Kerogen Content Research Articles

Methods for estimating petrophysical parameters from well logs in tight oil reservoirs: a case study

Estimating petrophysical parameters from well logs plays a significant role in the exploration and development of tight oil resources, but faces challenges. What’s more, the methods for petrophysical parameters from well logs are paid little attention at present. In this paper, the typical tight oil reservoirs of Northwest China are used as an example. Based on the characteristics of mineralogy and fluids in the study field, the rock is assumed into five components which are clays, quartz and feldspar, carbonates, kerogen and pore fluids (porosity). The sum of kerogen content and porosity is defined as the apparent porosity. Then, two porosity log response equations are established. Once the clay content is determined by an individual method, the quartz and feldspar content, carbonate content and apparent porosity are calculated through the established equations. The kerogen content is the difference of the apparent porosity and porosity from nuclear magnetic resonance (NMR) logs. This paper also presents a new approach that combines the complex refractive index method (CRIM) and pseudo Archie method to compute saturation from dielectric logs, which avoids selection for the dielectric constants of each of the minerals. The effectiveness and reliability of these methods are verified by the successful application in the study of the target tight oil play in Northwest China.

NMR petrophysical interpretation method of gas shale based on core NMR experiment

Abstract Nuclear magnetic resonance (NMR) characteristics provide critical information to study the storage of organic shale. Based on NMR petrophysical experiment of Haynesville Shale, the response characteristics of transverse relaxation time ( T 2 ) are analyzed. According to the shape and amplitude of T 2 distribution of shale, Haynesville Shale can be categorized into two types: continuous and discontinuous T 2 spectrums. Compared with routine density porosity, NMR porosity is generally underestimated for organic shale. Therefore, the controlling factors are investigated in detail. Through constructing the correlations of NMR porosity and clay volume, total organic carbon (TOC) content, kerogen content and pyrite volumetric concentration, the pyrite and kerogen are finally regarded as dominant factors. Subsequently, a new NMR porosity correction model is proposed. Moreover, the permeability model based on NMR bin porosity is built, and water, gas and oil saturation models are also established through building some correlations between gas saturation and NMR bin porosity. NMR experiment indicates that the kerogen and adsorbed gas are located in bound fluid part of NMR T 2 distribution, and the gas storage is dominant as absorbed gas rather than free gas. The study provides a novel petrophysical interpretation method for gas-bearing shale.

Methodological comparison for quantitative analysis of fossil and recently derived carbon in mine soils with high content of aliphatic kerogen

In mine soil, quantification of soil organic carbon (OC) derived recently from biomass decomposition is complicated by the presence of fossil (geogenic) C derived from coal, oil shale, or similar material in the overburden. The only reliable method for such measurement is 14C analysis (i.e. radiocarbon dating) using instrumentation such as accelerator mass spectrometry, which is too expensive for routine laboratory analysis. We tested two previously used and two new methods for recent C quantification and compared them with 14C AMS radiocarbon dating as a reference using a set of soil samples (n=14) from Sokolov, Czech Republic: (i) 13C isotope ratio composition, (ii) cross polarization magic angle spinning 13C nuclear magnetic resonance (CPMAS 13C NMR) spectroscopy, (iii) near infrared spectroscopy (NIRS) coupled with partial least squares regression and (iv) Rock–Eval pyrolysis. Conventional methods for OC determination (dry combustion, wet dichromate oxidation, loss-on-ignition) were also compared to quantify any bias connected with their use. All the methods provided acceptable recent carbon estimates in the presence of mostly aliphatic fossil C from kerogen. However, the most accurate predictions were obtained with two approaches using Rock–Eval pyrolysis parameters as predictors, namely (i) S2 curve components and (ii) oxygen index (OI). The S2 curve approach is based on the lower thermal stability of recent vs. fossil organic matter. The OI approach corresponded well with 13C NMR spectra, which showed that samples rich in recent C were richer in carboxyl C and O-alkyl C. These two methods showed the greatest potential as routine methods for recent C quantification.

Nanoscale Morphology of Kerogen and In Situ Nanomechanical Properties of Green River Oil Shale

AbstractOil shale is an important energy resource that is immensely underutilized due to the cost of extraction of crude oil from oil shale as a result of limited scientific understanding of the locking of kerogen, the precursor to crude oil in the oil shale. Here, nanomechanical properties of in situ kerogen surrounded by minerals in oil shale are evaluated for the Green River Formation oil shale of Colorado Piceance Basin. Electron microscopy and energy dispersive spectroscopy experiments indicate that the sizes of kerogen-rich phases in the oil shale samples are of the scale of 10–50 nm. Comparison of nanoindentation experiments on light- and dark-colored oil shale regions indicates that light oil shale has softer regions arising from higher kerogen content. There do not appear to be significant differences between light- and dark-colored oil shale in orientation parallel and perpendicular to the bedding plane. The elastic modulus values of dark- and light-colored oil shale from nanomechanical experime...

Rock-physics templates for clay-rich source rocks

Shale source rocks are composed of various minerals, mainly smectite and illite, depending on the burial depth, and they can be described as transversely isotropic media. The “pore space” may contain kerogen, water, oil, and gas determined by the in situ conditions. A petroelastic description is based on the following: Smectite-illite transformation as a function of depth is described by a fifth-order kinetic reaction. Backus averaging to “mix” isotropic smectite and anisotropic illite is then used to obtain the elasticity constants of the mineral composing the frame. Porosity is obtained from density, and water is part of the mineral, whose elasticity constants are obtained from Gassmann equations. Oil and gas generated from kerogen are assumed to saturate the kerogen phase. The bulk modulus of the oil-gas mixture is calculated by a mesoscopic-loss model, and the stiffnesses of the kerogen/fluid mixture are obtained with the Kuster and Toksöz model, assuming that the fluid is included in a kerogen matrix. Two models are considered to obtain the seismic velocities of the shale, namely, Backus averaging and the Gassmann equation generalized to the anisotropic case with a solid pore infill. We built rock-physics templates (RPTs) containing only kerogen (immature) and kerogen plus hydrocarbons (mature). Pore-pressure effects were modeled and used as templates. We considered the Kimmeridge Shale at different depths. To model kerogen-oil and oil-gas conversions, we assumed a basin-evolution model with a constant sedimentation rate, geothermal gradient, and a first-order kinetic (Arrhenius) reaction. The detection of the hydrocarbons was investigated from RPTs, built with wave velocities, impedances, Lamé constants, density, Poisson ratio, Young modulus, and anisotropy parameters for varying kerogen content, fluid saturations, and pore pressure. Moreover, the amplitude variation with offset intercept and gradients were computed, corresponding to the seismic response of a source rock layer for varying kerogen content and fluid saturation.

Introduction to special section: Organic-rich shales

Successful exploration and production programs for organic-rich shales depend significantly on the kerogen characterization, i.e., identification of kerogen content estimation of its maturity, and prediction of kerogen with different methods. When the kerogen matures, it initially produces oil, and

A rock physics model for the characterization of organic-rich shale from elastic properties

Kerogen content and kerogen porosity play a significant role in elastic properties of organic-rich shales. We construct a rock physics model for organic-rich shales to quantify the effect of kerogen content and kerogen porosity using the Kuster and Toksoz theory and the self-consistent approximation method. Rock physics modeling results show that with the increase of kerogen content and kerogen-related porosity, the velocity and density of shales decrease, and the effect of kerogen porosity becomes more obvious only for higher kerogen content. We also find that the Poisson’s ratio of the shale is not sensitive to kerogen porosity for the case of gas saturation. Finally, for the seismic reflection responses of an organic-rich shale layer, forward modeling results indicate the fifth type AVO responses which correspond to a negative intercept and a positive gradient. The absolute values of intercept and gradient increase with kerogen content and kerogen porosity, and present predictable variations associated with velocities and density.

Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360°C) and times (12–132h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C15+ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C15+ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C15+ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131m3/m3 during bitumen generation and remain essentially constant (81–84m3/m3) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C17 and phytane/n-C18) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.

Organic matter pores and oil generation in the Tuscaloosa marine shale

The Upper Cretaceous Tuscaloosa marine shale (TMS) is an oil play across central Louisiana and southwest Mississippi. The lower TMS is characterized by relatively high log resistivity (>5 ohm-m) compared to the upper part, and this elevated resistivity zone (ERZ) has become the primary target zone. This study is to investigate the cause of variation in log resistivity based on the data of petrography, mineralogy, and organic matter property and porosity. The results suggest that log resistivity is not controlled by mineralogy or porosity; rather, it is associated with oil generation during organic matter maturation. Total organic carbon (TOC) content, Rock-Eval free hydrocarbon yield (S1), and hydrogen index (HI) in the studied core increase with depth. Porosity within organic matter (OM), measured by field-emission scanning electron microscopy (FE-SEM), is also higher within the ERZ. The correlated variations among TOC content, S1 values, OM porosity, and log resistivity suggest that the higher log resistivity resulted from in situ oil generation and that the OM pores were generated during oil generation. Thermal maturity varies little in the core; whereas the downward-increasing HI indicates an increasing abundance of oil-prone type II kerogen. Higher OM porosity appears to be related to the greater proportion of type II kerogen in the ERZ. The data set demonstrates that higher contents of TOC and oil-prone kerogen are the combined factors for higher oil generation, therefore, higher log resistivity in the ERZ. The study provides a quantitative relationship between OM porosity and oil generation.

The importance of the formation and fracture pressures for the selection of the depths for casing setting in Slovakia

The successful development of shale gas requires a fundamental understanding of shales and that can be challenging because these rocks vary significantly. For recoverable shale gas resources assessment a broad range of geological, geochemical, geophysical and geomechanical data is required. Information about the variable lithologies, mineralogies, and kerogen content is vital to locate favorable intervals for gas production. Knowledge of the in-situ stresses and porosity of these intervals is essential for developing hydraulic fracturing strategies to recover the gas in place. Geomechanical properties of shales are important in terms of determination of the likelihood of fractures initiating and propagating in shale materials. Geomechanical properties of rock include: Poisson's Ratio, Total Minimum Horizontal Stress, Bulk, Young and Shear Modulus. These properties play significant role in developing shale assets. Having access to geomechanical data can assist engineers and geoscientists during geomechanical modeling, hydraulic fracture treatment design and in some cases during reservoir modeling in shale gas fields. This paper is intended to give characterization of geomechanical properties of shale rock. It then refers to a case study of Baltic Basin of shale gas in Poland, for discussing it geological condition and rock properties.

Strengthening the applicability of self-heating retorting process to oil shale via co-retorting

Recently a facile low-energy-input retorting route but without marked loss in the shale-oil yield is developed, which is achieved by a self-heating effect, that is, spontaneously increasing retorting temperature in the absence of external heat provision (Guo et al., 2013, 2014). In this work, the applicability of self-heating retorting (SHR) process to three Chinese oil shales from different places (i.e., Longkou, Huadian and Fushun) is studied. Of these three oil shales, Fushun oil shale is associated with coal and was previously abandoned during coal mining due to its not high kerogen or oil content. The results show that it’s hard for Fushun oil shale to obtain satisfying self-heating effect, while Longkou or Huadian oil shale with higher kerogen or oil content shows satisfactory SHR. However, by adding suitable amounts of Longkou or Huadian oil shale into Fushun oil shale, a satisfying self-heating effect can be obtained as well. Thus, the relatively low-grade Fushun oil shale can also be well utilized to produce shale oil via this facile SHR route. Moreover, to utilize Fushun oil shale with a greener SHR process, the process can be performed by co-retorting Fushun oil shale with pine needles, a kind of renewable biomass. This finding also provides a new starting point for exploring plentiful biomass resources to utilize low-grade oil shale to produce oil in the future work.

Sensitivity of the elastic anisotropy and seismic reflection amplitude of the Eagle Ford Shale to the presence of kerogen

ABSTRACTThe Eagle Ford Shale of Central and South Texas is currently of great interest for oil and gas exploration and production. Laboratory studies show that the Eagle Ford Shale is anisotropic, with a correlation between anisotropy and total organic carbon. Organic materials are usually more compliant than other minerals present in organic‐rich shales, and their shapes and distribution are usually anisotropic. This makes organic materials an important source of anisotropy in organic‐rich shales. Neglecting shale anisotropy may lead to incorrect estimates of rock and fluid properties derived from inversion of amplitude versus offset seismic data. Organic materials have a significant effect on the PP and PS reflection amplitudes from the Austin Chalk/Upper Eagle Ford interface, the Upper Eagle Ford/Lower Eagle Ford interface, and the Lower Eagle Ford/Buda Limestone interface. The higher kerogen content of the Lower Eagle Ford compared with that of the Upper Eagle Ford leads to a negative PP reflection amplitude that dims with offset, whereas the PS reflection coefficient increases in magnitude with increasing offset. The PP and PS reflection coefficients at the Austin Chalk/Upper Eagle Ford interface, the Upper Eagle Ford/Lower Eagle Ford interface, and the Lower Eagle Ford/Buda Limestone interface all increase in magnitude with increasing volume fraction of kerogen.

Sorption of methane, ethane, propane, butane, carbon dioxide, and nitrogen on kerogen

Sorption isotherms of nitrogen, methane (in the pressure range of 0.1–40 MPa), ethane (0.1–3.7MPa), propane (0.01–1 MPa), butane (0.01–0.2 MPa), and carbon dioxide (0.1–6 MPa) are measured on two adsorbents with kerogen contents of 16 and 75% at temperatures of 303, 323, 343 K. Adsorption volumes are calculated for all adsorption systems using two independent methods. The BET technique is used to determine the surface area values of the two adsorbents on the basis of sorption data for ethane, propane, butane, and carbon dioxide. The initial and isosteric adheat of sorption values are calculated on the basis of sorption isotherms of ethane, propane, butane, carbon dioxide measured at three temperatures. It is found from comparing the dependences of isosteric heat of sorption on the two adsorbents that molecules of the above gases diffuse into its bulk (adsorbent 2) in addition to sorbing on the outside surface formed by kerogen molecules, while sorption of the same gases on the rock (adsorbent 1) is similar to sorption on a smooth hard adsorbent surface.

Shale-gas reservoir-prediction study in Daanzhai, Eastern Sichuan Basin

In recent years, the economic viability of large-scale shale-gas exploration and development projects has been impacted directly by improvements in horizontal-well drilling and hydraulic-fracturing technologies. However, results from multiple shale-gas projects indicate that accurate reservoir descriptions and resulting predictions of sweet spots are also crucial to maximize production from those projects. Accurate reservoir description results in the most appropriate placement of well locations and trajectories, hydraulic-fracture design, and reservoir engineering. The successful experience in shale-gas exploration and development outside China can aid in the search for the most favorable geologic characteristics and rock-physical properties and the examination of appropriate well-log interpretation and seismic-reservoir-prediction technologies for a shale-gas study in the eastern area of Sichuan Basin, China. Favorable parameters in a shale-gas reservoir are mid- to high kerogen content, low clay volumes, high brittleness, high effective porosity, and high permeability, along with well-developed microfractures. Of those parameters, mid- to high total organic carbon (TOC) is favorable for shale-gas accumulation, and high brittleness is beneficial to hydraulic-fracture propagation. Hence, the aim is to find sweet spots with high TOC and high brittleness. Starting with petrophysical analyses that combine laboratory measurements, core data, and well logs, a statistical model is used to estimate relative volumes and compositions of TOC and minerals and to establish a qualitative evaluation criterion for shale-gas reservoirs in this area. Petrophysical modeling and rock-property analyses establish the relationship among petrophysical properties (such as TOC, effective porosity, and gas saturation) and elastic properties (such as P-impedance, VP/VS ratio, Poisson's ratio, and Young's modulus) of the formation, which are related to brittleness. Rock-property analysis, prestack simultaneous inversion, and facies-fluid probability-analysis technologies help to predict favorable development zones for the shale-gas reservoir. Finally, the values of brittleness, TOC, and shale-gas lithology volume are combined to predict the sweet spots of the gas shale and to guide subsequent developments.

Литолого - геофизические свойства сланцевых пород с повышенным содержание керогена

The key features of unconventional shale hydrocarbon accumulations include the following: a) all source rocks act as low permeability oil and gas res-ervoir rocks requiring no cover rock; b) effective pore space is distributed within the bulk of mature kerogen resulting from katagenetic transformations in organic material. Evaluating the properties of reservoir rocks with a high content of kerogen attracts a lot of interest due to new approaches to unconven-tional hydrocarbon exploration and the challenge of applying the technology of hydraulic fracturing in low-permeability formations. This research into the lithological and physical properties of facies with a high kerogen content was prompted by a correlation between the sedimentary features of the proven productive shale formations and similar formations of different ages in the Dnieper-Donets basin. The sedimen-tary conditions of shale formation in DDb being similar to those of forming oil and gas producing shales with a high content of kerogen in Utica/Point Pleasant paleobasins, the highest kerogen content was assumed to be associated with certain lithotypes holding interest for further study. Mathematical equations were derived to describe the correlation between radioactivity, uranium content, bulk density, electrical resistivity and organic carbon content for shales from the Utica formation and the DDb shales. There were clarified mathematical dependences of bulk density on organic carbon content for a number of Lower Carboniferous formations in DDb. As using separate mathematical expressions is likely to pro-duce results of doubtful validity, preference should be given to a system of equations to describe the nature of changes in different physical prop-erties of shales depending on the organic component content. That will provide accurate data on the share of kerogen in the studied reservoir rocks. Values of hydrogen and oxygen indices only predict low molecular weight products and their subsequent extraction. The findings on the lithological properties and mathematical relationships have been reported and discussed at international conferences.

Петрофізичні передумови оцінки вмісту керогену в гірських породах за даними промислової геофізики

Петрофізичні передумови оцінки вмісту керогену в гірських породах за даними промислової геофізики

Mechanical properties of shale-gas reservoir rocks — Part 1: Static and dynamic elastic properties and anisotropy

Understanding the controls on the elastic properties of reservoir rocks is crucial for exploration and successful production from hydrocarbon reservoirs. We studied the static and dynamic elastic properties of shale gas reservoir rocks from Barnett, Haynesville, Eagle Ford, and Fort St. John shales through laboratory experiments. The elastic properties of these rocks vary significantly between reservoirs (and within a reservoir) due to the wide variety of material composition and microstructures exhibited by these organic-rich shales. The static (Young’s modulus) and dynamic (P- and S-wave moduli) elastic parameters generally decrease monotonically with the clay plus kerogen content. The variation of the elastic moduli can be explained in terms of the Voigt and Reuss limits predicted by end-member components. However, the elastic properties of the shales are strongly anisotropic and the degree of anisotropy was found to correlate with the amount of clay and organic content as well as the shale fabric. We also found that the first-loading static modulus was, on average, approximately 20% lower than the unloading/reloading static modulus. Because the unloading/reloading static modulus compares quite well to the dynamic modulus in the rocks studied, comparing static and dynamic moduli can vary considerably depending on which static modulus is used.

Rock-physics model for unconventional shales

An analytic model was adopted to calculate bedding-normal, dry elastic moduli of rocks enriched with solid organic matter — kerogen. Elastic stiffnesses in the model are functions of solid matrix moduli, total porosity, pore-shape factor, and crack density. Crack density is taken to be an exponential decay function of stress, which was calibrated using ultrasonic core measurements, whereas pore-shape factor was calibrated using sonic logs. Bedding-normal, fluid-saturated moduli were computed by means of Gassmann's equation, i.e., ignoring anisotropy. As a result, a model to calculate elastic moduli of organic shales was constructed and used for sonic-velocity prediction and pore-pressure calibration. Among other things, the model established the fact that the saturating fluid effect on elastic properties in organic shales can be noticeable, especially at extremely low effective stress. However, it is the kerogen content that is largely responsible for the anomalous deviation of log data points from conventional shale trend toward the hydrocarbon-charged sandstone trend in the acoustic- versus shear-impedance (AI–SI) domain.

The Potential of Eocene Shale of Nanggulan Formation as a Hydrocarbon Source Rock

DOI: 10.17014/ijog.v8i1.152In western Indonesia, Eocene shale is generally considered as a potential source rock. The Nanggulan Formation outcropping at Kulonprogo Yogyakarta consists of a shale interval of Eocene in age. Analysis of its organic material content, kerogen type, and maturity level were conducted to know its potential. The laboratory analysis of eleven samples were done to measure its TOC content. Samples with TOC > 0.5% then were analyzed to measure its Rv and TAI. Maturity level was also calculated by TTI from burial history model. The result of analysis shows there are various TOC contents and seven samples of them are categorized into a good-excellent class (TOC > 1%). Kerogen content of those samples is type III (non fluorescene amorphous-humic kerogen). One sample has a good indication of hydrocarbon formation (PY = 9.0 mg HC/g rock). Unfortunately thermal maturity level of the samples is immature (highest Rv 0.39, Tmax 422oC, and TAI 2). Otherwise, TTI calculation result from subsurface burial history modelling indicates that some areas are mature having reached gas window since 0.4 mya, especially in the area which had been influenced by a volcanic intrusion at Oligocene (28.5 mya). Therefore, the Nanggulan Formation shale has a potential capacity as a source rock with some limitation in maturity level.

Organic geochemistry of the Lower Cretaceous black shales and oil seep in the Sinop Basin, Northern Turkey: An oil–source rock correlation study

In the Sinop Basin, a thick Liassic to Quaternary sedimentary section is exposed. A Lower Cretaceous-aged Çağlayan Formation crops out in the basin and consists of claystone, siltstone, sandstone, marl, and black-coloured shale that exhibits a fair to good source rock potential. An oil seep from the Çağlayan Formation is located in the Ekinveren region of the Sinop Basin.The average total organic carbon (TOC) values of two shale samples from the Çağlayan Formation in the Ekinveren and the Bürnük sections (Ekin-8, Bür-7) are 1.48 and 1.26 wt.%, respectively, and the hydrogen index (HI) values are 190 and 244 mgHC/g TOC, respectively. The potential yield (PY) value of the samples is >2.0 mgHC/g rock, which indicates fair–good hydrocarbon potential for the Çağlayan Formation.A unimodal n-alkane distribution with dominant light-end components is observed on the gas chromatograms of the shale samples from the Çağlayan Formation. Low TAR (terrigenous/aquatic organic matter ratios), low (C19 + C20)/C23 tricyclic terpane ratios and a higher type II kerogen content indicate that the shale samples predominantly contain marine organic matter. The Pr/Ph ratios of the shale samples are 1.39 and 0.89, respectively. The Pr/Ph values in combination with a high C30∗ diahopane/C29Ts ratio imply a suboxic–anoxic depositional environment for the Çağlayan Formation.The Tmax values of the Ekinveren and Bürnük shale samples are in the range of 425–432 °C and 431–434 °C, respectively, and the average Tmax values are 429 °C and 433 °C, respectively. Based on the Tmax data, the Çağlayan Formation shales are immature–early mature in the Ekinveren location and early mature–mature in the Bürnük location. The CPI values, isoprenoid/n-alkane ratio, 20S/(20S + 20R), ββ/(ββ + αα) C29 sterane and 22S/(22S + 22R) C32 homohopane ratios indicate that the shales from the Bürnük location are more mature than those of the Ekinveren location. The large UCM (unresolved complex mixture) and low amounts of n-alkanes and isoprenoid alkanes observed in the gas chromatogram of the oil seep indicate that the oil has been heavily biodegraded.The m/z 191 and m/z 127 mass chromatograms of the samples from the Çağlayan Formation and the Ekinveren oil seep were similar in their distributions of tricyclic terpane (C23 dominant), C24 tetracyclic terpane, norhopane, hopane, homohopane (with dominant C31 and a decreasing amount of the higher number homologues), diasterane and pregnane. The C27, C28, and C29 sterane distributions for the oil and the shale samples were also similar, demonstrating a C27 > C29 > C28 relationship.Thus, the biomarker data strongly indicate that the black shales and the Ekinveren oil seep are related to each other. In other words, the oil has been derived from the Çağlayan Formation.