Evaluation of Upper Triassic T3x5 Source Rocks (Western Sichuan Depression, Sichuan Basin) and their Hydrocarbon Generation and Expulsion Characteristics: Implication for Tight-Sand Gas and Shale Gas Accumulation Potential Assessment

An unconventional, continuous petroleum system consists of an accumulation of hydrocarbons that is found in low-matrix-permeability rocks and contain large amounts of hydrocarbons. Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T₃x⁵) are currently regarded as the most prolific emerging unconventional gas plays in China. The conventional and systematical evaluation of T₃x⁵ source rocks was carried out for the first time in the western Sichuan basin (WSD). Hydrocarbon generation and expulsion characteristics (including intensity, efficiency, and amount) of T₃x⁵ source rocks were investigated. Results show that T₃x⁵ source rocks are thick (generally >200 m), have high total organic content (TOC, ranging from 2.5 to 4.5 wt%), and dominated by III-type kerogen. These favorable characteristics result in a great hydrocarbon generating potential under the high thermal evolution history (R _o > 1.2%) of the area. An improved hydrocarbon generation potential methodology was applied to well data from the area to unravel the hydrocarbon generation and expulsion characteristics of T₃x⁵ source rocks in the WSD. Results indicate that the source rocks reached hydrocarbon expulsion threshold at 1.06% R _o and the comprehensive hydrocarbon expulsion efficiency was about 60%. The amount of generation and expulsion from T₃x⁵ source rocks was 3.14 × 10¹⁰ and 1.86 × 10¹⁰ t, respectively, with a residual amount of 1.28 × 10¹⁰ t within the source rocks. Continuous-type tight-sand gas was predicted to develop in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration (i.e., the hydrocarbon generation and expulsion center was located in Chengdu Sag), the Jurassic sandstone reservoirs were tight, and the gas expelled from the T₃x⁵ source rocks migrated for very short distances vertically and horizontally. The amount of gas accumulation in the Jurassic reservoirs derived from T₃x⁵ source rocks is up to 9.3 × 10⁸ t. The T₃x⁵ gas shale has good accumulation potential compared with several active US shale-gas plays. Volumetrically, the geological resource of shale gas is up to 1.05 × 10¹⁰ t. Small differences between the amounts calculated by volumetric method compared with that by hydrocarbon generation potential methodology may be due to other gas accumulations present within interbedded sands associated with the gas shales.     

Conventional and Unconventional Hydrocarbon Resource Potential Evaluation of Source Rocks and Reservoirs: A Case Study of the Upper Xiaganchaigou Formation,Western Qaidam Basin,Northwest China

The Paleogene upper Xiaganchaigou Formation (E₃²) is the most important source rock and reservoir in the Qaidam Basin. However, there are few studies on the processes of hydrocarbon accumulation in this formation; therefore, its hydrocarbon resource potential has not been estimated reasonably. This paper evaluates the hydrocarbon generation properties in light of an improved hydrocarbon generation and expulsion potential model. According to the geochemical characteristics of source rocks and the petrological features of reservoirs, the potentials of different resource types, including conventional oil, tight oil and shale oil, are quantified by combining the buoyancy-driven hydrocarbon accumulation depth (BHAD) and the lower limit for movable resource abundance. The results show that the source rocks are characterized by a large thickness (more than 1000 m), moderate organic matter content, high marginal maturity and a high conversion rate (50% hydrocarbons have been discharged before R_o?=?1%), which provide sufficient oil sources for reservoir formation. Moreover, the reservoirs in the Qaidam Basin consist mainly of low-porosity and low-permeability tight carbonates (porosity of 4.7% and permeability less than 1 mD). The maximum hydrocarbon generation, expulsion, retention and movable retention intensities at present are 350?×?10⁴ t/km², 250?×?10⁴ t/km², 130?×?10⁴ t/km² and 125?×?10⁴ t/km², respectively. The thresholds of hydrocarbon generation, expulsion and BHAD were 0.46% R_o, 0.67% R_o and 0.7% R_o, respectively. Moreover, the dynamic evolution process of hydrocarbon accumulation was divided into three evolution stages, namely, (a) initial hydrocarbon accumulation, (b) conventional hydrocarbon reservoir and shale oil accumulation and (c) unconventional tight oil accumulation. The conventional oil, tight oil and movable shale oil resource potentials were 10.44?×?10⁸ t, 51.9?×?10⁸ t and 390?×?10⁸ t, respectively. This study demonstrates the good resource prospects of E₃² in the Qaidam Basin. A comprehensive workflow for unconventional petroleum resource potential evaluation is provided, and it has certain reference significance for other petroliferous basins, especially those in the early unconventional hydrocarbon exploration stage.

     

Constraining the burial history of the Ghadames Basin, North Africa: an integrated analysis using sonic velocities, vitrinite reflectance data and apatite fission track ages

Constraining the burial history of a sedimentary basin is crucial for accurate prediction of hydrocarbon generation and migration. Although the Ghadames Basin is a prolific hydrocarbon province, with recoverable oil discovered to date in excess of 3.5 billion bbl, exploration on the eastern margin is still limited and the prospectivity of the area depends on the identification of effective source rocks and the timing of hydrocarbon generation. Sonic velocity, apatite fission track (FT) and vitrinite reflectance analysis offer three complementary methods to determine burial history and provide independent analytical techniques to evaluate the timing and amount of exhumation. The results indicate that two phases of tectonic activity had the biggest influence on basin evolution: the Hercynian (Late Carboniferous–Triassic) and Alpine (Late Mesozoic/Cenozoic) tectonic events. Exhumation during the Hercynian tectonic event increases from the SE, where an almost complete Palaeozoic section is preserved, towards the NW. This study quantifies the significant regional Alpine exhumation of the southern and eastern margins of the basin, with important implications for the timing of hydrocarbon maturation and expulsion, particularly for the Silurian source rock interval. Incorporating elevated Alpine exhumation values into burial history models for wells in the eastern (Libyan) part of the basin allows calibration with available maturity (Ro_eq) data using moderate values of Hercynian erosion. The result is preservation of the generation potential of Silurian (Tanezzuft) source rocks until maximum burial during Mesozoic/Cenozoic time, which improves the chance for preservation of hydrocarbon accumulations following entrapment.     

Deep-Lacustrine Shale Heterogeneity and Its Impact on Hydrocarbon Generation,Expulsion, and Retention: A Case Study from the Upper Triassic Yanchang Formation,Ordos Basin,China

The Chang-7 shale of the Upper Triassic Yanchang Formation was deposited in a deep-lacustrine environment in the southwest part of the Ordos Basin. It is characterized by a strong lithological heterogeneity, consisting primarily of pure shale and sandy laminated shale. This study explored the impact of sandy laminae in the thick pure shale on hydrocarbon generation, retention, and expulsion, which were rarely considered in previous studies. Based on core observation, thin section, and geochemical analysis, the hydrocarbon generation, retention, and expulsion characteristics were obtained for both pure shale and sandy laminated shale. In general, the Chang-7 shale stays at low mature to mature thermal evolution stage and has good hydrocarbon generation potential. It contains mainly Type II kerogen with an average total organic carbon (TOC) of 2.9% and average (S₁?+?S₂) of 8.2 mg/g. Compared with sandy laminated shale, pure shale contains more retained liquid hydrocarbon and has a higher amount of asphaltene and nitrogen–sulfur–oxygen (NSO) polarized components, indicating a relatively weak hydrocarbon expulsion process. The middle part of a thick pure shale retains more liquid hydrocarbon and has higher percentages of asphaltene and NSO polarized components than that of the top and basal part of the shale where sandy laminae occur. The difference in hydrocarbon retention capacity is interpreted to have been primarily caused by the comparatively higher reservoir quality of the sandy laminated shale, having higher amount of brittle minerals and larger pores than the pure shale. Polymer dissolution and nanopore adsorption are also key factors in hydrocarbon retention and component partition. Based on this study, we suggest that sandy laminated shale, which receives most of the hydrocarbon from adjacent pure shale, should be the current favorable shale oil exploration targets. Even though pure shale contains high hydrocarbon potential, its development is still pending improved technologies, which could solve the challenges caused by complicated geological conditions.

     

Numerical modelling of the hydrocarbon generation of Tertiary source rocks intruded by doleritic sills in the Zhanhua depression,Bohai Bay Basin,China

An igneous hydrocarbon reservoir had been found in the Zhanhua depression, Bohai Bay Basin, eastern China. Two doleritic sills successively intruded into the immature source rock of the third member of the Shahejie Formation (Es3). The heat released from the magma changed the mineral composition of wall rocks and accelerated the maturity of organic matter. Thin hornfels and carbargilite zones were found next to the sills. The vitrinite reflectances (%R_o) of these heated wall rocks increased to at least 1.4% near the contacts (<50 m), and accumulation of oil was found in the hornfels zone and dolerite bodies. With the aim of understanding the influence of the sills on the hydrocarbon generation process, a complex heat conduction model was used to simulate the thermal history of the organic‐rich wall rocks, in which both the latent heat of crystallization of intrusions and vapourization heat of pore water in wall rocks were considered. The simulation results suggested that the cooling of each sill continued for about 0.1 Ma after its emplacement and the temperature of wall rocks was considerably raised. The peak temperature (T_peak) that wall rocks experienced can reach 460–650°C in the region of 10 m away from the contacts. The thermal model was qualitatively verified by comparing the experimental data of vitrinite reflectances and mineral geothermometers of the wall rocks with the simulation results. Furthermore, we modelled the hydrocarbon generation of the source rocks based on the simulated thermal history. In the region of about 100 m from the contacts, the organic matter was heated and partially transformed into hydrocarbon within only a few 1000 years, which was significantly faster than the normal burial generation process.     

Uncertainty analysis and the relative contributions of geological factors for the Qingshankou source rocks in the North Songliao Basin, northeastern China

Source rock evaluation is a critical factor in resource assessment of oil and gas. Models for evaluating source rocks are dependent on established geomathematical principles, the calculation of source-rock parameters, and geological data. The sensitivities and uncertainties associated with these models are a matter of concern. In this paper, the effects and relative contributions of 13 major geological factors, as well as their variations and distribution probabilities, have been analyzed for the source rocks in the North Songliao Basin in northeastern China. The geological factors include the time of formation of the regional caprock, composition of the regional caprock, the phases of hydrocarbons in migration, and those factors associated with the generation, retention, and expulsion of hydrocarbons and their effects on source-rock efficiency. Of the 13 factors analyzed, the most important are the source-rock depth, sedimentation rate, total organic content, and kerogen-type index; the relative contributions to the uncertainty of efficient gas/oil migration amounts for the most important factors are 37, 25, 19, and 1% for oil and 32, 17, 20, and 15% for gas, respectively. These most reflect the changes that have occurred in the Qingshankou source rocks.     

Quantitative evaluation of coal as source rocks

Gas generated and expelled from coals often results in economic gas accumulations. As a consequence, it is important to consider the theoretical aspects of these processes and to develop methods that can be used to assess coal as a potential source rock. On the basis of results of modeling hydrocarbon generation, expulsion, and retention in coals, two comprehensive indexes are proposed for assessing the quality and the nature of coal as a potential source rock. Theoretical charts of the two indexes are used to assess coals as potential source rocks in the Turpan-Hami Basin in northwestern China.     

Geochemical Characteristics of Oil from Oligocene Lower Ganchaigou Formation Oil Sand in Northern Qaidam Basin,China

Oil from the Oligocene oil sands of the Lower Ganchaigou Formation in the Northern Qaidam Basin and the related asphaltenes was analyzed using bulk and organic geochemical methods to assess the organic matter source input, thermal maturity, paleo-environmental conditions, kerogen type, hydrocarbon quality, and the correlation between this oil and its potential source rock in the basin. The extracted oil samples are characterized by very high contents of saturated hydrocarbons (average 62.76%), low contents of aromatic hydrocarbons (average 16.11%), and moderate amounts of nitrogen–sulfur–oxygen or resin compounds (average 21.57%), suggesting that the fluid petroleum extracted from the Oligocene oil sands is of high quality. However, a variety of biomarker parameters obtained from the hydrocarbon fractions (saturated and aromatic) indicate that the extracted oil was generated from source rocks with a wide range of thermal maturity conditions, ranging from the early to peak oil window stages, which are generally consistent with the biomarker maturity parameters, vitrinite reflectance (approximately 0.6%), and T_max values of the Middle Jurassic carbonaceous mudstones and organic-rich mudstone source rocks of the Dameigou Formation, as reported in the literature. These findings suggest that the studied oil is derived from Dameigou Formation source rocks. Furthermore, the source- and environment-related biomarker parameters of the studied oil are characterized by relatively high pristane/phytane ratios, the presence of tricyclic terpanes, low abundances of C₂₇ regular steranes, low C₂₇/C₂₉ regular sterane ratios, and very low sterane/hopane ratios. These data suggest that the oil was generated from source rocks containing plankton/land plant matter that was mainly deposited in a lacustrine environment and preserved under sub-oxic to oxic conditions, and the data also indicate a potential relationship between the studied oil and the associated potential source rocks. The distribution of pristane, phytane, tricyclic terpanes, regular steranes and hopane shows an affinity with the studied Oligocene Lower Ganchaigou Formation oil to previously published Dameigou Formation source rocks. In support of this finding, the pyrolysis–gas chromatography results of the analyzed oil asphaltene indicate that the oil was primarily derived from type II organic matter, which is also consistent with the organic matter of the Middle Jurassic source rocks. Thus, the Middle Jurassic carbonaceous mudstones and organic rock mudstones of the Dameigou Formation could be significantly contributing source rocks to the Oligocene Lower Ganchaigou Formation oil sand and other oil reservoirs in the Northern Qaidam Basin.

     

H<Subscript>2</Subscript>-rich and Hydrocarbon Gas Recovered in a Deep Precambrian Well in Northeastern Kansas

In late 2005 and early 2006, the WTW Operating, LLC (W.T.W. Oil Co., Inc.) #1 Wilson well (T.D. = 5772 ft; 1759.3 m) was drilled for 1826 ft (556.6 m) into Precambrian basement underlying the Forest City Basin in northeastern Kansas. Approximately 4500 of the 380,000 wells drilled in Kansas penetrate Precambrian basement. Except for two previous wells drilled into the arkoses and basalts of the 1.1-Ga Midcontinent Rift and another well drilled in 1929 in basement on the Nemaha Uplift east of the Midcontinent Rift, this well represents the deepest penetration into basement rocks in the state to date. Granite is the typical lithology observed in wells that penetrate the Precambrian in the northern Midcontinent. Although no cores were taken to definitively identify lithologies, well cuttings and petrophysical logs indicate that this well encountered basement metamorphic rocks consisting of schist, gneiss, and amphibolitic gneiss, all cut by aplite dikes. The well was cased and perforated in the Precambrian, and then acidized. After several days of swabbing operations, the well produced shows of low-Btu gas, dominated by the non-flammable component gases of nitrogen (20%), carbon dioxide (43%), and helium (1%). Combustible components include methane (26%), hydrogen (10%), and higher molecular-weight hydrocarbons (1%). Although Coveney and others [Am. Assoc. Petroleum Geologists Bull., v. 71, no, 1, p. 39–48, 1987] identified H₂-rich gas in two wells located close to the Midcontinent Rift in eastern Kansas, this study indicates that high levels of H₂ may be a more widespread phenomenon than previously thought. Unlike previous results, the gases in this study have a significant component of hydrocarbon gas, as well as H₂, N₂, and CO₂. Although redox reactions between iron-bearing minerals and groundwater are a possible source of H₂ in the Precambrian basement rocks, the hydrocarbon gas does not exhibit the characteristics typically associated with proposed abiogenic hydrocarbon gases from Precambrian Shield sites in Canada, Finland, and South Africa. Compositional and isotopic signatures for gas from the #1 Wilson well are consistent with a predominantly thermogenic origin, with possible mixing with a component of microbial gas. Given the geologic history of uplift and rifting this region, and the major fracture systems present in the basement, this hydrocarbon gas likely migrated from source rocks and reservoirs in the overlying Paleozoic sediments and is not evidence for abiogenic hydrocarbons generated in situ in the Precambrian basement.     

Overpressures and hydrocarbon generation in the Sable sub-basin, offshore Nova Scotia

One of several interconnected depocentres lying offshore eastern Canada, the Sable sub-basin preserves a thick sequence of Mesozoic-Cenozoic clastic sediments, significant gas accumulations and an extensive development of abnormal pressures. In order to understand the basin's hydrocarbon generation, migration and accumulation history it is necessary to quantify the interplay between its burial, thermal, and maturation history, and to determine the influence on these of the basin's excess pressure history. Simple, one-dimensional reconstructions of maturity and pore pressure histories are derived for exploration well and pseudo-well locations on a seismic line running from the basin's structural high to its depocentre. Calibrated, where possible, by reference to measured maturity, temperature and pressures, these models provide a basic dynamic framework within which it is possible to consider the generation history of the basin's source rocks. Late Jurassic to Early Cretaceous sediments underwent an initial rapid, rift-related subsidence. The thermal/maturation models suggest that source rocks lying within these intervals quickly matured and began generating gas and condensates. Similarly, this rapid burial was translated, through sediment compaction disequilibrium processes, into an early expression of abnormal pressures. The pore pressure/time reconstructions in the modelling assume that sediment compaction disequilibrium and gas generation are the principal causal mechanisms. Matching pore pressure reconstructions with present-day pressure-depth profiles is particularly sensitive to assumed seal permeability profiles. Although the seal permeabilities used as model input are based on actual measured permeabilities at the present day, this does not mean that the permeability-time curves derived through the model's decompaction assumptions accurately reflect seal permeability evolution.     

Spatial coupling relationships of gas hydrate formation in the Tibetan Plateau

At present, gas hydrates are known to occur in continental high latitude permafrost regions and deep sea sediments. For middle latitude permafrost regions of the Tibetan Plateau, further research is required to ascertain its potential development of gas hydrates. This paper reviewed pertinent literature on gas hydrates in the Tibetan Plateau. Both geological and ge- ographical data are synthesized to reveal the relationship between gas hydrate formation and petroleum geological evo- lution, Plateau uplift, formation of permafrost, and glacial processes. Previous studies indicate that numerous residual basins in the Plateau have been formed by original sedimentary basins accompanied by rapid uplift of the Plateau. Ex- tensive marine Mesozoic hydrocarbon source rocks in these basins could provide rich sources of materials forming gas hydrates in permafrost. Primary hydrocarbon-generating period in the Plateau is from late Jurassic to early Cretaceous, while secondary hydrocarbon generation, regionally or locally, occurs mainly in the Paleogene. Before rapid uplift of the Plateau, oil-gas reservoirs were continuously destroyed and assembled to form new reservoirs due to structural and thermal dynamics, forcing hydrocarbon migration. Since 3.4 Ma B.P., the Plateau has undergone strong uplift and extensive gla- ciation, periglacier processes prevailed, hydrocarbon gas again migrated, and free gas beneath ice sheets within sedi- mentary materials interacted with water, generating gas hydrates which were finally preserved under a cap formed by frozen layers through rapid cooling in the Plateau. Taken as a whole, it can be safely concluded that there is great temporal and spatial coupling relationships between evolution of the Tibetan Plateau and generation of gas hydrates.     

A Simple Way to Model Nonsynchronous Generation of Oil and Gas from Kerogen

Many kinetic models for oil and gas generation use the same kinetics for generation of both oil and gas. In these models, gas is generated at precisely the same time as oil, despite agreement among geochemists that oil generation in nature largely precedes gas generation. Here we present a method for deriving separate kinetics for oil generation and gas generation from the available kinetics for total hydrocarbon generation. The method is based on published data in which oil kinetics are compiled separately from gas kinetics, but it is generalized to be applicable to any of the main kerogen types (I, IIa, IIb, or III), or to any mixtures of those types. Application of this new nonsynchronous model shows that the traditional synchronous models overpredict gas generation by about a factor of two within the oil window, and conversely severely underpredict late gas generation. The nonsynchronous model may predict gas generation several tens of million years later than does the synchronous model. The errors inherent in the synchronous models can be of significance in exploration decisions.     

Relevance of Pentane- and Hexane-Utilizing Bacterial Indicators for Finding Hydrocarbon Microseepage: A Study from Jamnagar Sub-basin, Saurashtra, Gujarat, India

Mesozoic sediments are source rocks for nearly half the world’s hydrocarbon reserves. Hence, there is great interest in the oil industry to know the trap and sub-trappean sediment thickness and their extent in the trap covered regions of Jamnagar study area. The microbial prospecting method is applied in the Jamnagar sub-basin, Gujarat for evaluating the prospects for hydrocarbon exploration by investigating the anomalous abundance of n-pentane- and n-hexane-oxidizing bacteria of this area. A total of 150 near-surface soil samples were collected in Jamnagar sub-basin, Gujarat for the evaluation of hydrocarbon resource potential of the basin. In this study, bacterial counts for n-pentane-utilizing bacteria range between 1.09 × 10² and 9.89 × 10⁵ cfu/g and n-hexane-utilizing bacteria range between 1.09 × 10² and 9.29 × 10⁵ cfu/g. The adsorbed hydrocarbon gases consisting of ethane plus hydrocarbons (ΣC₂₊) of 1–977 ppb and n-pentane (nC₅) of 1–23 ppb. The integrated geomicrobial and adsorbed soil gas studies showed the anomalous hydrocarbon zones nearby Khandera, Haripur, and Laloi areas which could probably aid to assess the true potential of the basin. Integrated geophysical studies have shown that Jamnagar sub-basin of Saurashtra has significant sediment thickness below the Deccan Traps and can be considered for future hydrocarbon exploration.     

Characterization of Late Cretaceous to Miocene source rocks in the Eastern Mediterranean Sea: An integrated numerical approach of stratigraphic forward modelling and petroleum system modelling

Stratigraphic forward modelling was used to simulate the deposition of Upper Cretaceous, Eocene and Oligo‐Miocene source rocks in the Eastern Mediterranean Sea and, thus, obtain a process‐based 3D prediction of the quantity and quality distribution of organic matter (OM) in the respective intervals. Upper Cretaceous and Eocene models support the idea of an upwelling‐related source rock formation along the Levant Margin and the Eratosthenes Seamount (ESM). Along the margin, source rock facies form a narrow band of 50 km parallel to the palaeo shelf break, with high total organic carbon (TOC) contents of about 1% to 11%, and HI values of 300–500 mg HC/g TOC. On top of the ESM, TOC contents are mainly between 0.5% and 3% and HI values between 150 and 250 mg HC/g TOC. At both locations, TOC and HI values decrease rapidly towards the deeper parts of the basin. In the Oligo‐Miocene intervals, terrestrial OM makes up the highest contribution to the TOC content, as marine organic matter (OM) is diluted by high‐sedimentation rates. In general, TOC contents are low (<1%), but are distributed relatively homogenously throughout the whole basin, creating poor quality, but very thick source rock intervals of 1–2 km of cumulative thickness. The incorporation of these source rock models into a classic petroleum system model could identify several zones of thermal maturation in the respective source rock intervals. Upper Cretaceous source rocks started petroleum generation in the late Palaeocene/early Eocene with peak generation between 20 and 15 Ma ca. 50 km offshore northern Lebanon. Southeast of the ESM, generation started in the early Eocene with peak generation between 18 and 15 Ma. Eocene source rocks started HC generation ca. 25 Ma ago between 50 and 100 km southeast of the ESM and reached the oil to wet gas window at present day. However, until today they have converted less than 20% of their initial kerogen. Although the Miocene source rocks are mostly immature, Oligocene source rocks lie within the oil window in the southern Levant Basin and reached the onset of the wet gas window in the northern Levant Basin. However, only 10%–20% of their initial kerogen have been transformed to date.     

Constraining basin thermal history and petroleum generation using palaeoclimate data in the Piceance Basin,Colorado

Careful assessment of basin thermal history is critical to modelling petroleum generation in sedimentary basins. In this paper, we propose a novel approach to constraining basin thermal history using palaeoclimate temperature reconstructions and study its impact on estimating source rock maturation and hydrocarbon generation in a terrestrial sedimentary basin. We compile mean annual temperature (MAT) estimates from macroflora assemblage data to capture past surface temperature variation for the Piceance Basin, a high‐elevation, intermontane, sedimentary basin in Colorado, USA. We use macroflora assemblage data to constrain the temporal evolution of the upper thermal boundary condition and to capture the temperature change with basin uplift. We compare these results with the case where the upper thermal boundary condition is based solely upon a simplified latitudinal temperature estimate with no elevation effect. For illustrative purposes, 2 one‐dimensional (1‐D) basin models are constructed using these two different upper thermal boundary condition scenarios and additional geological and geochemical input data in order to investigate the impact of the upper thermal boundary condition on petroleum source rock maturation and kerogen transformation processes. The basin model predictions indicate that the source rock maturation is very sensitive to the upper thermal boundary condition for terrestrial basins with variable elevation histories. The models show substantial differences in source rock maturation histories and kerogen transformation ratio over geologic time. Vitrinite reflectance decreases by 0.21%Ro, source rock transformation ratio decreases 10.5% and hydrocarbon mass generation decreases by 16% using the macroflora assemblage data. In addition, we find that by using the macroflora assemblage data, the modelled depth profiles of vitrinite reflectance better matches present‐day measurements. These differences demonstrate the importance of constraining thermal boundary conditions, which can be addressed by palaeotemperature reconstructions from palaeoclimate and palaeo‐elevation data for many terrestrial basins. Although the palaeotemperature reconstruction compiled for this study is region specific, the approach presented here is generally applicable for other terrestrial basin settings, particularly basins which have undergone substantial subaerial elevation change over time.     

Artificial Maturation of Organic Matter from Recent Venezuelan Sediments

Laboratory simulation of the catagenesis of organic matter in sedimentary rocks has been used to provide an understanding of the processes involved in petroleum generation. Several of these studies have focused on the thermal evolution of organic matter (OM) present in Recent sediments. This study examines the geochemical characteristics and experimental thermal evolution of primary organic matter from two organic facies that are thought to be major contributors to Venezuelan hydrocarbon source rocks. A third facies, generally considered unimportant for petroleum formation, is used to contrast the experimental results. Hydrous pyrolysis maturation experiments were performed for three intermediate temperatures. The products of the final 330°C stage are shown in this paper because they best illustrate the changes in the OM during catagenesis. Results from the hydrous pyrolysis experiments show that at 280°C and higher all three samples yield liquid hydrocarbons similar in composition to natural crudes and the transformed organic matter is similar to kerogen that occurs in natural source rocks. Chromatograms from the saturated fraction of extracts at 330°C are similar to natural crudes with respect to n-alkane distribution and abundance of beta; and beta;alpha; hopanes. The only difference seems to be the relative abundance of 22R over 22S isomers, which indicates immature oil. This is in contrast to indications from the R _o and T _max parameters measured on the accompanying kerogen.     

南极罗斯海盆地油气地质条件及资源潜力研究

罗斯海位于罗斯海湾北部、南极太平洋扇形区,该区域的罗斯海盆地是南极最具资源潜力的盆地之一,可进一步分为维多利亚地盆地、北部盆地、中央海槽和东部盆地四个次级单元。在对区域地层特征、地震地层特征进行总结归纳后,也分析了盆地的构造、沉积、温压及烃类地化条件,认为罗斯海盆地具有较好的油气地质条件。以二维地震、钻孔资料为基础,对盆地成熟度及生烃量进行了模拟。研究认为:东部盆地与维多利亚地盆地油气生成区均较广,但后者的源岩热演化程度较前者稍高,而中央海槽与北部盆地在油气生成区域及热演化程度方面均较差;根据生烃量模拟结果,同时选择合理的排聚系数,推测罗斯海盆地的地质资源量约为91.5亿吨。     

Unconventional Energy Resources: 2007–2008 Review

This paper summarizes five 2007–2008 resource commodity committee reports prepared by the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. Current United States and global research and development activities related to gas hydrates, gas shales, geothermal resources, oil sands, and uranium resources are included in this review. These commodity reports were written to advise EMD leadership and membership of the current status of research and development of unconventional energy resources. Unconventional energy resources are defined as those resources other than conventional oil and natural gas that typically occur in sandstone and carbonate rocks. Gas hydrate resources are potentially enormous; however, production technologies are still under development. Gas shale, geothermal, oil sand, and uranium resources are now increasing targets of exploration and development, and are rapidly becoming important energy resources that will continue to be developed in the future.

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The Astrakhan Arch of the Pricaspian basin: Geothermal analysis and modelling

The Astrakhan Arch (ASAR) region contains one of the largest sub‐salt carbonate structures of the Pricaspian salt basin (located to the northwest of the Caspian Sea), where prospects for hydrocarbon generation and accumulation in the Devonian to Carboniferous deposits are considered to be high. We evaluate the regional vertical temperature gradient within stratigraphic units based on the analysis of 34 boreholes drilled in the region. To show that the thermal gradient is altered in the vicinity of salt diapirs, we study measured temperatures in six deep boreholes. We develop a three‐dimensional geothermal model of the ASAR region constrained by temperature measurements, seismic stratigraphic and lithological data. The temperatures of the sub‐salt sediments predicted by the geothermal model range from about 100 °C to 200 °C and are consistent with the temperatures obtained from the analysis of vitrinite reflectivity and from previous two‐dimensional geothermal models. Temperature anomalies are positive in the uppermost portions of salt diapirs as well as within the salt‐withdrawal basins at the depth of 3.5 km depth and are negative beneath the diapirs. Two areas of positive temperature anomalies in the sub‐salt sediments are likely to be associated with the deep withdrawal basins above and with the general uplift of salt/sub‐salt interface in the southern part of the study region. This implies an enhancement of thermal maturity of any organically rich source rocks within these areas. The surface heat flux in the model varies laterally from about 40 to 55 mW m^?2. These variations in the heat flux are likely to be associated with structural heterogeneities of the sedimentary rocks and with the presence of salt diapirs. The results of our modelling support the hypothesis of oil and gas condensate generation in the Upper Carboniferous to Middle Devonian sediments of the ASAR region.     

Information gain in prospect assessment by using basin modeling

To enhance the quality of oil- and gas-resource assessments and to reduce the risks in oil and gas exploration, a number of assessment techniques have been developed. Unfortunately, these techniques have not always been effective in the timely transfer of information. The amount of time that is required for preparing assessments does not always allow for the necessary high-quality data to be generated. To overcome this problem, a method based on an analysis of the phase state of oil and the dynamics of fluids in secondary migration of hydrocarbons is proposed. The phase state of the oil and fluid potential for secondary migration is estimated initially for each prospect together with the extent of the drainage area. On the basis of these estimates, statistical calculations can be made for the generation and expulsion of hydrocarbons. As a result, more reliable data are available for prospect assessment. The application of this method has a practical significance in that it brings the role of basin modeling in prospect assessment into full play, increases the reliability of petroleum-resource assessments, and reduces the risks in exploration. A case study from the Beitang region in eastern China is presented.