Hydrocarbon compositions of bitumens from mineralized Devonian lavas and Carboniferous sedimentary rocks, central Scotland

Solid bitumens occur in mineralized veins in the Lower Devonian Ochil Volcanic Formation in the Midland Valley of Scotland. Bitumens are also widespread in the Carboniferous of the Midland Valley. Gas chromatography (g.c.) - mass spectrometry (m.s.) studies undertaken on bitumens from the Devonian rocks and on Devonian and Carboniferous mudrocks show that the bitumens contain biomarkers and that Carboniferous rocks are the more likely source for the bitumens. Hydrocarbons may have migrated into the Devonian rocks along the Ochil Fault zone from a downthrown Carboniferous basin to the south of the fault. The organic geochemistry of bitumen samples from the Carboniferous rocks reflects varying degrees of biodegradation, and heating by igneous intrusions.     

Oil/gas–source rock correlations in the Dniepr-Donets Basin (Ukraine): New insights into the petroleum system

The Dniepr-Donets Basin (DDB) hosts a multi-source petroleum system with more than 200 oil and gas fields, mainly in Carboniferous clastic rocks. Main aim of the present study was to correlate accumulated hydrocarbons with the most important source rocks and to verify their potential to generate oil and gas. Therefore, molecular and isotopic composition as well as biomarker data obtained from 12 oil and condensate samples and 48 source rock extracts was used together with USGS data for a geological interpretation of hydrocarbon charging history.Within the central DDB, results point to a significant contribution from (Upper) Visean black shales, highly oil-prone as well as mixed oil- and gas-prone Serpukhovian rocks and minor contribution from an additional Tournaisian source. Devonian rocks, an important hydrocarbon source within the Pripyat Trough, have not been identified as a major source within the central DDB. Additional input from Bashkirian to Moscovian (?) (Shebelinka Field) as well as Tournaisian to Lower Visean rocks (e.g. Dovgal Field) with higher contents of terrestrial organic matter is indicated in the SE and NW part, respectively.Whereas oil–source correlation contradicts major hydrocarbon migration in many cases for Tournaisian to Middle Carboniferous reservoir horizons, accumulations within Upper Carboniferous to Permian reservoirs require vertical migration up to 4000 m along faults related to Devonian salt domes.1-D thermal models indicate hydrocarbon generation during Permo-Carboniferous time. However, generation in coal-bearing Middle Carboniferous horizons in the SE part of the basin may have occurred during the Mesozoic.     

Organic geochemistry of marine source rocks and pyrobitumen-containing reservoir rocks of the Sichuan Basin and neighbouring areas,SW China

Three bitumen fractions were obtained and systematically analysed for the terpane and sterane composition from 30 Paleozoic source rocks and 64 bitumen-containing reservoir rocks within the Upper Sinian, Lower Cambrian, Lower Silurian, Middle Carboniferous, Upper Permian and Lower Triassic strata in the Sichuan Basin and neighbouring areas, China. These bitumen fractions include extractable oils (bitumen I), oil-bearing fluid inclusions and/or closely associated components with the kerogen or pyrobitumen/mineral matrix, released during kerogen or pyrobitumen isolation and demineralization (bitumen II), and bound compounds within the kerogen or pyrobitumen released by confined pyrolysis (bitumen III). In addition, atomic H/C and O/C ratios and carbon isotopic compositions of kerogen and pyrobitumen from some of the samples were measured. Geochemical results and geological information suggest that: (1) in the Central Sichuan Basin, hydrocarbon gases in reservoirs within the fourth section of the Upper Sinian Dengying Formation were derived from both the Lower Cambrian and Upper Sinian source rocks; and (2) in the Eastern Sichuan Basin, hydrocarbon gases in Middle Carboniferous Huanglong Formation reservoirs were mainly derived from Lower Silurian source rocks, while those in Upper Permian and Lower Triassic reservoirs were mainly derived from both Upper Permian and Lower Silurian marine source rocks. For both the source and reservoir rocks, bitumen III fractions generally show relatively lower maturity near the peak oil generation stage, while the other two bitumen fractions show very high maturities based on terpane and sterane distributions. Tricyclic terpanes evolved from the distribution pattern C₂₀ < C₂₁ < C₂₃, through C₂₀ < C₂₁ > C₂₃, finally to C₂₀ > C₂₁ > C₂₃ during severe thermal stress. The concentration of C₃₀ diahopane in bitumen III (the bound components released from confined pyrolysis) is substantially lower than in the other two bitumen fractions for four terrigenous Upper Permian source rocks, demonstrating that this compound originated from free hopanoid precursors, rather than hopanoids bound to the kerogen.     

Preliminary organic petrography of Palaeozoic rocks from the Grand Banks,Newfoundland

Samples of lower Palaeozoic bedrock from the Grand Banks of Newfoundland were examined using reflected light microscopy and Rock-Eval pyrolysis. These samples contained organic material which included bitumen (structureless organic material), acritarchs, chitinozoa, scolecodonts and graptolites. The reflectance of the organic material increased from acritarchs towards graptolites with bitumen showing a wide range of reflectance. Multiple phases of oil migration through one sample were inferred by examination of the bitumens: the lowest reflecting being more recent than the highest reflecting bitumen. Combined reflectance and Rock-Eval analysis indicate that these samples are mature to overmature. The two oldest samples (Arenig-Llanvirn, Ordovician) are assessed as mature and as having potential for generation of liquid hydrocarbons, but must be considered as mainly gas prone.     

Oil-bearing inclusions in vein quartz and calcite and,bitumens in veins: Testament to multiple phases of hydrocarbon migration in the Barrandian basin (lower Palaeozoic), Czech Republic

The petroleum charge history of the Barrandian basin was investigated by analysing quartz and calcite and organic phases that occur in veins and fractures cutting dolerite sills within the Liteň Formation (Silurian). The geochemical characteristics of fluid inclusions trapped in vein quartz and calcite, vein bitumens and adjacent potential source rocks when combined with burial and thermal history data reflect the presence of at least three separate hydrocarbon charge episodes. Solid highly reflecting (R_max = 0.92–1.49%) bitumen provides information on the first and oldest episode of oil migration. The precursor oil was probably derived relatively early during diagenesis from nearby organic-rich sediments and was subsequently thermally altered to form the solid bitumen.     

Evaluation of burial history, thermal maturity and source-rock assessment of the Upper Paleozoic succession of the eastern Taurus region, southern Turkey

The regional burial history pattern, thermal maturity variations and source rock assessment of the sedimentary succession in the eastern Taurus region, in the southern part of Turkey, have been studied on surface samples collected from the six different sections which represent the entire region. Organic petrography (Thermal Alteration Index) and geochemical data (TOC content, T_max and HI values) were obtained from transmitted-light microscopy and Rock-Eval pyrolysis.The Lower Paleozoic (Cambrian, Ordovician and Silurian) strata were not investigated and modeled in terms of the maturity and hydrocarbon source rock potential, because of their poor organic matter content and their over maturity resulting from great burial depth (more than 7630 m). Other Paleozoic strata, except the Lower Devonian Ayitepesi Formation, generally have the values of more than 0.5% TOC. Organic matter of the Middle Devonian Safaktepesi sediments are composed of highly terrestrial organic material (type III kerogen), while samples from other three formations (Gumusali, Ziyarettepe and Yigilitepe Formations), while samples from other organic matter (type II and type III kerogen). The average TAI values are as high as 3.4 (equivalent to 1.42 of R₀%) for Ayitepesi and as low as 2.75 (equivalent to 0.77 of R₀%) for Yigilitepe Formations. Time-temperature index values (TTI) indicate that Ziyarettepe and Yigilitepe sediments are marginally mature to mature, while the Devonian strata are overmature. There are minor discrepancies between ΣTTI values and geochemical data in terms of the organic maturity for Devonian strata. In contrast, the e is a consistency between those values for the Ziyarettepe and the Yigilitepe Formations. The onset of oil generation time in the region was initiated from as early as the Norian (216 Ma) to as late as the Lutetian (45 Ma).Regional variations in the level of thermal and source-rock maturities of the Upper Paleozoic sediments in the eastern Taurus region largely depend on burial depth.     

Analysis and evaluation of coral reef integrity based on borehole camera technology

At present, very few drilling surveys have been conducted on coral reefs, and comprehensive geological info on coral reefs is difficult to obtain. However, research on coral reefs is of great importance to development and exploitation of maritime resources. In the survey of Chenhang Island in Paracel (Xisha) Islands, we applied the digital borehole camera technology the first time in China, which resulted in a large amount of first-hand geological data. We utilized the rock mass integrity index (RMDI) method in our analysis of coral reef integrity, and the value of coefficient α in the RMDI was determined to evaluate the size effect of cavities on coral reefs. We then developed the correlation between RMDI values and coral reef integrity with references to the rock mass classification standard, which enabled the engineering evaluation of coral reef integrity. By statistical analysis of camera data gathered along the CK2 borehole for approximately 1-km length, we performed an integrity evaluation of the entire borehole length using the RMDI classification and created a coral reef stratum development diagram that was consistent with the actual cores. The results indicated: (1) the RMDI is a feasible approach for the analysis of coral reef integrity, (2) the classification system based on RMDI is feasible in the integrity evaluation of coral reefs, (3) the values of coral reef integrity obtained using the RMDI method are accurate, and (4) borehole camera survey and statistical analysis are important in the study of coral reefs.     

海南岛鹿回头珊瑚礁研究进展

前人在海南岛鹿回头珊瑚礁区所做的工作主要集中于以下三方面：(1)鹿回头珊瑚礁区地貌的粗略描述;(2)鹿回头珊瑚礁记录的古海平面研究：(3)鹿回头珊瑚礁记录的现代环境信息研究。通过野外实地考察,将鹿回头珊瑚礁分为8个生物地貌带：礁前斜坡活珊瑚带、礁缘砾石突起脊带、外礁坪带、中礁坪带、内礁坪带、海滩、沙堤、洼地,它们是全新世海平呵和气候环境变化的产物。关于本区珊瑚礁的研究,结合全球珊瑚礁与环境的研究来看,许多工作有待于展开和补充,大致可从以下4个方面进行深入研究：(1)珊瑚礁的生物地貌过程;(2)珊瑚及珊瑚礁的高分辨率环境记录;(3)珊瑚对海洋环境污染的记录：(4)珊瑚礁生态系统与社会、经济及人文系统的关系及其可持续发展。     

Hydrocarbon source rock potential in the southwestern Gulf of Suez graben: Insights from organic geochemistry and palynofacies studies on well samples from the Ras El Bahar Oilfield

Palynological and biomarker characteristics of organic facies recovered from Cretaceous–Miocene well samples in the Ras El Bahar Oilfield, southwest Gulf of Suez, and their correlation with lithologies, environments of deposition and thermal maturity have provided a sound basis for determining their source potential for hydrocarbons. In addition to palynofacies analysis, TOC/Rock-Eval pyrolysis, kerogen concentrates, bitumen extraction, carbon isotopes and saturated and aromatic biomarkers enable qualitative and quantitative assessments of sedimentary organic matter to be made. The results obtained from Rock-Eval pyrolysis and molecular biomarker data indicate that most of the samples come from horizons that have fair to good hydrocarbon generation potential in the study area. The Upper Cretaceous–Paleocene-Lower Eocene samples contain mostly Type-II to Type-III organic matter with the capability of generating oil and gas. The sediments concerned accumulated in dysoxic–anoxic marine environments. By contrast, the Miocene rocks yielded mainly Type-III and Type-II/III organic matter with mainly gas-generating potential. These rocks reflect deposition in a marine environment into which there was significant terrigenous input. Three palynofacies types have been recognized. The first (A) consists of Type-III gas-prone kerogen and is typical of the Early–Middle Miocene Belayim, Kareem and upper Rudeis formations. The second (B) has mixed oil and gas features and characterizes the remainder of the Rudeis Formation. The third association (C) is dominated by amorphous organic matter, classified as borderline Type-II oil-prone kerogen, and is typical of the Matulla (Turonian–Santonian) and Wata (Turonian) formations. Rock-Eval T_max, PI, hopane and sterane biomarkers consistently indicate an immature to early mature stage of thermal maturity for the whole of the studied succession.     

Organic geochemical study of source rocks and natural gas and their genetic correlation in the eastern part of the Polish Outer Carpathians and Palaeozoic–Mesozoic basement

Geochemical characteristics of organic matter in the profiles of Dukla, Silesian, Sub-Silesian and Skole units of the Polish Outer Carpathians and of the Palaeozoic–Mesozoic basement in the Dębica-Rzeszów-Leżajsk-Sanok area were established based on Rock-Eval, vitrinite reflectance, isotopic and biomarker analyses of 485 rock samples. The Oligocene Menilite beds have the best hydrocarbon potential of all investigated formations within the Dukla, Silesian, and Skole units. The Ordovician, Silurian, Lower Devonian and locally Middle Jurassic strata of the Palaeozoic–Mesozoic basement are potential source rocks for oil and gas accumulated in Palaeozoic and Mesozoic reservoirs. Thirty one natural gas samples from sandstone reservoirs of the Lower Cretaceous-Lower Miocene strata within the Outer Carpathian sequence and eight from sandstone and carbonate reservoirs of the Palaeozoic–Mesozoic basement were analysed for molecular and isotopic compositions to determine their origin. Natural gases accumulated both in the Outer Carpathian and the Palaeozoic–Mesozoic basement reservoirs are genetically related to thermogenic and microbial processes. Thermogenic gaseous hydrocarbons that accumulated in the Dukla and Silesian units were generated from the Menilite beds. Thermogenic gaseous hydrocarbons that accumulated in the Sub-Silesian Unit most probably migrated from the Silesian Unit. Initial, and probably also secondary microbial methane component has been generated during microbial carbon dioxide reduction within the Oligocene Menilite beds in the Dukla Unit and Oligocene-Lower Miocene Krosno beds in the Silesian Unit. Natural gases that accumulated in traps within the Middle Devonian, Mississippian, Upper Jurassic, and Upper Cretaceous reservoirs of the Palaeozoic–Mesozoic basement were mainly generated during thermogenic processes and only sporadically from initial microbial processes. The thermogenic gases were generated from kerogen of the Ordovician-Silurian and Middle Jurassic strata. The microbial methane component occurs in a few fields of the Dukla and Silesian units and in the two accumulations in the Middle Devonian reservoirs of the Palaeozoic–Mesozoic basement.     

夏威夷群岛的地貌特征

本文根据实地考察并结合有关资料,对夏威夷群岛地貌的一些特点进行探讨。首先,分析了这些岛群的大地地貌特征;其次,介绍了灾害性地质地貌现象的控制和利用;最后,对夏威夷群岛的地貌演变趋势进行了探讨。这对大地地貌的研究以及对我国海岛开发将有所借鉴。     

Origin of crude oils from oilfields in the Zagros Fold Belt,southern Iraq: Relation to organic matter input and paleoenvironmental conditions

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C₃₅ homohopane index and C₃₁-22R/C₃₀ hopane ratios, relatively high C₂₇ sterane concentrations, and the predominance of C₂₉-norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition.The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks.     

Vertical Sound Velocity Transition in the Coral Reef Core and Its Significance of Indicating Facies

On the basis of the sound velocity measurements of the coral reef core from Nanyong No.1 well of Yongshu Reef in the Nansha Islands,the paper studies the relations between the vertical sound velocity transition features in the coral reef core and the corresponding stratigraphic depositional facies change as well as stratigraphic gap of erosion,analyses the cause of the sound velocity transition,expounds the concrete process of the sea level change resulting in the stratigraphic gap of erosion and facies change in the coral reef and explains the relations between the vertical sound velocity transition in the coral reef core and the corresponding stratigraphic paleoclimate and the sea level change.This study is of important practical value and theoretical significance to the island and reef engineering construction and the acoustic logging for oil exploration in the reef limestone area as well as the paleoceanographic study of the marginal sea in the westerm Pacific Ocean.     

南沙海区珊瑚礁灰岩纵波波速特征及其影响因素 *

珊瑚礁灰岩是孔隙结构复杂、密度变化较大的一类岩石, 但过去对珊瑚礁灰岩纵波波速与孔隙结构的关系及其影响因素研究不够深入。本文测定和分析了南沙海区某岛礁钻孔中珊瑚礁灰岩的纵波波速、孔隙度以及密度特征, 结果显示礁灰岩的纵波波速变化范围为5104~5958m·s^-1, 孔隙度变化范围为1.47%~17.7%, 密度变化范围为2.07~ 2.72g·cm^-3。这些特征表明, 埋藏后的压实作用和重结晶作用, 对珊瑚礁灰岩的孔隙度和密度产生影响。珊瑚礁灰岩弹性波速主要受孔隙度和孔隙结构类型的影响, 礁灰岩横、纵波速比值能有效地确定岩体的结构和稳定性, 因此礁灰岩的声学特性研究成果可为珊瑚岛礁工程建设的稳定性评估提供可靠的数据支撑。     

Crude oil families in the Euphrates Graben (Syria)

The most petroliferous province in Syria is the Euphrates Graben system in the eastern part of the country. The source of the produced light and heavy oils has been a matter of debate from a petroleum geochemistry perspective as there are several possible source rock and just one proven source rock (R'mah formation). Based on gross composition and oil-oil correlation of biomarker and non-biomarker characteristics, three oil families have here been identified in the study area. Crude oils of Family 1 have been found to be generated from a marine and clay-rich source rock that is older than Jurassic in age based on age-related biomarker parameters (steranes and nordiacholestane ratios). Maturity-related parameters (aliphatic biomarkers and diamondoids) signal that the source of this oil family had a high maturation level. These features fit very well to the Tanf Formation (Abba Group) which is equivalent to Lower Silurian Hot Shales found elsewhere in the Middle East and North Africa. However, the Upper Cretaceous R'mah Formation and Shiranish Formation were found to be responsible for generating the majority of the crude oils studied (Family 2). Compositional and molecular differences between Families 2A and 2B were attributed to facies and subtle maturation variations. Geochemical oil-source rock correlations indicate that Family 2A was most likely sourced from the Shiranish Formation, while Family 2B was sourced from the R'mah Formation. Secondary alteration processes influenced bulk petroleum composition, most notably the depletion of light ends and the lowering of API gravity, particularly in the northwestern part of the graben.     

Beef veins and thrust detachments in Early Cretaceous source rocks,foothills of Magallanes-Austral Basin,southern Chile and Argentina: Structural evidence for fluid overpressure during hydrocarbon maturation

We describe (1) bedding-parallel veins of fibrous calcite (beef) and (2) thrust detachments, which we believe provide good evidence for fluid overpressure in source rocks for petroleum. Our examples are from the surface or subsurface of the Magallanes-Austral Basin, which lies at the southern tip of South America. There, the best source rocks for petroleum are of Early Cretaceous age. In the central parts of the basin these source rocks have become overmature, but at the eastern edge, onshore and offshore, they are today either immature or in the oil window.In Tierra del Fuego, the foothills of the Andes consist mainly of sedimentary rocks, which have undergone thin-skinned thrusting. In the Vicuña area (Chile), Early Cretaceous source rocks have reached the surface above thrust detachments, which are visible on seismic data and well data. At the surface, we have found calcite beef, containing hydrocarbons (solid and/or fluid), in the Rio Jackson and Vicuña formations, which have reached the wet gas window. In the Rio Gallegos area (Argentina), the source rocks have not reached the surface, but seismic and well data provide good evidence for thin-skinned thrusting above flat-lying detachments in Early Cretaceous source rock, where it is in the early oil window. In contrast, there is little or no deformation where the source rock is still immature. Thus the deformation front coincides with the maturity front. Next to the central parts of the basin, where the source rocks have reached the surface within the Andes proper, they have undergone low-grade metamorphism. Within these source rocks, we have found beef veins, but of quartz, not calcite. To the east, within the foreland basin, seismic and well data provide evidence for a few compressional structures, including thin-skinned detachments in the deeply buried source rock. Finally, in the northern part of the basin (Santa Cruz province, Argentina), where it is shallower, the source rocks have reached the surface in the foothills, above a series of back-thrusts. At Lago San Martín, the source rocks have reached the oil window and they again contain calcite beef.In conclusion, where we have examined Early Cretaceous source rocks at the surface, they contain either calcite beef (if they have reached the late oil window or wet gas window) or quartz beef (if they are overmature). Independent evidence for overpressure, in the form of source-rock detachments, comes from subsurface data, especially at the southern end of the basin, where the source rocks are not overmature and deformation is relatively intense. Thus we argue that hydrocarbon generation has led to overpressure, as a result of chemical compaction and load transfer, or volume changes, or both.     

Jurassic source rocks in the Vienna Basin (Austria): Assessment of conventional and unconventional petroleum potential

The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m²). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.     

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands,Arctic Russia

A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window.     

Oil migration driven by exhumation of the Canol Formation oil shale: A new conceptual model for the Norman Wells oil field,northwestern Canada

Thermal history, petroleum system, structural, and tectonic constraints are reviewed and integrated in order to derive a new conceptual model for the Norman Wells oil field, and a new play type for tectonically active foreland regions. The thermal history recorded by Devonian rocks suggests that source rocks experienced peak thermal conditions in the Triassic–Jurassic, during which time oil was likely generated. After initial oil generation and expulsion, the Canol Formation oil shale retained a certain fraction of hydrocarbons. The shallow reservoir (650–350 m) is a Devonian carbonate bank overlain by the Canol Formation and resides within a hanging wall block of the Norman Range thrust fault. Both reservoir and source rocks are naturally fractured and have produced high API non-biodegraded oil. Thrust faults in the region formed after the Paleocene, and a structural cross-section of the field shows that the source and reservoir rocks at Norman Wells have been exhumed by over 1 km since then.The key proposition of the exhumation model is that as Canol Formation rocks underwent thrust-driven exhumation, they crossed a ductile–brittle transition zone and dip-oriented fractures formed sympathetic to the thrust fault. The combination of pore overpressure and new dip-directed subvertical fractures liberated oil from the Canol Formation and allowed for up-dip oil migration. Reservoir rocks were similarly fractured and improved permeability enhanced charging and pooling of oil. GPS and seismicity data indicate that strain transfer across the northern Cordillera is a response to accretion of the Yakutat terrane along the northern Pacific margin of North America, which is also the probable driving force for foreland shortening and rock exhumation at Norman Wells.     

High resolution characterization of a core from the Lower Jurassic Gordondale Member,Western Canada Sedimentary Basin

The Gordondale Member is a hydrocarbon source rock and potential unconventional reservoir that extends across northeastern British Columbia and central-northwestern Alberta. It is an organic-rich, calcareous, fossiliferous mudstone with a median total organic carbon value of 6.0 wt%. A total of 230 samples were collected from approximately 25 m of Gordondale Member core for organic matter analysis using Rock-Eval 6 analysis and organic petrology. Detailed core logging provides sedimentological context for organic matter characterization. The predominant organic material in the samples is solid bitumen and liptinite with lesser zooclast and inertinite. Most kerogen is Type II, autochthonous marine biomass, with minimal dilution by inert organic carbon. Rock-Eval T_max values and random reflectance measurements of solid bitumen indicate the samples are within the oil generation window. Solid bitumen contributes a substantial amount of hydrocarbon potential to the interval. A micro-reservoir structure within the core is produced by thin intervals of impermeable displacive calcite that act as barriers to the upward migration of free hydrocarbons. These free hydrocarbon accumulations could make excellent targets for horizontal wells within the Gordondale Member.