Thermal History of the Northwestern Junggar Basin: Constraints From Clumped Isotope Thermometry of Calcite Cement, Organic Maturity and Forward Thermal Modelling

<p>Resolving the thermal history of sedimentary basins through geological time is essential when evaluating the maturity of source rocks within petroleum systems. Traditional methods used to estimate maximum burial temperatures in prospective sedimentary basin such as and vitrinite reflectance (%Ro) are unable to constrain the timing and duration of thermal events. In comparison, low-temperature thermochronology methods, such as apatite fission track thermochronology (AFT), can resolve detailed thermal histories within a temperature range corresponding to oil and gas generation. In the Peel Plateau of the Northwest Territories, Canada, Phanerozoic sedimentary strata exhibit oil-stained outcrops, gas seeps, and bitumen occurrences. Presently, the timing of hydrocarbon maturation events are poorly constrained, as a regional unconformity at the base of Cretaceous foreland basin strata indicates that underlying Devonian source rocks may have undergone a burial and unroofing event prior to the Cretaceous. Published organic thermal maturity values from wells within the study area range from 1.59 and 2.46 %Ro for Devonian strata and 0.54 and 1.83 %Ro within Lower Cretaceous strata. Herein, we have resolved the thermal history of the Peel Plateau through multi-kinetic AFT thermochronology. Three samples from Upper Devonian, Lower Cretaceous and Upper Cretaceous strata have pooled AFT ages of 61.0 ± 5.1 Ma, 59.5 ± 5.2 and 101.6 ± 6.7 Ma, respectively, and corresponding U-Pb ages of 497.4 ± 17.5 Ma (MSWD: 7.4), 353.5 ± 13.5 Ma (MSWD: 3.1) and 261.2 ± 8.5 Ma (MSWD: 5.9). All AFT data fail the χ<sup>2</sup> test, suggesting AFT ages do not comprise a single statistically significant population, whereas U-Pb ages reflect the pre-depositional history of the samples and are likely from various provenances. Apatite chemistry is known to control the temperature and rates at which fission tracks undergo thermal annealing. The r<sub>mro</sub> parameter uses grain specific chemistry to predict apatite’s kinetic behaviour and is used to identify kinetic populations within samples. Grain chemistry was measured via electron microprobe analysis to derive r<sub>mro</sub> values and each sample was separated into two kinetic populations that pass the χ<sup>2</sup> test: a less retentive population with ages ranging from 49.3 ± 9.3 Ma to 36.4 ± 4.7 Ma, and a more retentive population with ages ranging from 157.7 ± 19 Ma to 103.3 ± 11.8 Ma, with r<sub>mr0</sub> benchmarks ranging from 0.79 and 0.82. Thermal history models reveal Devonian strata reached maximum burial temperatures (~165°C-185°C) prior to late Paleozoic to Mesozoic unroofing, and reheated to lower temperatures (~75°C-110°C) in the Late Cretaceous to Paleogene. Both Cretaceous samples record maximum burial temperatures (75°C-95°C) also during the Late Cretaceous to Paleogene. These new data indicate that Devonian source rocks matured prior to deposition of Cretaceous strata and that subsequent burial and heating during the Cretaceous to Paleogene was limited to the low-temperature threshold of the oil window. Integrating multi-kinetic AFT data with traditional methods in petroleum geosciences can help unravel complex thermal histories of sedimentary basins. Applying these methods elsewhere can improve the characterisation of petroleum systems.</p>

Experimental evidence regarding the pressure dependence of fission track annealing in apatite

Migration of orogenic fluids through the Siluro-Devonian Helderberg Group during late Paleozoic deformation: constraints on fluid sources and implications for thermal histories of sedimentary basins

Identification of the source rock potential and distribution area is the most important stage of the basin analysis and oil, and gas reserves assessment. Based on analysis of the large geochemical and geological data base of the Petroleum geology department of the Lomonosov Moscow State University and integration of different-scale information (pyrolysis results and regional palaeogeographic maps), generation potential, distribution area and maturity of the main source rock intervals of the Barents-Kara Sea shelf are reconstructed. These source rocks wide distribute on the Barents-Kara Sea shelf and are characterized by lateral variability of generation potential and type of organic matter depending on paleogeography. During regional transgressions in Late Devonian, Early Permian, Middle Triassic and Late Jurassic, deposited source rocks with marine organic matter and excellent generation potential. However in the regression periods, during the short-term transgressions, formed Lower Carboniferous, Upper Permian, Induan, Olenekian and Late Triassic source rocks with mixed and terrestrial organic matter and good potential. Upper Devonian shales contain up to 20.6% (average – 3%) of marine organic matter, have an excellent potential and is predicted on the Eastern-Barents megabasin. Upper Devonian source rocks are in the oil window on the steps, platforms and monoclines, while are overmature in the basins. Lower Permian shale-carbonate source rock is enriched with marine organic matter (up to 4%, average – 1.4%) and has a good end excellent potential. Lower Permian source rocks distribute over the entire Barents shelf and also in the North-Kara basin (Akhmatov Fm). These rocks enter the gas window in the Barents Sea shelf, the oil window on the highs and platforms and are immature in the North-Kara basin. Middle Triassic shales contain up to 11.2% of organic matter, there is a significant lateral variability of the features: an excellent generation potential and marine organic matter on the western Barents Sea and poor potential and terrestrial organic matter in the eastern Barents Sea. Middle Triassic source rocks are in the oil window; in the depocenters it generates gas. Upper Jurassic black shales are enriched with marine and mixed organic matter (up to 27,9%, average – 7.3%) and have an excellent potential. On the most Barents-Kara Sea shelf, Upper Jurassic source rock are immature, but are in the oil window in the South-Kara basin and in the deepest parts of the Barents Sea shelf.

During the Late Triassic and Early Jurassic the Newark rift basin of the northeastern US accumulated in excess 5 km of continental, mostly lacustrine strata that show a profound cyclicity previousl...

Palynological evidence for identification of nonmarine petroleum source rocks, China

Influence of the conditions of deposition on the chemistry and the reflectance variations of the Brent coals

Vitrinite reflectance is the most commonly used index in the study of source rock evaluation, diagenetic stage division, basin simulation, and diagenesis. Because data on vitrinite reflectance are limited, many prediction models have been proposed to address this problem. However, these models may fail to predict vitrinite reflectance effectively in overpressured basins because overpressure can suppress organic-matter maturation. Overpressure appears to reduce the degree of disorder in the hydrocarbon generation reaction system and to increase the mechanical work against the force of pore fluid that occurs as the volume of the activated complex increases, thereby reducing the preexponential factor and increasing the activation energy of the hydrocarbon generation reaction; therefore, organic-matter maturation is slowed. In this article, the reasons for the abnormally low vitrinite reflectance in the overpressured system were analyzed, which revealed that overpressure is interpreted as significantly suppressing organic-matter maturation. A new prediction model for vitrinite reflectance, A-Ea-Ro, is proposed that accounts for the suppression of overpressure in organic-matter maturation based on data from wells in the Fukang Sag in the Junggar Basin, northwestern China. The overpressure is modeled by introducing a preexponential factor and activation energy in this model. Based on measured drilling and geochemical data and simulated data, the overpressure controlling factors were optimized by a nonlinear constrained programming method and assigned 151.23 MPa and 30.65 kJ·mol−1·MPa−1, respectively. Prediction models including A-Ea-Ro were applied to wells Fu10 and Mu7 of Fukang Sag. The reflectance values predicted by the model A-Ea-Ro, applied to wells Fu10 and Mu7, were in good agreement with the measured values. This model provides a closer match between predicted and observed vitrinite reflectance values for this study area.

Heating due to lateral introduction of hot fluids is becoming an increasingly recognized feature of the thermal histories of sedimentary basins. In some basins, heating by fluids may have an important effect on hydrocarbon source rock maturation history, so that quantification of the magnitude and timing of heating become essential elements in hydrocarbon prospectivity. In other cases, determining the time of fluid heating in a reservoir may provide a key constraint on hydrocarbon migration history. Examples are presented using AFTA apatite fission track analysis and vitrinite reflectance (VR) data to identify and quantify fluid heating in well sequences from several regions. In the West of Shetland region, in the vicinity of the Rona Ridge, non-linear palaeotemperature profiles defined by AFTA and VR results provide evidence of local heating shallow in the section. AFTA timing constraints suggest introduction of heated fluids produced by nearby Tertiary intrusive activity, although the time constraints are broad because of the low maximum palaeotemperatures involved ( R 0 max < 0.6%). In a well from Asia, transient maximum palaeotemperatures > 120°C resulted in R 0 max > 0.6% in an Eocene section, with AFTA constraining the fluid flow event responsible for the early to mid Miocene (25 to 10 Ma). On the North West Shelf of Australia transient fluid flow associated with hydrocarbon leakage, and possibly charge, has been previously identified by a combination of AFTA, VR and fluid inclusion homogenization temperature ( T h ) results. In the East Swan-2 well, a fracture inclusion in quartz from shallow Eocene sandstones gives a minimum T h value of 88°C, c. 40°C higher than the present temperature. AFTA and VR data show no direct evidence of sustained heating at such a temperature, and can only be reconciled if the duration of heating was c. 20 000 years. The results are consistent with this event being associated with passage of a hot brine and hydrocarbon fluid (O’Brien and Woods, 1995). These case studies demonstrate that a combination of thermal history tools can be used to identify and quantify the thermal effect of fluid flow, potentially allowing much tighter constraints on hydrocarbon generation and migration histories.

The thermal evolution of source rocks in the Paleozoic stratigraphic sequences has been an outstanding problem for petroleum exploration in the Tarim Basin, as the thermal history of the Paleozoic could not be reconstructed objectively due to the lack of effective thermal indicators in the early Paleozoic carbonate successions. The (U-Th)/He thermochronometry of apatite and zircon has recently been used as an effective tool to study the structural uplift and thermal history of sedimentary basins. The Paleozoic tectonothermal histories of two typical wells in the Tarim Basin were modeled using the thermal indicators of (U-Th)/He, apatite fission track (AFT), and vitrinite reflectance (Ro) data in this paper. The Paleozoic strata in the two wells were shallow due to persistent uplift and significant erosion during the Hercynian tectonic events (from Devonian to Triassic). Therefore, the paleothermal indicators in the Paleozoic strata may retain the original thermal evolution and can be used to reconstruct the Paleozoic thermal history of the Tarim Basin. The apatite and zircon helium ages from core and cuttings samples were analyzed and the Paleozoic thermal histories of wells KQ1 and T1 were modeled by combining helium ages, AFT, and equivalence vitrinite reflectance (VRo) data. The modeling results show that the geothermal gradient evolution is different in the Kongquehe Slop and Bachu Uplift of Tarim Basin during the Paleozoic. The thermal gradient in Well T1 on the Bachu Uplift was only 28–30°C/km in Cambrian, and it increased to 30–33°C/km in Ordovician and 31–34°C/km during the Silurian and Devonian. The thermal gradient of Ordovician in Well KQ1 on the Kongquehe Slope was 35°C/km and decreased to 32–35°C/km during the Silurian and Devonian. Therefore, the combined use of (U-Th)/He ages and other thermal indicators appears to be useful in reconstructing the basin thermal history and provides new insight into the understanding of the early Paleozoic thermal history of the Tarim Basin.

Objectives/Scope The challenge of optimizing exploration activities using numerical modeling is in having accurate model predictions with acceptable uncertainty tolerance for use in the decision making process. Unfortunately, the prediction results of typical numerical models bear major uncertainties, making any decision-making based on these models risky and greatly increasing exploration costs. The objective of this abstract is to develop an integrated workflow accounting for all geological processes from source to trap. Methods, Procedures, Process Aside from tectonic and structural influences, two major processes are responsible for hydrocarbon accumulation: deposition of sediments and fluid migration. Combining these two processes in a single modeling workflow is a powerful approach for accurate quantitative modeling of petroleum systems (forward modeling). This workflow can be used to predict new resources with some range of uncertainties. These uncertainties can be minimized by calibrating the integrated workflow with the well and seismic data (inverse modeling). Therefore, an optimization loop is added to the workflow to automatically calibrate the forward model to the available data: core description, horizons, borehole temperature, pressure, vitrinite reflectance, fluid analysis, known reservoir volume. Results, Observations, Conclusions This workflow was implemented for eastern Saudi Arabia (upper Jurassic). First of all, a forward depositional model was built to model the 3D facies distribution within the area of interest. To reduce the uncertainties associated with the 3D facies distribution, the forward depositional model was calibrated with well facies (facies from core description and predicted electro-facies using wireline logs). The 3D facies distribution derived from the calibrated depositional model was used to model and simulate the petroleum systems for the same area of interest (forward model). Data from the wells are used to calibrate the petroleum system model to improve its prediction capabilities. The combined model was used to quantitatively assess the four elements of the petroleum system: source rock, closure, seal, and reservoir rock. Reasonable agreement was obtained between the workflow prediction and the observed hydrocarbon accumulation in eastern Saudi Arabia. This agreement has provided enough confidence to the asset team to use the combined calibrated model in generating new prospects in the area of interest. Novel/Additive Information Source rock, closure, seal, and reservoir rock are key elements of identifying a petroleum system. Conventionally, each of these elements is evaluated independently from the others. Our quantitative workflow for prospect generation, using numerical modeling and simulation, is assessing prospect integrity by considering the four elements simultaneously. Moreover, to reduce the uncertainties associated with the prospect generation and prediction, this workflow is calibrated with the historical data (well, seismic, etc.) collected from the nearby area.

The Permian marks an important, yet poorly understood, tectonic transition in the Tian Shan region of northwestern China between Devonian–Carboniferous continental amalgamation and recurrent Mesozoic–Cenozoic intracontinental orogenic reactivation. The Turpan-Hami basin accommodated up to 3000 m of sediment and is ideally positioned to provide constraints on this transition. New stratigraphic data and mapping indicate that extension dominated Early Permian tectonics in the region, whereas flexural, foreland subsidence controlled Late Permian basin evolution. Lower Permian strata in the northwestern Turpan-Hami basin consist of coarse- grained debris-flow and alluvial-fan deposits interbedded with mafic to intermediate volcanic sills and flows. In contrast, Lower Permian rocks in the north-central and northeastern Turpan-Hami basin unconformably overlie a Late Carboniferous volcanic arc sequence. These Lower Permian strata include possible shallow-marine carbonate rocks and thick volcanic and volcaniclastic rocks that are in turn overlain by littoral- to profundal-lacustrine facies. Above a regional Lower Permian/Upper Permian unconformity, regional sedimentation patterns record the development of a more integrated sedimentary basin. The Upper Permian is entirely nonmarine and can be correlated east-west along the depositional strike of the basin. The lower Upper Permian consists of a broad belt of braided fluvial deposits shed northward. These strata are overlain by fluctuating littoral- and profundal-lacustrine facies and associated fluvial facies. The uppermost Permian is characterized by shallow lake- plain and fluvial environments. The Early Permian association of diffuse volcanism and partitioning of subbasins by normal faulting is consistent with an early phase of lithospheric extension. Local relationships indicate west-east extension in the Turpan-Hami basin along faults oriented normal to Late Devonian–Carboniferous collisional sutures within the Tian Shan. The cause of extension in the wake of Carboniferous orogenesis remains enigmatic. However, the temporal and spatial relationships of the two strain regimes suggest that they are genetically related. Upper Permian stratigraphy and unconformities and local Late Permian–Triassic contractional deformation record foreland-basin development when the Turpan-Hami region became a wedge-top basin with respect to the north Tian Shan fold-and-thrust belt. Flexurally induced Late Permian subsidence is also manifested in the larger Junggar basin to the north, where >4000 m of strata are preserved in the foredeep region. The Turpan- Hami and Junggar basins were depositionally connected for much of the Late Permian when a vast lacustrine system developed across northwestern China. This lacustrine paleogeography was only occasionally interrupted, possibly by structural damming during uplift of the orogenic wedge.

The Junggar Basin was an intracontinental basin enclosed by multiple orogenies in the Mesozoic. Unravelling the provenances development in the western Junggar Basin enclosed by the West Junggar Orogenic Belt (WJOB) and Tianshan Orogenic Belt (TSOB) would elucidate the exhumation history of these orogenic belts during the post-orogenic period. The TSOB includes Central Tianshan which includes a continental block with the Precambrian to early Palaeozoic metamorphic basements, while the WJOB includes Palaeozoic accretionary complexes. Given their contrasting geological histories, we use detrital garnets, metamorphic ilmenites, epidotes, and Precambrian zircons to distinguish the TSOB and detrital Cr-spinel to distinguish the WJOB. Combined with sedimentary analysis, palaeocurrents, heavy mineral data, seismic profiles, and zircon U-Pb geochronology, here we reconstruct a four-phase source-to-sink model. During the syn-rift phase, the southern basin was stably fed by the TSOB in the Triassic, evidenced by high Garnet-zircon index and stable single-peak Carboniferous detrital zircon age spectra. During the post-rift sag basin phase, the source-to-sink system experienced a significant change, because detrital zircon age spectra change into multiple peaks. During the transpressional basin phase, the WJOB replaced the TSOB as the dominant provenance in the late Middle Jurassic and the TSOB became the dominant provenance again in the Late Jurassic. Syndepositional volcanic materials provided a large amount of sediments. During the sag basin phase, lake transgression happened and the TSOB provenance could not reach the northern basin. We concluded that the WJOB experienced transpression and obvious denudation in the late Middle Jurassic, and the TSOB uplifted under transpression in the Late Jurassic. The transpression controlled the change of major provenances. The aridification in the Late Jurassic was recorded by the decrease in the Zircon-Tourmaline-Rutile index and the increase in epidotes and magnetites. The humidification in the Early Cretaceous was responded to by lake transgression and sediment recycling.

Astronomical forcing of Middle Permian terrestrial climate recorded in a large paleolake in northwestern China

In unconventional, self-sourced sedimentary rocks, organic matter type and maturity and therefore the hydrocarbon production potential, are the most critical parameters when evaluating unconventional hydrocarbon resources. Several methods exist that determine the maturity level of sedimentary rocks and the organic matter. Organic maturity is commonly determined by vitrinite reflectance (%Ro). Vitrinite is a type of maceral that is derived from higher order plants. In rock with little or no vitrinite, bitumen or other organic matter type reflectances are measured and calculated to a normalized reflectance value (%Ro). Measuring vitrinite/bitumen reflectance is time-consuming and subject to the interpretation of the analysts. Alternatively, organic matter type and maturity are also measured using Rock Eval or equivalent pyrolysis techniques. The temperature (Tmax) at which thermal cracking of heavy hydrocarbons and kerogen reaches the maximum depends on the nature and maturity of the kerogen and indicates the level of thermal maturity. Pyrolysis results are independent of an operator although the data output may still require validation. In order to compare data from these two techniques, a study from the Barnett in 2001 produced a conversion formula to calculate %Ro from Tmax data. The conversion formula (calculated Ro = 0.0180 × Tmax − 7.16) has been used extensively in basins worldwide despite the fact that the correlation was produced for the Barnett shale. Here we present new maturity data (>100) (%Ro and Tmax) within the Duvernay Formation in Alberta, Canada, which is compared to data using the conversion formula. The Duvernay Formation of the Western Canada Sedimentary Basin is an Upper Devonian (~360 Ma) source rock which has been praised as one of the most promising oil/gas resource plays in Canada. Since late 2009, land sale activity has seen over $1.4 Bn spent in Alberta with land purchases focused in the Pembina and Kaybob areas. The total organic carbon (TOC) content of the Duvernay Formation can exceed 20 wt% in areas of low maturity but on average, the dark shales have TOC contents ranging between 4–11 wt%. TOC is a key indicator of hydrocarbon generation potential. In this study, we discuss the details of both analytical techniques, findings of the organic petrography, bitumen reflectance data and corresponding Tmax data. The data is also compared to calculated Ro values and problems using the formula are highlighted. In addition, the data is put into perspective of production information and the hydrogen-generative models (initial production data). The results show that inherent problems are manyfold and conversion calculations should be avoided in new formations where a conversion formula has not been established.