Heat Flow History Research Articles

Geoenergy in the Styrian Basin

The Styrian Basin (SB) is the westernmost basin within the Pannonian Basin Complex and is located in SE Austria, where the crustal thickness decreases from more than 40 km to less than 30 km. It can be divided into the West and East Styrian Basin. The pre-Neogene basement includes Penninic and crystalline rocks overlain by Paleozoic rocks. The age of the basin fill ranges from the early to late Miocene. Despite a long hydrocarbon exploration history, only a single sub-economic gas field has been discovered. The lack of commercial deposits is probably due to limited source-rock quality and an unfavourable heat-flow history. In contrast, a significant number of geothermal wells with a cumulative length of >54 km have been drilled in the East SB. The main geothermal reservoirs are fractured Paleozoic carbonates and Miocene (Badenian) sandstones. Geothermal gradients in the SB are typically above 4°C/100 m. The hottest geothermal well (Frutura GT1) produces water with a temperature of 125°C (bottom hole temperature 138°C) from a depth of ∼3.3 km. Utilization of geothermal energy in the SB includes balneology, district and greenhouse heating, production of medical salt, CO 2 and electricity.

Present-Day Geothermal Regime and Thermal Evolution of the Fukang Sag in the Junggar Basin, Northwest China

The Fukang Sag in the Junggar Basin is an important petroleum exploration and exploitation region. However, the geothermal regime and tectono-thermal evolution of the Fukang Sag, which control its hydrocarbon generation and conservation, are still controversial. This study involved a systematic analysis of the present-day geothermal gradient, heat flow, and thermal history of the Fukang Sag for better further exploration. According to the well log data and well-testing temperature data, we calculated that the geothermal gradient of the Fukang Sag ranges from 16.6 °C/km to 29.6 °C/km, with an average of 20.8 °C/km, and the heat flow ranges from 34.6 mWm−2 to 64.3 mWm−2, with an average of 44.6 mWm−2. Due to the basement relief, they decrease from northeast to southwest. The weight averages of the single-grain apatite (U-Th)/He ages of the core samples are 1.3–85.2 Ma, and their apatite fission track ages range from 50.9 Ma to 193.8 Ma. The thermal modeling results revealed that the Fukang Sag experienced late Permian, late Jurassic, and late Cretaceous cooling events (although the timing and magnitude of these events varied among the samples), which were related to the continuous compression of the Junggar Basin. In addition, basin modeling indicated that the heat flow of the Fukang Sag decreased from 80 mWm−2 in the Carboniferous to the current value of 44.6 mWm−2. The Fukang Sag’s edge exhibits prolific hydrocarbon generation in the Carboniferous–Permian source rocks, while the Jurassic source rocks within the sag also undergo abundant hydrocarbon generation. This study provides new insights into the present-day geothermal field and tectono-thermal evolutionary history of the Fukang Sag, which are significant in terms of regional tectonic evolution and oil and gas resource assessment.

Burial and thermal history of the eastern transform boundary of the central western carpathians based on 1D basin modeling

This paper represents the first data on the thermal and burial history of Mesozoic and Cenozoic sedimentary rocks in the Maruszyna IG-1 deep borehole from the transpressional shear zone of the Western Carpathians. Representative, organic-rich mudstone and claystone samples were selected to determine thermal maturity using mean random vitrinite reflectance (Ro) and thermal alteration index (TAI) data. The reconstruction of the thermal history of fold-and-thrust units was carried out using 1D modeling. This study uniquely distinguishes various thermal maturity levels in the deep profile determined by strata repetition, different absorption of clay and carbonate mineral settings and structural thermal changes in humic particles and palynomorphs. Reflectance of autochthonous vitrinite varies from 0.77 to 1.95% indicating thermally mature to overmature organic matter. Different subsidence-uplift models were tested during modeling in order to find a plausible scenario of tectonic development and heat flow history. The thermal maturity of the individual thrust sheets was modeled separately allowing their individual thermal histories to be investigated before and after the main and final thrusting phase. The best-calibrated scenario assumes a low paleo heat flow ranging from 45 to 54 mW.m-2, affecting the eastern part of the Western Carpathians. The maximum temperature which lead to maturation of the organic matter seems to be related to its successive burial during Cretaceous due to compressional deformation. Individual thrust sheets reached thermal maturity prior to the final thrusting phase. The overthrust was accompanied by 3000–4000 m burial/erosion resulting in different thermal pathways during wedge growth.

Paleotemperature modeling of hydrocarbon generation centers and their role in the formation of «Paleozoic» oil deposits (Ostaninskoe field, Tomsk region)

Study and exploration of the pre-Jurassic oil and gas complex in Western Siberia is one of the aspects of hydrocarbon raw-material base development. The main scope of this study is to locate the source of Paleozoic hydrocarbons. The problem of modeling and assessing the role of Paleozoic-Mesozoic hydrocarbon generation centers in the formation of «Paleozoic» oil deposits in the section of the Ostaninskoe oil and gas condensate field (Tomsk region) is solved. In the formation of the oil and gas content of the pre-Jurassic basement two reservoirs are involved: the weathering crust and the roof of the bed-rock Paleozoic. The first was formed during the period of 213–208 Ma, and the second is genetically determined by epigenetic processes in the weathering crust. Potential hydrocarbon sources for the weathering crust and bed-rock Paleozoic reservoirs are Domanic type rocks in the crystalline basement: Larinskaya S1lr, Mirnaya D1mr, Chuzikskaya D2cz, Chaginskaya D3cg Formations, as well as Tyumenskaya J1-2tm and Bazhenovskaya J3bg Formations in sedimentary cover. To perform joint paleotemperature modeling of sedimentary basins of the «modern» Jurassic-Cretaceous and Paleozoic «paleobasins», the Ostaninskaya 438P well was selected, which is due to the presence of measured temperatures both in the Jurassic sections and in the pre-Jurassic formations, as well as fluid inflows from the pre-Jurassic horizons into the well. At the first step, the solution of the inverse problem of geothermics was obtained using reservoir temperatures and vitrinite reflectance measurements from the Mesozoic deposits: density of deep heat flow from the base of sedimentary section was determined, which is characterized by a quasi-constant value from the Jurassic to the present. The second step was to solve the inverse problem using vitrinite reflectance measurements from Paleozoic sediments. As a result, the heat flow value was obtained for the key moments of geodynamic history of the stratigraphic section, starting from the Silurian. By solving direct problems of geothermics with the given values of heat flow, the structural-tectonic and thermal history of four Paleozoic potential oil source formations (as well as Jurassic – Bazhenov and Tyumen Formations) has been retraced. The controversial aspects of the heat transfer model in the section of the Ostaninskoe field are considered. It has been established that the Tyumen and Bazhenov oil sources (most likely Bazhenov) are syngenetic (in terms of generation, accumulation and preservation time) for the weathering crust and the Paleozoic reservoirs. The role of the Chaginskaya Formation as gas source is insignificant.

Impact of differing heat flow solutions on hydrocarbon generation predictions: A case study from West Siberian Basin

Knowledge of the thermal history of a sedimentary basin is necessary for the quantitative and qualitative estimation of hydrocarbons generated from buried organic matter. Usually, specialists use a combination of backstripping and forward temperature modelling techniques for a basin history reconstruction. However, this approach decouples the structural and thermal solutions and therefore results in the less consistent modelling. The reliability of a basin model can be increased by using coupled approaches that resolve the structural and thermal solutions simultaneously.In this work, we investigate how using a backstripping-based versus a coupled thermo-tectono-stratigraphic approach for computing basement heat flow influences the predicted total hydrocarbon generation using a 808 km transect across the West Siberian basin as an example. Both coupled and decoupled approaches are used to reconstruct a basal heat flow history for the transect. Corresponding models have identical geological parameters and are calibrated with a set of temperature and vitrinite reflectance data. Furthermore, reconstructed heat flow histories are used separately as a lower boundary condition in a petroleum system model to evaluate the consequences for hydrocarbon generation. We find that the backstripping-based approach significantly overestimates hydrocarbon generation mass with respect to the basement heat flow solution obtained from the more consistent thermo-tectono-stratigraphic model. Also, the onset and time evolution of hydrocarbon generation is substantially different. These findings, obtained for the West Siberian Basin, show that calibrating a thermal model to the wellbore temperature and vitrinite data can lead to the inaccurate interpretation of the thermal history. The study results suggest that the presented advanced basin modelling strategy can help in decreasing risks in petroleum system analysis by providing more reliable and consistent heat flow solutions.

A Bayesian Approach for Thermal History Reconstruction in Basin Modeling

AbstractWe present a novel method for the joint inversion of thermal indicator data (vitrinite reflectance and apatite fission track) and additional data (bottom‐hole temperature and porosity) for thermal history reconstruction in basin modeling. A transdimensional and hierarchical Bayesian formulation is implemented with a reversible jump Markov chain Monte Carlo algorithm, with a 1‐D transient thermal model. The objective of the inverse problem is to infer the heat flow history below a borehole given the data and a set of geological constraints (e.g., burial histories and physical properties of the sediments). The algorithm incorporates an adaptive, data‐driven parametrization of the heat flow history, allows for automatic estimation of the relative importance of each data type and quantification of parameter uncertainties and trade‐offs. Our approach deals with uncertainties on the imposed geological constraints in two ways. First, the amount of erosion and timing of an erosional event are treated as independent parameters. Second, uncertainties on compaction parameters and surface temperature history are directly propagated into the final solution. Synthetic tests show that porosity data can be used to reduce uncertainties on the amount of erosion. This work illustrates a truly probabilistic analysis of the trade‐off between the magnitude of erosion and variations in heat flow histories which is key in basin modeling. The algorithm is then applied to real data from a well in the Barents Sea. Our algorithm can reconcile estimates of erosion from the thermal indicator and porosity data, which is a difficult and subjective task in basin modeling.

Inversion of thermal conductivity and heat flow from borehole temperature data affected by recent variation in ground surface temperature

We inverted the thermal conductivity of earth material, heat flow, and ground surface temperature (GST) history from borehole temperature data obtained at the carbon dioxide capture and storage demonstration project site in Tomakomai, Japan, by Bayesian inverse analysis. Past GST change that had disturbed the underground temperature was treated as a heat source in inversion analysis to determine thermal conductivity of the earth material from borehole temperature and underground structure data. The inverted past GST change suggested an increase of GST by 3 K from 1800 to the present. The inverted thermal conductivity of the earth material appeared to correspond to lithology in the borehole. The inverted heat flow was consistent with those measured around the site. To invert these model parameters from borehole temperature data, underground structure data are required. For inverse analysis of borehole temperature data without underground structure data, we propose a simple method for inferring underground structure related to thermal conductivity of the earth material and report the effectiveness of this method for the inversion of model parameters from borehole temperature data only.

Outdoor Test Cell Modelling with Modelica

The experimental setup implements a simplified PASSYS test cell construction, which is combined with a detailed simulation to reduce measurement effort. To analyze the cell’s dynamic behavior, the test cell was closely monitored with thermal sensors, and different static and dynamic heating modes were applied during a three-week calibration period. Co-heating tests were performed for steady-state measurements and cyclic heating periods account for the transient behavior of the test cell. The cells response was compared to the results of transient simulations with the software packet Modelica. The equation based Modelica framework allowed a detailed transient thermal simulation of the test cell’s dynamic to be set up that shows close agreement with the measurements. In addition, the flexibility of Modelica allowed unforeseen events affecting the experimental setup to be replicated, thereby ensuring an uninterrupted heat flow history of all surfaces. More than 96% of the predicted air temperatures (1 min resolution) match the experimental values within an error band of ±1.5 K, and 90% of all predictions are within ±1.0 K.

BURIAL, TEMPERATURE AND MATURATION HISTORY OF CRETACEOUS SOURCE ROCKS IN THE NW PERSIAN GULF, OFFSHORE SW IRAN: 3D BASIN MODELLING

This study presents a 3D numerical model of a study area in the NW part of the Persian Gulf, offshore SW Iran. The purpose is to investigate the burial and thermal history of the region from the Cretaceous to the present day, and to investigate the location of hydrocarbon generating kitchens and the relative timing of hydrocarbon generation/migration versus trap formation. The study area covers about 20,000 km2 and incorporates part of the intra‐shelf Garau‐Gotnia Basin and the adjacent Surmeh‐Hith carbonate platform. A conceptual model was developed based on the interpretation of 2700 km of 2D seismic lines, and depth and thickness maps were created tied to data from 20 wells. The thermal model was calibrated using bottom‐hole temperature and vitrinite reflectance data from ten wells, taking into account the main phases of erosion/non‐deposition and the variable temporal and spatial heat flow histories. Estimates of eroded thicknesses and the determination of heat‐flow values were performed by burial and thermal history reconstruction at various well and pseudo‐well locations. Burial, temperature and maturation histories are presented for four of these locations. Detailed modelling results for Neocomian and Albian source rock successions are provided for six locations in the intra‐shelf basin and the adjacent carbonate platform. Changes in sediment supply and depocentre migration through time were analyzed based on isopach maps representing four stratigraphic intervals between the Tithonian and the Recent. Backstripping at various locations indicates variable tectonic subsidence and emergence at different time periods.The modelling results suggest that the convergence between the Eurasian and Arabian Plates which resulted in the Zagros orogeny has significantly influenced the burial and thermal evolution of the region. Burial depths are greatest in the study area in the Binak Trough and Northern Depression. These depocentres host the main kitchen areas for hydrocarbon generation, and the organic‐rich Neocomian and Albian source rock successions have been buried sufficiently deeply to be thermally mature. Early oil window maturities for these successions were reached between the Late Cretaceous (90 Ma) and the early Miocene (18 Ma) at different locations, and hydrocarbon generation may continue at the present‐day.

Crustal structure and heat-flow history in the UK Rockall Basin, derived from backstripping and gravity-inversion analysis

Seismic data made available by the UK OGA (Oil & Gas Authority) has been used to constrain a model of crustal structure and heat-flow history for the UK Rockall Basin. Top basement/base sediment has been interpreted around the full extent of the seismic dataset. This has produced a model for the thickness of the sediment fill within the basin which is thicker than previous published estimates. The new sediment-thickness model has been incorporated into a 3D backstripping study, producing maps of subsidence and thinning factor. Analysis of backstripped subsidence shows the thinning factor reaching peak values of c. 0.8–0.85 (β factor >5) in the south-central axial area, reducing in magnitude northwards to c. 0.7. The new sediment-thickness model has also been incorporated into a 3D gravity-inversion study, mapping Moho depth, crustal thickness and thinning/stretching factor. The results show crustal-basement thickness reduced to c. 6 km, thinning factor c. 0.8, in the south-central area, while it spans the range c. 6–10 km further north. The results are compatible with previous seismic refraction work in both the UK and Irish sectors of the Rockall Basin. We believe that the extension which created the basin was non-magmatic and that the axial region is underlain by highly-thinned continental crust. The results from the gravity inversion have been used to make predictions about the top-basement heat-flow history. Heat flow in the basin centre is predicted to have been initially high, reducing with time, associated with cooling of the transient synrift heat-flow anomaly. On the basin flanks heat flow was less variable over time, its magnitude controlled primarily by constant radiogenic heat input from the basement, rather than by the transient geotherm anomaly. There remain considerable uncertainties associated with our interpretation and analysis. These uncertainties have been addressed with sensitivity analyses. A regional gravity-inversion model, using the new sediment-thickness data spliced into regional public-domain information, shows that structural and stretching continuity can be mapped at the crustal scale along the full length of the UK/Irish Rockall Basin, contrary to conclusions from some previous studies.

Pyrobitumen in South China: Organic petrology, chemical composition and geological significance

Pyrobitumen has been discovered in the dolostone reservoir of the Central Sichuan Basin, southwest China, accumulates coevally with hydrothermal minerals in pores. The pyrobitumen has strong anisotropy with an evolutionary sequence from mosaic to a fibrous texture. A similar sequence of anisotropy has also been observed in mesophase pitch during the process of coking coal. Reflectance of the pyrobitumen shows a positive correlation with anisotropic evolution and increasing depth. Hopane and sterane biomarkers are abundant in extracts of highly anisotropic pyrobitumen with smooth, rough, hyperplastic surface and honeycomb micropores. Methylpyrene and methylchrysene maturity indicators and the reflectance values of pyrobitumen show a positive linear correlation in Cambrian samples, but show random correlation in Sinian samples. Fluid inclusion microthermometry of hydrothermal minerals, together with the burial and heat flow history of the reservoir indicate an abrupt thermal event that may have impacted the generation and evolution of pyrobitumen. This appears to be confirmed by the reflectance values of pyrobitumen in the source rock and reservoir. The pyrobitumen in source rock was less heated by the hydrothermal fluid due to its poor porosity and have lower reflectance values. However, the pyrobitumen in weathering crust reservoir was more heated by the hydrothermal fluid and have higher reflectance values, because the reservoir rocks have higher porosity. The occurrence and characteristics of pyrobitumen indicate an in-situ pyrolysis of oil, which was triggered by an abrupt thermal event in the reservoir. The reconstruction of burial history and heat flow, as well as the hydrothermal fluid minerals of the dolomite reservoir all indicate the thermal event of the Sichuan Basin might correlate with the Emei mantle plume in Late Permian.

3D basin and petroleum system modelling of the NW German North Sea (Entenschnabel)

Abstract 3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale. Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

锦州25地区新生代古地温恢复研究

辽东湾位于渤海湾盆地东北部，是中国重要的油气产区，具有巨大的勘探潜力。本文通过现今地温场的研究，利用磷灰石裂变径迹和镜质体反射率恢复了锦州25地区的新生代热历史。研究结果表明地温梯度从38 Ma的大约36℃/km~38℃/km降低至现在的29℃/km~30℃/km，古地温演化曲线主要与所经历的埋藏史和古热流史有关。在东一段沉积末时(24.6 Ma)，地层温度达到最大为110℃左右，地温梯度在24.6 Ma至17 Ma出现了较大的波动，主要因为东一段沉积期末的构造抬升所致，至东营组沉积晚期温度逐渐降低为67℃，新近纪时期的沉积使得地层逐渐升温。此外，研究成果还揭示了该区的埋藏史和热史，可以为今后的油气资源评价奠定基础。 Located in the northeast of the Bohai Bay Basin, Liaodong Bay is the important oil producing area of China, with great exploration potential. Based on the present study of geothermal field, the Cenozoic thermal history in Jinzhou 25 area has been restored by apatite fission track and vitrinite reflectance. The results show that the geothermal gradient decreases from about 36˚C/km - 38˚C/km in 38 Ma to 29˚C/km - 30˚C/km nowadays, and the paleo geotemperature evolution curve is mainly related to the buried history and the ancient heat flow history. At the end of the east end of sedimentary period (24.6 Ma), the formation temperature reached a maximum of about 110 degrees, and the geothermal gradient had a great fluctuation from 24.6 Ma to 17 Ma, and the main reason is that the structural uplift in the end of the 1st Member of the Dongying Formation sedimentary period, the temperature decreased gradually to 67 degrees at the late stage of the Dongying formation sedimentary period, and the deposition of the Neogene Period has gradually increased the temperature. In addition, the study also reveals the burial history and thermal history of the area, which can lay a foundation for the evaluation of oil and gas resources in the future.

Reliability of very low-grade metamorphic methods to decipher basin evolution: Case study from the Markstein basin (Southern Vosges, NE France)

Low- and very low-grade metamorphic studies investigating the alteration and reaction progress of clay minerals are powerful tools to decipher the thermal evolution of sedimentary and inverted meta-sedimentary basins. Sheet silicates such as illite and chlorite are very common in sedimentary basin sequences. They can be used to determine the grade of diagenesis and low-temperature metamorphism as measured through the XRD: illite Kübler-Index (KI; illite “crystallinity” in older literature) and the chlorite Árkai-Index (ÁI; chlorite “crystallinity” in older literature), respectively. Although the ÁI method is considered to be slightly less sensitive than the KI method, a reliable correlation between both methods is often observed in metamorphic domains with a uniform heat-flow history and minor tectono-structural complexity. Complementary to these methods, the K-white mica b cell dimension provides a robust estimate of pressure facies reached in very low- to low-grade temperature domains.Here, we present a case-study from the Markstein basin located in the Southern Vosges. The lithostratigraphic units in the basin are characterized by deep marine flysch sequences of Upper Devonian to Upper Visean age and volcano-clastic sediments, respectively. The Markstein basin is surrounded by granitoids with intrusion ages between 340 and 326Ma. A previous study showed orogenic deformation characterized by regional folding, and a contact metamorphism found in an outer halo of the granitoids up to 1500m away from the contact (delineated by the occurrence of biotite). Here we present a multi-disciplinary study combining mineral assemblages, illite and chlorite “crystallinity indices”, and K-white mica b cell dimension. Our approach allows to (i) map in (great) detail the areal extent of both regional/burial metamorphic and contact metamorphic domains; (ii) reveal the metamorphic zonation within both domains; and (iii) better constrain regional/burial and contact metamorphic history. The contact metamorphic domain is characterized by the occurrence of biotite and/or actinolite and low K-white mica b cell dimensions, whereas the zone of incipient orogenic metamorphism yields KI and ÁI values of the high-grade diagenesis and anchizone with intermediate K-white b cell dimensions.

Hydrocarbon maturation modeling of Paleocene to Lower Miocene source rocks in the Niger Delta Basin: implications for hydrocarbon generation

This study evaluates the hydrocarbon generation potentials and time of generation for Paleocene to Lower Miocene source rock horizons from A-1, B-1, B-2, and C-1 wells in the Niger Delta Basin using 1D Petromod modeling software. Wells A-1, B-1 and B-2, and C-1 are located within the Central Swamp, the Coastal Swamp, and the Shallow Offshore depobelts, respectively. The thermal history was derived from the rifting–subsidence heat flow model. Maturity modeling were carried out by using Easy%Ro kinetic model and a heat flow history predicting present-day heat flow which were calibrated with measured temperature data. Results of the study suggest that these potential source rocks have attained maturity status to generate hydrocarbons, with vast differences existing in the timing of the onset of oil generation. Basin modeling suggests that Paleocene source rocks entered the oil generative window from the Oligocene to Miocene times with thermal maturity window that varies from gas generation to early-mature phase. The Eocene source rocks have also attained maturity from Miocene to Pliocene times, and their thermal maturity ranges from gas generation to early maturity stage. The Oligocene source rocks also began to generate oil during the Miocene and are currently within the early-mature to mid-mature stage. The thermal maturity window for the Lower Miocene source rocks ranges from immature to early-mature stage. The present modeling results reveals that higher levels of thermal maturity are attained in areas with high geothermal gradients and heat flow values while the cooler areas exhibits lower levels of maturation. The onset of the oil window lies at 2859 m at A-1 (Central Swamp), 3240 m at B-2 (Coastal Swamp), 4732 m at B-1 (Coastal Swamp), and 4344 m at C-1 (Shallow Offshore). The depth to the onset of oil window is found deeper in the Shallow Offshore and western parts of the study area than in the eastern and northwestern parts. The result of this study suggest that the Paleocene, Eocene, Oligocene, and Lower Miocene source rocks are the principal source rocks for oil and gas generation in the Niger Delta Basin.

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN, OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile.Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m2. The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m2.Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.

Paleo-Heat Flow Anomaly at the End of Middle Permian in NE Sichuan Basin, SW China: Did an Ocean Trough Exist?

It is an issue whether the Kaijiang-Liangping area (in the northeastern Sichuan Basin, SW China) was a controversial ocean trough during Changxing age in the late Permian-early Triassic. Some vitrinite reflectance (Ro) profiles from wells in the northeastern Sichuan Basin show obvious breaks, and the breaks are coincident with the boundary between the middle Permian and late Permian. Based on the Ro data, the heat flow history in the northeastern Sichuan Basin was reconstructed. The result shows that the heat flow reached its peak value at the end of middle Permian (~260Ma). The spatiotemporal feature of the heat flow evolution is not in agreement with the fact that there was a Kaijiang-Liangping Trough existing in the late-Permian to early Triassic. The palaeo-heat flow anomaly was, in fact, a response to the igneous activity in late middle Permian.

Phase States of Hydrocarbons in Chinese Marine Carbonate Strata and Controlling Factors for Their Formation

Chinese marine strata were mainly deposited before the Mesozoic. In the Tarim, Sichuan and Ordos Basins, the marine source rocks are made of sapropelic dark shale, and calcareous shale, and they contain type II kerogen. Because of different burial and geothermal histories, the three basins exhibit different hydrocarbon generation histories and preservation status. In the Tarim Basin, both oil and gas exist, but the Sichuan and Ordos Basins host mainly gas. The Tarim Basin experienced a high heat flow history in the Early Paleozoic. For instance, heat flow in the Late Cambrian varied between 65–75 mW/m2, but it declined thereafter and averages 43.5mW/m2 in the current time. Thus, the basin is a “warm to cold basin”. The Sichuan Basin experienced an increasing heat flow through the Early Paleozoic to Early Permian, and peaked in the latest Early Permian with heat flows of 71–77 mW/m2. Then, the heat flow declined stepwise to the current value of 53.2 mW/m2. Thus, it is a generally a high heat flow “warm basin”. The Ordos Basin has a low heat flow for most of its history (45–55 mW/m2), but experienced a heating event in the Cretaceous, with the heat flow rising to 70–80 mW/m2. Thus, this basin is a “cold to warm basin”. The Tarim Basin experienced three events of hydrocarbon accumulations. Oil accumulation formed in the late stage of Caledonian Orogeny. The generation and accumulation of oil continued in the Northern and Central Tarim (Tabei and Tazhong) till the late Hercynian Orogeny, during which, the accumulated oil cracked into gas in the Hetianhe area and Eastern Tarim (Tadong). In the Himalaya Orogeny, oil cracking occurred in the entire basin, part of the oil in the Tabei and Tazhong areas and most of the oil in the Hetianhe and Tadong areas are converted into gas. In the Sichuan Basin, another triple-episode generation and accumulation history is exhibited. In the Indosinian Orogeny, oil accumulation formed, but in the Yanshanian Orogeny, part of the oil in the eastern Sichuan Basin and most of the oil in the northeastern part was cracked into gas. In the Himalayan Orogeny, oil in the entire basin was converted into gas. The Ordos Basin experienced a double-episode generation and accumulation history, oil accumulation happened in the early Yanshanian stage, and cracked in the late stage. In general, multiple phases of heat flow history and tectonic reworking caused multiple episodes of hydrocarbon generation, oil to gas cracking, and accumulation and reworking. The phases and compositions of oil and gas are mainly controlled by thermal and burial histories, and hardly influenced by kerogen types and source rock types.

Heat-flow and subsurface temperature history at the site of Saraya (eastern Senegal)

Abstract. New temperature measurements from eight boreholes in the West African Craton (WAC) reveal superficial perturbations down to 100 m below the alteration zone. These perturbations are both related to a recent increase in the surface air temperature (SAT) and to the site effects caused by fluid circulations and/or the lower conduction in the alterites. The ground surface temperature (GST), inverted from the boreholes temperatures, increased slowly in the past (~0.4 °C from 1700 to 1940) and then, more importantly, in recent years (~1.5 °C from 1940 to 2010). This recent trend is consistent with the increase of the SAT recorded at two nearby meteorological stations (Tambacounda and Kedougou), and more generally in the Sahel with a coeval rainfall decrease. Site effects are superimposed to the climatic effect and interpreted by advective (circulation of fluids) or conductive (lower conductivity of laterite and of high-porosity sand) perturbations. We used a 1-D finite differences thermal model and a Monte-Carlo procedure to find the best estimates of these site perturbations: all the eight borehole temperature logs can be interpreted with the same basal heat-flow and the same surface temperature history, but with some realistic changes of thermal conductivity and/or fluid velocity. The GST trend observed in Senegal can be confirmed by two previous borehole measurements made in 1983 in other locations of West Africa, the first one in an arid zone of northern Mali and the second one in a sub-humid zone in southern Mali. Finally, the background heat-flow is low (31±2 mW m−2), which makes this part of the WAC more similar with the observations in the southern part (33±8 mW m−2) rather than with those in the northern part and in the Pan-African domains where the surface heat-flow is 15–20 mW m−2 higher.

MODELING OF HYDROCARBON POTENTIAL AND THERMAL MATURITY OF GONGILA SHALE, CHAD BASIN, NORTHEASTERN NIGERIA

The Bornu Basin, which represents a part of the Chad Basin in Nigeria, makes one-tenth of the total area of the Chad Basin that extends to the Republic of Niger, Chad and Cameroun. This basin is a sediment-filled broad depression straddling northeastern Nigeria and adjoining parts of the Republic of Chad. The cumulative thickness of the sedimentary rocks exceeds 3,600 metres. The Nigerian share of the Chad Basin is supposed to be a poten- tial hydrocarbon-producing basin. This is because commercial petroleum accumulations totalling over 120 billion barrels have been discovered in some parts of the basin outside Nigeria (largely in the Republic of Chad) in structurally related contiguous basins. The Gongila Formation (in the Chad Basin) is a transitional sequence between the underlying continental Bima sandstone and the overlying marine Fika shale. Determining whether the shale beds present in the Gongila Formation are matured enough to generate hydrocarbons, nine wells were used and the petro- physical parameters such as total organic carbon (TOC) and total organic matter (TOM) were calculated for each of the wells. The heat flow history of the basin was calculated by establishing the relationship between the modeled thermal maturity curve and the equivalent observed maturity parameter (vitrinite reflectance). Thereafter this calculated heat flow is used to predict thermal maturity of source rocks and the timing of hydrocarbon generation. The result obtained reveals that TOC and TOM of shale sequences in each well range from 3.58 to 27.48 wt% and from 1.15 to 8.79 wt%, respectively. Thus, TOC of the Gongila Formation exceeds the kerogen threshold of 0.5 wt% for the generation of hydrocarbons while TOM exceeds the kerogen threshold of 1 wt%. The heat flow was computed from the heat generation and was estimated to range between 33 and 75 mW/m 2 . The modeled vitrinite reflectance ranges between 0.56 and 0.76%Ro. It is concluded that the Gongila shale is a potential petroleum source rock. The temperature history is the factor controlling the maturation of organic compounds into fossil fuels. The Gongila Formation's thermal maturity,