Source Rock Data Research Articles

Basin evolution in western Newfoundland: New insights from hydrocarbon exploration

The Humber zone is the most external zone of the Appalachian orogen in western Newfoundland. It records multiphase deformation of the Cambrian-Ordovician passive margin and of the Ordovician to Devonian foreland basins by the Taconian, Salinian, and Acadian orogenic events. The recent phase of exploration drilling has provided new evidence for structural, stratigraphic, reservoir, and source rock maturation models of western Newfoundland. The first well, Port au Port 1, supported the hypothesis that the Round Head thrust had an earlier extensional history prior to the Acadian compressional inversion that created the present-day structural high of the Port au Port Peninsula. The well tested a small anticline formed in a footwall shortcut fault of the Round Head thrust. The second well, Long Point M-16, was drilled at the northern tip of Long Point to test a triangle zone identified by previous workers. This well demonstrates that the frontal monocline at the western edge of the triangle zone is elevated by a stack of imbricate thrusts composed of rocks of the Taconian allochthon and compressional basement-involved faults that have uplifted the Cambrian-Ordovician carbonate platform. The structural model developed in the Port au Port area with the aid of these wells has been extended throughout the Humber zone in western Newfoundland. Changes in structural style illustrated by regional cross sections suggest that prospective trap geometries are only developed in the southern and central parts of the region. The reservoir model proposed invokes exposure and karsting of the footwalls of extensional faults formed as the carbonate platform collapsed during a Middle Ordovician hiatus, the St. George unconformity. Structural relief became more pronounced as extensional collapse continued through the Middle Ordovician. (Begin page 394) These structurally high fault footwalls became the foci for dolomitizing and mineralizing fluids that used major faults as fluid conduits during the Devonian. Fluids deposited sulphide ores and created zebra and sparry dolomite and some sucrosic hydrothermal dolomites in the St. George Group and the Table Point Formation. The reservoir model, maturity and source rock data, and the structural models have been combined with seismic and onshore surface geology. This enables the prospectivity of the western Newfoundland Cambrian-Ordovician play trend to be evaluated for further exploration.

Organic geochemistry of the Cenomanian-Turonian sequence in the Bakr area, Gulf of Suez, Egypt

The Cenomanian-Turonian transgression has been studied in a 220 m cored section using common source rock data, elemental data and conventional biomarker parameters. Differences in the type of organic matter found in these regressive and transgressive offshore marine sediments have been documented and assessed within a sequence stratigraphic framework. The interval of maximum flooding of the Cretaceous seaway shoreline is delineated by discontinuities in the total organic carbon content and Hydrogen Index. The overall transgressive event is also accompanied by (a) an increase in the concentrations of elements such as thorium, vanadium, potassium, barium, sodium...etc., (b) changes in the relative concentrations and the characteristics of the biomarker parameters and (c) changes in the characteristic features of the kerogen. All of these data are consistent with a simultaneous decrease in terrigenous organic matter and increase in marine algal input.

Application of light hydrocarbons (C 4–C 13) to oil/source rock correlations: : a study of the light hydrocarbon compositions of source rocks and test fluids from offshore Mid-Norway

Relatively little work has been published on the correlation between the light hydrocarbon distributions in reservoir fluids and their proposed source rocks [Philippi, G. T. (1981)]. The aim of our work was to study this relationship in detail for samples from Mid-Norway. The main source rocks offshore Mid-Norway are the marine shales of the Late Jurassic Spekk Formation and the coals and paralic shales of the Early Jurassic Åre Formation. Reliable light hydrocarbon (C 4–C 13) data for source rock samples were acquired by thermal extraction-GC of the source rocks. Of these, notably the hydrocarbons in the C 6–C 8 range (routinely measured in test fluids) were used to discriminate between the Spekk and Åre Formation samples. A total of twenty-six samples from the Spekk Formation and twenty-four samples from the Åre Formation at different maturity levels and facies were analyzed. In general, the two source rock types differ in their light hydrocarbon composition by the presence of relatively more aromatics and cyclohexanes in the Åre samples, while the Spekk samples are richer in cyclopentanes and acyclic hydrocarbons. We show that source rock facies is a more important indicator of light hydrocarbon composition than maturity variation. Differences in the chemical composition, which can be used to discriminate between the two source rocks, were supported by differences in the carbon isotope composition of individual components of the same fraction, as determined by GHM-IR-MS analysis of eleven samples. Further, the light hydrocarbon compositions of reservoir fluids (oils and condensates) were compared with those for the source rock(s). Sixty-six gas chromatograms of oils and condensates, representing most of the known petroleum accumulations in Mid-Norway, were collected. Of these, five oil samples were selected for detailed isotopic analysis of individual components (GC-IR-MS). When using a classification scheme based on data from sediment samples, data for the light hydrocarbon fraction of oils and condensates indicate that the Spekk Formation is the dominant source for most of the fields from Mid-Norway, with a significant contribution from the Åre Formation being detected principally in one field. Differences in the chemical composition of the C 6–C 8 fractions were supported by differences in the carbon isotope composition of individual components, which also discriminate between the oils. Although the classification diagrams used in this study are based on source rock data from Mid-Norway, the method can be applied to other areas, providing that the diagrams are calibrated with source rock data from the area of interest.

Oil families in Mannville Group reservoirs of southwestern Alberta, Western Canada sedimentary basin

Lower Cretaceous oils in southern Alberta have been assessed using column chromatography, sulphur analysis, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). These oils can be divided into four oil families, E, Q, EQ and F, on the basis of biomarker characteristics. Family E oils are characterized by low pristane/phytane ratios and a C 35 homohopane prominence. Family Q oils are identified by the presence of so-called “Q compounds” (Q/R ratio > 0.5) and have high C 27 diasterane to regular sterane ratios. Family EQ oils are a mixture of Family E and Family Q oils, with biomarker characteristics intermediate between these two families and low abundance of “Q compounds” (Q/R ratio < 0.5). Family F oils have high saturate/aromatic ratios, high pristane/phytane ratios (> 1.2) and no C 35 homohopane prominence. Oil-source rock correlation to available source rock data suggest that Family E oils are derived from the Upper Devonian-Mississippian Exshaw Formation and Family Q oils correlate to the Lower Cretaceous Ostracode Zone. Family F oils are likely derived from shales of the Upper Jurassic Rierdon Formation, however additional geochemistry data from this potential source rock are required to confirm this interpretation.

Integration of Natural Gases in Hydrocarbon Systems of the Northern Gulf of Mexico Basin: ABSTRACT

Associated and non-associated natural gases of the northern Gulf of Mexico Basin have been characterized as part of Exxon`s multidisciplinary study of hydrocarbon source, maturation and migration. Analyses of over 600 natural gases were integrated within the hydrocarbon (HC) system context provided by evaluation of more than 2000 reservoired oils, 1200 HC-bearing sea bottom drop cores, and extensive source rock data, all synthesized within a geologic framework developed from 2-D and 3-D seismic. The molecular and isotopic compositions of gases can vary due to type of organic matter and level of maturity of the source, mixing with biogenic methane, and biodegradation. Organic matter type is a primary control on the compositions of natural gases, as documented by the close correspondence of gas compositions to HC systems defined from oil and source rock characterization. For example, the predominance of relatively dry gas on the Texas shelf primarily reflects generation from a terrestrial, gas-prone source. The recognition of significant source controls on gas composition has important implications to evaluation of gas maturity and inferred timing of generation. Complications from widespread occurrence of biogenic gas are incorporated in gas interpretations. Integration of these gas and oil data strongly supports the concept that mostmore » associated thermogenic gases have been cogenerated with oils within the normal oil window. On the slope, large seeps contain early mature oils and abundant wet thermogenic gases, documenting comigration and suggesting that the two have a common origin. In contrast, high maturity gases are distinctly absent.« less

Petroleum Generation and Expulsion in the Constrained Bakken Petroleum System and Its Relevance to the Formation of Fractures: ABSTRACT

The lack of direct and unequivocal evidence for the existence of fractures in the Bakken petroleum system (Williston Basin, U.S.A./Canada) has led to controversial discussions with respect to the magnitude, orientation and frequency of fractures and especially their formation mechanism. Amongst other hypotheses, the creation of overpressuring as a result of high petroleum generation rates was called upon to induce fracturing. On the basis of a comprehensive organic geochemical study incorporating source rock and reservoir data, the present contribution provides evidence for an alternative pressure-controlled fracture formation mechanism: Mass balance calculations performed on Bakken Shale samples covering a maturity spectrum from 0.3% to 1.1% R{sub o} has revealed that the main phase of petroleum formation took place very early during catagenesis (ca. 0.4 - 0.8% R{sub o}) and that its potential has already been realized in those areas of the basin which currently produce from Bakken reservoirs. (1) It has been shown recently that the Bakken petroleum system represents a closed system, i.e. the Bakken sourced oils have not entered the Madison reservoirs. Hence, overall high expulsion efficiencies indicate that Bakken Shale over- and underlying units might represent the principal reservoirs and, most importantly, the strata where overpressuring should bemore » expected. (2) Detailed analysis of Bakken sourced oils which are produced from Bakken reservoirs imply that their bulk and molecular composition may have been altered by significant in-situ thermal alteration which took place after the main phase of expulsion. (3) The hypothesized process of reimpregnation of petroleum from the reservoir back into the source rock system may account for locally occurring high concentrations of solvent extractable organic matter in Bakken Shales.« less

Routine Quantification of Oil Expulsion from Source Rock Data: An Example from the Utica Formation (Ordovician) of the Michigan Basin

Routine Quantification of Oil Expulsion from Source Rock Data: An Example from the Utica Formation (Ordovician) of the Michigan Basin

THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA

There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.

Petroleum Potential of Baikit Anteclise, Siberian Platform

The Baikit Anteclise lies east of the Yenisei ridge, and it occupies an area of 155,000 km[sup 2] of the western part of the Siberian platform. The major structure of the anteclise outlined by seismic survey is the Kanovsky arch, complicated by three domal uplifts. The basic petroleum potential of the area is associated with Riphaean, Vendian, and Cambrian complexes. The Vendian is represented mainly by mudstones interbedded with sandstones and siltstones. Two layers have proven potential for gas. Four carbonate horizons in the Cambrian are regarded as potential reservoirs with a total thickness of 20-30 m. The most important petroleum potential in the area is associated with the Riphaean. From seismic and deep drilling evidence, its total thickness ranges from 0 to 3000 m. Source rock data and distribution of organic matter and its level of catagenetic transformation lead to the conclusion that the Riphaean complex is a petroleum-generating complex likely to be the most productive within the Baikit region. The region is currently an area of special interest for petroleum geologists because for the first time, the Riphaean has proved to be of commercial importance with the discoveries of the large Yurubcheno-Tokhoma oil and gas accumulations.

Automated Geological Evaluation of Continuous Slim-Hole Cores

Summary Slim-hole continuous coring and drilling techniques applied to oil exploration are receiving wide recognition. Slim-hole coring methods produce high-quality continuous cores that yield valuable exploration information. Amoco Production Co.'s geological evaluation modules furnish an on-site automated instrumentation system to extract a maximum of information from the core, thus providing the vital link in developing high-speed slim-hole coring into an integrated exploration tool. "Inverse logging" (logging the core instead of the borehole) is the primary goal of on-site geological evaluation. Up-hole measurements on cores include gamma scan, magnetic susceptibility, infrared mineralogy, ultraviolet fluorescence, nuclear magnetic resonance porosity, and pyrolysis (source rock) data; macroscopic and microscopic video images for analysis and archiving; and sedimentological/lithological description. Continuous rock samples through entire basin-filling sequences are used to calibrate seismic and well log data. This information provides insight into opportunities and risks associated with exploration and development in all types of basins. Introduction In recent years it has become apparent that the oil and gas industry needs major innovative changes to improve exploration effectiveness and decrease the costs of finding. The results of studies done to assess the technical risk associated with exploration and development indicate a need to better understand the actual geological and geophysical characteristics of reservoir, seal, and source packages. In both basin reconnaissance and subtle-trap exploration modes, the need has never been greater to pursue the acquisition of continuous cores actively to better analyze subsurface hydrocarbon systems and improve technical databases. Continuous cores acquired through complete sedimentary sections enhance geological and geophysical data. Direct observation of lithology, sedimentary structures, fossils, reservoir pore geometry, source-rock characteristics, seal characteristics, and petrophysical rock properties permits fact (instead of interpreted, indirect information) to guide subsequent exploration and exploitation programs. Traditional slim-hole continuous coring and drilling techniques are receiving wide recognition in their application to oil exploration; core analytical capabilities are considered deficient and present a challenge to the oil industry. Automated geological analysis of continuous slim-hole cores results in on-site, real-time evaluation. The geological evaluation modules provide the critical link for connecting high-speed slim-hole coring into an integrated exploration system, and, thus, have the potential to revolutionize exploration and development philosophies and create entirely new oil and gas paradigms. Slim-hole drilling and on-site evaluation can be applied to all phases of exploration and development, including rank wildcat well analysis, field development studies, and regional trend or basin analysis studies.

Petroleum Classification Based on the Ratio of Sulfur to Nitrogen: Application in the East Texas Basin

ABSTRACT Petroleum families are characterized by limited ranges of organic sulfur to nitrogen (S/N) ratios, despite thermal crack ing. In the East Texas Basin three families are recognizable on the basis of both carbon isotopic and S/N ratio data. Jurassic oils possess modal saturated hydrocarbon values of -25% 13C and S/N ratios close to 20; Lower Cretaceous oils, values of -26 and 10, and Upper Cretaceous oils, values of -28 and 3. Numerous published analyses of sulfur and nitrogen in oils facilitated mapping the detailed geographic distributions of the families recognized. Both source rock and petroleum data demonstrate that Upper Cretaceous oil, including that of the supergiant East Texas field, was generated only beyond the confines of the East Texas basin, principally to the south and west in the Gulf Coast basin. Migration distances to present pool sites are of the order of 30 to 200 miles. End_of_Record - Last_Page 602-------

Organic Matter Variations in a Depositional Sequence: Implications for Use of Source Rock Data in Sequence Stratigraphy

Variations in the amount and type of organic matter preserved in shelf sediments are predictable within a sequence stratigraphic framework. These variations can be documented using routine petroleum source rock evaluation techniques. The type and preservation of organic matter is related to the rate of allochthonous shelf sedimentation. Each depositional systems tract in a sequence has a distinct depositional style that affects changes in the amount of terrigenous influx. Therefore, integration of source rock data with sedimentologic and regional stratigraphic results provides greater resolution in locating the critical surfaces that bound depositional systems tracts within the depositional sequence. This integrated sequence stratigraphic approach has been applied to conventional cores of Upper Cretaceous strata in the San Juan basin of New Mexico. Fine-grained marine sediments in transgressive systems tracts possess high total organic carbon and yield relatively high amounts of hydrocarbons during pyrolysis. Petrographically, this organic matter is composed primarily of amorphous macerals. Both the lower Juana Lopez and the Mancos Shale above the Tocito Sandstone provide examples of organic matter deposited in the transgressive systems tract. In contrast, marine depositional systems of both the lowstand and highstand systems tracts contain less total organic carbon and less pyrolyzable hydrocarbons. This methodologymore » not only improves systems tract identification in fine-grained, basinward intervals but also reveals those portions of the depositional sequence that are most favorable for marine petroleum source rock formation.« less

ONSHORE AND OFFSHORE PETROLEUM SEEPAGE: CONTRASTING A CONVENTIONAL STUDY IN PAPUA NEW GUINEA AND AIRBORNE LASER FLUOROSENSING OVER THE ARAFURA SEA

Two case studies from the northern margin of the Australian continental plate are presented to illustrate mapping and understanding seepage in an onshore and an offshore area. The first involves an integrated approach to the detection and analysis of onshore seeps in the Aure Thrust Belt of Papua New Guinea. The second study is an application of BP's proprietary Airborne Laser Fluorosensor (ALF) technology to the systematic detection and mapping of offshore oil seepage in the Arafura Sea, northern Australia.In the absence of well or outcrop source rock data, the source risking in the Aure Thrust Belt has been constrained using oil and gas seeps. Mapping the seeps required optimum use of the local peoples' observational prowess. Geochemical analyses of the seeps allowed the identification of an oil-prone source rock of probable Jurassic age. The data reveal that the seeping petroleum liquids are gas condensates in the subsurface, and provide information on the maturation history of the source and the nature of the reservoir/carrier beds, as well as differentiating the biogenic and thermogenic gas components. In this uplifted region, seepage is likely to be from accumulations only.To help reduce the exploration risk in offshore areas such as the Arafura Sea, BP have developed the ALF system which detects oil seepage at the sea surface. It does this by detecting its characteristic fluorescence, which is induced by an aircraft-mounted ultraviolet excimer laser.The ALF data over the western Arafura Sea indicate active oil seepage showing a distribution which is compatible with our current understanding of the subsurface Palaeozoic and Mesozoic source kitchens. The mapped seepage over the Goulburn Graben is most likely derived from the Palaeozoic to (?)Triassic section (with a possible contribution from other Mesozoic sources), and must be migrating through a largely unfaulted Mesozoic seal. Additionally, there is evidence for liquid petroleum seepage from the Mesozoic section in the Calder Graben via faults which cut through the regional seal along the Lynedoch Bank Fault System. In this region of the Arafura Sea, seepage is likely to derive from accumulations, mature source kitchens and secondary migration routes.

Origin of the Offshore Louisiana/Mississippi Delta Oils by Reservoir-Source Decoupling

ABSTRACT Carbon and sulphur stable isotope composition, metal and sulphur content, biomarker fingerprints and reservoir age; have been used to define the distribution of major oil types in the northern Gulf of Mexico. These groups include the oils with characteristics typical of carbonate sources (Smackover, Florida, Shelf Break, Campeche and a Cuban oil), the Austin Chalk oils, the Woodbine Trend oils, Tuscaloosa oils, Mississippi Delta oils, South Texas oils influenced by lignites, post-mature oils (condensates) and oils contaminated with bitumen during migration or pooling (see Figure 1). A given oil type is confined to reservoir rocks of specific age (see Figure 1). The spatial and chronological association of the oils suggest that multiple source rocks need to be invoked to explain the chemistry of Gulf of Mexico crude oils. Oils exhibiting characteristics typical of carbonate influenced sources are probably of Mesozoic age, including the North Florida Smackover oils of Jurassic age and the South Florida oils of Lower Cretaceous age. The source of the Shelf Break (Flexure Trend) oils is unknown, however, little carbonate is present in the associated Tertiary section, suggesting that these Shelf Break oils are also of Mesozoic age (probably Lower Cretaceous). Other characteristics suggestive of a Mesozoic origin include relatively high sulphur contents and trace element compositions similar to onshore Mesozoic oils. The three groups of oils produced from the Mississippi Delta have stable carbon and sulphur isotope ratios and trace element contents similar to the Flexure Trend oils. However, the oils lack biomarker fingerprints typical of carbonate influenced source rocks. The biomarker compositions of one minor group of Mississippi Delta oils are most similar to Tuscaloosa and Woodbine oil types (Upper Cretaceous). Further indication of a Mesozoic source is provided by the bio-marker content of the Pine Island formation (Lower Cretaceous) which has a signature similar to the largest group of the Mississippi Delta oils. However, many of the offshore Mississippi Delta oils (but not all) and Flexure Trend oils contain 18(H) oleanane and bisnorhopane. These biomarkers are also present in onshore Paleogene reservoired lignite influenced oils. One possible scenario is that much of the Gulf of Mexico shelf oils are a mixture of two oil types (Mesozoic and Paleogene). Thus, I8(H) oleanane and bisnorhopane are tracers of lignite sourced oils, since they are absent from Mesozoic oils reservoired onshore. The offshore Mississippi area formed part of the abyssal carbonate rich source facies during the Late Jurassic-Early Cretaceous and it seems likely that these organic rich formations are the primary source of the Delta oils. A Mesozolc source would explain the huge volumetric quantity of oil and gas in the Mississippi Delta areas (and elsewhere in the northern Gulf of Mexico), but requires an explanation of how these oils were preserved and trapped in Neogene-Quaternary reservoirs. The presumed parent source rocks have burnt out due to deep burial and presently occur in the post-mature gas generation zone. A halokinetic model in which hydrocarbons and Jurassic Louann salt migrated vertically in response to Tertiary sediment loading, would postulate sequential movement of oil away (vertically) from the zone of thermal destruction into younger sediments. This reservoir-source decoupling model would predict the marked correlation between halokinetic phenomena and oil accumulation long noted in the Northern Gulf of Mexico. Thermal modelling of source rock data spuriously indicates that Neogene source rocks (presently mature and sourcing oil in some parts of offshore south Texas) are the major source of the northern Gulf of Mexico petroleum. However, Miocene sources would only be of local rather than regional significance due to their generally poor source qualities. The implications of this study are that only halokinetic phenomena, rather than source rock burial, ultimately control the distribution of oil and gas offshore Louisiana and that the Lower Cretaceous is the most likely source. The timing of generation and successive migration and remigration into shallower, younger reservoir rocks would determine whether the oil completely leaked out, was cracked to gas/or successfully reiterated to cooler reservoirs. This comply history and continuing generation of gas from deeply buried petroleum source rocks has lead to the surprisingly highly altered nature of many Gulf Coast crude oils. End_Page 98------------------------- Figure 1. Sketch map of the northern Gulf of Mexico oil and reservoir ages. Due to the constraints imposed by shading techniques, areas of mixing between two or more oil types (offshore) are not shown. End_of_Record - Last_Page 99--------

Yucca Mountain, a High-Level Nuclear Waste Repository Over a Billion Barrel Oil Field?

New structural models and source rock data suggest that the proposed Yucca Mountain, Nevada, high-level nuclear waste repository lies in the Central Nevada thrust belt. The Central Nevada thrust belt could contain billion-barrel oil fields. The Central Nevada thrust belt coincides with an organic richness fairway and a maturation fairway of Mississippian source rocks that have already produced more than 25 million barrels of oil. Giant thrust-related structures along the thrust belt have yet to be tested. However, new work in the Tempahute Range, which lies between Yucca Mountain and the prolific Grant Canyon field, confirms the thrust belt concept and sheds light on source and reservoir rock quality and thrust belt geometry. Klippen of overmature Mississippian rocks are distinct on maturation maps such as the Diamond Range klippe in central Nevada. Thrust trends suggest that the Eleana Range near Yucca Mountain may be another klippe of overmature rocks over Mississippian source rocks in the oil window. There is a strong possibility that the subthrust source rocks may have generated large quantities of hydrocarbons that may be trapped in large thrust features beneath Yucca Mountain.

Characteristics of Selected Petroleum Source Rocks, Xianjiang Uygur Autonomous Region, Northwest China (1)

The sedimentary basins of Xinjiang Uygur Autonomous Region, China, are moderately to poorly explored for petroleum. Volumetric adequacy of petroleum source rocks is a critical exploration risk in these basins, particularly because source rock data are limited. This study provides new source rock data and speculatively assesses the source rock potential of Xinjiang basins. The Junggar (Zhungaer) basin, the best explored of the Xinjiang basins and containing a giant oil field, is underlain in many areas by an Upper Permian lacustrine oil-shale sequence remarkable for its organic richness and oil source quality. Depending on its position in the basin, the Permian section ranges from immature to overmature and is inferred to be the principal source of oil in the basin. Upper Triassic-Middle Jurassic coal measures, including lacustrine rocks, constitute a secondary source rock sequence in the basin. The smaller, intermontane Turpan (Tulufan) basin contains a very similar Upper Triassic-Middle Jurassic sequence, which, where sufficiently buried, probably comprises the only significant oil source sequence in the basin. The vast Tarim (Talimu) basin offers the greatest variety of potential source rocks of all Xinjiang basins but remains the least well documented. From limited but geologically planned and focused sampling, Cambrian, Carboniferous, and Permian strata are not considered major oil contributors in the dominantly shallow marine Paleozoic section of the northern Tarim basin. Only Ordovician black shales appear to have significant potential. The Upper Triassic-Middle Jurassic sequence of the northern Tarim basin is similar to that of the Junggar and Turpan basins--a section rich in coal and lacustrine shale that constitutes another potentially significant oil source. Due to the size, stratigraphic packaging, and structural relief of the northern Tarim basin, Paleozoic and Mesozoic potential il source beds range from immature to overmature.

Sequence stratigraphy and the habitat of hydrocarbons, Gippsland Basin, Australia

Abstract The Gippsland Basin is Australia’s most prolific oil and gas province, with initial reserves estimated at 3.6 billion barrels crude/condensate, 0.6 billion barrels liquid petroleum gas (LPG) and 8.3 TCF dry gas. It is located in southeastern Australia, mainly offshore. Significant hydrocarbons were first discovered in 1964, in large structures at the top of the Late Cretaceous-Eocene Latrobe Group. All of the large structures have now been drilled, with current exploration concentrating on fault-dependent and combined stratigraphic structural traps within the Latrobe Group. Hydrocarbon, source rock and maturation data suggest that there is a widespread and uniform non-marine source of Late Cretaceous age. The concentration of hydrocarbons at the top of the Latrobe Group is due to the presence of large structures, an excellent cap seal, and the relatively sandy nature of the underlying, intra-Latrobe section. The distribution of oil versus gas at this level is largely explained by maturation variations and migration pathways within the basin. Vertical migration of up to 2 km is required in most cases. The distribution of oil versus gas is also influenced by minor source rock variations, fresh water washing, biodegradation, and the variable quality of fault seal. Recent exploration studies have concentrated on locating stratigraphic and combination traps, especially within the Latrobe Group. Prediction and subsequent discovery of these traps is a challenging task that has been aided by sequence-stratigraphic and seismic-stratigraphic analysis of the rock record. This has allowed the prediction of reservoir, source and seal geometries and distributions. The techniques used to construct this chronostratigraphic framework are presented, together with examples of its application within fields and on a regional basis.

Well-Log Signatures of Alluvial-Lacustrine Reservoirs and Source Rocks, Lagoa Feia Formation, Lower Cretaceous, Campos Basin, Offshore Brazil: ABSTRACT

The Campos basin is situated in offshore southeastern Brazil. The Lagoa Feia is the basal formation in the stratigraphic sequence of the basin, and was deposited during rifting in an evolving complex of lakes of different sizes and chemical characteristics, overlying and closely associated with rift volcanism. The stratigraphic sequence is dominated by lacustrine limestones and shales (some of them organic-rich), and volcaniclastic conglomerates deposited on alluvial fans. The sequence is capped by marine evaporites. In the Lagoa Feia Formation, complex lithologies make reservoirs and source rocks unsuitable for conventional well-log interpretation. To solve this problem, cores were studied and the observed characteristics related to log responses. The results have been extended through the entire basin for other wells where those facies were not cored. The reservoir facies in the Lagoa Feia Formation are restricted to levels of pure pelecypod shells (''coquinas''). Resistivity, sonic, neutron, density, and gamma-ray logs were used in this work to show how petrophysical properties are derived for the unconventional reservoirs existing in this formation. The same suite of logs was used to develop methods to define geochemical characteristics where source rock data are sparse in the organic-rich lacustrine shales of the Lagoa Feia Formation. Thesemore » shales are the main source rocks for all the oil discovered to date in the Campos basin.« less

Application of Geochemical, Engineering, and Geological Methods to Petroleum Exploration--Bell Creek Field, Powder River Basin, Montana: an Example: ABSTRACT

Various geochemical, engineering, and geological methods can be applied in a progressive series of steps for the exploration of oil. These steps are source, generation, migration, and entrapment. Source rock data for oil generation are usually obtained from geochemical analyses of the total organic carbon (TOC) content. Generally, a measurement of 0.5% TOC or more is considered adequate for a source rock. Generation of petroleum from a source rock is primarily dependent on the paleotemperature history. The oil-generating temperature window is approximately 125/degrees/-300/degrees/F (52/degrees/-149/degrees/C). A temperature indicator that defines these limits is the T/sub max/ value from rock pyrolysis analyses. Migration of petroleum can be inferred from oil chromatography. This geochemical method can determine if molecular separation (a migration characteristic) of the oil has occurred. A rough estimate of migration distance can be made by the degree of molecular separation. Entrapment areas for petroleum can be interpreted from a geologic paleostructure map of the producing formation at the time of oil accumulation. Time of oil accumulation can be ascertained from oil-gas solution data in the area. Final pinpointing of a well location is sometimes possible by calculating oil column height from capillary pressure data. Bell Creek field is an example,more » after the fact, of how a combination of geochemical, engineering, and geological methods could have been used in its discovery.« less

Oil—source correlation by the combined use of principal component modelling, analysis of variance and a coefficient of congruence

Kvalheim, O.M., 1987. Oil—source correlation by the combined use of principal component modelling, analysis of variance and a coefficient of congruence. Chemometrics and Intelligent Laboratory Systems : 2: 127–136. Using the distributions of C 6 and C 7 saturates as input, crude oils are correlated with potential source rocks. 1. (i) Principal components are obtained treating all oil and source rock samples from one geographical area jointly. 2. (ii) Source-specific principal components are identified by analysis of variance and by comparing principal components obtained for different regions by means of a coefficient of congruence. The method is demonstrated on oil—source rock data previously investigated by Philippi.