Timing Of Petroleum Generation Research Articles

Oil generation and expulsion modeling of the syn-rift Salif oil-source rock in the Tihamah Basin, Yemeni Red Sea: Implications for shale oil exploration

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur.

Velocity modeling of supercritical pore fluids through porous media under reservoir conditions with applications for petroleum secondary migration and carbon sequestration plumes

Computational methods to characterize secondary migration in porous media traditionally rely on fluid transport equations with assumptions of time invariance, such as flow-path modeling of buoyancy vectors, statistical percolation algorithms, capillary pressure curves, or a form of Darcy’s law, which presumes instantaneous fluid transport. However, in petroleum systems modeling, the timeframe of secondary migration from source to reservoir is important to quantify in relation to other geologic factors, such as the timing of petroleum generation, fault movement, and seal formation. In addition, quantifying migration velocities enables an estimation of the distance a plume of geologically sequestered carbon dioxide travels over time, as well as the identification of low-permeability strata appropriate for long-term containment. This study introduces a method to quantify transport velocities of supercritical fluids in low-permeability lithologies for a broad range of rock and fluid properties likely encountered in the sedimentary sequence. A time-dependent form of Darcy’s law for pressure-driven viscous flow through homogeneous isotropic porous media was used to model flow velocities within a carrier bed. Thermodynamic equations of state were used to determine thermophysical properties of supercritical pore fluids under reservoir pressures ranging from 0 MPa to 200 MPa (0–29,000 psi) to constrain the momentum equations. Three case studies were examined that (1) estimated fluid flow velocities of methane within the low-permeability Upper Jurassic Haynesville Formation, (2) defined permeability-based flow units to evaluate saline formations for long-term geologic carbon sequestration, and (3) calculated the migration distance of carbon dioxide plumes at the Decatur, Illinois injection and sequestration project.

Silurian hot shale occurrence and distribution, organofacies, thermal maturation, and petroleum generation in Ghadames Basin, North Africa

The Silurian hot shale in one of the African superglobal petroliferous sedimentary basins (Ghadames) were studied to provide new regional insights regarding the organofacies type, occurrence and distribution, thermal maturation levels, and the timing of petroleum generation and expulsion. Based on regional integrated geochemical data such as Rock-Eval and Leco TOC, the evaluation of hot shale organofacies was carried out to characterize the type, occurrence and distribution and to obtain present-day regional maps of total organic carbon content (%TOCpd), hydrogen index (HIpd) and kerogen transformation (TRpd). The hot shale thermal maturation levels were obtained using pyrolysis Rock-Eval Tmax, equivalent vitrinite reflectance (%VRo), and one, two and three-dimensional calibrated basin modeling approaches. Results show that the hot shale was entirely dominated by typical marine organofacies type B (kerogen type I/II) with %TOC ranging from 2% to 17.5%, and hydrogen index ranged from 50 to 750 mg HC/g TOC with apparent systematic trends throughout the basin margins, and depocenter for both %TOC and HI. The hot shale thermal maturation study indicates a general maturation range from early to the post-mature stages with 0.45–2.45 %VRo and 380 °C–510 °C as pyrolysis temperature range. The one and two-dimensional kerogen transformation study based on the obtained refined thermal model shows a general range from 20% to 98% transformation levels with a systematic increase from the basin margins toward the basin depocenter. The hot shale oil window (top and bottom) is defined to be in the range of 1,400 m–4,000 m burial depth, while the dry gas window of the hot shale is presented at a burial range of 4,000 m–5200 m. Such an observation and current geological and geochemical conditions rank the hot to be an attractive potential sweet spot area as an unconventional shale oil/gas play target in Ghadames Basin for future exploration activity in western Libya, eastern Algeria, and southern Tunisia.

Peculiar Berriasian “Wealden” Shales of northwest Germany: Organic facies, depositional environment, thermal maturity and kinetics of petroleum generation

This study provides new organic geochemical, organic petrological and isotope data on the Berriasian Wealden Shales, northwest Germany as well as new kinetic data on petroleum generation determined both for kerogen concentrates and whole rock samples. The kinetics were applied in numerical petroleum system models for two wells: one in the western Lower Saxony Basin (LSB) and the other one in the Pompeckj Block further north. The study increases the understanding on rate, conversion and timing of petroleum generation and is consistent with oil fields and prospects in the area, which was not the case in previous studies.The first facies of the Wealden 3–4 members is partly very rich in organic matter (TOC up to 21.85 wt%), the organic matter being composed almost exclusively of thin lamalginites. The second organic facies is characterized by lower TOC values (3.86–10.73 wt%) containing both Botryococcus algae and lamalginites. High atomic H/C and C/S ratios as well as the occurrence of Botryococcus algae prove a brackish–freshwater depositional environment with high HI values, which are typical of type I or type II kerogen. Broad n-alkane distributions without odd-even predominance are surprising in view of vitrinite reflectance, HI and Tmax data, which are typical of immature or early mature kerogen.Several biomarker indices indicate dysoxic/anoxic bottom water conditions and possibly water stratification, while the low steranes/terpanes ratio suggests a significant bacterial contribution to the organic matter. Low δ13C values (−28.5 to −34.5‰) are in line with previously obtained data for the Wealden and support the presence of microbial-derived kerogen.Low Pristane/Phytane, low Pristane/nC17 and Phytane/nC18 ratios and the absent odd-even predominance are regarded as a result of kerogen being derived from microbial rather than algal biomass; it is not related to thermal maturation. Lamalginite is in this case probably derived from microbial mats producing no chlorophyll and little sterane precursors. Deeper in the water or in the sediments, denitrification of the bacterial biomass took place leading to extraordinarily low nitrogen/carbon ratios and extraordinarily high ẟ15N values. The occurrence of H2S in the lower water column resulted in excellent organic matter preservation leading to very high TOC values (up to 21.8 wt%). Abundant framboidal pyrites indicate a microbial pyrite origin.The burial, thermal and maturity history calibrated by Easy%RoDL reveals that more erosion is required than assumed in previous studies to explain the present-day maturation in the western LSB and Pompeckj Block. In both wells (A, B), the Wealden source rocks experienced sufficient temperatures for hydrocarbon generation and primary migration. Kinetics obtained from kerogen concentrates indicate earlier generation (i.e. at slightly lower temperatures) than those from whole rock samples. The Botryococcus algae facies reveals lower transformation ratios at a given temperature history, suggesting that most of the oil was generated by the lamalginite facies. Significant and late (~40 million years ago; Lutetian) kerogen-to-oil conversion in the northern part of the study area lowers the charge risk in future conventional oil exploration.

Remotely constraining the temporal evolution of offshore oil systems

An understanding of the temporal evolution of a petroleum system is fundamental to interpreting where hydrocarbons may be trapped in the subsurface. However, traditional exploration methods provide few absolute constraints on the timing of petroleum generation. Here we show that 187Re/187Os geochronology may be applied to natural crude oil seepage to determine when petroleum generation occurred in offshore sedimentary basins. Using asphaltites collected from the South Australian coastline, our determined Re-Os age (68 ± 15 million years ago) is consistent with their derivation from a Late Cretaceous source rock in the nearby Bight Basin, an interpretation similarly favoured by source-specific biomarker constraints. Furthermore, the calculated initial 187Os/188Os composition of the asphaltites, a value inherited from the source rock at the time of oil generation, suggests that the source rock represents the later stage of Oceanic Anoxic Event 2. Our results demonstrate a new approach to identifying the origin of crude oils encountered in coastal environments by providing direct constraints on the timing of petroleum generation and potential source rock intervals in poorly characterised offshore sedimentary basins prior to exploratory drilling.

Organic richness, hydrocarbon potentiality, maturity, and timing of petroleum generation of the Cretaceous and Miocene source rocks in the central Gulf of Suez, Egypt

ABSTRACTTotal organic carbon (TOC) and pyrolysis analysis of the Cretaceous and Miocene source rocks in the central Gulf of Suez were evaluated throughout the 25 rock samples collected from 6 formations, namely Wata, Raha, Nubia “A” (Cretaceous source rocks); and Nukhul, Zeit, and Belayim (Miocene source rocks) from Gharib-252, Gharib-153, Gharib-163, Gharib-164, Gharib-167, and Gharib-165 wells. These data are used to study the probabilities of the source rock in the Cretaceous and Miocene source rocks in the central Gulf of Suez for the hydrocarbon generation through identifying the organic richness, type of organic matters, and thermal maturation of these organic materials. The results revealed that the Cretaceous formations are immature source rocks, ranging from fair to good source rocks and have kerogen of type III and type III/II. Meanwhile, Miocene source rocks, ranging from immature to marginally mature source rocks, are considered to range from good to very good source rocks for potential generation of both oil and gas and are characterized by kerogen of type III/II and type II.

Source rocks evaluation and timing of petroleum generation of selected wells in Meleiha Area, North Western Desert, Egypt

ABSTRACTFifteen rock samples were subjected to comprehensive organic geochemical studies aiming to evaluate potential source rocks as well as to predict the time of petroleum generation and expulsion of Kharita, Alam El Bueib, and Khataba Fms. in some wells in Meleiha area. The study revealed the Kharita Fm. is immature and has fair potential to produce gas. The organic matter is derived from terrestrial origin. Alam El Bueib Fm. is mature with fair to good capability of producing mixed oil and gas. The organic matter is originated mainly from mixed organic sources. Khatatba Fm. is mature and has good potentiality for generating oil. The organic matter is derived mainly from marine origin. The geothermal profile revealed that Kharita Fm. reached only the early stage of hydrocarbon generation and did not enter the oil widow till the present time. Alam El Bueib Fm. entered the oil window during Late Eocene time. Khatatba Fm. entered the oil window during Late Cretaceous. Consequently, Khatatba Fm. in Meleiha area can be considered as effective source rocks for generating both oil and gas.

Timing of petroleum generation and source maturity of selected wells in Abu Gharadig Basin, North Western Desert, Egypt

ABSTRACTThe timing of petroleum generation of source rocks is recognized to investigate the maturation level of the proven potential source formations for oil preservation dead lines, and predict the levels of thermal maturity of the studied sequences in terms of hydrocarbon generation and expulsion. For theses purposes four thermal burial history and maturity profiles were constructed of the Abu Gharaig-1 SW Umbaraka-1, GPZ-1, and GPX-1 wells. The results showed Abu Roash and Bahariya formations are immature to mature source rocks and have poor to fair potential to generate both oil and gas and still are within the early stage of hydrocarbon generation till the present time. Alam El Bueib and Masajid formations bear mature source rocks and have good generating capability for generating both oil and gas and entered the oil window since Cretaceous to Miocene times and lies within oil and gas windows at present time. Khatatba Formation bears a mature source rock and has good generating capability for both oil and gas and entered the oil window during Late Cretaceous to Eocene times.

Petroleum generation modeling of the Late Cretaceous coals from the Jiza-Qamar Basin as infer by kerogen pyrolysis and bulk kinetics

Abstract The petroleum generating potential of the Late Cretaceous coal within the Mukalla Formation is evaluated. Bulk and quantitative pyrolysis techniques and organic petrology were used to characterize the kerogen composition, generative potential and kinetic models to determine the variability of the organic matter and their effect on the timing of petroleum generation. These measurements identified one major organic facies containing an oil-prone Type II/III kerogen, with HI values >300 mg HC/g TOC that produces mainly paraffinic and paraffinic–naphthenic–aromatic (P–N–A) oils with high wax contents. Bulk kinetic analysis on Late Cretaceous coal samples reveal a relatively broad distribution of activation energies (42–69 kcal/mol). Using a generic heating rate of 3.3 °C/My, the onset temperature for oil generation (TR 10%) is ∼139 °C and the peak generation temperature (geologic Tmax) range from 150 to 167 °C. A 1D model predicts that the Mukalla coals in the Jiza-Qamar Basin began oil generation at ∼40 My and reached peak generation ∼20–15 My ago. Therefore, the Mukalla coals could have be generated mature oils in the Jiza-Qamar Basin.

Re–Os geochronology and Os isotope fingerprinting of petroleum sourced from a Type I lacustrine kerogen: Insights from the natural Green River petroleum system in the Uinta Basin and hydrous pyrolysis experiments

Rhenium–osmium (Re–Os) geochronology of marine petroleum systems has allowed the determination of the depositional age of source rocks as well as the timing of petroleum generation. In addition, Os isotopes have been applied as a fingerprinting tool to correlate oil to its source unit. To date, only classic marine petroleum systems have been studied. Here we present Re–Os geochronology and Os isotope fingerprinting of different petroleum phases (oils, tar sands and gilsonite) derived from the lacustrine Green River petroleum system in the Uinta Basin, USA. In addition we use an experimental approach, hydrous pyrolysis experiments, to compare to the Re–Os data of naturally generated petroleum in order to further understand the mechanisms of Re and Os transfer to petroleum.The Re–Os geochronology of petroleum from the lacustrine Green River petroleum system (19±14Ma – all petroleum phases) broadly agrees with previous petroleum generation basin models (∼25Ma) suggesting that Re–Os geochronology of variable petroleum phases derived from lacustrine Type I kerogen has similar systematics to Type II kerogen (e.g., Selby and Creaser, 2005a,b; Finlay et al., 2010). However, the large uncertainties (over 100% in some cases) produced for the petroleum Re–Os geochronology are a result of multiple generation events occurring through a ∼3000-m thick source unit that creates a mixture of initial Os isotope compositions in the produced petroleum phases. The 187Os/188Os values for the petroleum and source rocks at the time of oil generation vary from 1.4 to 1.9, with the mode at ∼1.6. Oil-to-source correlation using Os isotopes is consistent with previous correlation studies in the Green River petroleum system, and illustrates the potential utility of Os isotopes to characterize the spatial variations within a petroleum system.Hydrous pyrolysis experiments on the Green River Formation source rocks show that Re and Os transfer are mimicking the natural system. This transfer from source to bitumen to oil does not affect source rock Re–Os systematics or Os isotopic compositions. This confirms that Os isotope compositions are transferred intact from source to petroleum during petroleum generation and can be used as a powerful correlation tool. These experiments further confirm that Re–Os systematics in source rocks are not adversely affected by petroleum maturation. Overall this study illustrates that the Re–Os petroleum geochronometer and Os isotope fingerprinting tools can be used on a wide range of petroleum types sourced from variable kerogen types.

The Upper Jurassic–Cretaceous petroleum system of southern Iraq: A 3-D basin modelling study

ABSTRACT A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.

Modeling of petroleum generation in the Vietnamese part of the Malay Basin using measured kinetics

Two-dimensional (2-D) modeling of source rock maturation and hydrocarbon (HC) generation histories were conducted for the Malay-Cho Thu Basin in the Gulf of Thailand and South China Sea. The source rocks comprise Oligocene synrift lacustrine mudstones and coals, postrift coals, and terrigenous-influenced mudstones. Three different lacustrine mudstone source rocks and coals were considered in the 2-D modeling, and each source rock was assigned specific generation potential and kinetics. Measured kinetics for bulk petroleum generation determined on two thermally immature upper Oligocene oil-prone lacustrine mudstones and on a terrigenous-influenced mudstone derived from wells were used together with published coal kinetics. The onshore Krong Pa graben, a small-scale rift basin in central Vietnam, was used as a conceptual model for the distribution of lithofacies, including source rock types, in the 2-D models. Exploration targets and drilled direct HC indicators (DHIs) are mainly located in the tectonically disturbed postrift succession. Modeling results suggest that the risks related to this play are (1) timing of petroleum generation from the oil-prone lacustrine synrift deposits relative to structural trap formation, (2) complex migration pathways through strongly faulted strata, and (3) relatively small kitchen areas. Oil generation from uppermost synrift and postrift coaly source rocks with minor contribution from lacustrine deposits after principal trap formation is consistent with the prominent terrigenous geochemical signature of oils in the Malay-Cho Thu Basin. A new untested play is proposed based on mapping of potential DHIs associated with sandstone bodies in tectonically undisturbed synrift traps.

Petroleum secondary migration and accumulation in the central Junggar Basin, northwest China: Insights from basin modeling

The timing of petroleum generation, migration, and accumulation in the central Junggar Basin has been evaluated using basin modeling technology to decipher the processes of petroleum secondary migration and accumulation in the Jurassic carrier beds during the Yanshan and Himalayan orogenies. During the early Yanshan orogeny (J2–J3), crude oils, sourced mainly from the Permian source rocks, migrated laterally from depocenters to adjacent structural high points. During the late Yanshan orogeny (Cretaceous–Eocene), the hydrocarbon secondary migration pattern changed significantly. Specifically, in the Cretaceous, a large-scale regional second phase of generation and migration occurred in the western part of the central Junggar Basin; in the eastern part of the central Junggar Basin, crude oils emplaced in the depressions migrated mainly to the eastern uplifts. In the early Tertiary, oils in the source kitchens generally began migrating to the north and mixed with the Jurassic-generated hydrocarbons. During the Himalayan orogeny (Neogene–Quaternary), this migration was strengthened continually. The modeled results agree with migration-associated geochemical information of the Jurassic accumulations. Integration of the regional geological setting and some petroleum geology data suggest that the Jurassic tectonic high points and facies-change- and unconformity-associated subtle traps are of crucial importance for current oil exploration. Both overpressured bodies in the Triassic and Permian systems and volcanic rock reservoirs of the Carboniferous basement in the uplifts have important implications for future natural oil and gas exploration. This work should help reduce exploration risk in this region.

Migração de depocentros na Bacia de Santos: importância na exploração de hidrocarbonetos

Recent important discoveries of gas and oil fields during the last few years have called attention to the Santos Basin, offshore Southeast Brazil. The basin is located south of the Campos Basin, the most prolific Brazilian oil province. The Cabo Frio Arch is the frontier between them, but the two basins present many similarities in their structural and stratigraphic evolution. Meanwhile, the Upper Cretaceous record is significantly more preserved in the Santos Basin, being characterized by thick Santonian to Maastrichtian progradational siliciclastic clinoforms. The accommodation space was generated by salt basinward withdrawal, which in consequence caused the rafting of the Albian Guaruja carbonate sequences and of the deposition of Cenomanian to Turonian marine shales and Ilhabela turbidites. Because of the withdrawal of Aptian transitional evaporites and rafted younger sequences, the deltaic clastic wedges downlap the pre-Aptian unconformity, placing in contact Upper Cretaceous reservoirs with Lower Cretaceous rift source-rocks. Progradation was not simultaneous along the basin and resulted from migration of sediment input along the Brazilian margin. In order to understand the way of depocenter migration, a sequence stratigraphic analysis was carried out using available seismic lines and well data. The sequence boundaries were traced in 60 wells, and isopach and several lithologic ratio maps were produced for each sequence. The maps show clearly a depocenter migration towards northeast during the Late Cretaceous along the Santos Basin into the Campos Basin, where the Tertiary section is well developed. Early Tertiary section is well developed in the north portion of the Santos Basin, represented by prominent deltaic progradation and associated turbidite systems. Another important Tertiary depocenter is placed in the southmost portion of the Santos Basin, where deep-water systems were recognized in seismic sections. The recognition of the pathway of depocenter migration is an important guide to oil and gas exploration, since it support interpretation concerning the relation between the formation of reservoir rocks and the timing of petroleum generation and migration.

Migração de depocentros na Bacia de Santos: importância na exploração de hidrocarbonetos

Recent important discoveries of gas and oil fields during the last few years have called attention to the Santos Basin, offshore Southeast Brazil. The basin is located south of the Campos Basin, the most prolific Brazilian oil province. The Cabo Frio Arch is the frontier between them, but the two basins present many similarities in their structural and stratigraphic evolution. Meanwhile, the Upper Cretaceous record is significantly more preserved in the Santos Basin, being characterized by thick Santonian to Maastrichtian progradational siliciclastic clinoforms. The accommodation space was generated by salt basinward withdrawal, which in consequence caused the rafting of the Albian Guarujá carbonate sequences and of the deposition of Cenomanian to Turonian marine shales and Ilhabela turbidites. Because of the withdrawal of Aptian transitional evaporites and rafted younger sequences, the deltaic clastic wedges downlap the pre-Aptian unconformity, placing in contact Upper Cretaceous reservoirs with Lower Cretaceous rift source-rocks. Progradation was not simultaneous along the basin and resulted from migration of sediment input along the Brazilian margin. In order to understand the way of depocenter migration, a sequence stratigraphic analysis was carried out using available seismic lines and well data. The sequence boundaries were traced in 60 wells, and isopach and several lithologic ratio maps were produced for each sequence. The maps show clearly a depocenter migration towards northeast during the Late Cretaceous along the Santos Basin into the Campos Basin, where the Tertiary section is well developed. Early Tertiary section is well developed in the north portion of the Santos Basin, represented by prominent deltaic progradation and associated turbidite systems. Another important Tertiary depocenter is placed in the southmost portion of the Santos Basin, where deep-water systems were recognized in seismic sections. The recognition of the pathway of depocenter migration is an important guide to oil and gas exploration, since it support interpretation concerning the relation between the formation of reservoir rocks and the timing of petroleum generation and migration.

Source rock heterogeneity of the Upper Jurassic Draupne Formation, North Viking Graben, and its relevance to petroleum generation studies

The Upper Jurassic Draupne Formation in the North Viking Graben, North Sea, has been studied to identify lateral and vertical variations in source rock characteristics and their effect on the timing of petroleum generation. Fourteen source rock samples from the western flank of the graben and five from the eastern flank were analysed using Rock-Eval analysis, microscopy, open system pyrolysis gas chromatography and kinetic experiments. Two major organic facies with different petroleum generation characteristics were identified: a stratigraphically higher, thermally less stable facies, corresponding to a type II kerogen with HI (Hydrogen index) values of >350 mg HC/g TOC; and a stratigraphically lower, more stable type II/III facies with HI values <350 mg HC/g TOC. Only the former is conventionally considered in basin modelling studies. Both organofacies are dominated by marine aliphatic-rich organic matter with variable contributions from transported terrestrial organic matter, resulting in the formation of paraffinic–naphthenic–aromatic petroleum with variable amounts of gas. Bulk kinetic experiments have shown that predicted petroleum formation temperatures are very different, with onset (TR 10%) temperatures of 126 °C (geological T max 144 °C) for the less stable facies and 153 °C (geological T max 170 °C) for the more stable. This corresponds to ∼400 m difference in burial depth or delayed onset of petroleum generation by ∼14 My. Based on a larger dataset from industry, the more stable facies may represent at least 40% of the Draupne Formation in our study areas. Our results imply that petroleum generation from the formation extends to greater depths than generally recognized and that the more stable Draupne organic facies also needs to be included in basin modelling studies to cover the full history of petroleum formation.

Kerogen: from Types to Models of Chemical Structure

The aim of the present paper is to review the conceptual and analytical developments in the period 1970-1990 which have led, through kerogen isolation and analysis on one hand, and case studies of petroleum systems on the other hand, to the concept of kerogen types, evolution paths, and statistical chemical models. Kerogen is defined as the sedimentary organic matter generating petroleum, an insoluble product as opposed to its counterpart soluble in usual organic solvents, such as petroleum. As kerogen is a complex organic material intimately mixed with minerals in sediments, the first task was to set up a robust procedure for its isolation, enabling then its study by various physicochemical analyses. The parallel development of oil exploration, resulting in geological sample availability, made the geochemical comparison of various petroleum systems possible. Comparisons concerned not only oils, source rock extracts and kerogen compositions, but also the timing of petroleum generation. The notion of kinetic cracking of kerogen into petroleum stemming from these case studies, associated with the observation of time and temperature compensation, resulted in the use of pyrolysis to evaluate the oil potential still to be generated by the kerogen, and in the construction of the Rock-Eval. In the mid 70s, all main parameters on kerogens from reference series of source rocks were available to define the notions of types and evolution paths of kerogens upon geological maturation. A further important step for improving the knowledge of kerogen composition was achieved in the 80s using new techniques of analytical and preparative pyrolysis and their coupling with different detectors. The pyrolysis products, small building blocks issued from the kerogen thermal cracking, could thus be analyzed and quantified at the molecular level, without the problems of representativity associated with natural extract analyses, such as loss of volatile fractions or product migration out of source rocks. ;Contemporaneous developments in solid state 13C NMR allowed quantification of the various forms of carbon and their molecular environment in the kerogen, whereas quantification was not possible with IR or UV spectroscopy. The quantification of molecular building blocks and their bonding functional groups in kerogens allowed conceptual averaged molecular models of kerogens to be proposed in order to visualize their atomic and molecular composition, and the changes occurring in this composition according to types and maturity. Although it will never be possible to represent a true kerogen structure, simply because it is a mixture of various nonpolymeric macromolecules, an hypothetical average structure of kerogen, representing a large amount of information from various analyses, can provide a synthetic view of the main resemblances and differences among sedimentary organic matters.

Evaluation of petroleum generation and expulsion from a source rock by open and restricted system pyrolysis experiments. Part I. extrapolation of experimentally-derived kinetic parameters to natural systems

The kinetic data sets obtained on two different grain-size splits, finely ground (<0.106 mm) and chip (1–4 mm), of the very same sample show remarkable differences. The geochemical meaning of these differences were investigated by extrapolation of these laboratory-derived kinetic parameters to natural setting by help of a 2-D basin modelling software. The results suggest that modelling's predictions are significantly different, from one kinetic data set to the other, in terms of temperatures and timing of petroleum generation in nature which are very important from the standpoint of petroleum exploration. Application of laboratory-derived kinetic parameters for simulation of petroleum generation from sedimentary organic matter (kerogen) in natural system requires great caution. Conventional use of finely ground (powder) samples in pyrolysis to derive kinetics of petroleum generation is far from representing source rock environments in nature.

Geohistory Analysis and Petroleum Reservoir Characteristics of Lower Cretaceous (Neocomian) Sandstones, Eastern Kopet-Dagh Basin, Northeastern Iran (1)

The eastern part of the Kopet-Dagh basin of northeastern Iran contains over 4000 m of Upper Jurassic through Tertiary strata deposited in a variety of shallow-marine and terrestrial environments. Geohistory diagrams from well and outcrop data provide a useful mechanism with which to relate the stratigraphic framework of this part of the basin to the tectonic history of the region. During some episodes of regional tectonic uplift (e.g., episodes occurring 99-95 Ma, 74-70 Ma, and 63-54 Ma), sediment accommodation space continued to be created in the basin due to sediment loading and compaction of increased amounts of fine-grained sediments, in some cases concomitant with eustatic sea level rises. Much of the post-Jurassic subsidence in this part of the Kopet-Dagh basin was aused by sediment loading rather than tectonism. The effects of basin geohistory on petroleum reservoir properties were studied using the Lower Cretaceous (Neocomian) Shurijeh Formation as an example. Detailed petrologic, sedimentologic, and geohistory analyses done on this formation show that the petroleum reservoir properties of Shurijeh sandstones were affected by their depositional settings and the subsequent subsidence of these units through meteoric and compactional hydrogeologic regimes in this part of the Kopet-Dagh basin. These rocks consist mostly of sublitharenitic red beds deposited during a regressive phase of sedimentation dominated by rapid siliciclastic sediment supply. The lower and middle parts of the interval studied were deposited in low-sinuosity braided fluvial systems, and the upper part was deposited in high- inuosity meandering systems. By relating the paragenetic sequence of the Shurijeh sandstones to the geohistory of this formation, we determined the timing of both porosity-destroying and porosity-enhancing diagenetic processes and related these processes to the timing of petroleum generation.

Estimation of Paleogeothermal Gradients and Their Relationship to Timing of Petroleum Generation, Eagle Basin, Northwestern Colorado: ABSTRACT

Lopatin time-temperature index (TTI) modeling of three locations in the Eagle basin, northwestern Colorado, where vitrinite reflectance (R/sub m/) profiles were obtained, shows that paleogeothermal gradients and the timing of oil generation in the Belden Formation (Pennsylvanian) varied due to differing thickness of the Pennsylvanian section across the basin. At the Gilman location, where the Pennsylvanian section is thickest (7,900 ft or 2,408 m), two paleogeothermal gradient models were generated that match the average 3.70% R/sub m/ and the corresponding TTI value between 40,000 and 50,000. The first model assumes a constant geothermal gradient of 2.4/sup 0/F/100 ft (43.8/sup 0/C/km), which places the oil window between 270 and 230 Ma. The second model assumes a changing paleogeothermal gradient of 2.80/sup 0/F/100 ft (51/sup 0/C/km), from 320 to 265 Ma and 2.20/sup 0/F/100 ft (40.2/sup 0/C/km) from 265 Ma to present, which places the oil window between 275 and 250 Ma. For the Glenwood location, where the Pennsylvanian section is 4,960 ft (1,512 m), a constant paleogeothermal gradient of 1.80/sup 0/F/100 ft (32.9/sup 0/C/km) works the best in correlating the 2.50% R/sub m/ with the corresponding TTI value of approximately 2,700. Using this gradient, the oil window falls between 175 andmore » 75 Ma.« less