Petroleum basins of Turkey

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Petroleum systems of the Tethyan region
Series AAPG Memoir
Chapter Petroleum systems of Turkish basins
Author Ahmet Sami (A. S.) Derman
Link Web page
Store AAPG Store
Figure 1 Tectonic map showing the continental fragments involved in the evolution of Turkey as proposed by Şengör and Yilmaz.[1] In this scheme various belts have been recognized and described which correspond to either a continental block or a suture zone that is amalgamated as a result of the Neo-Tethyan collision and which is marked by an ophiolitic suite of rocks (redrawn from Şengör and Yilmaz[1]). 300 km (186.4 mi).

Turkey is located in an area where the Eurasian and African plates collided. Due to this collision, not only European and African plates amalgamated, but also small continental fragments. These fragments, from north to south, are: 1) Rhodope-Pontide fragments, 2) Sakarya continent, 3) Anatolide-Tauride platform, and 4) Bitlis Pötürge Massifs (Figure 1). The boundaries between these fragments are still debated. The northern boundary of the Rhodope-Pontide fragments are thought to be under the Black Sea and therefore not easily observed. The southern boundary is marked by an ophiolitic belt. The boundary between the Rhodope-Pontide fragments, the Sakarya continent, and the Anatolide-Tauride platform is marked by the ophiolitic melange of the İzmir-Ankara-Erzincan Zone representing a suture zone of the northern branch of the Neo-Tethyan Ocean. The boundary between the Anatolide-Tauride platform and the Arabian plate is also marked with another ophiolitic imbricate zone representing a suture zone which formed as a result of the collision of the Anatolide-Tauride platform and the Arabian plate (Şengör and Yilmaz;[1] Yilmaz[2]). Within this framework, Turkey has seven onshore and four offshore basins of Tethyan and Tertiary origin. Most of the basins are related to and are located between and over the major suture zones of the Mesozoic and Tertiary domains of the Tethyan system.[3] Basins associated with the Tethyan domain are: 1) SE Anatolian, 2) Tauride platform area, 3) interior basins, 4) Pontide Basin, and 5) East Anatolian basins. Basins associated with Tertiary tectonics are: 1) Thrace Basin in the northeast and 2) Adana Basin in the south. Offshore basins are: 1) the Mediterranean, 2) the Aegean, 3) the sea of Marmara, and 4) the Black Sea basins (Figure 2).

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

Figure 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;[4] Perinçek and Özkaya;[5] Şengör and Yilmaz;[1] Barka and Kadinsky-Cade;[6] Perinçek;[7] Robertson;[8] Jaffey and Robertson;[9] Şengör et al.[10]).

Southeast Anatolian basin[edit]

SE Anatolian Basin is part of the Arabian plate and located at the northern margin (Figure 2). It evolved from a passive margin (in Paleozoic to early Mesozoic) to an active margin in most of the Cretaceous. During the the collision between the Arabian plate and the Anatolian plate, multiphase deformation occurred and shaped the structure of SE Anatolian Basin. The collision also created a foreland basin on the Arabian platform. Due to collision and ophiolite obduction, imbricated structures have been developed. Much of the present structures are related to these features. So far structural traps have been targeted. Stratigraphic traps are not sufficiently explored and are awaiting exploration. The majority of production is made from Mesozoic reservoirs (mainly Cretaceous), and Paleozoic reservoirs have just started production.

Source rocks[edit]

There is more than one source rock in SE Turkey. For three of them, oil to source rock correlations have been made, and for one oil to source correlation is not certain yet. Three of them are dated as Middle, Late Cretaceous, and Paleozoic. These are described from older to younger units in the following paragraphs.

The Paleozoic source rocks have been studied in 32 wells and more than 400 samples have been analyzed.[11] [12] Two levels in the Upper Ordovician (B3 and B4) and three levels in the Upper Silurian-Lower Devonian (D1, D2, and D3) are considered for analysis. TOC values are as follows:

  • B3 has six samples analyzed. TOC values vary from 0.14% to 0.38% and the mean is 0.25% ± 0.09%. This level contains type III kerogen and mean Tmax value is 455.44 °C.
  • B4 has 132 samples analyzed. TOC values vary from 0.03% to 2.98% and mean value is 0.44% ± 0.36%. It contains a mixture of type II and type III kerogen. Mean Tmax value is 444.138°C.
  • D1 has 123 samples analyzed. TOC values vary from 0.05% to 10.82% and mean value is 3.5% ± 2.55%. It contains a mixture of type II and type III kerogen. Mean Tmax value is 442.249°C.
  • D2 has 71 samples analyzed. TOC values vary from 0.13% to 13.86% and mean value is 2.13% ± 3.65%. It has a mixture of type II and type III kerogen. Mean Tmax value is 441.159°C.
  • D3 has 41 samples analyzed. TOC values vary from 0.1% to 1.34% and mean value is 0.40% ± 1.26%. D3 facies contain a mixture of type II and type III kerogen. Max Tmax value is 439.162°C (Ediger et al., 1996).

Ediger et al.[12] interpret that type II kerogen is arcritarc, bitumen, and spores, and considers that type III kerogen is not land-derived, but rather marine chitinozoans, and not terrestrial higher plant as commonly discussed. Physicochemical factors controlled and played an important role in the distribution of organic matter. Maturity increases toward the north due to the thrust loading. It has been estimated that 9 billion barrels of oil were generated.[13] [12]

Lower Cretaceous (Berriasian-Barremian) sediments are not present in the region because they were either deposited and eroded, or they were not deposited at all. In either case, an erosional topography had been created.

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.[14] [15] [16] Distribution of rich TOC values may reflect paleotopographic irregularities. Maturation is tied to thickness of the sediment due to tectonic loading under the thrust.[15] 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,[15] oil generation started in Early Miocene. Oil has migrated toward the Pre-Miocene structures.

Source rock in the second sequence is a dark muddy carbonate which was deposited in a deeper water environment as indicated by planktonic foraminiferas.[16] It also contains phosphate and glauconite together with richness in organic matter. The second sequence (member A) is probably a condensed section.[14] [16] Upward the sequence shows shallowing upward character.

Member A of the sequence has TOC values varying from 0.76% to 7.65% in the Adiyaman area.[14] 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).[14] [17] It has relatively high sulfur content.[17] 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.

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.[11]

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.[11]

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.[11]

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.

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[18] 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.[18] 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[18]).

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,[19] depending on the location within the basin.

Reservoir rocks[edit]

There are a number of producing reservoir rocks in SE Turkey. The most important are the Cretaceous carbonates. These units are carbonates and mostly mud-stones. Primary porosity is low, but the fractured nature gives the unit a relatively high permeability. Since the area is affected by Cretaceous and Miocene thrusting, fracturing was developed within the mud dominated carbonates.

The second reservoir unit is composed of carbonates of Late Cretaceous age. It is a shallowing upward unit in the northern areas, but shows a deepening upward character in the southern areas in the eastern part of the SE Anatolia.

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.

Figure 3 Chronostratihraphic chart of Thrace Basin (redrawn from Siyako[20]).

Thrace basin[edit]

The Thrace Basin is a SE-NW trending trough controlled by fault systems, and the sediment fill reaches about 9000 m (29,527 ft).[20] [21]

The basement of the Thrace Basin is composed of four to five different units (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.
  • İstanbul Paleozoic
  • Kocaeli Triassic sediments cropping out to the east of the basin.[22] [23] [24] [25] [26] [10] [21]
  • Early Cretaceous–Paleocene age Çetmi Ophiolitic Mélange[27] constituting the basement of the southern block of the NAFS in the Gallipoli Peninsula and the Mürefte–Şarköy region.[28]

Source rock, maturation, and migration[edit]

Bürkan[29] 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%.[29] [30] Bürkan[29] 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%.[29] [30] There are contrasting data on the type of kerogen. Bürkan[29] reports that all three formations have Type I and II kerogen. However, Soylu et al.[30] 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[29] 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.,[30] 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.[30] 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).

Gürgey et al.[31] 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.

Reservoir rocks[edit]

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.[32] [33] [34] [35] [7] [36] 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.[21] 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.[21]

Figure 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[37]). 10 km (6.2 mi).

Adana basin[edit]

Adana Basin is located in southern Turkey and is a Neogene Basin (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,[38] [39] by Ecemiş fault zone that lies within the Anatolian plate to the west,[40] [41] [42] [9][43] and by the Taurus Mountains to the north,[44] [45] [46] and opens into the Mediterranean Basin to the south (Figure 4). These boundaries were developed by the interaction between the African-Arabian and Anatolian plates.[6] [39] [47] [8] [42]

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.[1] [48] [49] 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.[1] [50] [51] 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[edit]

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[52] 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.[52] 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[edit]

The main reservoir rocks are the carbonates of Burdigalian age. Not all carbonates of this formation have good porosity and permeability. Locally however, there is a good leaching porosity that depends on the facies types and diagenetic history. Bulgurdaǧ field is producing from fractures of marbles within the basement and overlying carbonates. Submarine fan conglomerates and sandstones are another candidate for any oil and gas. The Tortonian sandstones may have the potential for being reservoir rocks.

Black sea basin[edit]

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 (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 (Figure 1). Offshore, there are two seeps: Çayeli (oil) and Inceburun (gas).[53] The first exploratory well (Boyabat-1) was drilled in 1960, targeting the İnalti Formation of Late Jurassic-Early Cretaceous age (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[edit]

Western and Central Pontides[edit]

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. 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. 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. The maturity level of the organic matter ranges from middle mature in general to postmature.[54] 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 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.[54]

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.[54]

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.[55] 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. 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 %. 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.[54]

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 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.[54]

Eastern Pontides[edit]

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.[54]

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[54]

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 Miocene samples have enough organic matter to be a source rock, ranging from 0.73–1.61 wt %. The HI and P2 values are between 55 and 520 mg HC/g TOC and 1040 and 8380 ppm respectively, due to low maturity in some interval. The Tmax (416–437°C) and SCI (4.5–6.0) values indicate that the unit is early mature. Relatively high HI values may be due to low maturity of organic matter. Thus, the Miocene unit has been evaluated as an immature potential source rock for oil and gas in the area.

Reservoir Rocks[edit]

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[56] 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[edit]


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