Changes

Of these basins, the SE Anatolian basin, Thrace Basin, Adana Basin, and the Black Sea Basin have hydrocarbon (HC) production.

Of these basins, the SE Anatolian basin, Thrace Basin, Adana Basin, and the Black Sea Basin have hydrocarbon (HC) production.

[[file:M106Ch13Fig02.jpg|thumb|300px|{{figure number|2}}Main structural elements of Turkey and their relation with the sedimentary basins. Offshore areas are not adequately explored yet, so scarcity of data is the result of absence of subsurface data. Petroleum fields are marked as green and gas fields are marked as yellow. Oil fields are numbered in Thrace and SE Turkey. For SE Turkey: 1. B. Firat, 2. B. Kayaköy, 3. B. Kozluca, 4. B. Malatepe, 5. B. Migo, 6. B. Raman, 7. Barbeş, 8. Baysu, 9. Beşikli, 10. Beyçayir, 11. Beykan, 12. Bozova, 14. Çamurlu, 18. Çaylarbaşi, 15. Çelikli, 16. Çemberlitaş, 17. Cendere, 18. Çukurtaş, 19. D. Beşikli, 20. D. Silivanka, 21. D. Yatir, 22. Şahaban, 23. Tokaris, 24. G. Şahaban, 25. Germik, 26. G. Saricak, 27. Malatepe, 28. Dodan, 29. Kahta, 30. Raman, 31. G. Karakuş, 32. Silivanka, 33. Kayaköy, 34. K. Karakuş, 35. Eskitaş, 36. Şelmo, 37. Karakuş, 38. Kurkan, 39. Yeniköy, 40. G. Adiyaman, 41. Hazro, 42. Kartaltepe, 43. G. Dinçer, 44. Maǧrip, 45. O. Sungurlu, 46. Katin, 47. Yeşildere, 48. Mehmetdere, 49. Oyuktaş, 50. Saricak, 51. Kastel, 52. Garzan, 53. İkiztepe, 54. G. Kayaköy, 55. G. Kurkan, 56. İkizce, 57. Sincan, 58. Adiyaman. For the Thrace Basin: 1. Adatepe, 2. Deǧirmenköy, 3. Umurca, 4. Hamitabat, 5. K. Osmancik, 6. Kavakdere, 7. Deveçataǧi, 8. Göçerler, 9. Tekirdaǧ, 10. Hayrabolu, 11. Karaçali, 12. K. Marmara. (Compiled from Perinçek;<ref name=Perincek_1980>Perinçek, D., 1980, Arabistan Kitasi kuzeyindeki tektonik evrimin kita üzerinde çökelen istifteki etkileri: Turkiye 5. Petrol Kongresi TebliǧIeri, p. 77–93.</ref> Perinçek and Özkaya;<ref name=Perincekandozkaya_1981>Perinçek, D. and İ. Özkaya, 1981, Arabistan levhasi kuzey kenari tektonik evrimi. Yerbilimleri: Hacettepe Üniversitesi Yerbilimleri Enstitüsü Bülteni, v. 8, p. 91–101.</ref> Şengör and Yilmaz;<ref name=Sengorandyilmaz_1981 /> Barka and Kadinsky-Cade;<ref name=Barkaandkadinskycade_1988>Barka, A. and Kadinsky-Cade, C., 1988, Strike-slip fault geometry in Turkey and its influence on earthquake activity: Tectonics, v. 7, p. 663–684.</ref> Perinçek;<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> Robertson;<ref name=Robertson_1998>Robertson, A. H. F., 1998, Mesozoic-Tertiary tectonic evolution of the easternmost Mediterranean area: Integration of Marine and land evidence, in A. H. F. Robertson, K. C. Emeis, C. Richter, and A. Camerlenghia, eds., Proceedings of the Ocean Drilling Program: Scientific Results, v. 160, p. 723–782.</ref> Jafey and Robertson;<ref name=Jafeyandrobertson_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> Şengör et al.<ref name=Sengoretal_2005>Şengör, A. M. C., Tüysüz, O., İmren, C., Sakinç, M., Eyidoǧan, H., Görür, N., Le Pichon, X., and Rangin, C., 2005, The North Anotolian fault: A new look: Annual Review of Earth and Planetary Science, v. 33, p. 37–112.</ref>).]]

[[file:M106Ch13Fig02.jpg|thumb|300px|{{figure number|2}}Main structural elements of Turkey and their relation with the sedimentary basins. Offshore areas are not adequately explored yet, so scarcity of data is the result of absence of subsurface data. Petroleum fields are marked as green and gas fields are marked as yellow. Oil fields are numbered in Thrace and SE Turkey. For SE Turkey: 1. B. Firat, 2. B. Kayaköy, 3. B. Kozluca, 4. B. Malatepe, 5. B. Migo, 6. B. Raman, 7. Barbeş, 8. Baysu, 9. Beşikli, 10. Beyçayir, 11. Beykan, 12. Bozova, 14. Çamurlu, 18. Çaylarbaşi, 15. Çelikli, 16. Çemberlitaş, 17. Cendere, 18. Çukurtaş, 19. D. Beşikli, 20. D. Silivanka, 21. D. Yatir, 22. Şahaban, 23. Tokaris, 24. G. Şahaban, 25. Germik, 26. G. Saricak, 27. Malatepe, 28. Dodan, 29. Kahta, 30. Raman, 31. G. Karakuş, 32. Silivanka, 33. Kayaköy, 34. K. Karakuş, 35. Eskitaş, 36. Şelmo, 37. Karakuş, 38. Kurkan, 39. Yeniköy, 40. G. Adiyaman, 41. Hazro, 42. Kartaltepe, 43. G. Dinçer, 44. Maǧrip, 45. O. Sungurlu, 46. Katin, 47. Yeşildere, 48. Mehmetdere, 49. Oyuktaş, 50. Saricak, 51. Kastel, 52. Garzan, 53. İkiztepe, 54. G. Kayaköy, 55. G. Kurkan, 56. İkizce, 57. Sincan, 58. Adiyaman. For the Thrace Basin: 1. Adatepe, 2. Deǧirmenköy, 3. Umurca, 4. Hamitabat, 5. K. Osmancik, 6. Kavakdere, 7. Deveçataǧi, 8. Göçerler, 9. Tekirdaǧ, 10. Hayrabolu, 11. Karaçali, 12. K. Marmara. (Compiled from Perinçek;<ref name=Perincek_1980>Perinçek, D., 1980, Arabistan Kitasi kuzeyindeki tektonik evrimin kita üzerinde çökelen istifteki etkileri: Turkiye 5. Petrol Kongresi TebliǧIeri, p. 77–93.</ref> Perinçek and Özkaya;<ref name=Perincekandozkaya_1981>Perinçek, D. and İ. Özkaya, 1981, Arabistan levhasi kuzey kenari tektonik evrimi. Yerbilimleri: Hacettepe Üniversitesi Yerbilimleri Enstitüsü Bülteni, v. 8, p. 91–101.</ref> Şengör and Yilmaz;<ref name=Sengorandyilmaz_1981 /> Barka and Kadinsky-Cade;<ref name=Barkaandkadinskycade_1988>Barka, A. and Kadinsky-Cade, C., 1988, Strike-slip fault geometry in Turkey and its influence on earthquake activity: Tectonics, v. 7, p. 663–684.</ref> Perinçek;<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> Robertson;<ref name=Robertson_1998>Robertson, A. H. F., 1998, Mesozoic-Tertiary tectonic evolution of the easternmost Mediterranean area: Integration of Marine and land evidence, in A. H. F. Robertson, K. C. Emeis, C. Richter, and A. Camerlenghia, eds., Proceedings of the Ocean Drilling Program: Scientific Results, v. 160, p. 723–782.</ref> Jaffey and Robertson;<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> Şengör et al.<ref name=Sengoretal_2005>Şengör, A. M. C., Tüysüz, O., İmren, C., Sakinç, M., Eyidoǧan, H., Görür, N., Le Pichon, X., and Rangin, C., 2005, The North Anotolian fault: A new look: Annual Review of Earth and Planetary Science, v. 33, p. 37–112.</ref>).]]

==Southeast Anatolian basin==

==Southeast Anatolian basin==

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_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>

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>

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.

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.

==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,<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).

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>Koçyiǧit, A. and Bayhan, A., 1998, A new intercontinental transcurrent structure: The central Anatolian fault zone, Turkey: Tectonophysics, v. 284, p. 317–336.</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 /><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,<ref name=Yalcinandgorur_1984>Yalçin, M. N and Görür, N. 1984. Sedimentological evolution of the Adana Basin, in O. Tekeli and M. C. Göncüoǧlu, eds., Proceedings of the International Symposium on the Geology of Taurus Belt, Ankara, p. 165–172.</ref> <ref name=Unlugencetal_1993>Ünlügenç, U., Demirkol, C., and Şafak, U., 1993, Adana Baseni K-KD’sunda yer alan Karsanti Baseni çökellerinin stratigrafik-sedimantolojik nitelikleri [Stratigraphic and sedimentalogic characteristics of Karsant Basin fill N-NE of Adana Basin]. Proceedings of A. Suat Erk Jeoloji Sempozyumu, p. 215–227 [in Turkish with English abstract].</ref> <ref name=Williametal_1995>William, G. D., Ünlügenç, U., Kelling, G. and Demirkol, C., 1995, Tectonic control on stratigraphic evolution of the Adana Basin, Turkey: Journal of the GSL, v. 152, p. 873–882.</ref> 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.<ref name=Barkaandkadinskycade_1988 /> <ref name=Karigandkozlu_1990 /> <ref name=Jacksonandmckenzie_1998>Jackson, J. and McKenzie, D. P., 1998, The relationship between plate motions and seismic moment tensors, and the rates of active deformation in the Mediterranean and Middle East: Geophysical Journal, v. 93, p. 45–73.</ref> <ref name=Robertson_1998 /> <ref name=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.<ref name=Sengorandyilmaz_1981 /> <ref name=Dilekandmoores_1990>Dilek, Y. and Moores, E. M., 1990, Regional tectonics of the eastern Mediterranean ophiolites, in J. Malpas, E. Moores, A. Panayiotou, and C. Xenophontos, eds., Oceanic crustal analogues, proceeding of the symposium “Trodos 1987": The Geological Survey Department, Nicosia, Cyprus, p. 295–309.</ref> <ref name=Dileketal_1999>Dilek, Y., Thy, P., Hacker, B., and Grundwig, S., 1999, Structure and petrology of Tauride ophiolites and mafic dike intrusions (Turkey): implications for the Neo-Tethyan ocean: Geological Society of America Bulletin, v. 111, p. 1192–1216.</ref> 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.<ref name=Sengorandyilmaz_1981 /> <ref name=Clarkandrobertson_2002>Clark, M. and Robertson, A., 2002, The role of the Early Tertiary Ulukisla Basin, southern Turkey, in suturing of the Mesozoic Tethys ocean: Journal of the Geological Society, London, v. 159, p. 367–378.</ref> <ref name=Kellingetal_2005>Kelling, G., Robertson, A. H. F., and Van Buchem, F. H. P., 2005, Cenozoic sedimentary basins of south central Turkey: An introduction, in G. Kelling, A. H. F. Robertson, and F. H. F. Van Buchem, eds., Cenozoic sedimentary basins of South Central Turkey: Special issue sedimentary geology, v. 173, p. 1–13.</ref> 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.

===Source rocks===

===Source rocks===

Oil production comes from one field since the 1960s, and there are a number of gas shows in the wells drilled in the basin. Oil and gas shows are present in some wells in the İskenderun Basin. Some gas shows are also present in Adana Basin from shallow depths.

Oil production comes from one field since the 1960s, and there are a number of gas shows in the wells drilled in the basin. Oil and gas shows are present in some wells in the İskenderun Basin. Some gas shows are also present in Adana Basin from shallow depths.

There have not been many organic geochemical studies in the Adana Basin. Yalçin (1987) analyzed some samples from the Adana Basin sediments and some samples from the pre-Miocene sediments. Analyses indicate that Miocene sediments are poor in organic matter. Maturation values from vitrinite reflection are low. All are below 0.6%, indicating immature organic matter. The 0.6% value is reached at about 4000 m (13,123 ft) depth, meaning that only sediments buried under 4000 m (13,123 ft) have potential for generating oil. Oil analysis indicate that Bulgurdaǧ oil is derived from an organic matter whose vitrinite reflectance is 1.03%. Since Bulgurdaǧ field is producing shallower than 2000 m (6561 ft), the oil cannot be derived from Adana Basin sediments, or at least not the sediments surrounding the field (Yalçin, 1987). Samples (shales) from one of the wells yield 1.24–2.47% TOC. They contain a mixture of Type II and Type III kerogen. Therefore hydrocarbon generating potential of Paleozoic shales are greater than that of Miocene. It may be possible for the Paleozoic shales to be the source for the Bulgurdaǧ oil, however uncertainty exists.

There have not been many organic geochemical studies in the Adana Basin. Yalçin<ref name=Yalcin_1987>Yalçin, M.N., 1987, Adana Havzasi petrol ve doǧal gazin kökeni (Origin of hydrocarbons in the Adana Basin, south Turkey). Proceedings of 7th Petroleum Congress of Turkey, Ankara, 427-441. Turkish with english abstract).</ref> analyzed some samples from the Adana Basin sediments and some samples from the pre-Miocene sediments. Analyses indicate that Miocene sediments are poor in organic matter. [[Maturation]] values from vitrinite reflection are low. All are below 0.6%, indicating immature organic matter. The 0.6% value is reached at about 4000 m (13,123 ft) depth, meaning that only sediments buried under 4000 m (13,123 ft) have potential for generating oil. Oil analysis indicate that Bulgurdaǧ oil is derived from an organic matter whose vitrinite reflectance is 1.03%. Since Bulgurdaǧ field is producing shallower than 2000 m (6561 ft), the oil cannot be derived from Adana Basin sediments, or at least not the sediments surrounding the field.<ref name=Yalcin_1987 /> Samples (shales) from one of the wells yield 1.24–2.47% TOC. They contain a mixture of Type II and Type III kerogen. Therefore hydrocarbon generating potential of Paleozoic shales are greater than that of Miocene. It may be possible for the Paleozoic shales to be the source for the Bulgurdaǧ oil, however uncertainty exists.

===Reservoir Rocks===

===Reservoir Rocks===

==Black sea basin==

==Black sea basin==

Hydrocarbon shows have been known in northern Turkey for more than 100 years. Some of the oil has been collected for medicinal purposes. Six hydrocarbon seeps are known in the Black Sea and adjacent onshore areas ([[:file:M106Ch13Fig01.jpg|Figure 1]]). Carbonates and sandstones of the Namurian contain two oil seeps in the Zonguldak area. Gas is seeping out ~5 km (3.1 mi) west of the town of Ulus from turbidite sediments of Cretaceous age (Aslanci seep). Another oil seep, the Ekinveren seep, is located near Boyabat in the Central Pontides in a Cretaceous sandstone along a fault zone ([[:file:M106Ch13Fig01.jpg|Figure 1]]). Offshore, there are two seeps: Çayeli (oil) and Inceburun (gas) (Norman and Atabey, 1992). The first exploratory well (Boyabat-1) was drilled in 1960, targeting the İnalti Formation of Late Jurassic-Early Cretaceous age ([[:file:M106Ch13Fig01.jpg|Figure 1]]). In 1976, offshore wells Akçakoca-1 and 2 wells were drilled and 2.5 MMCFGD (million cubic feet of gas per day) was tested. A total of about 40 wells have been drilled to date; six wells have gas shows and others were completed as dry holes.

Hydrocarbon shows have been known in northern Turkey for more than 100 years. Some of the oil has been collected for medicinal purposes. Six hydrocarbon seeps are known in the Black Sea and adjacent onshore areas ([[:file:M106Ch13Fig01.jpg|Figure 1]]). Carbonates and sandstones of the Namurian contain two oil seeps in the Zonguldak area. Gas is seeping out ~5 km (3.1 mi) west of the town of Ulus from turbidite sediments of Cretaceous age (Aslanci seep). Another oil seep, the Ekinveren seep, is located near Boyabat in the Central Pontides in a Cretaceous sandstone along a fault zone ([[:file:M106Ch13Fig01.jpg|Figure 1]]). Offshore, there are two seeps: Çayeli (oil) and Inceburun (gas).<ref name=Normanandatabey_1992>Norman, T.N. and M.E. Atabey, 1992, Sea floor gas escape features around Inceburun Peninsula, Northern Turkey (abs.): General Directorate of Mineral Research and Exploration and Chamber of Geological Engineers, International Symposium on the Geology of the Black Sea Region, Ankara, Turkey, September 7-11, p. 83.</ref> The first exploratory well (Boyabat-1) was drilled in 1960, targeting the İnalti Formation of Late Jurassic-Early Cretaceous age ([[:file:M106Ch13Fig01.jpg|Figure 1]]). In 1976, offshore wells Akçakoca-1 and 2 wells were drilled and 2.5 MMCFGD (million cubic feet of gas per day) was tested. A total of about 40 wells have been drilled to date; six wells have gas shows and others were completed as dry holes.

===Source rocks===

===Source rocks===

====Western and Central Pontides====

====Western and Central Pontides====

Organic geochemical studies on subsurface and surface samples indicate that there are several potential hydrocarbon source rock units in the region (Table 1). Sediments of Early Devonian, Middle Devonian-Early Carboniferous, Carboniferous, Middle Jurassic, Cretaceous, middle Cretaceous, Late Cretaceous, and Eocene ages are all considered to be potential hydrocarbon source rocks.

Organic geochemical studies on subsurface and surface samples indicate that there are several potential hydrocarbon source rock units in the region. Sediments of Early Devonian, Middle Devonian-Early Carboniferous, Carboniferous, Middle Jurassic, Cretaceous, middle Cretaceous, Late Cretaceous, and Eocene ages are all considered to be potential hydrocarbon source rocks.

The Early Devonian sediments are exposed in a few places in the Western Pontides. No well has penetrated this formation in the subsurface. The unit is composed of predominantly clastics and some carbonates. Total organic carbon values range from 0.12 to 2.35 wt%. The organic matter is generally Types III and IV, and in some places Type II (Harput et al., 1993). The SCI measurements indicate that the maturity level of the unit changes from middle mature to overmature.

The Early Devonian sediments are exposed in a few places in the Western Pontides. No well has penetrated this formation in the subsurface. The unit is composed of predominantly clastics and some carbonates. Total organic carbon values range from 0.12 to 2.35 wt%. The organic matter is generally Types III and IV, and in some places Type II. The SCI measurements indicate that the maturity level of the unit changes from middle mature to overmature.

The Middle Devonian-Early Carboniferous sediment is a carbonate unit with thin beds of black shales that contain up to 7.92 wt % TOC (Harput, 1993). The kerogen is mostly Type II and the maturity level of the unit changes from middle mature to overmature, based on the surface samples [R0 = 0.72–2.0%, SCI (spore coloration index) = 6.2–9.0]. It shows oil potential in a few areas where it is covered by younger sediments. Other Devonian and Early Carboniferous sediments show a similar maturity trend as Early Devonian sediments.

The Middle Devonian-Early Carboniferous sediment is a carbonate unit with thin beds of black shales that contain up to 7.92 wt % TOC. The kerogen is mostly Type II and the maturity level of the unit changes from middle mature to overmature, based on the surface samples [R0 = 0.72–2.0%, SCI (spore coloration index) = 6.2–9.0]. It shows oil potential in a few areas where it is covered by younger sediments. Other Devonian and Early Carboniferous sediments show a similar maturity trend as Early Devonian sediments.

The Carboniferous sediment consists of prodelta and delta front shale, which contains in its lower part up to 8.03 wt % TOC. It has both Type II and Type III organic matter (Harput, 1993). The maturity level of the organic matter ranges from middle mature in general to postmature (Derman and İztan, 1997). Maturity may be related to Tertiary volcanics (Ro = 0.55–1.33%; SCI = 5.0–8.5; Tmax = 412–486°C) (Table 1).

The Carboniferous sediment consists of prodelta and delta front shale, which contains in its lower part up to 8.03 wt % TOC. It has both Type II and Type III organic matter. The maturity level of the organic matter ranges from middle mature in general to postmature.<ref name=Dermanandiztan_1997>Derman, A. S. and İztan, H., 1997, [http://archives.datapages.com/data/specpubs/memoir68/ch16/ch16.htm Results of Geochemical analysis of seeps and potential source rocks from Northern Turkey, and then Türkish Black Sea], in A.G. Robinson, ed., Regional and petroleum geology of the Black Sea and surrounding region: [http://archives.datapages.com/data/alt-browse/aapg-special-volumes/m68.htm AAPG Memoir 68], p. 313–330.</ref> Maturity may be related to Tertiary volcanics (Ro = 0.55–1.33%; SCI = 5.0–8.5; Tmax = 412–486°C).

The Carboniferous sediments are present between the Zonguldak and Cide areas. It crops out in the Zonguldak area but is covered between Bartin and Cide. Coal samples taken from this formation have also been analyzed. The analytical data (Table 1) show that samples have high petroleum (oil + gas) source rock potential as indicated by high TOC (30–70 wt %), high HI (222–598 mg HC/g), high petroleum yield (PY) (12,600–206,000 ppm), R (0.75–0.85), and Tmax (422–447°C) values (Derman and İztan, 1997).

The Carboniferous sediments are present between the Zonguldak and Cide areas. It crops out in the Zonguldak area but is covered between Bartin and Cide. Coal samples taken from this formation have also been analyzed. The analytical data show that samples have high petroleum (oil + gas) source rock potential as indicated by high TOC (30–70 wt %), high HI (222–598 mg HC/g), high petroleum yield (PY) (12,600–206,000 ppm), R (0.75–0.85), and Tmax (422–447°C) values.<ref name=Dermanandiztan_1997 />

The upper part of the Carboniferous sediments consist of shale, sandstone, and a conglomerate of delta plain origin. This formation is present between Zonguldak and Cide. Outcrop samples show up to 5.42 wt % TOC. The kerogen is mostly Type III, which is capable of producing mainly gas (Tissot et al., 1980), but Type II kerogen is also present. The Ro, SCI, and Tmax values vary from 0.45 to 1.2 wt %, 5.5 to 7.5, and 436 to 494°C, respectively (Table 1), which indicates moderate maturity. Maturity increases from moderately mature to postmature. In the Amasra-1 well, TOC values of the shaly sections range from 0.07 to 2.66%. The R values, on the surface, range from 0.65 to 1.2% throughout the unit in the well, which indicates moderate maturity (Deman and İztan, 1997).

The upper part of the Carboniferous sediments consist of shale, sandstone, and a conglomerate of delta plain origin. This formation is present between Zonguldak and Cide. Outcrop samples show up to 5.42 wt % TOC. The kerogen is mostly Type III, which is capable of producing mainly gas, but Type II kerogen is also present. The Ro, SCI, and Tmax values vary from 0.45 to 1.2 wt %, 5.5 to 7.5, and 436 to 494°C, respectively, which indicates moderate maturity. Maturity increases from moderately mature to postmature. In the Amasra-1 well, TOC values of the shaly sections range from 0.07 to 2.66%. The R values, on the surface, range from 0.65 to 1.2% throughout the unit in the well, which indicates moderate maturity.<ref name=Dermanandiztan_1997 />

The Middle Jurassic sediments are made up of sandstones at the bottom, dark-gray shales in the middle, and coal and some sandstones at the top. It is not present to the west of Kurucaşile (Derman, 1995a). Organic matter measurements from shaley intervals give high TOC values <3.92 wt %. Kerogen is predominantly Types III and IV at the bottom and at the top, but Type II has been observed in the middle part of the formation. The unit is early mature to postmature in the south of Cide based on Ro (0.68–0.86%), SCI (6.0–7.5), and Tmax (428–475°C) values.

The Middle Jurassic sediments are made up of sandstones at the bottom, dark-gray shales in the middle, and coal and some sandstones at the top. It is not present to the west of Kurucaşile.<ref name=Derman_1995a>Derman, A.S., 1995, Megabreccias and other mass flow deposits in the Ulus Basin: Ph.D. thesis, Middle East Technical University, Ankara, Turkey, 229 p.</ref> Organic matter measurements from shaley intervals give high TOC values <3.92 wt %. Kerogen is predominantly Types III and IV at the bottom and at the top, but Type II has been observed in the middle part of the formation. The unit is early mature to postmature in the south of Cide based on Ro (0.68–0.86%), SCI (6.0–7.5), and Tmax (428–475°C) values.

The Cretaceous sediments are dominantly a turbidite unit made up of shale-sandstone interbeds. It is a very extensive unit in the Pontide region. Due to its turbiditic character and variable burial history in different parts of the region, organic geochemical parameters change drastically from one area to another. The TOC values range from 0.09 to 2.14%, averaging 0.60%. Organic matter varies from Type I to Type IV, but is mainly Types II and III (Table 1). Maturity values also show great diversity, which is the result of volcanic and magmatic intrusions during the Late Cretaceous and Eocene, and variable burial history. The Ro, SCI, and Tmax values vary from 0.35 to 1.40%, 3.0 to 9.0, and 423 to 471°C, respectively, suggesting that the unit is immature between Sinop and Boyabat to overmature in the İnebolu-Abana area, probably due to island arc volcanism of Late Cretaceous age.

The Cretaceous sediments are dominantly a turbidite unit made up of shale-sandstone interbeds. It is a very extensive unit in the Pontide region. Due to its turbiditic character and variable burial history in different parts of the region, organic geochemical parameters change drastically from one area to another. The TOC values range from 0.09 to 2.14%, averaging 0.60%. Organic matter varies from Type I to Type IV, but is mainly Types II and III. Maturity values also show great diversity, which is the result of volcanic and magmatic intrusions during the Late Cretaceous and Eocene, and variable burial history. The Ro, SCI, and Tmax values vary from 0.35 to 1.40%, 3.0 to 9.0, and 423 to 471°C, respectively, suggesting that the unit is immature between Sinop and Boyabat to overmature in the İnebolu-Abana area, probably due to island arc volcanism of Late Cretaceous age.

The sediments in the Ulus Basin are also a turbiditic unit and are mostly developed in and around the Ulus Basin. The content of organic matter depends on the amount of sand and silt-sized material present. To the west of the Ulus Basin, inflow of abundant coarse clastics and suspended matter has probably diluted the basinal sediments with respect to organic content. The TOC content of the unit varies from 0.25 to 1.84 wt % (Harput, 1993). The organic matter type changes from Type II to Type IV. Ro, SCI, and Tmax values are between 0.44–1.70%, 4–10, and 427–498°C, respectively. Maturity increases from west to east and from the margin toward the center of the Ulus Basin (Derman and İztan, 1997).

The sediments in the Ulus Basin are also a turbiditic unit and are mostly developed in and around the Ulus Basin. The content of organic matter depends on the amount of sand and silt-sized material present. To the west of the Ulus Basin, inflow of abundant coarse clastics and suspended matter has probably diluted the basinal sediments with respect to organic content. The TOC content of the unit varies from 0.25 to 1.84 wt %. The organic matter type changes from Type II to Type IV. Ro, SCI, and Tmax values are between 0.44–1.70%, 4–10, and 427–498°C, respectively. Maturity increases from west to east and from the margin toward the center of the Ulus Basin.<ref name=Dermanandiztan_1997 />

The Cretaceous sediment near Zonguldak consists of bluish-gray colored marl that has up to 1.46 wt % TOC values, most of which are −1.0 wt %. The unit has Type II organic matter, which is early mature-marginally mature in surface exposures. Maturity level increases from south to north, with R values changing from 0.45 to 0.55%. Average SCI and Tmax values are 5.5 and 435°C, respectively.

The Cretaceous sediment near Zonguldak consists of bluish-gray colored marl that has up to 1.46 wt % TOC values, most of which are −1.0 wt %. The unit has Type II organic matter, which is early mature-marginally mature in surface exposures. Maturity level increases from south to north, with R values changing from 0.45 to 0.55%. Average SCI and Tmax values are 5.5 and 435°C, respectively.

The volcaniclastic unit has not been considered a potential source rock due to its volcaniclastic nature. In one well (Filyos-1 well), however, it has a 400 m (1312 ft) thick shaley level which has up to 1.12 wt % organic carbon content. The organic matter is Types II and III, and the kerogen is mature in this interval (RQ = 0.88–0.94 wt %; SCI = 6.5; Tmax = 443–447°C). Additionally, C1–C4 gas reading recorded during drilling in this interval shows that the C2+ wet gas ratio is about 80%, which indicates that this zone is in the oil window. Other levels in the Yemisliçay Formation do not have any source rock potential in the well.

The volcaniclastic unit has not been considered a potential source rock due to its volcaniclastic nature. In one well (Filyos-1 well), however, it has a 400 m (1312 ft) thick shaley level which has up to 1.12 wt % organic carbon content. The organic matter is Types II and III, and the kerogen is mature in this interval (RQ = 0.88–0.94 wt %; SCI = 6.5; Tmax = 443–447°C). Additionally, C1–C4 gas reading recorded during drilling in this interval shows that the C2+ wet gas ratio is about 80%, which indicates that this zone is in the oil window. Other levels in the Yemisliçay Formation do not have any source rock potential in the well.

The Eocene sediments have TOC values between 0.08 and 0.93 wt %. The organic matter is predominantly Type III, and the maturity level changes from early to middle mature (RQ = 0.31–0.33 wt %; SCI = 2.5–7.5; Tmax = 432–453°C) (Table 2). Thus, the unit is considered to be a potential source rock for only gas (Derman and İztan, 1997).

The Eocene sediments have TOC values between 0.08 and 0.93 wt %. The organic matter is predominantly Type III, and the maturity level changes from early to middle mature (RQ = 0.31–0.33 wt %; SCI = 2.5–7.5; Tmax = 432–453°C). Thus, the unit is considered to be a potential source rock for only gas.<ref name=Dermanandiztan_1997 />

====Eastern Pontides====

====Eastern Pontides====

In the Eastern Pontides, samples ranging in age from Liassic to Miocene have been evaluated geochemically for their source rock potential (Table 2).

In the Eastern Pontides, samples ranging in age from Liassic to Miocene have been evaluated geochemically for their source rock potential.

Most of the samples taken from Liassic outcrops around Bayburt have low organic matter content (0.12–1.53 wt %), low P2 (10–3190 ppm) values, and show high maturity levels (Tmax = 470°C; SCI = 7.5–9.0; RQ = 0.82–1.3%). In one section, the unit has been found to be early mature (Tmax = 425–435°C; SCI = 4.5–6.0; Ro = 0.55–0.65%). The unit has no source rock potential in this area (Derman and İztan, 1997).

Most of the samples taken from Liassic outcrops around Bayburt have low organic matter content (0.12–1.53 wt %), low P2 (10–3190 ppm) values, and show high maturity levels (Tmax = 470°C; SCI = 7.5–9.0; RQ = 0.82–1.3%). In one section, the unit has been found to be early mature (Tmax = 425–435°C; SCI = 4.5–6.0; Ro = 0.55–0.65%). The unit has no source rock potential in this area.<ref name=Dermanandiztan_1997 />

The Cretaceous unit also has low TOC (0.13–0.79 wt %) and P2 (30–200 ppm) values. The HI values are also very low (7–41 mg HC/g TOC). The maturity level of the unit ranges from middle to postmature (Tmax = 432–485°C, SCI = 6.0–8.0%; Ro = 0.88–1.22%). Therefore, this unit does not have source potential (Derman and İztan, 1997).

The Cretaceous unit also has low TOC (0.13–0.79 wt %) and P2 (30–200 ppm) values. The HI values are also very low (7–41 mg HC/g TOC). The maturity level of the unit ranges from middle to postmature (Tmax = 432–485°C, SCI = 6.0–8.0%; Ro = 0.88–1.22%). Therefore, this unit does not have source potential<ref name=Dermanandiztan_1997 />

The Eocene samples are relatively rich in organic matter, ranging from 0.47–1.69 wt %, averaging 1.0 wt %. However, low P2 (140–540 ppm) and HI values (8–80 mg HC/g TOC) indicate that this unit cannot be considered as a potential source rock. The maturity level of the unit is middle mature-postmature (Tmax = 457–482°C, SCI = 6.0–7.0; R0 = 0.75–0.88%).

The Eocene samples are relatively rich in organic matter, ranging from 0.47–1.69 wt %, averaging 1.0 wt %. However, low P2 (140–540 ppm) and HI values (8–80 mg HC/g TOC) indicate that this unit cannot be considered as a potential source rock. The maturity level of the unit is middle mature-postmature (Tmax = 457–482°C, SCI = 6.0–7.0; R0 = 0.75–0.88%).

There are a number of potential reservoir rocks in the region varying from Paleozoic to Tertiary, and a deepening paleogeographic trend from west to east during early Paleozoic. Early Paleozoic rocks are tightly cemented and have only limited reservoir potential. The most important candidates in the Paleozoic are Carboniferous deltaic sands. A coal-bearing unit of Carboniferous has both reservoir and seal within. Aeolian sandstone of Triassic, shoreline sands of Middle Jurassic, dolomitized limestones of Late Jurassic-Earliest Cretaceous, shoreline sands of Early Cretaceous, rudistid shallow marine carbonate sands of Late Cretaceous, and shallow marine carbonate sands of Eocene are the potential reservoir rocks of the western Pontide. All these units have restriction in geometry and geographic extend. The Middle Pontide reservoir rock is limited due to the environmental conditions and tectonic evolution. The area is dominated by fine grained sediments and some fine grained turbidites. The only potential reservoir would be fractured limestones of the İnalti Formation. In the eastern Pontide, however, upper Jurassic-lower Cretaceous limestone and dolomites may have reservoir potential. Its aerial extent and depositional environments need additional study in order to define the reservoir potential of the unit since only part of the platform type carbonates are exposed.

There are a number of potential reservoir rocks in the region varying from Paleozoic to Tertiary, and a deepening paleogeographic trend from west to east during early Paleozoic. Early Paleozoic rocks are tightly cemented and have only limited reservoir potential. The most important candidates in the Paleozoic are Carboniferous deltaic sands. A coal-bearing unit of Carboniferous has both reservoir and seal within. Aeolian sandstone of Triassic, shoreline sands of Middle Jurassic, dolomitized limestones of Late Jurassic-Earliest Cretaceous, shoreline sands of Early Cretaceous, rudistid shallow marine carbonate sands of Late Cretaceous, and shallow marine carbonate sands of Eocene are the potential reservoir rocks of the western Pontide. All these units have restriction in geometry and geographic extend. The Middle Pontide reservoir rock is limited due to the environmental conditions and tectonic evolution. The area is dominated by fine grained sediments and some fine grained turbidites. The only potential reservoir would be fractured limestones of the İnalti Formation. In the eastern Pontide, however, upper Jurassic-lower Cretaceous limestone and dolomites may have reservoir potential. Its aerial extent and depositional environments need additional study in order to define the reservoir potential of the unit since only part of the platform type carbonates are exposed.

Part of the Lower Cretaceous sediments are interpreted as shoreline (Derman, 1990) and beach to fluvial deposits (Tye et al., 2000). Absence of the unit in some wells indicates facies change and supports the idea that it was deposited along horst blocks. It is rich in quartz and interpreted as being derived from a recycled orogenic province (Tye et al., 2000). Surface samples show very high porosity values, but fresh samples taken from the core or from the surface yield porosities much lower than altered surface samples (Tye et al., 2000). The possible candidate for the source is the underlying Carboniferous deltaic sandstone. Carboniferous deltaic sands and fluvial conglomerates are also candidates for the reservoir in the region. It forms a prograding delta sequence, and the delta front channelized sandstone and delta plain fluvial sandstone may act as a good reservoir, although they have lenticular geometry.

Part of the Lower Cretaceous sediments are interpreted as shoreline<ref name=Derman_1990>Derman, A.S., 1990, Bati Karadeniz Bölgesinin Geç Jura-Erken Kretasedeki Jeolojik evrimi: Türkiye 8 Petrol Kongresi Bildiriler Kitaby, Ankara, p. 328–339.</ref> and beach to fluvial deposits. Absence of the unit in some wells indicates facies change and supports the idea that it was deposited along horst blocks. It is rich in quartz and interpreted as being derived from a recycled orogenic province. Surface samples show very high porosity values, but fresh samples taken from the core or from the surface yield porosities much lower than altered surface samples. The possible candidate for the source is the underlying Carboniferous deltaic sandstone. Carboniferous deltaic sands and fluvial conglomerates are also candidates for the reservoir in the region. It forms a prograding delta sequence, and the delta front channelized sandstone and delta plain fluvial sandstone may act as a good reservoir, although they have lenticular geometry.

==See also==

==See also==

* [[Jordan petroleum geology]]

* [[Jordan petroleum geology]]

* [[Iraq petroleum geology]]

* [[Iraq petroleum geology]]

==References==

==References==