Measured Vitrinite Reflectance Values Research Articles

1D basin modeling and hydrocarbon generation potential of the Late Carboniferous Limburg Group formations, Northwest European Basin, Netherlands

The Carboniferous rock samples of the Limburg Group formations were studied to investigate the source rock characteristics and the hydrocarbon generative potential. The source rock samples have been collected representing four rock units from three different wells. These samples were analyzed using Rock-Eval pyrolysis results and measured vitrinite reflectance values, and also by generating a one-dimensional basin model of K1 Field. The total organic carbon in these samples varies from 0.31 to 83.56% with a mean of 37.68%, suggesting that Limburg Group formations have excellent potential as a source of hydrocarbons. Kerogen in the Limburg Group formations is type II-III and type III, generate gas prominently. The outcomes of thermal maturation by Tmax and measured vitrinite reflectance reveal that the examined Limburg source rocks are located in the mature zone. The burial and thermal history models show irregular trend patterns due to uplift, erosion, and non-deposition events that took place in the K1 field (where the structural element is Cleaver Bank High). For the Maurits Formation, the oil generation took place at 2011 m at 230.1Ma ago and the top of the gas window was encountered 217.8Ma ago at 2535 m, whereas for the Hospital Ground Formation, the top of the oil window was encountered 186.8Ma ago at 2404 m and the gas generation took place at 2404 m at 161.9Ma ago.

A maturation scale for molecular simulation of kerogen thermal degradation

Correlating molecular dynamics (MD) simulations of thermal degradation of organic matter with natural processes in ancient sediments is vital for revealing the mechanisms of hydrocarbon generation at molecular and atomic levels. This study establishes a practical maturation scale for molecular modeling of the thermal degradation of kerogen. ReaxFF reactive MD simulations of the thermal evolution of typical kerogen types (Type I, II, and III) were carried out at temperatures ranging from 1200 K to 2600 K. The results demonstrate that the H/C and O/C atomic ratios of kerogen molecules decrease as simulation temperatures increase and that the evolutionary paths of the three kerogen types fit well with those shown in the van Krevelen diagram. The corrected activation energies of pyrolysis for these three typical kerogen types were found to be 61.1 kcal/mol, 53.5 kcal/mol and 52.8 kcal/mol, respectively, consistent with those obtained from both laboratory simulations and basin modeling. By comparison with the relationships between measured vitrinite reflectance values and the H/C atomic ratios of kerogen samples reported in the literature, a quantitative relationship was established between the vitrinite reflectance (%Ro) values of kerogen and simulation temperatures (T). The cross-plots of T vs %Ro for kerogen types II and III show that vitrinite reflectance exponentially increases with increasing simulation temperature. Two logarithmic correlation equations were constructed to match geological maturation levels to the corresponding levels in MD simulations of thermal degradation of types II and III kerogen. These maturation scales are generally in line with the simulation temperatures set for thermal degradation in kerogen pyrolysis in previous studies. This work has promising practical implications for research on the thermal evolution behavior of ancient sedimentary organic matter using ReaxFF MD simulation.

Geochemical characterization of Neogene sediments from onshore West Baram Delta Province, Sarawak: paleoenvironment, source input and thermal maturity

AbstractThe Neogene strata of the onshore West Baram Province of NW Borneo contain organic rich rock formations particularly within the Sarawak basin. This basin is a proven prolific oil and gas province, thus has been a subject of great interest to characterise the nature of the organic source input and depositional environment conditions as well as thermal maturation. This study is performed on outcrop samples of Lambir, Miri and Tukau formations, which are of stratigraphic equivalence to the petroleum bearing cycles of the offshore West Baram delta province in Sarawak. The investigated mudstone samples are organic rich with a total organic carbon (TOC) content of more than 1.0 wt.%. The integration of elemental and molecular analyses indicates that there is no significant variation in the source input between these formations. The investigated biomarkers parameters achieved from acyclic isoprenoids, terpanes and steranes biomarkers of a saturated hydrocarbon biomarkers revealed that these sediments contain high contribution of land plants with minor marine organic matter input that was deposited and preserved under relatively oxic to suboxic conditions. This is further supported by low total sulphur (TS), high TOC/TN ratios, source and redox sensitive trace elements (V, Ni, Cr, Co and Mo) concentrations and their ratios, which suggest terrigenous source input deposited under oxic to suboxic conditions. Based on the analysed biomarker thermal maturity indicators, it may be deduced that the studied sediments are yet to enter the maturity stage for hydrocarbon generation, which is also supported by measured vitrinite reflectance values of 0.39-0.48% R

MATURITY AND PETROLEUM SYSTEMS MODELLING IN THE OFFSHORE ZAMBEZI DELTA DEPRESSION AND ANGOCHE BASIN, NORTHERN MOZAMBIQUE

Petroleum systems analysis and maturity modelling is used to predict the timing and locations of hydrocarbon generation in the underexplored offshore Zambezi Delta depression and Angoche basin, northern Mozambique. Model inputs include available geological, geochemical and geophysical data. Based on recent plate‐tectonic reconstructions and regional correlations, the presence of Valanginian and Middle and/or Late Jurassic marine source rock is proposed in the study area.The stratigraphy of the Mozambique margin was interpreted along reflection seismic lines and tied to four wells in the Zambezi Delta depression. Thermal maturity was calibrated against measured vitrinite reflectance values from these four wells. Four 1‐D models with calibration data were constructed, together with another five without calibration data at pseudo‐well locations, and indicate the maturity of possible source rocks in the Zambezi Delta depressions and Angoche basin. Two 2‐D petroleum systems models, constrained by seismic reflection data, depict the burial history and maturity evolution of the Zambezi Delta basin. With the exception of the deeply‐buried centre of the Zambezi Delta depression where potential Jurassic and Lower Cretaceous source rocks were found to be overmature for both oil and gas, modelling showed that potential source rocks in the remaining parts of the study area are mature for hydrocarbon generation.In both the Zambezi Delta depression and Angoche basin, indications for natural gas may be explained by early maturation of oil‐prone source rocks and secondary oil cracking, which likely began in the Early Cretaceous. In distal parts of the Angoche basin, however, the proposed source rocks remain in the oil window.

Petrographic characteristics and palaeoenvironment of the Permian coal resources of the Barapukuria and Dighipara Basins, Bangladesh

Abstract Twenty-seven coal samples from the Barapukuria and Dighipara Coal Basins of Bangladesh were analysed for their maceral content, petrographic characteristics and vitrinite reflectance. The most predominant maceral was the inertinite group (mean 40%), followed by vitrinite (mean 31%) and liptinite (mean 22%), with considerable amounts of mineral matter (mean 7%). Semifusinite, fusinite and inertodetrinite were the most common macerals of the inertinite group. Collotelinite, collodetrinite and vitrodetrinite were the most frequently found macerals of the vitrinite group, while sporinite and cutinite were the most common in the liptinite group. Clay minerals occurred in higher concentrations than other minerals. The measured vitrinite reflectance values (%Ro) ranged from 0.71 to 0.80, indicating a high volatile bituminous B ranking. Facies modelling using maceral composition and maceral indices suggested an environment of forest swamps with alternating oxic–anoxic depositional conditions. Microlithotype-dependent depositional modelling indicated evolution in limno-telmatic zones under fluvio-lacustrine control, accompanied by the development of upper to lower deltaic plain conditions. A terrestrial origin with dry forest to piedmont plain conditions was suggested by the Gelification Index (GI) and Tissue Preservation Index (TPI). The lateral variation of the measured TPI values indicated an increase in the rate of basin subsidence. A cross-plot of the Ground Water Index (GWI) vs. the Vegetation Index (VI) suggested mires under ombotrophic to mesotrophic hydrogeological conditions containing herbaceous plants.

Vitrinite reflectance gradients of deep wells with thick chalk sections and high pressure: Implications for source rock maturation, Danish–Norwegian Central Graben, North Sea

Nine deep wells (TD from 4793 to 5903 m) drilled with Jurassic syn-rift targets in the Danish-Norwegian Central Graben show abnormal vitrinite reflectance (VR) profiles. They all penetrated thick (up to 950 m) post-rift Upper Cretaceous chalk sections and about 3000 m of Cenozoic mudstone-dominated sediments. The penetrated strata in the wells are further characterised by high fluid pressures (overpressure) in the thick sections of Upper Jurassic–lowermost Cretaceous mudstones forming the principal source rocks in the area. The overpressure in the Jurassic sandstone reservoir target may attain a value of about 50 MPa. The wells display overall the same VR profiles characterised by three VR segments: (i) a more or less well-defined increase in VR through the Cenozoic to the top of the Upper Cretaceous chalk, (ii) an interpolated lower VR gradient through the chalk section, and (iii) a likewise well-defined increase in VR from the base of the chalk and through the Upper Jurassic–lowermost Cretaceous mudstones, but with a higher gradient than determined for the Cenozoic strata. The VR values at the top of the source rock section are much lower than expected indicating that maturation is significantly retarded. The lower VR values are determined by two factors: (i) the high thermal conductivity of chalk accounts for the interpolated lower VR gradients in the thick chalk sections, while the higher VR gradients and the higher geothermal gradients in the Upper Jurassic–lowermost Cretaceous source rock mudstones agree with the low thermal conductivity of mudstone, and (ii) the thick sections of overpressured mudstones serve as insulator for the overlying chalk and retard source rock maturation as excessive pressure can prevent liquid and gaseous generation products to escape the source rock and thereby preventing the condensation and reorganisation of the organic matter, which is necessary to increase maturity. Indirect evidence of the effect of excessive pressure comes from maturity modelling of the measured VR values in the Danish Hejre-1 well using the Easy%R o and PresR o models, the latter incorporating pressure. Calibrated with measured present day pressures the PresR o model is able to predict the measured VR values, and thus the maturity gradient, and predicts the source rock interval in the well to be in the middle of the oil window even at a depth of 5000 m. Hence, as a consequence of the irregular maturity trends the Upper Jurassic – lowermost Cretaceous source rocks are of lower thermal maturity than expected and if the top of the oil window is set at a VR of 0.6%R o the decreased maturation results in a downward displacement of the top of the oil window of up to approximately 200–350 m. ► Thick chalk sections and overpressure in the source rocks affects thermal maturation. ► Irregular vitrinite reflectance gradients with three segments are the result. ► The oil window is downward displaced about 200–350 m. ► Pressure must be included in order to model thermal maturity correctly.

Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems

A series of methane (CH4) adsorption experiments on bulk organic rich shales and their isolated kerogens were conducted at 35°C, 50°C and 65°C and CH4 pressure of up to 15MPa under dry conditions. Samples from the Eocene Green River Formation, Devonian–Mississippian Woodford Shale and Upper Cretaceous Cameo coal were studied to examine how differences in organic matter type affect natural gas adsorption. Vitrinite reflectance values of these samples ranged from 0.56–0.58%Ro. In addition, thermal maturity effects were determined on three Mississippian Barnett Shale samples with measured vitrinite reflectance values of 0.58, 0.81 and 2.01%Ro.For all bulk and isolated kerogen samples, the total amount of methane adsorbed was directly proportional to the total organic carbon (TOC) content of the sample and the average maximum amount of gas sorption was 1.36mmol of methane per gram of TOC. These results indicate that sorption on organic matter plays a critical role in shale-gas storage. Under the experimental conditions, differences in thermal maturity showed no significant effect on the total amount of gas sorbed. Experimental sorption isotherms could be fitted with good accuracy by the Langmuir function by adjusting the Langmuir pressure (PL) and maximum sorption capacity (Γmax). The lowest maturity sample (%Ro=0.56) displayed a Langmuir pressure (PL) of 5.15MPa, significantly larger than the 2.33MPa observed for the highest maturity (%Ro>2.01) sample at 50°C.The value of the Langmuir pressure (PL) changes with kerogen type in the following sequence: type I>type II>type III. The thermodynamic parameters of CH4 adsorption on organic rich shales were determined based on the experimental CH4 isotherms. For the adsorption of CH4 on organic rich shales and their isolated kerogen, the heat of adsorption (q) and the standard entropy (Δs0) range from 7.3–28.0kJ/mol and from −36.2 to −92.2J/mol/K, respectively.

Source rock potential of selected Cretaceous shales, Orange Basin, South Africa

Twenty Cretaceous shale samples from two wells in the Orange Basin of South Africa were evaluated for their source rock potential. They were sampled from within a 1400 m-thick sequence in boreholes drilled through Lower to Upper Cretaceous sediments. The samples exhibit total organic carbon (TOC) content of 1.06–2.17%; Rock-Eval S2 values of 0.08–2.27 mg HC/g; and petroleum source potential (SP), which is the sum of S1 and S2, of 0.10–2.61 mg HC/g, all indicating the presence of poor to fair hydrocarbon generative potential. Hydrogen index (HI) values vary from 7 to 128 mg HC/g organic carbon and oxygen index (OI) ranges from 37 to 195 mg CO2/g organic carbon, indicating predominantly Type III kerogen with perhaps minor amounts of Type IV kerogen. The maturity of the samples, as indicated by T max values of 428–446°C, ranges from immature to thermally mature with respect to oil generation. Measured vitrinite reflectance values (%Ro) of representative samples indicate that these samples vary from immature to mature, consistent with the thermal alteration index (TAI) (spore colour) and fluorescence data for these samples. Organic petrographic analysis also shows that amorphous organic matter is dominant in these samples. Framboidal pyrite is abundant and may be indicative of a marine influence during deposition. Although our Rock-Eval pyrolysis data indicate that gas-prone source rocks are prevalent in this part of the Orange Basin, the geochemical characteristics of samples from an Aptian unit at 3318 m in one of the wells suggest that better quality source rocks may exist deeper, in more distal depositional parts of the basin.

Hydrocarbon potential of the Barnett Shale (Mississippian), Delaware Basin, west Texas and southeastern New Mexico

The Barnett Shale (Mississippian) in the Delaware Basin has the potential to be a prolific gas producer. The shale is organic rich and thermally mature over large parts of the basin. Depths to the Barnett range from 7000 ft (2133 m) along the western edge of the basin to more than 18,000 ft (5486 m) along the basin axis. The Barnett Shale began generating petroleum about 250 Ma and reached its maximum temperature about 260 Ma. Present-day thermal maturity is indicative of maximum burial and temperature. Wells in northern Reeves County are in the gas window based on measured vitrinite reflectance values and kerogen transformation ratios. The shale can be divided into an upper clastic unit and a lower limy unit by changes in resistivity. The lower unit can be subdivided into five subunits by distinctive well-log markers. Preliminary analyses suggest that intervals in the lower Barnett marked by high resistivity and high neutron porosity readings on well logs have high gas contents. Areas in which to focus the future exploration in the lower Barnett can be delineated by mapping a net resistivity greater than 50 ohm m. The Barnett Shale contains significant gas resources in the Delaware Basin. Realizing the potential of these resources depends on the current efforts to optimize drilling and completion techniques for this shale-gas play.

DETERMINATION OF THE TEMPERATURE HISTORY FOR THE U THONG OILFIELD AREA (SUPHAN BURI BASIN, CENTRAL THAILAND) USING A REALISTIC SURFACE TEMPERATURE

The temperature history for the BPI‐W2 well in the oil‐producing Suphan Buri Basin, central Thailand, has been investigated using different surface temperatures (Ts). Two ID models using Ts values of 0°C and ∼22°C were able to fit the suppression‐corrected vitrinite reflectance (VR) values and burial peak temperatures (Tpeak) in the well. The geothermal gradient averaged over 3 km is ∼54°C/km for Ts= 0°C, whereas it is ∼42°C/km for Ts∼22°C. Ts= 0°C is, however, considered to be unrealistic and the ∼54°C/km gradient is therefore too high. Similarly, a previously determined geothermal gradient of 62°C/km is considered to be an overestimate. The geothermal gradient of ∼42°C/km is plausible compared to other geothermal gradients onshore and offshore Thailand, although it is at the low end. This may be due to a too low suppression correction for the measured VR values. The obtained temperature history can be used to predict measured present‐day temperatures of Ts∼22°C and 77°C in the reservoir in the U Thong oilfield. The obtained temperature history associated with the geothermal gradient of ∼42°C/km seems realistic as it predicts that the onset of oil generation at 107°C will have post‐dated reservoir and trap formation in Middle to Late Miocene times.

Aromatic hydrocarbon biomarkers in terrestrial organic matter of Devonian to Permian age

This paper presents the results of a detailed study on the occurrence and distribution of alkylnaphthalenes and alkylphenanthrenes in 39 coal and sediment samples from the Late Palaeozoic containing predominantly terrestrial organic matter. Most of the samples represent the Euramerian flora realm and originate from locations beyond the Variscan front in Eastern, Northern and Central Europe, i.e. especially England and the Moscow Basin. The samples are of relatively low maturity (0.32 to 1.80% R r) and consist mainly of mixtures of type III and II kerogen. Quantification of the C 0- to C 4-naphthalenes and the C 0- to C 4-phenanthrenes showed that these compound classes were highly abundant in all samples. Aromatic hydrocarbon maturity parameters in general are in good agreement with measured vitrinite reflectance values. 1,2,7-Trimethylnaphthalene, an assumed diagenetic product of oleanane type biomarkers was present in all investigated samples. This observation provides evidence that oleanane type lipids were biosynthesised by organisms predating the evolution of angiosperms or that assumed formation pathways for 1,2,7-trimethylnaphthalene are insecure. 1,2,8-Trimethylphenanthrene was significantly enriched in samples from the Permian and the one sample from the Devonian investigated in this study. The precursor(s) of 1,2,8-trimethylphenanthrene therefore may have been produced by organisms which were least abundant in the Carboniferous depositional environments represented by our samples.

Fluorescing macerals in South African coals

Maceral, microlithotype and fluorescing maceral content were analysed along with the vitrinite relative fluorescence measurements. Thirty samples from the South Africa Soutpansberg, Waterberg and Main Karoo Basins were investigated. These results were also compared with previously measured vitrinite reflectance values. The application of fluorescence techniques has allowed the identification of much higher liptinite content (about 5%) as compared with the results of routine maceral analysis in white light. Results presented provide an explanation of this difference, which is caused by difficulties in identifying fine liptodetrinite particles under illumination by the halogen lamp. Therefore, detritic particles of uncertain affinity should be verified under fluorescing light during routine maceral analysis. The presence and intensity of the fluorescing vitrinite in South African coals were also studied. The occurrence of this component is connected with the rank of coal but could be also affected by the facies (sample no. B 35) and in situ coal oxidation (sample no. B 3). The relative fluorescence intensity of vitrinite depends on the rank of the coal but also on its degree of oxidation. It seems also to be connected with the expulsion of oil which enhances its intensity. The influence of the fluorescing macerals content on some coal properties was proved by the positive correlation between fluorescing vitrinite as well as sum of fluorescing macerals and calorific value (0.66 and 0.74 corr. coeff., respectively). This proves the necessity of fluorescence application in routine maceral analysis carried out for coal quality evaluation.

SUPPRESSION AND RETARDATION OF VITRINITE REFLECTANCE, PART 2. DERIVATION AND TESTING OF A KINETIC MODEL FOR SUPPRESSION

The presence of suppressed and retarded vitrinite reflectance (VR) data introduces a number of dificulties into the prediction of hydrocarbon generation in sedimentary basins. Although the effects of suppression can be removed from measured VR values manually, a kinetic model for suppressed vitrinite maturation would enable both suppressed and unsuppressed VR values to be predicted using thermal histories derived from basin modelling. The evaluation of hydrocarbon generation fiom suppressed and unsuppressed vitrinite shows that both have similar reaction kinetics. While hydrocarbon generation involves the rupture of the bonds holding volatiles into the vitrinite structure, increases in VR are mainly produced by aromatisation and condensation reactions which take place after volatiles have been expelled. The reactions involved in hydrocarbon generation are diyerent from those responsible for increases in VR, and it is not therefore appropriate to derive kinetic models of vitrinite maturation from laboratory hydrocarbon generation experiments.During the maturation of normal (unsuppressed) vitrinite, the volatiles generated are expelled via the microporous network; the expulsion efficiency is not limited by the capacity of the microporous network. In hydrogen‐rich (suppressed) vitrinites, excess volatiles saturate the microporous network, restricting further aromatisation and condensation processes within the vitrinite, which results in suppression of VR. Kinetically, this has been modelled by using a variable pre‐exponential or “A” value. Two versions of a kinetic model of vitrinite maturation (SMod‐1 and SMod‐2) have been prepared, based on the amount of suppression predicted by HI‐VR calibration models published by Lo (1993) and Samuels son and Middleton (1998).Two case studies, involving wells Bunga Orkid‐1 (Malay Basin) and 2013–4 (Outer Moray Firth, North Sea), are discussed. Both wells contain suppressed VR values; well 20/3–4 is also overpressured and contains VR data that are both retarded and suppressed. The application of the SMod model to the wells enables heat flow histories derived from tectonic (rift) histories to be used for the prediction of VR data, although in the case of well 20/3–4, the use of a pressure retardation model was also required. Complementary evidence to support the use of the heat flow history applied to well 2013–4 is provided by palaeotemperature data obtained from diagenetic concretions.

99/02921 Petrology of the Cenozoic basalts from eastern Kazakhstan

Twenty-seven coal samples from the Barapukuria and Dighipara Coal Basins of Bangladesh were analysed for their maceral content, petrographic characteristics and vitrinite reflectance. The most predominant maceral was the inertinite group (mean 40%), followed by vitrinite (mean 31%) and liptinite (mean 22%), with considerable amounts of mineral matter (mean 7%). Semifusinite, fusinite and inertodetrinite were the most common macerals of the inertinite group. Collotelinite, collodetrinite and vitrodetrinite were the most frequently found macerals of the vitrinite group, while sporinite and cutinite were the most common in the liptinite group. Clay minerals occurred in higher concentrations than other minerals. The measured vitrinite reflectance values (%Ro) ranged from 0.71 to 0.80, indicating a high volatile bituminous B ranking.Facies modelling using maceral composition and maceral indices suggested an environment of forest swamps with alternating oxic–anoxic depositional conditions. Microlithotype-dependent depositional modelling indicated evolution in limno-telmatic zones under fluvio-lacustrine control, accompanied by the development of upper to lower deltaic plain conditions. A terrestrial origin with dry forest to piedmont plain conditions was suggested by the Gelification Index (GI) and Tissue Preservation Index (TPI). The lateral variation of the measured TPI values indicated an increase in the rate of basin subsidence. A cross-plot of the Ground Water Index (GWI) vs. the Vegetation Index (VI) suggested mires under ombotrophic to mesotrophic hydrogeological conditions containing herbaceous plants.

Changes in Molecular Biomarker and Bulk Carbon Skeletal Parameters of Vitrinite Concentrates as a Function of Rank

A sequential extraction scheme to differentiate between molecular alkanes and those covalently-bound to the macromolecular structure has been applied to a suite of vitrinite concentrates handpicked from six UK bituminous coals covering the rank range % Ro = 0.47−1.32 (at 546 nm). The aim was to ascertain whether the biomarker maturity indices (i) were consistent with the measured vitrinite reflectance values and (ii) differ markedly for the easily extractable, clathrated, and covalently-bound phases. The quantitatively reliable single-pulse excitation (SPE) solid state 13C NMR technique has also been used to elucidate the changes in the bulk vitrinite structure across the relatively narrow rank range investigated. Although both hopane and methylphenanthrene parameters for easily extractable species are sensitive to small variations in vitrinite reflectance, significant variations have been found between the biomarker parameters for easily extractable, clathrated, and covalently-bound material. In general, the steric protection afforded to covalently-bound biomarker species by the macromolecular structure make the latter less mature, as reflected by the hopane, sterane, and methylphenanthrene parameters, than the easily extractable and clathrated molecular species. Solid state 13C NMR revealed that the variations in carbon aromaticity and the degree of condensation of the aromatic structure occurring in the % Ro range of ca. 0.45−0.80 are relatively small.

Isoprenoid constituents in kerogens as a function of depositional environment and catagenesis

The ratio of the abundance of the C 19:1 isoprenoids 1-pristene and 2-pristene to the abundance of ( nC 17:1 + nC 17:0) is significantly lower in pyrolysates of kerogens from highly anoxic depositional environments than in pyrolysates of kerogen if similar types and levels of catagenesis from more oxic organic facies. 13C-NMR analysis shows that the occurrence of lower relative concentrations of isoprenoid precursors also correlates with the occurrence of low proportions of oxygen-bonded carbon and high proportion of aliphatic carbon in kerogens. The ratio of 1-pristene to ( n-C 17:1 + nC 17:0) can be correlated laterally and statigraphically within a basin. There is no clearly discernible dependence of relative isoprenoid concentration of kerogen type for oil-generative kerogens, although immature lignites have high 1-pristene/( nC 17:1 + nC 17:0) ratios. The 1-pristene/( nC 17:1 + nC 17:0) ratios in kerogens pyrolysates from the same organic facies decrease logarithmically with increasing catagenesis and can be correlated directly with measured vitrinite reflectance values. Geologic and experimental data imply that 1-pristene precursors are lost from kerogen more rapidly than the precursors of the C 18 isoprenoid. The lower relative isoprenoid concentrations observed in anoxically deposited kerogens appear to be the result of the enhanced preservation of normal alkyl groups and the enhanced formation of free isophrenoids early in the sequence of kerogen alteration. These results are significant to the use of isoprenoids as geochemical marker oils, bitumens, and kerogens and to the determination of the structure and diagenesis of isoprenoid precursors.