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Hydrocarbon generation potential of shales in Hekimhan basin Eastern Anatolia Region, Turkey

Fig. 3 Stratigraphic columnar sections of the Hekimhan Formation (modified from Gürer 1992) and sampled measured sections (locations 1 and 2).

Hydrocarbon generation potential of late cretaceous shales and carbonates in Hekimhan basin and genetic relationships with Karadere oil seep (Eastern Anatolia Region, Turkey)

Abstract

In this study, Karadere oil seep (solid bitumen) and Late Cretaceous shales and carbonate levels of the Hekimhan Formation in Hekimhan Basin are compared genetically by means of organic-geochemical data. Investigated shale samples have generally low (< 0.5%) the total organic carbon values (TOC, wt%) and there is no petroleum and gas source-rock potential; however, the amount (0.11–5.92%) and type (type II–III kerogen) of organic matter within limestone are consistent for source-rock potential.

Author
Nazan Yalcin Erik

Cumhuriyet University of Depth of Geological Engineering, 58140 Sivas, Turkey
Received: 1 November 2017 / Accepted: 10 May 2018

© The Author(s) 2018

On the basis of average Tmax (433 °C) and 0.53% R0 values, the investigated samples are at the immature and early mature level for hydrocarbon generation. According to biomarker data, the bitumen is pre-Cretaceous in age, highly reducing conditions, formed in a marine depositional environment at normal salinity, and under the influence of high bacterial activity, and was originate from an immature carbonate source rock. These geochemical data are highly in agreement with the late Cretaceous limestone of the Hekimhan Formation, and these rocks may be considered the source rock of the solid bitumen.

However, these organic richness zones formed from non-indigenous organic material, and therefore, it is concluded that this seepage which generates from non-indigenous organic materials cannot be due to the limestone at the evaluated level. On the basis of organic-geochemical evaluations, it has been concluded that, in Hekimhan Basin, some hydrocarbons developed in deeper, more mature intervals of the limestone, and that these were migrated probably only a short distance within the basin and became really surfaced in relation to tension fractures.

Introduction

The restricted Turkey’s local energy resource, particularly fossil fuels in light of its growing energy claim have resulted in obedience on energy imports. At present, around 25% of the total energy demand is being met by local sources, while the rest is being supply from a different sources of imports. Turkey imports nearly 89% of its oil requirement (http://www.mta.gov.tr/). The total petroleum reserve of Turkey is approximate fourty-two million tonnes (Korkmaz et al. 2008).

Principally prolific oil fields are in the southeastern Turkey territory especially around Diyarbakır, Adıyaman, Raman and Garzan regions, and production is made from the Paleozoic and Mesozoic aged formations (Korkmaz et al. 2008). In particular, due to limited fossil energy sources of Turkey petroleum and natural gas seepages create a remarkable point for research on this subject. The aim of this study is to evaluate the solid oil seep features in Hekimhan Basin, to estimate the possible source rock, and determine the genetic relationship together with organic geochemical evaluations.

Since the early periods of oil and gas exploration activities, hydrocarbon seeps (solid or liquid) have been considered as an important clue. Although it does not always show an oil accumulation of economic value, it has been considered as a sign that requires assessment for new exploration areas (Clarke and Cleverly 1991). Hydrocarbon seep is important in following the movement of oil that is generated by the source rocks or from underground reservoir towards surface, and therefore, for the estimation of the migration route and accumulation areas. The seeps of the hydrocarbon accumulations in bigger and continuous amounts on the sedimentations that are on the surface is defined as “Active Seep-macro seeps”; and the residues that are not observable as continuous flow on the surface are defined as “Passive Seeps-micro seeps” (Abrams 1996).

Macro seeps may be monitored with petroleum, gas, bitumen traces, and asphalt; and micro seeps (such as La Brea tar pits, Los Angeles; Baku, Azerbaijan and Bermudez (Guannoco) Lake in Venezuela) may be monitored with various organic geochemical analyses and with the volatile or semi-volatile hydrocarbons or with hydrocarbon changes in the soil and sediments (Abrams 1996, 2005; van der Meer et al. 2002). For example, the Mescid-i Suleyman oil field and Gipssland Basin were discovered by making use of petroleum and gas seeps (Hunt 1996). As in this study, leaking oil can be observed in rock cracks or void fill and such residues are defined as solid bitumen (Jacob 1989).

Solid bitumen (“migrabitumen”) are secondary organic matter products that are filling voids and fractures in the rocks, and can occur within the source rocks and reservoir rocks in various basins around the world. The main reasons for their occurrence are the advanced thermal maturity and migration mechanism, mainly degradation (Curiale 1986). Many studies make it possible to better understanding to the solid bituminous origin and the thermal maturity of the sequences (Curiale 1986; Landis and Castaño 1995; George et al. 2007; Huc et al. 2000; Hwang et al. 1998; Kelemen et al. 2008, 2010; Petersen et al. 2013).

There are many important studies on the comparison of solid bitumen and source rock. For example; upper Jurassic–lower Cretaceous solid bitumen and bituminite properties of Chia Gara formation in the northern Iraq–Kurdistan region, Kirkuk oil field, were evaluated by Kus et al. (2016). The presence of oil spills and the association with solid bitumen in the cracks and spaces between the granules were stated to be a genetic relationship with the liquid hydrocarbon formation process of the Chia Gara formation. Another study was carried out by Gonçalves et al. (2015) at the sub-(Lusitanian Basin, Portugal). The middle Jurassic to Cretaceous sedimentary record in the Lusitanian Basin (Portugal) reveals the presence of disseminated solid bitumen. With the help of the results obtained by optical microscopy (fluorescence and reflection), three different solid bitumen types were identified and they corresponded to allochthonous (migrated) bitumens.

According to this research, the presence of allochthonous bitumen indicates hydrocarbon formation and / or migration movements in the Lusitanian Basin or adjacent basins. In a study by Fink et al. (2016) the solid bitumens determined in the calcite cracks in the Natih Formation limestones in the Oman Mountains have been investigated in order to evaluate the oil migration mechanisms in this area. According to study, the solid bitumen formed in multiple events and were most likely derived from the Natih B source rocks. Additionally, the asphaltic solid bitumen was identified in the pore spaces of the middle Jurassic Khatatba sandstone reservoir in the Tut Field, Egypt (Shalaby et al. 2012). Organic geochemical data indicate active non-biodegrade hydrocarbons in Khatatba sandstones. Also, biomarker data suggest that the bitumen originated from a marine shale source rock that was deposited in anoxic to suboxic conditions and the natural deasphalting is the dominant mechanism for the formation of the bitumen.

Fig. 1 Simplified geological map (modified from Gürer 1992) and location of the study area within the Anatolian Tectonic Complex, with sample locations.

Fig. 1 Simplified geological map (modified from Gürer 1992) and location of the study area within the Anatolian Tectonic Complex, with sample locations.

The investigated area located in Hekimhan Basin is between Eastern Anatolian Fault Zone (EAFZ) and Ecemiş Fault Zone (EFZ) in Eastern Anatolian Region (Fig. 1a). Bitumen was observed in the limestone, fractures–cracks and in the plaster in this area, and was defined as “Passive Seep”. This area has been named as “Karadere Oil Seep” (Fig. 1b) for the first time in this study.

Hekimhan Basin has been the subject of many comprehensive general and economic–geological studies due to its rich underground resources (especially metallic minerals). Some studies on petroleum geology were conducted by Görmüş (1992), Gürer (1992), Gürer and Aldanmaz (2002), however they were not conducted in the present study area, and examined the city of Malatya and its surroundings (Ayan 1961; Ayyıldız and Önal 2005; Önal 2009). Among these, there are no studies examining Karadere oil seep, and the source rock potentials of upper-Cretaceous carbonates around Hekimhan district of Malatya city. The clue that appeared as seep of oil, which is an indispensable energy source, stance the subject matter of this study in the form of examining the sediments that might be the source rocks in detail.

The geology of the Hekimhan basin

The investigated area is located on the Southeastern Anatolia Edgefolds of the Anatolian Tectonic complex separated by Ketin (1966), and positioned in the southern side of the Anatolids and represents nearly 1000 km2 area (Fig. 1a). The Hekimhan Basin formed as part of the northern margin of the Taurides during the collision of the Inner Tauride Ocean and the İzmir–Ankara–Erzincan ocean (Fig. 1a). The units in this area have mainly folded and fractured structure because of being influenced by Alpine Orogenesis. A constant sedimentary sequence has been loaded on the overthrusts that occurred in the Late Kimmeridge Phase of Early Alpine Orogenesis, starting from Maastrichtian until Upper Miocene begining. Campanian–Maastrichtian aged transgressive and regressive series present the common crop area (Şengör and Yılmaz 1981; Booth et al. 2014). This basin has been precipitated together with shallow marine and continental sedimentation, which is the case in the other basins of Central Anatolia, which reflects the clastic and carbonate precipitation in common. Maastrichtian sediments, which are rich in detritics, and coral reef limestone that contain rudist (Hippurites sp.) show the precipitation process of the basin in early periods (Gürer 1992).

According to the general stratigraphic properties of the study area, the Hocalıkova ophiolite, which is in the base, consists of dunite, harzburgite, pyroxenite, gabbro, spilite and pelagic sediments, and possibly originated from internal Torids Ocean on the North. This unit is obducted as improper by braided stream, deltaic Karadere formation deposited in marine, and with upper Campanien pebble–sandstone–mudstone alternation; and lateral and vertical transition with the Hekimhan Formation, which is precipitated in shelf conditions in the upper level. There are the Hasançelebi Volcanites on the upper side.

The upper-Cretaceous sequence, which progresses with Hüyük Limestone (Gürer 1992) and Zorbehan Dolomite, is in obduction position improperly in northern areas, and with Akpınar Formation, which is precipitated in shelf-lagoon depositional environment in southern areas that are as old as Paleocene–Mid-Eocene. The lower levels of the Hüyük limestone sequence have medium-thick layers, and the upper levels have multi-layers or are massive. This sequence was settled in the extremely stationary basin in tectonic terms in upper Cretaceous period, and developed in pelagic fossils rich biomicrite facies. Zorbehan Formation consists mainly of medium-thick layered dolomitic limestone. The Davulgu metamorphite was formed around the Yücesafak syenitoid, which moved towards inside of Hasancelebi Volcanites in Upper Maastrichtian.

Leylek Volcanites and the diorite in the Upper Eocene, and the Gala Marble contact diorite. The Oligocene–lower Miocene Kamatlar Formation covers all units before it with unconformity. The Katillikaya limestone precipitated in Middle Miocene, and the upper Miocene–Pliocene Yamadag volcanites, which consist of pyroclastic and lava were placed on the sequence (Gürer 1992) (Fig. 1c).

Fig. 2 Macroseeps and solid bitumen of the study area (a, b) and microseeps in petrographic thin-sections made from limestone specimens (c–f)

Fig. 2 Macroseeps and solid bitumen of the study area (a, b) and microseeps in petrographic thin-sections made from limestone specimens (c–f)

Hekimhan Formation, which has been assessed in detail in terms of source rock potential, consists of pebble with sandstones, limestone, sandstones, and sandstone–marl–shale alternation on top of them (Fig. 3a). Lenticular limestone is observed mainly in the lower levels, and olistostromal and channel filling pebbles at various levels together with clayey limestone are observed in the upper levels (Gürer 1992). The formation is extremely rich in benthic and pelagic foraminifera, rudist etc. pelecypods; and is as old as upper Cretaceous–Maastrichtian according to paleontological data (Gürer 1992). The bitumen trace in the study area is observed in the surface as flow trace and solidified bitumen in nearly 45–50 cm2 area; and in filling and cracks in nearly 1 cm fracture (Fig. 2a, b). In petrographic examinations, fracture filling and scattered microscopic bitumen traces attract attention especially in limestone samples that are close to seep area (Fig. 2c–f).

Fig. 3 Stratigraphic columnar sections of the Hekimhan Formation (modified from Gürer 1992) and sampled measured sections (locations 1 and 2).

Fig. 3 Stratigraphic columnar sections of the Hekimhan Formation (modified from Gürer 1992) and sampled measured sections (locations 1 and 2).

Materials and methods

The upper-Cretaceous Hekimhan Formation has been assessed with surface samples taken from two different locations (Fig. 2a). A total of 150 surface samples were collected at different locations from investigated area. Principally dark-grey, greenish-grey shales and alternated limestone were sampled and assessed as “Location 1” (L-1); the limestone and shales around Karadere Village were assessed as “Location 2” (L-2); and the bitumen/solidified oil on the rocks (MH-30), especially the solid bitumen scratched from the rocks, and the bitumen in the cracks of the rocks were assessed as MH-29 sample (Figs. 2b, 3b, respectively).

Rock-Eval/TOC analyses were done on 25 samples using Rock-Eval 6 instrument (Turkish Petroleum Laboratories, Ankara). The bulk mineralogical compositions and clay fraction mineralogy of samples were determined using a Rigaku DMAX IIIC X-ray diffractometry equipment (Cumhuriyet University laboratories, Sivas). Polished blocks were done from selected ten samples for organic petrographical determinations and huminite reflectance (R0) evaluation. These analyses were performed with a Leitz MPV-Spectra microscope (546 nm) using reflected white light. Also, especially in shale samples (45 samples) kerogen was isolated using Durand and Nicaise (1980)’s standard palynological preparation procedures.

Some shale and carbonaceous samples (> 0.5 TOC) were applied with solvent extraction liquid chromatography gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) analyses were done on bulk extracts obtained from four bituminous samples. The aliphatic components acquired by chromatographic fractionation were done according to ASTM (D 5307-97, 2002) by Agilent 6850 instrument. Steran and terpan ratios were computed by integration of peak highs from the m/z 217 (for steranes) and m/z 191 (for terpanes) mass fragmentograms. Biomarker analyses were done in the research laboratories of the Turkish Petroleum Corporation (TP Research Group, Ankara). Furthermore, stable carbon isotopic (δ13C) values for the samples (eight whole rock sample) were measured on homogenized portion of rock sample using GV Instruments Isoprime EA-IRMS equipment according to PDB Standard (TP, Ankara, Turkey).

Results

Organic geochemical investigations

Total organic carbon value (wt%) varies between 0.13–0.54% in the grey, greenish grey-brown shale and limestone samples that were taken from Location 1 (L-1); and is extremely low in shales (avg. 0.20%) in the unit, and relatively higher (avg. 0.30%) in the alternated limestone. The TOC values in the Location 2 (L-2), which is close to the seep area, vary between 0.11 and 0.12% in shale samples and 0.11–5.92% in limestone. As it is the case in sample MH-8 in L-1, the extractable hydrocarbon amounts are low (217 ppm) in the samples that are poor in organic matter, and extremely higher in the limestone in the L-2 (13,456–91,137 ppm) (Table 1).

Table 1 Total organic carbon (TOC, wt%), Rock-Eval pyrolysis, vitrinite reflectance and carbon isotope (δ13C) results of the investigated samples.

Table 1 Total organic carbon (TOC, wt%), Rock-Eval pyrolysis, vitrinite reflectance and carbon isotope (δ13C) results of the investigated samples.

TOC Total Organic Carbon (wt%), S1 free hydrocarbons in rock (mg HC/g rock), S2 hydrocarbon generated from the thermal breakdown of kerogen (mg HC/g rock), T max Maximum temperature of pyrolysis (°C), HI Hydrogen Index (mg HC/g TOC), OI Oxygen Index (mg CO2/g TOC), PI Production Index (S1/S1 + S2), S2/S3 Hydrocarbon Type Index, PY potential yield (S1 + S2; mg HC/g rock), Extract (ppm), B/T Bitumen/TOC ratio, δ 13 C carbon isotope value, R0 vitrinite reflectance (%)

The type of the organic matter, which is an important parameter for hydrocarbon generation potential, is determined mainly with Rock Eval pyrolysis. The hydrogen index (HI) values vary between 0 and 19 mg HC/g TOC in L-1, the oxygen index (OI) values vary between 96 and 442 mg CO2/g TOC. In L-2 samples, on the other hand, the HI is between 0 and 653 mg HC/g TOC, the OI is between 6 and 291 mgCO2/g TOC. In HI–Tmax diagram (Mukhopadhyay et al. 1995), all of the samples taken from L-1 are distributed in type III area (terrestrial, residue organic matter). The limestone samples in L-2 are observed in type II–III kerogen, which is mostly close to type II, and the shale samples are observed in type III area (Fig. 4).

Fig. 4 Distribution of Hekimhan formation samples in the HI versus Tmax diagram

Fig. 4 Distribution of Hekimhan formation samples in the HI versus Tmax diagram

This conclusion is supported by palynological investigations on kerogen slide, because of amorphous and herbaceous materials are predominant (Fig. 5a).

Fig. 5 Ternary diagrams showing organic-petrographic composition and the distribution of C2T–C28–C29 regular steranes

Fig. 5 Ternary diagrams showing organic-petrographic composition and the distribution of C2T–C28–C29 regular steranes

The Tmax value, which is used commonly to assess the sedimentary rocks in terms of organic maturation (Tissot and Welte 1984), varies between 423 and 496 °C in L-1 samples, and 416 between 474 °C in L-2 samples (Table 1). In HI–Tmax diagram, the limestone samples from L-2 are distributed in the immature-early mature, and the shale samples from L-1 are distributed in immature-mature zone (Fig. 4). The high Tmax values determined especially in L-1 might have developed due to the clay content of the samples and due to the low levels of organic matter. Since there are no samples that are S2 value > 0.2, it will not be proper to use the Tmax data for maturity assessment (Table 1) (Peters 1986; Waple 1985).

Fig. 6 Distribution of the studied samples in the Tmax versus PI diagram (Katz 1995)

Fig. 6 Distribution of the studied samples in the Tmax versus PI diagram (Katz 1995)

The clay mineral determined in 30–45% rate in especially MH-1, 2, 4, 6 and 9 samples caused the formation of high Tmax values like 450–496 °C in this sample. The production index (PI) has also been used in maturity assessments, and is higher than 0.1 in number 1 and 2 location samples; and shows mature phase (Table 1; Fig. 6); however, due to the migrated hydrocarbon existence in these samples, the PI parameter alone is not sufficient for maturity (Peters and Moldowan 1993). Generally, with the developing maturity, the bitumen/TOC ratio also increases (Tissot and Welte 1984); and the oil formation occurs between 0.05 and 0.1 range, and lower levels show immature rocks (Peters and Moldowan 1993). High bitumen/TOC ratio was determined in the limestone and organic matter rich shale samples were examined in location 2; however, low Tmax values were detected showing pollution or migrated hydrocarbon existence rather than maturity phase (Table 1; Fig. 7).

Fig. 7 Source-rock potential rating for the studied samples, based on TOC and extracted organic matter

Fig. 7 Source-rock potential rating for the studied samples, based on TOC and extracted organic matter

The huminite reflection values (R0, %) at the rate of 0.49–0.53% in the shale samples in L-1, and between 0.50 and 0.55% in the shale samples in L-2 show immature–early mature phase (Table 1). When these data are compared with the Tmax values, it is observed that low TOC value gives extremely different results from the other maturity parameters like huminite reflection and biomarker maturation data due to the hydrocarbons that are not indigenous and due to high clay content; and when the assessment is made based on one single parameter, it might produce significant mistakes.

Hydrocarbon generation potential

The S2/S3 values of the samples from L-1 are between 0 and 0.19, and the values of the samples from L-2 are between 0 and 118.6 (Table 1). It is possible to claim that the Hekimhan Formation limestone have the potential of producing oil only in L-2. The S2/S3 values are extremely low (0–0.19) in shale levels, and these samples do not have the potential of generating hydrocarbon Espitalié et al. (1985), Lafarqué et al. (1998) and Peters (1986).

The potential yield values (PY), vary between 0.0 and 49.29 mg HC/g rock. Although this value is extremely low in the samples taken from L-1, they are extremely high in the limestone in L-2 (8.76–49.29 mg HC/g rock) (Table 1). Production Index values that are higher than 0.1; low Tmax, and bimodal S2 peak when compared with the rocks in the areas. For this reason, only high HI and TOC values do not provide accurate results about the source rock potential, which is the case in these samples.

In the Tmax–PI diagram, it is observed that the samples from L-1 are immature, and distributed in hydrocarbon generation also in non-indigenous areas (Fig. 6). Due to high Tmax values, although some of the samples (MH-1, 2, 5 and 6) are observed in hydrocarbon generation areas, organic geochemical properties especially organic matter amounts and types are not proper for source rock potential. The majority of the samples from L-2 are distributed in non-indigenous hydrocarbon area, and the shales that contain less organic matter are distributed in immature and residue carbon area. The same result is also observed in TOC—total extract diagram (Fig. 7).

Especially, the organic richness levels in the samples that are examined show the non-indigenous (migrated) richness. For this reason, it is possible to claim that at least the limestone in Hekimhan formation that is sampled does not have source rock potential.

Molecular composition

The gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) and thin layer chromatography (TLC) analyses of the Karadere solid bitumen, bituminous limestone, shale and limestone samples from the Hekimhan Formation have been performed; and using the obtained data, the basic similarities and differences in terms of their origins between the bitumen and the extracts of the other samples have been defined. However, especially the alteration effects of the bitumen sample and the migrated hydrocarbon effects in the other samples have been considered during the assessments.

Isoprenoids and n-alkanes

The total extract ratio of the analyzed samples varies between 217 and 91137 ppm, and is extremely high especially in the limestone in L-2 (Table 2). Polar, asphaltene and aromatic compounds are dominant in the investigated samples, and the level of saturated hydrocarbons is relatively less (20–21.35%). Aromatic hydrocarbons are at the rate of 17–30%, and NSO + polar compounds are at the rate of 52–68%. With the atmospheric influence on the bitumen sample or with its biodegradation (water, bacteria etc.), the components in gas chromatograms are not separated completely, and “humps” have been observed formed by these non-separated components (Fig. 8).

Fig. 8 Gas chromatograms of C15+ saturated hydrocarbons in extracts from Hekimhan Formation and bitumen samples

Fig. 8 Gas chromatograms of C15+ saturated hydrocarbons in extracts from Hekimhan Formation and bitumen samples

The odd-numbered and even-numbered n-alkanes ranges between the C15 and C27, which are among the definable components, are close to each other in terms of abundance; however, the ratios have not been calculated because the peak values were not separated completely. There are n-alkanes, especially short-chain (< n-C21) and medium-chain (n-C21–n-C25) as well as long-chain n-alkanes (> n-C25) like C26 and C27, in clayey limestone (MH-14, -16 and -19). Medium-chain n-alkanes (C21, C22, C23) are abundant in the MH-14 sample when compared with the other samples, and show aquatic–seashore vegetation (Hunt 1996). The peak distribution in the biomarker area in chromatograms is at the lower maturity level when compared with Pr/Ph (0.14), Pr/n-C17 (0.39) and n-C18 (0.58) rates. It is possible to claim that there are mostly sea algae and they are influenced by oxidation. However, these parameters alone are not sufficient for interpreting about the generation and maturity characteristics especially both of early-mature and biodegraded samples (Volkman and Maxwell 1986).

Table 2 Organic geochemical results and determined parameters of solid bitumen and extracts of examined samples

Table 2 Organic geochemical results and determined parameters of solid bitumen and extracts of examined samples

Hydrocarbon generation potential of shales in Hekimhan basin Eastern Anatolia Region, Turkey

In this study, Karadere oil seep (solid bitumen) and Late Cretaceous shales and carbonate levels of the Hekimhan Formation in Hekimhan Basin are compared genetically by means of organic-geochemical data. Investigated shale samples have generally low (< 0.5%) the total organic carbon values (TOC, wt%) and there is no petroleum and gas source-rock potential; however, the amount (0.11–5.92%) and type (type II–III kerogen) of organic matter within limestone are consistent for source-rock potential.
Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo.
http://www.allaboutshale.com

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