also present. Maturation varies from mature to a little overmature. The southern part of the region is mature, but northern areas are pre-overmature. This unit has TOC values 0.09–2.28.<ref name=Soylu_1991>Soylu, C., 1991, Oil source rocks in the Adiyaman area, southeast Turkey: Journal of Southeast Asian Earth Science, v. 5, no. 1-4, p. 429–434.</ref> <ref name=Sengunduzandsoylu_1990>

Source rock in the second sequence is a dark muddy carbonate which was deposited in a deeper water environment as indicated by planktonic foraminiferas (Çoruh et al., 1997). It also contains phosphate and glauconite together with richness in organic matter. The second sequence (member A) is probably a condensed section (Soylu, 1991; Çoruh et al., 1997). Upward the sequence shows shallowing upward character.

Şengündüz, N. and C. Soylu, 1990, (Turkish with English abstract) Sedimentology and organic chemistry of sphaeroidal-rich horizon of the Derdere Formation, in Proceeding of 8th petroleum congress of Turkey, Ankara: Geology, p. 50–61.</ref> <ref name=Coruhetal_1997>Çoruh, T., Yakar, H., and Ediger, V. Ş., 1997, Güneydoǧu Anadolu Bölgesi Otokton İstifinin Biyostratigrafisi. Türkiye Petrolleri A. O. Araştirma Merkezi Grubu Başkanliǧi Eǧitim Yayinlari 30, 401 p.</ref> Distribution of rich TOC values may reflect paleotopographic irregularities. Maturation is tied to thickness of the sediment due to tectonic loading under the thrust.<ref name=Sengunduzandsoylu_1990 /> It has Type II kerogen and Tmax values are >435°C especially in the middle of the region (between Adiyaman and Şanliurfa trending NE-SW direction). According to Şengündüz and Soylu,<ref name=Sengunduzandsoylu_1990 /> oil generation started in Early Miocene. Oil has migrated toward the Pre-Miocene structures.

Member A of the sequence has TOC values varying from 0.76% to 7.65% in the Adiyaman area (Soylu, 1991). Here, it contains type I and II kerogens and shows varying degree of maturity from south to north and from east to west (SCI = 3.5 to 8 and Tmax values 429°C to 457°C respectively) (Soylu, 1991; Soylu et al., 2005). It has relatively high sulfur content (Soylu et al., 2005). Toward the east, the unit shallows and it becomes difficult to differentiate Sequence I and sequence II.

 

Member A of the sequence has TOC values varying from 0.76% to 7.65% in the Adiyaman area.<ref name=Soylu_1991 /> Here, it contains type I and II kerogens and shows varying degree of maturity from south to north and from east to west (SCI = 3.5 to 8 and Tmax values 429°C to 457°C respectively).<ref name=Soylu_1991 /> <ref name=Soyluetal_2005>Soylu, C., M. N. Yalçin, B. Horsfield, H. J. Schenk, and U. Mann, 2005, Hydrocarbon generation habitat of two Cretaceous carbonate source rocks in SE Turkey: Journal of Petroleum Geology, v. 28, no. 1, p. 67–82.</ref> It has relatively high sulfur content.<ref name=Soyluetal_2005 /> Toward the east, the unit shallows and it becomes difficult to differentiate Sequence I and sequence II.

A third sequence of Middle Campanian age was deposited in a shallow marine–lagoonal environment. It begins with the deposition of shallow water carbonates deepening upward and grading into deeper marine carbonate containing phosphate, glauconite, and rich organic matter. It contains a shallowing upward sequence. This may represent a complete sequence, and development of organic-rich facies may be related to a condense section of the sequence. One hundred and fifty seven samples from SE Turkey have been analyzed for geochemical evaluation of this unit. Total organic carbon values vary from 0.32 to 1.86% (average being 1.0%). Pyrolysis analysis indicates type II organic matter that is oil prone. Organic matter is thermally mature, as indicated by SCI (5–7) and Tmax (430–445°C) values. Maturation increases from south to north.

A third sequence of Middle Campanian age was deposited in a shallow marine–lagoonal environment. It begins with the deposition of shallow water carbonates deepening upward and grading into deeper marine carbonate containing phosphate, glauconite, and rich organic matter. It contains a shallowing upward sequence. This may represent a complete sequence, and development of organic-rich facies may be related to a condense section of the sequence. One hundred and fifty seven samples from SE Turkey have been analyzed for geochemical evaluation of this unit. Total organic carbon values vary from 0.32 to 1.86% (average being 1.0%). Pyrolysis analysis indicates type II organic matter that is oil prone. Organic matter is thermally mature, as indicated by SCI (5–7) and Tmax (430–445°C) values. Maturation increases from south to north.

Oil to source correlations confirmed that oils were derived mainly from Cretaceous and Paleozoic source rocks. Analysis of 44 crude oil samples from 12 oil fields in SE Turkey suggest four groups of oil and one of mixed origin. Group I oils (Batman area oil) are immature and heavy in character and show the features of a mixture of degraded and normal oils. Altered molecular composition did not allow to predict the nature of their source rock (Gürgey and Harput, 1990).

Oil to source correlations confirmed that oils were derived mainly from Cretaceous and Paleozoic source rocks. Analysis of 44 crude oil samples from 12 oil fields in SE Turkey suggest four groups of oil and one of mixed origin. Group I oils (Batman area oil) are immature and heavy in character and show the features of a mixture of degraded and normal oils. Altered molecular composition did not allow to predict the nature of their source rock.<ref name=Gurgeyandharput_1990 />

Group II oils (Batman-Nusaybin area oils) are also immature and heavy in character. The composition suggests an evaporitic-carbonate source rock deposited in an extremely anoxic reduced and hypersaline environment. In the region, the only unit meeting these requirements is the Triassic-Jurassic sediments. Therefore, these strata are most probably the source for the Group II oils. The areal distribution and thickness of the Triassic to Jurassic rocks geologically supports this prediction (Gürgey and Harput, 1990).

Group II oils (Batman-Nusaybin area oils) are also immature and heavy in character. The composition suggests an evaporitic-carbonate source rock deposited in an extremely anoxic reduced and hypersaline environment. In the region, the only unit meeting these requirements is the Triassic-Jurassic sediments. Therefore, these strata are most probably the source for the Group II oils. The areal distribution and thickness of the Triassic to Jurassic rocks geologically supports this prediction.<ref name=Gurgeyandharput_1990 />

Group III oils (Kozluk-Adiyaman area oils) are widely distributed and show a wide maturity spectrum from the early mature to mature-light oils. They are most likely derived from carbonate marine source rocks deposited in anoxic, reducing, and saline environments. The Campanian sediment best meets these requirements and is the possible source rock for the Group III oils. The distribution and kitchen map of the unit strongly supports this hypothesis (Gürgey and Harput, 1990).

Group III oils (Kozluk-Adiyaman area oils) are widely distributed and show a wide maturity spectrum from the early mature to mature-light oils. They are most likely derived from carbonate marine source rocks deposited in anoxic, reducing, and saline environments. The Campanian sediment best meets these requirements and is the possible source rock for the Group III oils. The distribution and kitchen map of the unit strongly supports this hypothesis.<ref name=Gurgeyandharput_1990 />

Group IV oils (Northern Diyarbakir area oils) are mature-light oils and are significantly different from the other groups. They are most likely derived from a clay rich marine source rock deposited in suboxicoxic and slightly reduced brackish environment. The considered source rock for this group is most probably the upper Silurian source.

Group IV oils (Northern Diyarbakir area oils) are mature-light oils and are significantly different from the other groups. They are most likely derived from a clay rich marine source rock deposited in suboxicoxic and slightly reduced brackish environment. The considered source rock for this group is most probably the upper Silurian source.

The last group of oils is the mixture of Group II and Group III oils. The possible source rocks for these oils is of Campanian age and of Triassic–Jurassic age.

The last group of oils is the mixture of Group II and Group III oils. The possible source rocks for these oils is of Campanian age and of Triassic–Jurassic age.

In addition to oil samples, many asphaltenes have been analyzed and correlated with the source rocks present in the area. Asphaltenes are present and have been subjected to many studies (Harput and Harput, 1990) in SE Turkey in various localities. One of them is mined and sold as hard coal. Some asphaltenes are also present in the fractures of Triassic-Late Cretaceous rocks. One of the studies attempts to correlate these asphaltites with Raman-Garzan field oils.

In addition to oil samples, many asphaltenes have been analyzed and correlated with the source rocks present in the area. Asphaltenes are present and have been subjected to many studies<ref name=Harputandharput_1990>Harput, B. and A. Harput, 1990, Güneydoǧu Anadolu’daki Seridahli (Şirnak) asfaltitlerinin jeokimyasal deǧerlendirilmesi, 8. Türkiye Petrol Kongresi bildirileri (Proceedings of 8th Petroleum Congress of Turkey), 16-20 Nisan 1990, 92-106.</ref> in SE Turkey in various localities. One of them is mined and sold as hard coal. Some asphaltenes are also present in the fractures of Triassic-Late Cretaceous rocks. One of the studies attempts to correlate these asphaltites with Raman-Garzan field oils.

Asphaltites are present in the fractures of the Cudi Group (Triassic-Jurassic), Germav Formation (Late Cretaceous-Paleocene), and Gercüş Formation (Eocene) units. These asphaltites were developed in NE-SW striking fractures that were developed under a N-S oriented stress regime (Harput and Harput, 1990). Total organic carbon values of asphaltites are >39% but the host rock contains 0.2–3.13% TOC. Tmax values are greater than 453°C. Soluble organic matter is poor in the host rock, but rich in natural bitumen Ro 10%. Descriptions and evaluations of data indicate that natural bitumen did not penetrate into host rock due to very low porosity and permeability. The Tmax and Ro values indicate that natural bitumen were subjected to high temperatures and oil migrated into the fracture system.

Asphaltites are present in the fractures of the Cudi Group (Triassic-Jurassic), Germav Formation (Late Cretaceous-Paleocene), and Gercüş Formation (Eocene) units. These asphaltites were developed in NE-SW striking fractures that were developed under a N-S oriented stress regime.<ref name=Harputandharput_1990 /> Total organic carbon values of asphaltites are >39% but the host rock contains 0.2–3.13% TOC. Tmax values are greater than 453°C. Soluble organic matter is poor in the host rock, but rich in natural bitumen Ro 10%. Descriptions and evaluations of data indicate that natural bitumen did not penetrate into host rock due to very low porosity and permeability. The Tmax and Ro values indicate that natural bitumen were subjected to high temperatures and oil migrated into the fracture system.

Bitumen shows different physical and chemical characteristics that indicate either they were generated from different source rocks or they have different degradation processes. In general, available data indicate that these are asphaltites that represent multistage migration processes and bitumen that have gone through various degradation processes. Interpretations of various authors suggest that these asphaltites derived from a marine source rock and possibly are candidates for a Cretaceous source rock (e.g., Harput and Harput, 1990).

Bitumen shows different physical and chemical characteristics that indicate either they were generated from different source rocks or they have different degradation processes. In general, available data indicate that these are asphaltites that represent multistage migration processes and bitumen that have gone through various degradation processes. Interpretations of various authors suggest that these asphaltites derived from a marine source rock and possibly are candidates for a Cretaceous source rock (e.g., Harput and Harput<ref name=Harputandharput_1990 />).

There are different views on the timing of onset of oil generation. The results suggest that HC generation was reached during Paleocene, and as the thickness of the unit above decreases, the generation phase gets younger. The results also suggest that HC generation mostly prevails during the Paleocene and Oligocene time for the Cretaceous age organic matter. For the Paleozoic aged source rocks, generation may have started from the end of the Early Cretaceous to Paleocene and the Eocene time. They sometimes enter the oil window up to the end of the Miocene time (Kumsal and Karahanoǧlu, 1992), depending on the location within the basin.

There are different views on the timing of onset of oil generation. The results suggest that HC generation was reached during Paleocene, and as the thickness of the unit above decreases, the generation phase gets younger. The results also suggest that HC generation mostly prevails during the Paleocene and Oligocene time for the Cretaceous age organic matter. For the Paleozoic aged source rocks, generation may have started from the end of the Early Cretaceous to Paleocene and the Eocene time. They sometimes enter the oil window up to the end of the Miocene time,<ref name=Kumsalandkarahanoglu_1992>Kumsal, K. and N. Karahanoǧlu, 1992, Mathematical approximation for the source rock maturity in SE Turkey, Proceedings of 9th Petroleum Congress and Exhibition of Turkey, p. 18–33.</ref> depending on the location within the basin.

===Reservoir rocks===

===Reservoir rocks===

The middle Maestrichtian carbonates unit was deposited on a ramp setting. There is no break in slope, and a gently inclined surface represents the top of this carbonate unit on seismic sections. On the ramp the carbonate has rudist buildups that have relatively high porosities, but in the areas between rudist buildups the porosities are low and mud content increases. Upper Maestrichtian carbonates also act as a reservoir depending on the type of facies.

The middle Maestrichtian carbonates unit was deposited on a ramp setting. There is no break in slope, and a gently inclined surface represents the top of this carbonate unit on seismic sections. On the ramp the carbonate has rudist buildups that have relatively high porosities, but in the areas between rudist buildups the porosities are low and mud content increases. Upper Maestrichtian carbonates also act as a reservoir depending on the type of facies.

[[file:M106Ch13Fig07.jpg|thumb|300px|{{figure number|3}}Chronostratihraphic chart of Thrace Basin (redrawn from Siyako, 2005).]]

[[file:M106Ch13Fig07.jpg|thumb|300px|{{figure number|3}}Chronostratihraphic chart of Thrace Basin (redrawn from Siyako<ref name=Siyako_2006>Siyako, M., 2006, Tertiary lithostratigraphic units of the Thrace Basin, in A. Siyako, A. Okay, and A. Yurtsever, eds., Lithostratigraphic units of the Thrace region, lithostratigraphic units series-2: General Directorate of Mineral Reseach and Exploration Publications, Ankara, p. 43–83.</ref>).]]

==Thrace basin==

==Thrace basin==

The Thrace Basin is a SE-NW trending trough controlled by fault systems, and the sediment fill reaches about 9000 m (29,527 ft) (Siyako, 2006; Siyako and Huvaz, 2007).

The Thrace Basin is a SE-NW trending trough controlled by fault systems, and the sediment fill reaches about 9000 m (29,527 ft).<ref name=Siyako_2006 /> <ref name=Siyakoandhuvaz_2007>Siyako, M. and O. Huvaz, 2007, Eocene stratigraphic evolution of the Thrace Basin, Turkey: Sedimentary Geology, v. 198, no. 2007, p. 75–91.</ref>

The basement of the Thrace Basin is composed of four to five different units ([[:file:M106Ch13Fig07.jpg|Figure 3]]):

The basement of the Thrace Basin is composed of four to five different units ([[:file:M106Ch13Fig07.jpg|Figure 3]]):

* Istranca-Rhodope Massive metamorphics, cropping out in northern Thrace. These metamorphic rocks extend from the Istranca Mountains to the North Anatolian fault system (NAFS) to the south.

* Istranca-Rhodope Massive metamorphics, cropping out in northern Thrace. These metamorphic rocks extend from the Istranca Mountains to the North Anatolian fault system (NAFS) to the south.

* İstanbul Paleozoic

* İstanbul Paleozoic

* Kocaeli Triassic sediments cropping out to the east of the basin (Şengör et al., 1985; Barka, 1997; Tüysüz et al., 1998; Siyako et al., 2000; Tüysüz et al., 2004; Şengör et al., 2005; Siyako and Huvaz, 2007).

* Kocaeli Triassic sediments cropping out to the east of the basin.<ref name=Sengoretal_1985>Şengör, A. M. C., Görür, N., and Saroglu, F., 1985, Strike-slip faulting and related basin formation in zones of tectonic escape: Turkey as a case study, in K.T. Biddle and N. Christie-Blick, eds., Strike-slip faulting and basin formation: Society of Economical Paleontologists and Mineralogists Special Publication, v. 37, p. 227–264.</ref> <ref name=Barka_1997>Barka, A. A., 1997, Neotectonics of the Marmara region, in C. Schindler and M. Pfister, eds., Active Tectonics of the Northwestern Anatolia-The Marmara Poly Project; A multidisciplinary approach by space geodesy, geology, hydrogeology, geothermics and seismology: Vdf. Hochschulerl an der ETH, Zurich, p. 55–87.</ref> <ref name=Tuysuzetal_1998>Tüysüz, O., Barka, A. A., and Yiǧitbaş, E., 1998, Geology of the Saros Graben and its implications for the evolution of the North Anatolian fault in the Ganos-Saros region, northwestern Turkey: Tectonophysics, v. 293, p. 103–126.</ref> <ref name=Siyakoetal_2000>Siyako, M., Taniş, T., and Şaroǧlu, F., 2000. Active fault geometry of the Marmara Sea: Science and Technology, v. 388, p. 66–71.</ref> <ref name=Tuysuzetal_2004> Tüysüz, O., Aksay, A., and Yiǧitbaş, E., 2004, Lithostratigraphic units of the western Black Sea region. General Directorate of Mineral Reseach and Exploration, Stratigraphy Commeetee, Lithostratigraphic Units Series-2. MTA Publications, Ankara, 92 p.

* Early Cretaceous–Paleocene age Çetmi Ophiolitic Mélange (Okay et al., 1990) constituting the basement of the southern block of the NAFS in the Gallipoli Peninsula and the Mürefte–Şarköy region (Bayrak et al., 2004).

* Early Cretaceous–Paleocene age Çetmi Ophiolitic Mélange<ref name=Okayetal_1990>Okay, A.I., Siyako, M., and Bürkan, K.A., 1990, Geology and tectonic evolution of the Biga Peninsula (in Turkish): Bulletin of the Turkish Association of Petroleum Geologists, v. 2, p. 83–121.</ref> constituting the basement of the southern block of the NAFS in the Gallipoli Peninsula and the Mürefte–Şarköy region.<ref name=Bayraketal_2004>

Bayrak, M., Gürer, A., and Gürer, Ö.F., 2004, Electromagnetic imaging of the Thrace Basin and intra-Pontide subduction zone, Northwestern Turkey: International Geology Review, v. 46, no. 1, p. 64–74.</ref>

===Source rock, maturation, and migration===

===Source rock, maturation, and migration===

Bürkan et al. (1999) has mapped Ro, TOC, and TOM and concluded that shales of Oligocene age have oil, and siliciclastics of Eocene age have gas and some oil generating potential. The Eocene unit has TOC values between 0.01% and 6.37% (Bürkan, 1993; Soylu et al., 1993). Bürkan (1993) claim that higher values are at the deeper part of the basin. Another unit of Eocene age has TOC values between 0.01% and 3.52%. The deltaic unit has higher and better TOC values in the deeper part of the basin and is between 0.22% and 7.27% (Bürkan, 1993; Soylu et al., 1993). There are contrasting data on the type of kerogen. Bürkan (1993) reports that all three formations have Type I and II kerogen. However, Soylu et al. (1993) report that while some Early to Middle Eocene sediments have mainly Type III kerogen, some wells also have Type I kerogen. Some Late Eocene sediments have mainly Type II, but some wells have Type III kerogen. Deltaic sediments of Late Eocene-Oligocene age have Type II and Type III kerogen. Bürkan (1992) mapped all geochemical parameters together with maturation parameters and reached a conclusion that the central part of the basin has the highest maturity values, and that in these areas the organic matter is in overmature state. Maturity decreases toward the marginal areas of the basin. He also concluded that Deltaic sediments of Late Eocene-Oligocene have mainly oil, some Middle to Late Eocene sediments have both oil and gas, and some Early to Middle Eocene sediments have gas generating potential. Soylu et al. (1993), however, concluded that the same unit has gas and very limited oil generating potential. Some Middle to Late Eocene sediments have gas and limited oil generating potential. It is difficult to determine if it has oil and/or gas generating potential, because the immature part of the basin has high organic matter but the mature part has very poor organic content.

Bürkan<ref name=Burkan_1992>Bürkan, K., 1992. Geochemical evaluation of the Thrace Basin, in Proceedings of the ninth petroleum congress of Turkey, 17-21 February 1992, Ankara, Turkey, Chamber of Petroleum Geology of Turkey: TPAO, Ankara p. 34–48.</ref> has mapped Ro, TOC, and TOM and concluded that shales of Oligocene age have oil, and siliciclastics of Eocene age have gas and some oil generating potential. The Eocene unit has TOC values between 0.01% and 6.37%.<ref name=Burkan_1992 /> <ref name=Soyluetal_1992>Soylu, C., B. Harput, H. I. Illeez, O. Ertuürk, H. Iztan, F. A. Ugǔr, T. Göker, A. Harput, K. Gürgey, and S. Sayili, 1992, Organic geochemical evaluation of the northern Thrace Basin: Proceedings of the 9th Petroleum Congress of Turkey, p. 49–61.</ref> Bürkan<ref name=Burkan_1992 /> claims that higher values are at the deeper part of the basin. Another unit of Eocene age has TOC values between 0.01% and 3.52%. The deltaic unit has higher and better TOC values in the deeper part of the basin and is between 0.22% and 7.27%.<ref name=Burkan_1992 /> <ref name=Soyluetal_1992 /> There are contrasting data on the type of kerogen. Bürkan<ref name=Burkan_1992 /> reports that all three formations have Type I and II kerogen. However, Soylu et al.<ref name=Soyluetal_1992 /> report that while some Early to Middle Eocene sediments have mainly Type III kerogen, some wells also have Type I kerogen. Some Late Eocene sediments have mainly Type II, but some wells have Type III kerogen. Deltaic sediments of Late Eocene-Oligocene age have Type II and Type III kerogen. Bürkan<ref name=Burkan_1992 /> mapped all geochemical parameters together with maturation parameters and reached a conclusion that the central part of the basin has the highest maturity values, and that in these areas the organic matter is in overmature state. Maturity decreases toward the marginal areas of the basin. He also concluded that Deltaic sediments of Late Eocene-Oligocene have mainly oil, some Middle to Late Eocene sediments have both oil and gas, and some Early to Middle Eocene sediments have gas generating potential. Soylu et al.,<ref name=Soyluetal_1992 /> however, concluded that the same unit has gas and very limited oil generating potential. Some Middle to Late Eocene sediments have gas and limited oil generating potential. It is difficult to determine if it has oil and/or gas generating potential, because the immature part of the basin has high organic matter but the mature part has very poor organic content.

Soylu et al. (1993) classifies the oil from the Thrace Basin as Group I and II. Group I oil is derived from marine organic matter, and the most likely candidate for Group I oil is deltaic sediments of Late Eocene-Oligocene age. They could not determine the source of the Group II oil.

Soylu et al.<ref name=Soyluetal_1992 /> classifies the oil from the Thrace Basin as Group I and II. Group I oil is derived from marine organic matter, and the most likely candidate for Group I oil is deltaic sediments of Late Eocene-Oligocene age. They could not determine the source of the Group II oil.

In terms of gas, the source of the thermogenic gas is Early to Middle Eocene, since this formation has overmature organic matter and organic matter capable of generating gas. The source of southern gas is probably Late Eocene-Oligocene. The depth for petroleum generation is about 2000–2500 m (6561–8202 ft).

In terms of gas, the source of the thermogenic gas is Early to Middle Eocene, since this formation has overmature organic matter and organic matter capable of generating gas. The source of southern gas is probably Late Eocene-Oligocene. The depth for petroleum generation is about 2000–2500 m (6561–8202 ft).

Gürgey et al. (2005) has analyzed gas and condensate samples from the various fields in the Thrace Basin and tried to correlate the gas and condensate to source rocks. They have classified the gas samples into three categories. Group-1 gas is CH4, bacteriogenic, and is found in Oligocene reservoirs and mixed with the thermogenic Group-2 CH4. They probably formed in the Upper Oligocene coal and shales deposited in a marshy-swamp environment of fluvio-deltaic settings. Group-2 and Group-3 methanes are thermogenic and share the same origin with the Group-2 and Group-3 C2+ gases. They are produced from both Eocene (overwhelmingly) and Oligocene reservoirs. These gases were almost certainly generated from isotopically heavy terrestrial kerogen present in the Eocene deltaic shales. The Group-3 C2+ gases, produced from one field, were generated from isotopically light marine kerogen. Lower Oligocene shales deposited in prodeltaic settings are believed to be the source of these gases.

Gürgey et al.<ref name=Gurgeyetal_2005>Gürgey, K., Philp, R. P., Clayton, C., Emiroǧlu, H., and Siyako, M., 2005, Geochemical and isotopic approach to maturity/source/mixing estimations for natural gas and associated condensates in the Thrace Basin, NW Turkey: Applied Geochemistry, v. 20, no. 11, p. 2017–2037.</ref> has analyzed gas and condensate samples from the various fields in the Thrace Basin and tried to correlate the gas and condensate to source rocks. They have classified the gas samples into three categories. Group-1 gas is CH4, bacteriogenic, and is found in Oligocene reservoirs and mixed with the thermogenic Group-2 CH4. They probably formed in the Upper Oligocene coal and shales deposited in a marshy-swamp environment of fluvio-deltaic settings. Group-2 and Group-3 methanes are thermogenic and share the same origin with the Group-2 and Group-3 C2+ gases. They are produced from both Eocene (overwhelmingly) and Oligocene reservoirs. These gases were almost certainly generated from isotopically heavy terrestrial kerogen present in the Eocene deltaic shales. The Group-3 C2+ gases, produced from one field, were generated from isotopically light marine kerogen. Lower Oligocene shales deposited in prodeltaic settings are believed to be the source of these gases.

As the source rock matured, the generated gas migrated updip from basinal areas toward the marginal areas. Some of the gas followed sealed the faults that are not sealed at the lower levels.

As the source rock matured, the generated gas migrated updip from basinal areas toward the marginal areas. Some of the gas followed sealed the faults that are not sealed at the lower levels.

===Reservoir rocks===

===Reservoir rocks===

There are a number of reservoir rocks in the basin. These are from older to younger: turbiditic sandstones at the lower levels and deltaic and fluvial sandstones at the upper levels of Early to Middle Eocene, shallow water sandstones of Late Eocene, reefal carbonates of Middle Eocene-Early Oligocene, prodelta sands of Late Eocene-Oligocene, Deltaic sandstone of Oligocene, and some sandy levels of Late Eocene-Oligocene (Doust et al. Arikan, 1974; Keskin, 1974; Turgut et al., 1983; Saner, 1985; Perinçek, 1991; Turgut et al., 1991). Shallow water sandstones of Late Eocene have 10–15% porosity and 0.1–1 md permeability values. Middle Eocene-Oligocene has 10–30% porosity and 1–80 md permeability. Turbiditic sandstone of Late Eocene has 10–18% porosity, but no permeability values are published (Siyako and Huvaz, 2007). Prodelta sands of Late Eocene-Oligocene have 10–15% porosity and 0.1–10 md permeability. Delta front sands of Oligocene have 10–25% porosity and 0.1–10 md permeability. Deltaic sands of Oligocene-Early Miocene have 10–23% porosity and 0.1–10 md permeability. Oligocene-Early Mioceneage deltaic sand is a gas producer, Oligocene sand is an oil and gas producer, Late Eocene-Oligocene is an oil producer, Late Eocene is a gas producer, Middle Eocene-Oligocene carbonates are gas producers, and Late Eocene clastics are oil and gas producers (Siyako and Huvaz, 2007).

There are a number of reservoir rocks in the basin. These are from older to younger: turbiditic sandstones at the lower levels and deltaic and fluvial sandstones at the upper levels of Early to Middle Eocene, shallow water sandstones of Late Eocene, reefal carbonates of Middle Eocene-Early Oligocene, prodelta sands of Late Eocene-Oligocene, Deltaic sandstone of Oligocene, and some sandy levels of Late Eocene-Oligocene.<ref name=Arikan_1975>Arikan, Y., 1975, The geology and petroleum prospects of the Tuz Gölü Basin: Bulletin of the mineral research and exploration institute of turkey, v. 85, p. 17–44.</ref> <ref name=Keskin_1974>

Keskin, C, 1974, Kuzey Trakya Havzasi’nin stratigrafisi. Türkiye_kinci Petrol Kongresi Tebli_leri Kitabi, p. 137–163.</ref> <ref name=Turgutetal_1983>Turgut, S., Siyako, M., and Dilki, A., 1983, Trakya havzasinin jeolojisi ve hidrokarbon olanaklari: Türkiye Jeoloji Kongresi Bülteni, v. 4, p. 35–46.</ref> <ref name=Saneretal_1980>Saner, S., M. Siyako, Z. Aksoy, K.A. Burkan, and O. Demir, 1980, Zonguldak dolayinin jeolojisi ve petrol olanaklari: Unpublished TPAO Report, Ankara.</ref> <ref name=Perincek_1991>Perinçek, D., 1991, Possible strand of the north Anatolian fault in the Thrace basin, Turkey - An interpretation. American Association of Petroleum Geologists Bulletin, v. 75, p. 241–257.</ref> <ref name=Turgutetal_1991>Turgut, S., Türkaslan, M., and Perinçek, D., 1991, Evolution of the Thrace sedimentary basin and its hydrocarbon prospectivity, in A. M. Spencer, ed., Generation, Accumulation, and Production of Europe’s Hydrocarbons: Special Publication of European Association of Petroleum Geoscientists, London, p. 415–437.</ref> Shallow water sandstones of Late Eocene have 10–15% porosity and 0.1–1 md permeability values. Middle Eocene-Oligocene has 10–30% porosity and 1–80 md permeability. Turbiditic sandstone of Late Eocene has 10–18% porosity, but no permeability values are published.<ref name=Siyakoandhuvaz_2007 /> Prodelta sands of Late Eocene-Oligocene have 10–15% porosity and 0.1–10 md permeability. Delta front sands of Oligocene have 10–25% porosity and 0.1–10 md permeability. Deltaic sands of Oligocene-Early Miocene have 10–23% porosity and 0.1–10 md permeability. Oligocene-Early Mioceneage deltaic sand is a gas producer, Oligocene sand is an oil and gas producer, Late Eocene-Oligocene is an oil producer, Late Eocene is a gas producer, Middle Eocene-Oligocene carbonates are gas producers, and Late Eocene clastics are oil and gas producers.<ref name=Siyakoandhuvaz_2007 />

[[file:M106Ch13Fig11.jpg|thumb|300px|{{figure number|4}}Simplified geological map of the Adana Neogene Basin. Misis structural trend divides the basin into two parts: Adana and İskenderun subbasins (redrawn from Derman and Gürbüz, 2007). 10 km (6.2 mi).]]

[[file:M106Ch13Fig11.jpg|thumb|300px|{{figure number|4}}Simplified geological map of the Adana Neogene Basin. Misis structural trend divides the basin into two parts: Adana and İskenderun subbasins (redrawn from Derman and Gürbüz<ref name=Dermanandgurbuz_2007>Derman, A. S. and K. Gürbüz, 2007, Nature, provenance and relationship of Early Miocene Paleovalley Fills, Northern Adana Basin, Turkey: Their significance for sediment-bypassing on a carbonate shelf: Turkish Journal of Earth Science, v. 16, p. 181–209.</ref>). 10 km (6.2 mi).]]

==Adana basin==

==Adana basin==

Adana Basin is located in southern Turkey and is a Neogene Basin ([[:file:M106Ch13Fig11.jpg|Figure 4]]). The basin is bordered by the Misis-Andirin strike-slip fault zone that forms the boundary between the Arabian and Anatolian plates to the east (Gökçen et al., 1988; Karig and Kozlu, 1990), by Ecemiş fault zone that lies within the Anatolian plate to the west (Yetiş, 1968; Koçyiǧit and Beyhan, 1998; Westaway, 1999; Jaffey and Robertson, 2001, 2005), and by the Taurus Mountains to the north (Yalçin and Görür, 1984; Ünlügenç et al., 1993; Williams et al., 1995), and opens into the Mediterranean Basin to the south ([[:file:M106Ch13Fig11.jpg|Figure 4]]). These boundaries were developed by the interaction between the African-Arabian and Anatolian plates (Barka and Kadinsky-Cade, 1988; Karig and Kozlu, 1990; Jackson and McKenzie, 1998; Robertson, 1998; Westaway, 1999).

Adana Basin is located in southern Turkey and is a Neogene Basin ([[:file:M106Ch13Fig11.jpg|Figure 4]]). The basin is bordered by the Misis-Andirin strike-slip fault zone that forms the boundary between the Arabian and Anatolian plates to the east,<ref name=Gokcen_1967>Gökçen, L. S., 1967, Keşan bölgesinde Eosen-Oligosen sedimantasyonu, Güneybati Türkiye Trakyasi. Maden Tetkik ve Arama Enstitüsü Dergisi, v. 69, p. 1–10.</ref> <ref name=Karigandkozlu_1990>Karig, D. E. and Kozlu, H., 1990, Late Paleogene-Neogene evolution of the triple junction region near Marafl, South-central Turkey: Journal of the GSL, v. 147, p. 1023–1034.</ref> by Ecemiş fault zone that lies within the Anatolian plate to the west,<ref name=Yetis_1968>Yetiş, C., 1968, Geology of the Camardi (Niǧde) region and the characteristics of the Ecemiş Fault Zone between Maden Boflaz and Kamisli. İstanbul Universitesi Fen Fakultesi Mecmuasi, Serie B, v. 43, p. 41–61.</ref> <ref name=Kocyigitandbeyhan_1998>Yetiş, C., 1968, Geology of the Camardi (Niǧde) region and the characteristics of the Ecemiş Fault Zone between Maden Boflaz and Kamisli. İstanbul Universitesi Fen Fakultesi Mecmuasi, Serie B, v. 43, p. 41–61.</ref> <ref name=Westaway_1999>Westaway, R., 1999, Present-day kinematics of the Middle East and eastern Mediterranean, Journal of Geophysical Research, v. 99, no. 12071, 2090 p.</ref> <ref name=Jaffeyandrobertson_2001>Jaffey, N. and Robertson, A. H. F., 2001, New sedimentological and structural data from the Ecemifl fault zone, southern Turkey: Implications for its timing and offset and the Cenozoic tectonic escape of Anatolia: Journal of the Geological Society, London, v. 158, p. 367–378.</ref> <ref name=Kaffeuamdrpbertspm_2005>Jaffey, N. and Robertson, A. H. F., 2005, Non-marine sedimentation associated with Oligocene-Recent exhumation and uplift of Central Taurus Mountains, S Turkey: Sedimentary Geology, v. 173, p. 53–89.</ref> and by the Taurus Mountains to the north (Yalçin and Görür, 1984; Ünlügenç et al., 1993; Williams et al., 1995), and opens into the Mediterranean Basin to the south ([[:file:M106Ch13Fig11.jpg|Figure 4]]). These boundaries were developed by the interaction between the African-Arabian and Anatolian plates (Barka and Kadinsky-Cade, 1988; Karig and Kozlu, 1990; Jackson and McKenzie, 1998; Robertson, 1998; Westaway, 1999).

Late Cretaceous ophiolites constitute a significant component of the eastern Mediterranean region and tectonically overlie Mesozoic platform carbonates and Paleozoic rocks of the Tauride Belt (Şengör and Yilmaz, 1981; Dilek and Moores, 1990; Dilek et al., 1999). Continued subduction of the Neo-Tethyan Ocean floor following the emplacement of ophiolites resulted in the terminal closure and amalgamation of the bounding continental fragments and termination of marine deposition by Late Eocene (Şengör and Yilmaz, 1981; Clark and Robertson, 2002; Kelling et al., 2005). The Adana Basin is located on the southern flank of the Taurus Mountains. Therefore, the Adana Basin has a complex basement structure and stratigraphy, and the nature and relations of all the basement units have not been fully resolved. Wells drilled in the basin have penetrated several units that are not exposed within or on the margins of the basin.

Late Cretaceous ophiolites constitute a significant component of the eastern Mediterranean region and tectonically overlie Mesozoic platform carbonates and Paleozoic rocks of the Tauride Belt (Şengör and Yilmaz, 1981; Dilek and Moores, 1990; Dilek et al., 1999). Continued subduction of the Neo-Tethyan Ocean floor following the emplacement of ophiolites resulted in the terminal closure and amalgamation of the bounding continental fragments and termination of marine deposition by Late Eocene (Şengör and Yilmaz, 1981; Clark and Robertson, 2002; Kelling et al., 2005). The Adana Basin is located on the southern flank of the Taurus Mountains. Therefore, the Adana Basin has a complex basement structure and stratigraphy, and the nature and relations of all the basement units have not been fully resolved. Wells drilled in the basin have penetrated several units that are not exposed within or on the margins of the basin.