geothermometry and geochemistry of aqueous and oil bearing fluid inclusions from fateh field dubai abstract the production of oil from fateh field dubai is principally from the cretaceous mishrif formation porosity in the reservoir facies is partly occluded by late coarse grained calcite cement this cement contains both aqueous and oil bearing fluid inclusions fluid inclusion geothermometry was used to determine the temperature of that cement precipitation and calculate its timing relative to basin burial history these data were related to source rock maturation and from that the timing of oil migration was inferred to be oligocene to mid miocene which is geologically contemporaneous with early petroleum generation r 0 0 5 0 6 in the khatiyah source rock the fluid inclusions were analyzed by a thermal decrepitation gas chromatography technique benzene and low molecular weight paraffins were present and a series of normal alkenes was tentatively identified in the aqueous inclusions fresh oil inclusions consisted of c 1 n c 25 compounds whose light hydrocarbon composition was consistent with derivation from an early mature source rock altered petroleum residues detected in many mishrif samples are contained either in inclusions or along crystal cleavages these materials are the subject of an ongoing geochemical study of fateh field

dating reservoir filling a case history from the north sea abstract secondary petroleum inclusions in reservoir sandstones in the froy field and the rind discovery are used in combination with burial history modelling reservoir oils and core extracts to shed light on how and when these structures received their hydrocarbon charges analysis of normal alkane and biomarker distributions in these three data sets fluid inclusions core extracts and drill stem tests dsts provide information on the changes in organic facies and maturity of petroleum in the various reservoir strata over time the geochemistry of core extracts and dst oils in rind and froy reveal that the maturity of the rind petroleum system is higher and also of slightly less anoxic facies compared to the oil present in the froy system biodegraded oil is found today in a small sub compartment of the froy field using the burial history of the froy and the assumption that biodegradation effectively comes to a halt at 70 80 c we tentatively conclude that the filling of this sub compartment and the biodegradation of the oil must have occurred earlier than 30 40 m y b p and before oil from the upper jurassic draupne shales more recently homogeneously filled the main froy structure at 30 40 m y b p the froy structure was at a depth of 1 5 2 km compared to the present depth of 3 5 4 km and it is more than likely that neither the heather nor the draupne formations were mature in the paleo drainage area of the field at this time still the stratigraphically deeper dunlin formation could have been mature and the geochemical signatures of the now biodegraded oil correlates with known signatures from the dunlin formation in this region in the rind discovery no fluorescent petroleum inclusions are observed in k feldspar overgrowths however the number of inclusions in quartz and plagioclase is larger than that observed in the shallower froy field from the mean homogenization temperatures of the petroleum inclusions which are close to the present reservoir temperature filling of the froy field and main rind structure is suggested to have been a recent event a presently dry compartment penetrated by well 25 2 15r2 in the rind discovery contains high residual oil saturations indicating loss of oil from this structure either by direct cap rock leakage or displacement of oil by gas and subsequent cap rock leakage numerous petroleum and coexisting water inclusions were found in the presently dry overpressured structure and it is clear from measurements of homogenization temperatures that the water and the petroleum inclusions are not both saturated with respect to gas due to the lower solubility of hydrocarbon gas in water compared to in oil it is more likely that water inclusions are closer to saturation than are the petroleum inclusions using the difference in homogenization temperatures in these two systems and the burial history we tentatively suggest that the cap rock leakage occurred later than 10 m y b p such information on time for reservoir filling and seal failure when used to calibrate basin modelling should facilitate better models for understanding movement of hydrocarbon fluids in basins

biomarkers in fluid inclusions a new tool in constraining source regimes and its implications for the genesis of mississippi valley type deposits biomarkers in fluid inclusion s can constrain source regimes for hydrocarbons associated with mississippi valley type pb zn deposits significant amounts of hydrocarbons have been detected in fluid inclusions in sphalerite and dolomite intimately associated with pb zn sulfides in the canning basin western australia the hydrocarbons are more mature than those in the host rocks to the ore and are therefore derived from an external source furthermore there are differences between the biomarker components of hydrocarbonas in inclusions in pb zn prospects but they are all different from hydrocarbons in organic rich strata and also in oils from the canning basin yet the hydrocarbons are mature and oil like suggesting that mature organic rich strata deeper in the basin which are less significant as potential source rocks for petroleum generation in the canning basin have contributed to the ore forming fluids

light hydrocarbon redistribution in a shallow core from the ravnefjeld formation on the wegener halvo east greenland abstract twenty nine core samples extending from the surface to 60 m depth from the upper permian organic rich ravnefjeld formation source rock of east greenland have been analyzed for detailed light hydrocarbon composition in addition complementary organic carbon and rock eval analysis as well as some mineralogical and permeability analyses were carried out the objective was partly to determine if the changes in light hydrocarbon composition reflect generation patterns i e small scale changes in kerogen type and amount or are controlled primarily by redistribution processes a second objective was to discuss possible modes by which hydrocarbon redistribution took place the interval examined in the ravnefjeld formation is overmature 1 75 ro organic carbon contents toc and hydrogen index values range mostly between 1 0 5 5 and 10 20 mg hc g toc respectively the amount of hydrocarbons present in the examined section represent only a fraction of the total amount generated petroleum expulsion efficiency pee exceeding 0 99 was calculated systematic changes of light hydrocarbon composition with depth indicate that effective redistribution has occurred over wide intervals in particular there is good evidence to suggest that there was major loss with chemical fractionation of molecular species by depletion into several zones of fractures and also towards the outcrop surface and that fracture occurrence is the single most important factor in controlling the present day hydrocarbon depth trends in this paper a novel scheme is presented for effective and objective comparison of hydrocarbon depth trends the application of this method to elucidation of the migration mechanisms responsible for fractionation during hydrocarbon loss in the fractured zones is illustrated

inter and intrafield hydrocarbon compositional variations in the ula and the gyda fields central graben north sea implication for understanding the controls on hydrocarbon distribution within and between these fields abstract a suite of 34 oil samples from the ula and 30 from the gyda oil fields lying in the central graben of the norwegian continental shelf was analyzed using thin layer chromatography with flame ionization detection tlc fid capillary gas chromatography with flame ionization detection gc fid and gas chromatography mass spectrometry gc ms the results obtained were used to calculate several source and maturity based parameters these parameters suggest that within the ula field oils produced more recently have greater compositional homogeneity than those produced earlier this has been attributed to a recent change in the crestal fault behavior this change in fault behavior is probably production related the gyda field oils are compositionally more homogeneous however oils from the gyda south culmination are compositionally different this difference shows up in both maturity and source related parameters

gas condensate migration and oil fractionation in deltaic systems abstract the term evaporative fractionation is proposed to describe several phenomena involved in the secondary alteration of reservoired oil firstly it is suggested that oil is frequently partially vaporized in the reservoir secondly that gas bearing substantial portions of the oil in solution is conducted along faults to form independent gas condensate accumulations thirdly that residual oils formed in this fashion bear internal evidence of fractionation in addition to the conspicuous loss of light ends there is an increase in the content of light aromatic and naphthenic hydrocarbons relative to paraffins in the residual oil evaporative fractionation effects are recognized for the first time in the distillation and physical property data of us bureau of mines routine method oil analyses fractionation effects are postulated to be the cause of sigmoid as opposed to normal curvilinear aromatic profiles the effects of evaporative fractionation are widespread in oils throughout the united states they are evident in approximately 75 of oils in the gulf coast region and in a large proportion of the gas condensate accumulations the process is a major and apparently unrecognized means of petroleum alteration and of generation of gas condensates experimental evidence shows that partial vaporization results in enhanced levels of light aromatic hydrocarbons in residual oils oil samples were partially vaporized in excess methane at elevated pressure and temperature followed by removal of the vapour the gas chromatographic features of many gulf coast oils were reproduced various levels of light end depletion and enhancement of aromaticity were brought about

hydrocarbon composition of authigenic inclusions application to elucidation of petroleum reservoir filling history abstract geochemical analysis of petroleum inclusions trapped in authigenic feldspar and quartz in the ula formation in the north sea ula oil field revealed a petroleum of markedly different composition than the oil presently in the reservoir using microthermometry and the burial history as a dating tools it is concluded that the petroleum in the k feldspar inclusions was present in the more porous and permeable parts of the ula formation as early as 45 75 my bp when the field was at a depth of about 1 0 1 5 km as compared with the current depth of 3 4 km this early petroleum which was trapped as inclusions in authigenic k feldspar shows a distinctly different distribution of tricyclic terpanes and pentacyclic triterpanes from that of the current petroleum charge in the ula formation which was derived from the mandal formation source rock in late neogene time molecular parameters show that the oil in the k feldspar inclusions is significantly less mature than the crude oil in the present reservoir the approximate 90 c temperature increase occurring after entrapment of the early petroleum in kfeldspar the field is currently at 143 c appears not to have reset the low maturity signature of the oil in the k feldspar inclusions this could suggest that the temperature in the inclusions is too low for isomerization selective thermal degradation to occur lack of catalysts or that there are other controls on the ratio of some of these parameters still parameters like the ratio of c21 to c28 triaromatic steroids and those based on dimethyl and trimethyl naphthalenes are comparatively similar in both the inclusions and in the reservoir crude the oil inclusions in authigenic quartz and albite formed from about 10 my bp burial depth 2 5 km until the present burial depth 3 4 km are interpreted as representing a palaeo petroleum charge having a composition intermediate between the oil found in k feldspar inclusions and the oil charge in the present reservoir our data suggest strongly that the petroleum trapped in the inclusions in quartz and plagioclase represents progressive dilution of the early reservoired oil now found only in k feldspar inclusions with oil from the mandal formation analysis of solution gas in these inclusions suggests that the first petroleum associated gas to arrive at the trap from the progressively maturing mandal formation had a much wetter composition than the current reservoir solution gas to explain the present comparatively drier and isotopically lighter reservoir solution gas composition the inference is made that there has been a recent during formation of k feldspar inclusions 45 75 my bp maturation of the upper jurassic mandal formation the main source rock in this region was limited possibly to the graben axis this suggests that the petroleum found in the k feldspar inclusions was most likely derived from a deeper post caledonian palaeozoic formation

relationship between diagenesis and reservoir quality in sandstones of the garn formation haltenbanken mid norwegian continental shelf a quantitative model is proposed for the dependence of porosity and permeability on diagenesis in subarkosic arenites of the middle jurassic garn formation porosity variation is controlled by the combined effects of compaction and quartz cementation in general more porosity has been lost by compaction than by quartz cementation but compactional porosity loss appears to have occurred relatively early in the burial history before burial below 2 km below the sea floor thus progressive reduction of the total porosity with increasing burial below 2 km results mainly from quartz cementation permeability is a function of the abundance of intergranular macroporosity which is interpreted to be a measure of effective porosity at depths less than 3 5 km below the sea fl or intergranular macroporosity generally comprises more than 50 percent of the total porosity but at greater depth as total porosity decreases below about 16 percent the ratio of effective to ineffective porosity drops below one this depth corresponds to the onset of extensive illitization and grain dissolution which results in major reorganization of the pore system generation of secondary porosity by feldspar dissolution appears not to have been beneficial to reservoir quality in the garn formation but it is regarded as an intrinsic part of the overall process of porosity destruction with increasing diagenesis

24 norcholestanes as age sensitive molecular fossils biomarkers molecular fossils are organic compounds in holocene to precambrian sedimentary deposits that can be related to specific chemical compounds produced in the biosphere we demonstrate here that 24 norcholestane biomarkers i e c26 steranes saturated hydrocarbons having a steroid skeleton can be useful to constrain the age and paleolatitude of geologic samples the biological precursors of 24 norcholestanes remain unclear but samples from more than 100 basins provide evidence that 24 norcholestanes may be derived directly or indirectly from diatoms ratios of 24 norcholestanes to 27 norcholestanes show an initial increase above background in jurassic oils but they increase dramatically in cretaceous oils coincident with diatom evolution the highest ratios are found in oils and rock extracts from oligocene or younger marine siliceous source rocks in which the sources were deposited at paleolatitudes 30 n

geochemical and biological marker assessment of depositional environments using brazilian offshore oils abstract a combined geochemical and molecular characterization of a wide selection of oils from the major brazilian offshore basins has been undertaken the elemental sulphur nickel and vanadium and bulk oapi and 13c properties of each sample been considered together with its molecular composition determined using liquid and gas chromatography and quantitative biological marker investigations using gas chromatography mass spectrometry for alkanes the results reveal significant differences in the chemical features of the various oils which enable them to be divided into five groups the distinction of the groups appears to reflect differences in the depositional environment of the source rocks of the oils each group is correlated tentatively with source rocks laid down in a specific depositional regime namely lacustrine freshwater lacustrine saline water marine evaporitic marine carbonate or marine deltaic the diagnostic features that allow this classification are the relative abundance and carbon number distributions of n alkanes pristane phytane ratios sulphur nickel and vanadium contents carbon isotope data the absolute concentrations of hopanes and steranes and their abundance relative to 4 methylsteranes and also the occurrence and abundance of several specific biological markers including 18 h oleanane gammacerane carotane tricyclic terpanes higher acyclic isoprenoids 28 30 bisnorhopane and 25 28 30 trisnorhopane this investigation shows the value of a combined geochemical and molecular approach in the assessment of the palaeoenvironment of deposition of the source rocks which gave rise to the oils

some aspects of the organic geochemistry of petroleum fluids the most important influences on the compositions of petroleum fluids are in many cases the composition of a petroleum sample may allow the depositional environment of its source rock and its temperature history before and after expulsion to be determined this information assists the search for more petroleum in a region we suggest that this approach should be used more frequently to validate models of petroleum generation and migration in the second part of the paper we discuss the origin and nature of the differences in petroleum composition which are frequently found within individual petroleum reservoirs petroleum accumulations in permeable reservoirs are normally found to be inmechanical equilibrium and verticalchemical equilibrium this is manifested by constant subsurface fluid density at any given depth across the accumulation and increases in subsurface density with depth known as gravitational segregation however even in permeable reservoirs lateral differences in composition inherited from the reservoir filling process are not totally eliminated by mixing processes such as diffusion and convection thus lateral chemical equilibrium is often not achieved and lateral compositional variations are observed in present day oil and gas reservoirs these observations are justified in terms of order of magnitude estimates for the rates at which reservoirwide mixing occurs a case history is presented

potassium leached zones at the contacts of the garn formation mid norwegian continental shelf evidence for the role of shale in sandstone diagenesis abstract

coal as a source rock for oil a review the geological debate about whether and to what extent humic coals have sourced oil is likely to continue for some time despite some important advances in our knowledge of the processes involved it is clear that not only liptinites but also perhydrous vitrinites have the potential to generate hydrocarbon liquids in the course of natural coalification some liptinites especially alginite cutinite and suberinite contain a higher proportion of aliphatic moieties in their structure than other liptinites such as sporinite and resinite and are therefore more oil prone it is of potential value to be able to predict the several environments of deposition in which coals with high liptinite contents or containing perhydrous vitrinites may have been formed review of the distribution of oil prone coals in time and space reveals that most are jurassic tertiary with key examples from australia new zealand and indonesia methods based both on experimental simulations and the examination of naturally matured samples have been used to determine the order of generation of hydrocarbons from different macerals results are not entirely consistent among the different approaches and there is much overlap in the ranges of degradation but it seems probable that in the natural environment vitrinites begin to generate early followed by labile liptinites such as suberinite then cutinite sporinite and finally alginite petroleum potential may be determined by experimental simulation of natural coalification or inferred through various micro techniques especially fluorescence and infrared ir spectroscopy or bulk techniques such as elemental analysis and 13c nmr spectroscopy the latter three techniques enable a measure of the polymethylene component of the coal which now appears to be one of the best available approaches for determining petroleum potential no method of experimental simulation of petroleum generation from coals is without criticism and comparative results are highly variable however hydrous pyrolysis confined pyrolysis and forms of open system hydrous pyrolysis approach acceptable simulations whether and to what degree generated liquid hydrocarbons are expelled has long been the central problem in oil from coal studies the structure of vitrinite was believed until recently to contain an interconnected microporous network in which generated oil would be contained until an expulsion threshold was attained recent studies show the pores are not interconnected combined with a dynamic model of pore generation it now seems that expulsion of hydrocarbons is best explained by activated diffusion of molecules to maceral boundaries and ultimately by cleats and fractures to coal seam boundaries the main reason for poor expulsion is the adsorption of oil on the organic macromolecule which may be overcome 1 if coals are thin and interbedded with clastic sediments or 2 if the coals are very hydrogen rich and generate large quantities of oil the existence of oil in vitrinite is attested to by solvent extractions fluorescence properties and by microscopic observations of oil and bitumen experimental simulation of expulsion of oil from coals has only recently been attempted the relative timing of release of generated co2 and ch4 could have considerable importance in promoting the expulsion of liquid hydrocarbons but the mechanism is unclear as it is universally agreed that dispersed organic matter dom in some shales readily generates and expels petroleum it is curious that few consistent geochemical differences have been found between coal macerals and dom in interbedded shales unambiguous evidence of expulsion from coals is limited and in particular only a few commercial oil discoveries can be confidently correlated to coals these include upper cretaceous fruitland formation coals in the usa from which oil is produced new zealand tertiary coals and middle jurassic coals from the danish north sea it is likely that coals have at least contributed to significant oil discoveries in the gippsland basin australia in the turpan basin china and in the kutei and ardjuna basins in indonesia but this remains unproven early reports that early jurassic coals in mid norway were a major source of the reservoired oils have been shown to be inaccurate none of the proposed rules of thumb for generation or expulsion of petroleum from coals seem particularly robust decisions on whether a particular coal is likely to have been an active source for oil should consider all available geological and geochemical information the assumptions made in computational models should be well understood as it is likely with new understandings of processes involved that some of these assumptions will be difficult to sustain

biodegradation of oil in uplifted basins prevented by deep burial sterilization biodegradation of crude oil by bacterial activity which has occurred in the majority of the earth s oil reserves is known to reduce greatly the quality of petroleum in reservoirs for economically successful prospecting for oil it is therefore important to understand the processes and conditions in geological formations that lead to oil biodegradation although recent studies speculate that bacterial activity can potentially occur up to temperatures as high as 150 degrees c refs 3 4 it is generally accepted that effective petroleum biodegradation over geological timescales generally occurs in reservoirs with temperatures below 80 degrees c ref 2 this appears however to be at odds with the observation that non degraded oils can still be found in reservoirs below this temperature here we compile data regarding the extent of oil biodegradation in several oil reservoirs and find that the extensive occurrence of non biodegraded oil in shallow cool basins is restricted to those that have been uplifted from deeper hotter regions of the earth we suggest that these petroleum reservoirs were sterilized by heating to a temperature around 80 90 degrees c during deep burial inactivating hydrocarbon degrading organisms that occur in the deep biosphere even when such reservoirs are subsequently uplifted to much cooler regions and filled with oil degradation does not occur implying that the sterilized sediments are not recolonized by hydrocarbon degrading bacteria

degradation and maturity controls on oil field petroleum column heterogeneity in the gullfaks field norwegian north sea abstract a geochemical mapping of the gullfaks reservoir petroleum column based on 226 reservoir core extracts and 23 drill stem test dst and repeat formation test rft oil samples indicates the presence of statistically testable lateral compositional heterogeneities in the petroleum column these different petroleum populations can be related to lateral filling of the field from two source basins and a more pervasive subsequent episode in reservoir biodegradation petroleum maturity gradients within the field were detected using conventional biomarker gc ms methods on saturated hydrocarbon fractions the degree of biodegradation was monitored by quantitative gc of n alkanes in whole oil samples using a squalane internal standard the observed compositional differences in the gullfaks petroleum column are consistent with diffusion being the primary mixing process thermal convection being eliminated on both compositional and modeling grounds compositional differences between core extracts and dst samples from the same intervals suggest that fractionation of petroleum might occur during testing and that interpretation of reservoir petroleum columns from mixed sample sets should be treated cautiously

assessment of fluid contacts and compartmentalization in sandstone reservoirs using fluid inclusions an example from the magnus oil field north sea location of an oil water contact is crucial for estimating reserves and for designing production strategies identifying hydrodynamic barriers or baffles is also important for optimizing both recovery and flow rates in some oil fields identifying fluid contacts and barriers is not always possible using conventional wireline and formation testing methods

controls on the oil and gas potential of humic coals abstract humic coals are highly heterogeneous both with respect to maceral content and chemical composition although the oldest known humic coals albeit gas prone are of devonian age the majority of humic coals capable of generating and expelling non volatile oil are of cretaceous and tertiary age from australia new zealand and southeast asia in contrast the middle jurassic humic coals of the sleipner and hugin formations in the south viking graben of the north sea are primarily gasprone but have the capability to expel aliphatic rich volatile oil these coals have toc contents up to 80 and hydrogen indices hi ranging from 200 to 400 they are vitrinite rich with some containing up to 45 inertinite liptinite concentrations are generally around 10 20 chiefly as spores pollen and abundant resinite the main control on the oil potential of humic coals is the concentration of long chain aliphatic hydrocarbons in the coal matrix although the aliphatics have a high h c ratio the inference on hydrogen content from the rock eval pyrolysis hi value can be misleading for hi values below 500 mg hc g oc there is no relation between hi and the potential of the coals to generate non volatile oil consequently the hi is a poor indicator of the non volatile oil potential of humic coals a more robust indicator is the relative amount of c8 aliphatic groups also the bulk measure of liptinite content may also prove misleading when assessing the oil potential of coals high resinite concentrations can lead to an overprediction of the non volatile oil potential as they contribute significantly to the hi value but will generate primarily volatile aromatic rich oils expulsion from the sleipner and hugin coals appears to have occurred in a gaseous phase with preferential release of short chain alkanes

generation and migration of hydrocarbons on southern norwegian shelf abstract the southern norwegian shelf 56 58 30 primen has proved to be one of the most prolific hydrocarbon provinces in europe recoverable reserves of about 2 billion bbl of oil are found predominantly in upper cretaceous danian age chalk and jurassic sandstones the excellent quality of seismic data moderate dense well control and the detailed geochemical evaluations of the kimmeridge clay the principal source rock make the southern norwegian shelf an ideal area for hydrocarbon generation studies a geochemical analysis of the area contained 4 basic steps 1 construction of a 9 layered 3 dimensional grid summarizing the burial history of the sediments using well control and seismic data 2 calculation of geothermal gradients 3 source rock analysis to investigate variations in thickness and richness throughout the study area of the kimmeridge clay and 4 maturation study based on the results of the 3 initial steps major factors affecting hydrocarbon accumulations in the structural and stratigraphic closures of the study area include the amount of oil generated within the catchment areas of the various closures and particularly in the case of the chalk fields the level of hydrocarbon generation of the kimmeridge clay directly under the crest of the structure and the presence of faults to act as conduits for vertical migration of hydrocarbons from the upper jurassic kimmeridge clay to the upper cretaceous danian chalk the expulsion and migration efficiency hydrocarbons in place hydrocarbons generated within the catchment area of individual closures for tested closures averages approximately 8 for the study area with individual culminations having values as high as 40 or as low as 0 based in part on the previously mentioned factors end of article last page 796

paleoreconstruction by biological markers abstract during diagenesis and conversion of the original lipid fraction of biological systems to petroleum hydrocarbons the following four basic events needed for paleoreconstruction can be monitored by biological markets 1 sourcing 2 maturation 3 migration and 4 biodegradation actual cases of applying biological markers to petroleum exploration problems in different parts of the world are demonstrated cretaceous and phosphoria sourced oils in the wyoming thrust belt can clearly be distinguished from one another by high quality source fingerprinting of biomarker terpanes using gas chromatography mass spectrometry identification of recently discovered biological markers head to head isoprenoids allows subtle source differentiation between oils from sumatra the degree of crude oil maturation in basins from california alaska russia wyoming and louisiana can be assessed by specific novel biomarker ratios 20s 20r sterane epimers field evidence from such interpretation is confirmed by laboratory pyrolysis of the rock an example of immature sumatra rock is given extensive migration is documented by biomarkers in several oils the effect of biodegradation on biomarker steranes and terpanes is exemlified in a california basin all biological marker results are consistent with the geological setting and add a new dimension in assisting the petroleum explorationist toward paleo reconstruction

significance of coniferous rain forests and related organic matter in generating commercial quantities of oil gippsland basin australia contrary to the conventional belief that humic coal generates primarily gas 3 billion bbl of recoverable oil has been discovered in the humic coaly succession of the fluviodeltaic latrobe group upper cretaceous tertiary that serves as both the reservoir and the source for hydrocarbons in the offshore gippsland basin of southeastern australia evidence for generation of liquid hydrocarbons from the coaly succession includes 1 similarity of n alkane distribution in the oil and in the coal extracts 2 high wax content of oil up to 27 by weight 3 high ratio of pristane phytane in oil 5 6 and 4 dominance of c29 steranes in the oil in the gippsland basin coniferous rain forests dominated by kauri vegetation flourished in a raised bog setting present temperate climate and kauri vegetation of new zealand are considered to be the modern analog to the gippsland basin the coniferous vegetation provided large quantities of hydrogen rich exinite macerals such as cutinite and resinite with potential to generate oil high rainfall raised ground water level low oxygen high acidity and low nutrient conditions of a raised bog setting were suitable for preserving organic matter a comparison of gas chromatograms of oils in the gippsland basin with gas chromatograms of oils generated by hydrous pyrolysis in the laboratory from the immature source rocks suggests that the paraffinic fraction of the oil was derived from coal and the naphthenic fraction was derived chiefly from resin

asphaltene rich residues in sandstone reservoirs of haltenbanken province mid norwegian continental shelf abstract thin zones of asphaltene rich residue are present near the crests of two adjacent oil and gas filled structures in one structure the smorbukk sor field multiple thin 5 50 cm dark coloured zones are observed within the lower 20 m of the 88 m thick garn formation these dark coloured zones tend to occur immediately above stylolitized mica clay laminations and become gradually lighter upwards apparently reflecting gradual upward decrease in residue abundance in the other structure the smorbukk field the lowermost 1 m of the formation is dark coloured and the sandstone gradually becomes lighter in colour upwards for a distance of about 3 m similar but more diffuse residues are also present throughout the oil zone in two other fields nearby organic geochemical analyses show that the residue rich dark coloured zones differ from the sorrounding lighter coloured sandstone mainly in having a higher content of asphaltenes whereas the total content of extractable organic matter is often similar thus the darker rocks might be regarded more as zones of conspicuous oil staining due to asphaltene deposition rather than as small tar mats the residues typically appear to have accumulated under the influence of gravity at points where the downward flow was hindered by a lithological discontinuity present day zonation upward decreasing gas to oil ratio in the oil column of the smorbukk sor reservoir is consistent with a model of asphaltene precipitation in the lower part of the reservoir in response to upward leakage of gas from an underlying gas condensate reservoir in the ile formation this is also consistent with the available organic geochemical data in thin section the asphaltene rich material is seen to preferentially coat feldspar and clay but not quartz surfaces thus illustrating why sandstone wettability should be expected to depend on both mineralogy and the asphaltene content of the petroleum involved

classification of offshore gulf of mexico oils and gas condensates five groups of petroleums can be recognized in the offshore gulf of mexico on the basis of carbon isotope and sulfur isotope ratios sulfur content and relative abundances of nickel and vanadium of 355 oils analyzed 341 96 1 are evidently closely related and cannot be subdivided on the basis of carbon or sulfur isotopes we suggest that these oils represent a single broad superfamily however two subgroups within this set are distinguishable on the basis of sulfur content and relative abundances of nickel and vanadium group 1a sigma 13 c 26 5 0 4 parts per mil sigma 34 s 5 6 2 4 parts per mil s 0 25 0 15 v ni v 0 27 0 10 and group 1b sigma 13 c 26 5 0 3 parts per mil sigma 34 s 5 9 1 2 parts per mil s 0 73 0 43 v ni v 0 67 0 07 group 1a oils are broadly distributed across the louisiana and adjacent texas continental shelf whereas group 1b oils are found along the louisiana shelf edge and continental slope group 1b oils have substantial genetic affinities to those from the campeche shelf offshore mexico of mesozoic origin the remaining 14 analyzed petroleums include supermature condensates from offshore texas and oils from offshore southern florida believed to be cogenetic with those from the jurassic smackover formation a three dimensional appraisal of geohistory suggests that petroleum generation began in the eocene in the region of the rio grande delta progressed coastwise to the mississippi delta area by the miocene and then occurred in regions of progres ively deeper water during the pliocene pleistocene

application of 24 norcholestanes for constraining source age of petroleum abstract two c26 sterane ratios the 24 nordiacholestane ratio ndr and the 24 norcholestane ratio ncr are useful for assessing petroleum source age values for these parameters generally increase in the cretaceous when diatoms were rapidly radiating and further in the oligo miocene due to widespread high latitude deposition of diatomaceous sediments sources with shale lithologies tend to exhibit the highest ratios while carbonate and terrigenous rich lithologies generally show lower ratios on the north slope of alaska elevated ratios are observed for cretaceous hrz oils and mixed oils containing cretaceous input compared to older triassic and jurassic derived oils tertiary sourced oils from romania and bulgaria have much higher ratios relative to jurassic sourced oils in the black sea region oleanane was observed in comparable levels in some black sea tertiary and jurassic oils and source rocks ndr and ncr coupled with other age diagnostic indicators such as oleanane and dinosterane provide powerful tools for differentiating age of source and organic facies for oils from the black sea and sub andean basins of peru and ecuador respectively oils derived from sources deposited in low tropical latitudes tend to have little diatom input and as a consequence do not display high values regardless of age

kaolinized potassium leached zones at the contacts of the garn formation haltenbanken mid norwegian continental shelf abstract the middle jurassic garn formation consists mainly of subarkosic arenite in which potassium feldspar is several times as abundant as plagioclase in cores from eight wells the top of the formation upper 6 12 m appears to have undergone relatively intense alteration of potassium feldspar to kaolinite with the resulting loss of bulk postassium content this could be explained as a result of subaerial weathering of the top of the sandstone body except for the fact that in two of the wells the same pattern of alteration is observed at the base of the formation an alternative explanation is that alteration resulted from the introduction of acid released by the maturation of organic matter in adjacent shales in all instances the altered zones display a gradual increase in kaolinite content and a decrease in the ratio of bulk rock potassium aluminium over a distance of several metres approaching the formation boundary this pattern indicates that the active species responsible for the alteration entered vertically from the formation contacts rather than being introduced by lateral flow along the sandstone bed the cores studied are tentatively interpreted as recording different stages in the following depth related sequence of diagenetic events 1 early kaolinization throughout the formation by meteoric water flushing 2 formation of additional kaolinite near the formation contacts by the influx of acid from surrounding shales at approximately 2 7 km depth below the sea floor and 3 extensive alteration of kaolinite to illite at approximately 3 7 km depth illitization has been impeded in the leached zones near the formation contacts due to a local deficiency in reactive potassium here kaolinite survives unaltered whereas kaolinite throughout the rest of the formation has been extensively replaced by illite this implies that the illitization of sandstone can occur by short range diffusion in a chemically closed system solely in response to increasing thermal exposure at greater depth

analysis of petroleum fractions by tlc fid applications to petroleum reservoir description abstract thin layer chromatography and flame ionization detection iatroscan tlc fid offers a rapid and accurate method for quantifying saturated and aromatic hydrocarbons and resin asphaltene fractions in solvent extracts of petroleum source rocks reservoir rocks and crude oils while the instrument is superficially simple special precautions need to be taken in calibration and parameter setting due to complexities arising from the operational characteristics of the detector system nevertheless the technique offers superior speed and precision to conventional mplc analysis of petroleum fractions this paper describes the choice of operational parameters provides comparison with the traditional group type analysis technique mplc and presents some geochemical applications

expulsion of oil from petroleum source rocks inferences from pyrolysis of samples of unconventional grain size oil expulsion efficiencies from different lithologies have been investigated and compared employing pyrolyses of samples of unconventional grain size from 300 mg hc g corg show that liquid range hydrocarbons are expelled from coal when the generated oil exceeds the coal sorption capacity this suggests that expulsion of oil from liptinite poor or in general h poor humic coals is primarily limited by the release of generated liquid hydrocarbons from kerogen because such coals generally do not generate sufficient amounts of liquid hydrocarbons to overcome the coal sorption capacity

a fluid inclusion study of quartz cemented sandstones from offshore mid norway possible evidence for continued quartz cementation during oil emplacement abstract jurassic sandstones from the oil zone in a well from the haltenbanken area offshore mid norway contain both aqueous and hydrocarbon fluid inclusions within quartz overgrowths homogenization temperatures for the inclusions range from 92 c up to the present formation temperature of approximately 118 c since the inclusions mostly are located at the boundaries between quartz clasts and quartz overgrowths the homogenization temperatures indicate that quartz cementation started at temperatures slightly below 92 c poikilotopic ferroan calcite cement usually predates formation of quartz overgrowths and most calcite cement must be precipitated at temperatures below 90 c although in one calcite cemented zone ferroan calcite encloses quartz overgrowths with inclusions trapped at temperatures of up to 105 c none of the examined hydrocarbon inclusions homogenized below 102 c and this suggests that oil started entering the reservoir at temperatures of around 100 c the burial history of the examined sandstones indicates that temperatures of 100 c were not reached before the late pliocene and that filling of the reservoir has taken place during the last few million years homogenization temperatures approximately equal to present formation temperature suggest that quartz cementation may still be in progress and that emplacement of oil did not necessarily stop precipitation of quartz cement possible continued quartz cementation after oil filled the reservoir could be explained by dissolution of quartz at stylolites and grain contacts as transport of dissolved quartz from these sources might possibly take place by diffusion through irreducible water

application of aromatic compounds as maturity indicators in source rocks and crude oils concentration ratios of aromatic compounds such as naphthalenes phenanthrenes and dibenzothiophenes are at present attracting increasing attention as maturity indicators in sedimentary rocks and crude oils generally these indicators rely either on an increase with maturity in the degree of alkylation of a given parent compound or a shift in the isomer distribution of alkyl aromatic homologues towards thermally more stable isomers a combination of both concepts in the methylphenanthrene index mpi resulted in an excellent maturity parameter as demonstrated for rock extracts by an improved correlation with mean vitrinite reflectance rm between 0 65 and 1 4 i e in the zone of oil formation in cases that rm measurements were ambiguous this empirical relationship has proved useful in the calculation of theoretical vitrinite reflectance rc values from the mpi on the other hand for potential petroleum source rocks reaching maturity at relatively low temperatures the influence of the organic matter type on the aromatic distributions cannot be neglected consequently organic facies effects should be taken into account in the interpretation of aromatic distributions of such source rocks and related crude oils since the impact of the organic facies is strongly reduced with increasing maturity aromatic maturity parameters are particularly useful in the maturity evaluation of post mature crude oils and condensates in contrast to biological markers substantially higher concentrations of the key alkyl aromatics persist at elevated maturation levels thus aromatic maturity parameters should be considered as versatile tools in organic maturation studies and can complement established maturity indicators based on steranes and terpanes

the jurassic petroleum system north and west of britain a geochemical oil source correlation study abstract recent significant oil discoveries have focused exploration attention on the atlantic margin areas north and west of britain in particular the west of shetlands area these discoveries the foinaven and schiehallion fields each have reserves of 250 to 500 million barrels 39 8 to 79 5 106 m3 of 24 27 api oil while an earlier heavy oil discovery the clair field is the largest undeveloped oil discovery on the u k continental shelf with resources estimated in the range 3 5 billion barrels 477 to 795 106 m3 other discoveries include suilven the very heavy oil in well 204 28 1 and the quadrant 205 strathmore and solan fields potential source rocks in areas adjacent to the west of shetlands include the upper jurassic kimmeridge clay formation equivalent the middle and lower jurassic and the middle devonian the results of geochemical studies of the oils reservoir core extracts and source rocks from released wells from these west of shetlands discoveries show them to be genetically related to north sea oils sourced from the kimmeridge clay formation equivalent detailed geochemical analysis biomarkers source rock reaction kinetics compound specific isotope analysis and fluid inclusion crush leach analysis of the clair field and foinaven complex oils showed that at least two episodes of charging from different source facies within the kimmeridge clay formation took place with an intervening biodegradation event oil charging from middle jurassic lacustrine source rocks is also indicated in the foinaven complex oils the source rocks are shown to exhibit variations in organic facies from very oil prone to mixed oil and gas with a corresponding range of kinetic parameters this complex generation migration and trapping scenario is directly linked with the tectonic evolution of the west of shetlands with major oil generation from very oil prone kimmeridge clay and middle jurassic lacustrine facies into shallow buried reservoirs biodegradation of the oils appears to have occurred shortly after migration into the traps followed later by a second charge of unaltered oil this appears to have been from a different source facies with more terrestrial slower reacting type ii iii kerogens similar to those seen in the kimmeridge clay formation or heather formation in wells on the basin margins kinetics studies show the middle and upper jurassic kerogens to be fast reacting and very oil prone with little potential for later gas generation this finding appears crucial in the understanding of the west of shetlands petroleum system as it explains the lack of large gas accumulations in a basin of such high thermal maturity

episodic fluid expulsion from geopressured sediments numerical simulation of fluid explusion from geopressured sediments using a one dimensional finite difference model shows that large volumes of fluid can be transported through a fractured seal during short lived 100 year expulsion events in this model abnormal fluid pressures are maintained by an impermeable seal when the fluid pressure exceeds 85 of the lithostatic pressure a vertical fracture opens in the seal providing a permeable pathway from the geopressured sediments into the overlying section fluid pressure in the seal decreases as fluid flows through the fracture closing the fracture as sediments in the seal compact once the fracture closes the seal remains impermeable until fluid flowing from deeper in the section increases fluid pressure to the fracture criteria a process that takes 10 000 500 000 years fractures emplaced in relatively incompressible seals such as compacted and or cemented sediments remain open for 20 50 years fluid fluxes through the seal integrated over the life of these events are 1 5 107 kg m2 and temperatures in the overlying sediments are increased by 5 20 c these temperature anomalies decay to less than half their original value in 300 years suggesting that the thermal anomalies observed in wells that are attributed to fluid expulsion formed in response to a very recent or currently active event

molecular analysis of petroleum in fluid inclusions a practical methodology a method is described for extracting the petroleum from petroleum bearing fluid inclusions hosted in the diagenetic cements of sedimentary rocks whilst minimising contamination from petroleum in the pore space a clean up technique involving the addition of extraction standards to the rock prior to analysis has been developed that allows increased confidence that the hydrocarbons extracted are only from included petroleum and are not mixtures of included petroleum and petroleum or other organic material adhering to the surface of the host minerals within the sample replicate quantitative analyses indicate that the technique produces highly reproducible results the problems of analysing included petroleum and the clean up method development are discussed and examples of analyses of included petroleums from carbonate reservoir and carrier units are given

relationship between reservoir diagenetic evolution and petroleum emplacement in the ula field north sea abstract the diagenetic and petroleum filling histories of the ula field have been studied by analysing aqueous and petroleum inclusions occurring in authigenic cements this study shows that diagenesis continues actively after the arrival of petroleum in the sandstones although the reaction rates and petroleum saturation remain obscure microthermometric measurements of fluid inclusions in authigenic quartz suggest an onset of extensive quartz cementation at temperatures around 110 c i e 2 5 km and that this cementation has continued to the present day synchronously with quartz cementation authigenic albite was formed as inter and intragranular cements large amounts of petroleum inclusions locally occur in the albite and quartz cements these inclusions were trapped in the cements as the main charge of petroleum arrived at the structure diffusion through thin water layers between the petroleum and the mineral surface would probably have dominated mass transfer of solutes for the precipitation of authigenic quartz and albite it is evident from analysis of the petroleum inclusions in early formed k feldspar overgrowths that some secondary migrated petroleum probably arrived in the reservoir at a shallow burial depth before the rapid subsidence in the last 25 my compared with petroleum in the free porosity of the ula formation the petroleum in the k feldspar inclusions is evidently sourced from a different source facies and most maturity parameters testify to the latter being less mature later trapped petroleum inclusions in quartz and albite have characteristics found both in k feldspar and in the ula formation dst oil and thus is likely to reflect the progressive change in the ula field petroleum charge which occurred during the time period of quartz diagenesis

a dynamic deterministic model of hydrocarbon generation in the midgard field drainage area offshore mid norway the midgard field offshore mid norway is a gas condensate accumulation with a thin oil leg reservoired in early and middle jurassic sandstones there are two potential source rocks in the area the late jurassic spekk formation is a marine shale with type ii kerogen and a rich potential for oil and the are formation of early jurassic age which is a thick coal bearing sequence with type iii kerogen and potential mainly for gas geochemical analyses indicate that both the condensate and the oil leg are sourced mainly from the coal bearing are formation any contribution from the spekk formation appears to be of minor importance computer simulation of hydrocarbon generation in the drainage area for the midgard field indicates that huge volumes are formed and confirms that hydrocarbon generation from the are formation is volumetrically far more important than from the spekk formation the simulation results also exclude any contribution to the reservoired gas from the spekk formation

exploring foredune growth capacity in a coarse sandy beach abstract dunes are key elements of coastal landscapes in almost every latitude they host high levels of biodiversity and provide important benefits to society e g protection against floods and erosion or recreation coastal dune growth is constrained by intrinsic factors which are critical when managing dune systems or choosing coastal dune restoration as an alternative green solution for coastal protection here the evolution of a beach dune system characterized by a reflective coarse sandy beach and low dunes is explored to identify the favourable and optimal conditions for dune growth in these settings dune growth capacity is evaluated by analysing the topographical changes observed along a coastal dune over two different temporal scales interannual and event scale and comparing the observations with theoretical approximations of sediment transport potentials observations and predictions over interannual scale document that 1 temporal variability in external conditions wind regime and spatial variability of estimated wind fetch length alone fail to explain alongshore dune growth patterns and 2 optimal conditions for dune growth occur when storms strong winds impact the study area jointly with low runup levels at zones of shoreline progradation and absence of direct human influence conversely lowest values of dune accumulation are associated with areas where shoreline retreat was documented observations from event timescales suggest that sediment transport potential can be reached over zones with no significant signs of beach erosion if runup levels remain low and the event duration is shorter than the time scale of sand surface depletion within the upper beach

understanding of hc migration in sedimentary basins present state of knowledge abstract great advances were made during the decade of 1975 1985 in the understanding of hc migration by establishing that the main mechanisms were polyphasic flow whatever its stage and that migration in solution in water and or by molecular diffusion was insignificant except for methane ethane and benzene research is now focusing on points which still have not been satisfactorily answered such as 1 1 behaviour of source rocks during hc expulsion the main driving force for fluid expulsion has been recognized to be excess fluid pressure within the source rock with respect to its surrounding environment of permeable beds the pressure build up is due mainly to accommodation by the fluids of part of the mechanical stresses which are exerted on the rock mainly sedimentary load but also stresses developed by tectonics to thermal expansion of water and to hc formation from kerogen in response to increasing temperatures however it is not clear whether or not petroleum expulsion proceeds preferentially along oil wet networks kerogen or oil wet mineral surfaces nor it is not clear whether or not microfracturing provoked by an internal fluid pressure higher than allowed by the mechanical strength of source rocks is necessary for hc expulsion 2 2 modifications of the compositions of hc phases e g oil versus gas or the distribution of biomarkers during migration and losses of hydrocarbons along the migration pathways although careful observations of natural sample series and also experimentation have been done no clear picture has emerged for the moment however compositional effects seem to be due more to changes in thermodynamic conditions along migration pathways which provoke inter alia hydrocarbon phase separation retrograde condensation than to differential retention by mineral surfaces it is likely that while careful observations on a large variety of source rock samples are needed to more clearly understand source rocks functioning progress in understanding hc migration will come increasingly from modeling and experimentation models which mathematically simulate natural processes are necessary to help the human mind in handling such complex phenomena and therefore are of precious help to focus research on the most important points they replace migration in its geological and historical dimensions with numerical or conceptual tools while observation only describes the present state models are also the tools by which knowledge on migration can be applied to exploration problems however quantitative applications of models require numerous and precise geological data that are difficult to gather at early stages of exploration in the field of experimentation it will be easier to design crucial experiments now that hc migration mechanisms are better understood thanks to experimentation it should also be possible to validate models however so as to reach such aims substantial progress has to be made in the technology of experimental systems

sequential extraction a useful tool for reservoir geochemistry abstract little is known about the microscale distribution and potential molecular fractionation of bitumen residing in reservoir rocks few data exist on the comparative organic geochemistry of hydrocarbons in authigenic inclusions formed in reservoir rocks and the bitumen in the pore space a three step sequential extraction technique has been applied to clastic petroleum reservoir samples using a suite of solvents with increasing polarity in order to address these questions in the analyzed samples the following main trends were observed i the first extract represents 95 of the total extract ii the relative polar compound content increases going from the first to the last extract iii the last extract has generally a slightly lower apparent maturity as assessed using biomarker parameters additionally a reduction in the degree of biodegradation from the first to the last extracts was observed implying tentatively that biodegradation takes place dominantly in the center of the pores fluid inclusion extracts show distinct source characteristics however the last extract appears to approach the fluid inclusion extract signature in some aspects the use of sequential extraction as a routine tool in the reservoir geochemical context is judged to be limited however it may help to solve specific problems

a study of natural and artificially generated light hydrocarbons c4 c13 in source rocks and petroleum fluids from offshore mid norway and the southernmost norwegian and danish sectors abstract the free or natural light hydrocarbon composition obtained by thermal extraction gc of source rock samples is compared with the light fraction generated by pyrolysis products of the kerogens even though there are large differences between the composition of the free c 4 c 13 hydrocarbon fraction and the same fraction generated by pyrolysis some characteristics have been detected which can be used interchangeably for both data types visual inspection of gas chromatograms from thermal extracts and pyrolysates indicates that in particular the relative content of m p xylene corresponds well between these two analytical methods the source rock samples used are upper jurassic marine shales and middle and lower jurassic coals and coaly shales from offshore mid norway and denmark more detailed analysis of the data shows that the most effective parameter which can distinguish between different source rock types in both thermal extracts and pyrolysates is the m p xylene n c 8 ratio this parameter has been used to derive classification diagrams for interpreting the source of light hydrocarbons of both natural petroleum fluids analysed by gas chromatography and the same fraction generated by pyrolysis of asphaltenes from the fluids the model was first tested on 17 natural petroleum fluids from mid norway since a comprehensive study of light hydrocarbon distributions already has been published further the parameter was applied to correlate with asphaltene pyrolysates of the fluids from mid norway and a total of 22 natural oils and condensates from the southernmost norwegian and danish sectors

petroleum migration faults and overpressure part ii case history the haltenbanken petroleum province offshore norway abstract petroleum inclusion and geochemical data from core extracts were applied to deduce a model for oil migration overpressure development and palaeo leakage of oil from currently dry structures in the haltenbanken vest area the existence of fluorescent oil type inclusions in quartz in the smorbukk asgard 2 field suggest that oil migrated into this structure 70 50 million years before present ma bp this is also the case for the dry structures 6506 12 4 6506 11 3 and 6506 11 1 west of the main smorbukk fault zone black oil inclusions with medium gas oil ratio gor occur in these fields together with condensate type petroleum inclusions this suggests that the dry structures transformed from containing oil to condensate before leakage petroleum extracted from inclusions in these structures and in nearby fields have identical marine type ii kerogen signatures source rocks at the spekk formation level in the current drainage area of smorbukk and these dry structures were immature 70 50 ma bp and the smorbukk sor asgard 3 field did not fill at this early time thus oil must initially have entered into smorbukk from areas to the w sw through the currently pressure sealing smorbukk fault zone which today marks the westward limit of the smorbukk field diagenesis in this fault zone caused the much later overpressure development and petroleum was lost from the 6506 12 4 6506 11 3 and 6506 11 1 structures as overpressure built up regionally petroleum loss from these structures with their often thick seals must have occurred via self propagating open fracture induced mechanisms lack of petroleum in the cretaceous strata above these structures suggests that leakage occurred to even shallower strata this could imply that the cretaceous strata in halten vest were overpressured at the time of leakage in contrast the oil in the cretaceous lysing and lange formation above the jurassic reservoirs in smorbukk and smorbukk sor most likely originated based on geochemistry and gors from the jurassic reservoirs below and not from cretaceous strata this migration event would have been facilitated if it occurred before these sands became overpressured as they are today modelling suggests that the spekk formation became mature in the smorbukk sor region

geochemical study on a well in the western canada basin relation of the aromatic distribution pattern to maturity of organic matter abstract thirty one rock samples from a western canada basin well have been analysed for aromatics using glass capillary gas chromatography with simultaneous flame ionization and sulfur selective flame photometric detection a uniform aromatic distribution pattern with a marked predominance of di and tricyclic aromatic hydrocarbons was observed throughout a depth interval of 3000 meters comprising cretaceous and jurassic sediments the very high relative abundance of sulfur aromatics at two narrow intervals in the triassic and mississippian is attributed to a major change in facies gradual changes with increasing depth have been observed for a series of compound ratios which had been calculated from the isomers of methyl and dimethylphenanthrene and their parent compounds these changes reflect the increasing thermal maturation of the sedimentary organic matter a methylphenanthrene index mpi has been introduced which exhibited a very good correlation with vitrinite reflectance data the mpi is the first maturity parameter which is based on a series of aromatic hydrocarbons this hydrocarbon internal maturity parameter permits the recognition and definition of maturity levels in extracts which can be compared to the maturity e g vitrinite reflectance of source rocks

application of light hydrocarbons c4 c13 to oil source rock correlations a study of the light hydrocarbon compositions of source rocks and test fluids from offshore mid norway abstract 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 are 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 are formation samples a total of twenty six samples from the spekk formation and twenty four samples from the are 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 are 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 are 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

the ratios of dibenzothiophene to phenanthrene and pristane to phytane as indicators of depositional environment and lithology of petroleum source rocks abstract the ratio of dibenzothiophene to phenanthrene and the ratio of pristane to phytane when coupled together provide a novel and convenient way to infer crude oil source rock depositional environments and lithologies such knowledge can significantly assist in identifying the source formation s in a basin thereby providing valuable guidance for further exploration the ability to infer this information from analysis of a crude oil is especially valuable as frequently the earliest samples in a new area may be shows and or drill stem test samples from exploratory wells which are characteristically drilled on structural highs stratigraphically remote from the source formation s a cross plot of dibenzothiophene phenanthrene versus the pristane phytane ratios measured on seventy five crude oils from forty one known source rocks ranging in age from ordovician to miocene consistently classified the oils into the following environment lithology groups marine carbonate marine carbonate mixed and lacustrine sulfate rich lacustrine sulfate poor marine and lacustrine shale and fluvial deltaic carbonaceous shale and coal the dibenzothiophene phenanthrene ratio alone is an excellent indicator of source rock lithology with carbonates having ratios 1 and shales having ratios the dibenzothiophene to phenanthrene and the pristane to phytane ratios can also be used to classify source rock paleodepositional environments the classification scheme is based on the premise that these ratios reflect the different eh ph regimes resulting from the significant microbiological and chemical processes occurring during deposition and early diagenesis of sediments the dibenzothiophene phenanthrene ratio assesses the availability of reduced sulfur for incorporation into organic matter and the pristane phytane ratio assesses the redox conditions within the depositional environment interpretation of these ratios has been aided by quantitative biomarker analysis and by carbon isotope data for pristane and phytane obtained by gas chromatography isotope ratio mass spectrometry

petroleum biodegradation in the tertiary reservoirs of the north sea abstract a suite of 17 oil samples from the tertiary reservoirs palaeocene eocene of the north sea was subjected to routine geochemical analytical techniques in order to evaluate the degree of biodegradation the methods included latroscan tlc fid gas chromatography of the saturated and aromatic hydrocarbon fractions gas chromatography mass spectrometry of the saturated hydrocarbon fraction and stable carbon and hydrogen isotope analyses in addition api gravities and weight percentages of asphaltene were also determined based on these data it was found that oils in the suite were derived from the jurassic aged kimmeridge clay formation originating from source rock horizons at similar maturity levels the oils in the suite were taken from reservoirs with present day temperatures 49 114 c differences in the chemical composition of the oils e g reduced relative amounts of saturated hydrocarbons increased polar amounts and reduced relative concentrations of n alkanes were attributed to secondary alteration processes of which the most likely process to occur at temperatures less than 80 c and consistent with the observed chemical characteristics of the oils is biodegradation the differences in chemical composition are thus attributed to different degrees of biodegradation the oils were ranked and classified in terms of the degree of biodegradation using a range of restricting parameters based on the gas chromatographic concentrations of different alkane species based on these parameters oils were divided into four classes these classes are a non to slightly biodegraded b mildly biodegraded c moderately biodegraded and d severely biodegraded in cases where the degree of biodegradation was found to have reached levels where unambiguous identification of alkanes was not possible unresolved complex mixture ucm parameters were utilised to assess the extent of biodegradation the degree of biodegradation was subsequently compared to the type of reservoir sandstone facies from which oils in this study were taken it was found that at similar temperatures oils in the balder formation upper late palaeocene were biodegraded to a higher degree compared to oils from either the forties lower late palaeocene or sele middle late palaeocene formation the higher degree of biodegradation in balder reservoirs is attributed to relatively greater openness to meteoric water invasion in these reservoirs

application of pyrolysate carbon isotope and biomarker technology to organofacies definition and oil correlation problems in north sea basins abstract detailed sampling of apparently homogeneous potential source rock intervals frequently indicates unsuspected variations in organic facies which may or may not be reflected in the wireline logs carbon isotope analyses of pyrolysates provide a useful technique in these investigations which are essential for valid oil to source correlations in the jurassic of a north sea viking graben well the rich source shales at the top of the draupne formation are significantly depleted in 13 c and correlate with the oils from this area thus suggesting that this interval has acted as the primary source of the viking graben crudes a quite different pattern is evident in a well from the central graben and the data not only explain why the oils of the greater ekofisk area are relatively enriched in 13 c but also demonstrate that the variations within these oils are facies controlled pyrolysate carbon isotopes provide an excellent correlation between the middle devonian upper caithness flagstones of the inner moray firth and the beatrice crude oil this correlation is supported by the biomarker data and there is no need to appeal to a contribution from either an upper or middle jurassic source to achieve a match with the beatrice oil

correlation of natural gas by use of carbon isotopic distribution between hydrocarbon components the natural distribution of carbon isotopes between hydrocarbon gas components is used for 1 determining a gas s maturity 2 correlating a reservoired gas to its source 3 correlating one reservoired gas with another and 4 recognizing gas mixtures calculated separations of carbon isotopes between the normal alkane components of a natural gas have been related to source rock maturity by use of a single continuous diagram independent of source type actual data from a wide variety of geologic settings and geologic ages confirm this relationship and demonstrate its applicability to the source rock levels of organic metamorphism ranging from 8 to 13 covering the entire range of oil and wet gas generation at greater maturities the wet gas components are found to undergo thermal degradation losing their usefulness for correlation three examples showing indigenous gas west texas non indigenous gas gippsland basin australia and gas mixtures from multiple sources southeastern alberta illustrate exploration applications

extraction of whole versus ground source rocks fundamental petroleum geochemical implications including oil source rock correlation abstract in petroleum geochemistry extractable hydrocarbons hcs in source rocks have typically been studied by grinding the rock to a fine powder 100 mesh and then extracting the hcs from the rock with a solvent this procedure carries the implicit assumption that the hcs are homogeneously distributed throughout the rock however sequential soxhlet extractions of whole unpowdered source rocks have shown that progressive extracts from the same rock can be quite different and may not even correlate with each other a crude oil like material clearly has been fractionated from indigenous bitumen in these rocks has moved to cracks and parting laminae in the rocks is ready for expulsion from the rocks and is thus most accessible to the first extracting solvents this process which we believe is largely due to hc gases and carbon dioxide generated over all maturation ranks in source rocks carries petroleum geochemical implications of a fundamental nature for oil source rock correlations and gives insight into primary migration mechanisms origin of oil deposits and use of maturity and organic facies indices

hydrocarbon inclusions in late calcite cements migration indicators in the great oolite group weald basin s england abstract the fluorescence responses of hydrocarbon inclusions in calcite and dolomite cements are used to indicate the timing and longevity of oil migration in great oolite reservoirs of the weald basin of southern england oil migration and late stage calcite cementation were penecontemporaneous processes the gravity of the included hydrocarbons increases towards the basin depocentre through the range of 20 to 40 api reflecting the maturity of the source rocks reservoirs with a spread in the gravity of oil within inclusions were charged throughout source rock maturation those reservoirs with oil inclusions of a single gravity were charged in a discrete event

where did all the coal gas go isotopic models indicate that reservoired gases in mid norway were generated predominantly from marine source rocks despite the presence of abundant mature coal and terrestrial carbonaceous shales in the are formation there are at least three different possible explanations as to why this may be the case i source models for gas from coals are not valid ii modification of the carbon isotope signature of gas occurs post expulsion iii loss of gas due to poor expulsion efficiencies and complex migration pathways each of these possibilities is discussed in turn the most likely explanation is that loss of gas due to poor expulsion and or complex migration routes in the are formation results in most of the gas not reaching the reservoir however it should also be noted that current isotopic models for gas from coal are less rigorous than those for gas from marine source rocks

genetic characterization of natural gases natural gases can be characterized genetically using four properties c2 concentration carbon and hydrogen isotope variations in methane and carbon isotope variation in ethane three diagrams for genetic characterization of gases have been designed in which the carbon isotopic composition of methane is correlated with the other parameters in these diagrams compositional fields have been defined for primary gases biogenic thermogenic associated and thermogenic nonassociated and for gases which result from mixing of these gases these fields are strictly empirical and comprise compositional variations found in about 500 natural gases the isotopic and compositional variations in natural gases can be described in terms of 1 processes during formation of the gases such as bacterial fermentation or maturation of organic matter and 2 processes during secondary migration mixing of primary gases is an important and common process migration of gases predominantly affects the c2 concentration whereas the isotopic properties of gaseous hydrocarbons primarily remain unchanged allowing an assessment of the origin of migrated gases and properties of their source rocks the formation of gas from humic organic matter and coals is not yet clear from published data the diagrams use data from various basins and areas interstitial gases from the gulf of california are entirely of bacterial origin traces of thermogenic gases are formed only in the vicinity of dolerite sills gases in the south german molasse basin and in the vienna basin are of bacterial mixed and thermogenic origins data from the north italian po basin provide examples for genetic characterization of migrated gases

simple kinetic models of petroleum formation part iii modelling an open system abstract the movement of petroleum from organic rich source beds to potential carrier beds is the net result of two processes expulsion the release of generated petroleum from kerogen within the source bed and primary migration flow of a petroleum phase through the inorganic void networks of the source bed and all other intervening fine grained rocks expulsion is by far the more important process within the source bed orgas a simple zero dimensional model of the source rock as an open system explicitly models expulsion concurrent with oil and gas generation and oi lgas cracking as a storage threshold problem oil and gas are retained adsorbed absorbed within kerogen until their concentrations exceed the respective sorptive capacity of the residual organic carbon 0 1 and 0 02 g g ck 1 the initial hydrogen index hl 0 controls the important balance between potential sorbate petroleum and sorbant residual carbon using simple geochemical measurements the initial organic carbon is divided into initial oil inert kerogen and oil and gas generative reactive kerogen components reactive kerogens are assigned to one of five global kinetic organofacies with pre determined kinetic parameter sets governing separately rates of oil and gas generation kinetic parameters governing the rates of oil cracking within the source rock are predicted from hl 0 the two most important determinants of source rock behaviour are organofacies and hl 0 at a reference constant heating rate of 2 c ma 1 the projected oil expulsion threshold for typical organofacies members increases in the order a de 100 110 120 135 c f typically expels no oil an order of magnitude increase decrease in heating rate increases decreases these thresholds by ca 15 c typical cumulative gas mass fractions in their ultimate expulsion products are a f 0 25 0 3 0 25 0 65 and 1 0 g g 1 a value of 200 mg hc g c 1 is an approximate minimum hl 0 prerequisite for oil expulsion irrespective of absolute petroleum potential p 0 as a family coals vary dramatically in their expulsion behaviour as their hl 0 ranges both above and velow this value primary migration is efficient for expulsive source rocks movement within the source bed is limited only at low p 0 a source rocks total genetic potential p 0 thickness becomes important during migration outside the source bed it potentially restricts the primary migration distance and the excess of petroleum available for secondary migration and entrapment we evaluate primary migration approximately using a small migration loss factor no more than about 10 saturation of porosity or 1 mg g 1 coupled with an understanding of fluid potential gradients which determine migration direction within the stratigraphic architecture ultimately kerogen degradation and oil to gas cracking in the source rock are the rate limiting processes in petroleum accumulation

constraining the oil charge history of the south pepper oilfield from the analysis of oil bearing fluid inclusions abstract the south pepper oilfield located in the barrow sub basin on the nw margin of the australian continent has experienced a multi phase charge history abundant oil bearing fluid inclusions are present in samples from within the current gas cap suggesting that an oil column existed prior to gas this palaeo oil gas leg fi oil has ts tm and c29 c30 hopane ratios of 1 and the c35 homohopanes are a significant proportion of the extended homohopanes it has lower pr ph and diasterane sterane ratios than the currently reservoired live oil and contains gammacerane a series of peaks tentatively identified as c30 to c34 17 h 30 norhopanes and a large amount of 2 methylhopanes collectively geochemical analysis of the gas leg fi oil suggests that it was generated from a less mature more calcareous source rock deposited under more reducing conditions than the upper jurassic dingo claystone the main source of the live oil in addition the presence of c30 dinosteranes in the gas leg fi oil provides a triassic or younger age constraint this makes palaeozoic carbonates an unlikely source possible source intervals for the gas leg fi oil are thin lower jurassic limestones and marls which occur at the base of the lower dingo claystone or a thin limestone unit the cunaloo member at the base of the triassic locker shale samples from within the present oil leg also contain abundant oil inclusions consistent with high oil saturations at the present day however these oil inclusions exhibit different fluorescence colours suggesting they represent a second oil charge geochemically the oil leg fi oil has an intermediate composition between the live oil and the gas leg fi oil suggesting that gas charge displaced the first oil charge samples of which were preserved as fluid inclusions in the oil leg sample biodegradation of the first oil charge indicated by the presence of 17 h 25 norhopanes in the currently reservoired live oils can be attributed to the ingress of meteoric waters probably during sub aerial exposure of the basin margin during miocene wrenching changing environmental conditions curtailed bacterial activity and allowed unaltered oil sourced from the dingo claystone to accumulate below the gas cap and mix with the biodegraded residues of the first oil charge to achieve the live oil composition the biodegradation event must have preceded the second charge as the live oil contains compounds such as n alkanes which would have been removed had alteration occurred after the second charge complex charge histories are common and the analysis of palaeo oils trapped within fluid inclusions provides the opportunity to achieve a more comprehensive assessment of hydrocarbon charge

compositional modeling of petroleum generation and expulsion trial application to a local mass balance in the smorbukk sor field haltenbanken area norway 1 we present an application of a compositional kinetic model of petroleum generation degradation into gas and residue and simultaneous expulsion petroleum composition is described by four carbon fractions c 1 c 2 c 5 c 6 c 14 c 15 and expulsion is related to a petroleum saturation threshold expulsion is important because rapid expulsion of petroleum from source rocks favors oil whereas late expulsion increases the cracking reactions and favors gas accumulation such a model is tested against field data for the first time by applying it to the smorbukk sor field previously named smorbukk greek beta located in the norwegian sea geometrical and one dimensional thermal reconstructions are performed followed by a computation of a mass balance of expelled and unexpelled products for each source rock throughout the drainage area comparison of the model results is made with rock eval data vitrinite reflectance and actual composition of accumulations lower jurassic coals were the main source expelling gas and oil mainly since 5 ma as the present accumulation accounts for less than 10 of total expelled petroleum major petroleum losses probably occurred through the structural spillpoint this migration scheme is supported by the simila composition of the reservoired petroleum and the petroleum expelled since 0 5 ma although various uncertainties are possible this study shows that our model has the capability to quantify expulsion consistently with the observed amounts of unexpelled petroleum in mature source rocks and with the reported composition of the accumulation

the application of fluid inclusions to migration of oil and diagenesis in petroleum reservoirs abstract fluid inclusions can be used to interpret thermal history and petroleum maturation and migration relative to burial history temperature pressure and composition data collected from fluid inclusions are used to determine the environment of diagenesis and the timing of cementation and migration cements in petroleum reservoirs contain both oil and aqueous fluid inclusions fluorescence spectroscopy is used to identify oil inclusions and to determine the maturity of entrapped oil the lifetime of fluorescence induced by a pulsed laser is related to the api gravity of entrapped oil interpretation of fluid inclusion data depends on knowing the origin of fluid inclusions and the probability that they survive in the burial environment those aspects of fluid inclusion study are investigated by synthesizing oil and aqueous inclusions in calcite crystals in laboratory experiments examples of how fluid inclusions are used to determine the physico chemical environments of diagenesis in petroleum reservoirs and the timing of cementation and migration are given for the wealden basin england the mishrif formation dubai the smackover formation gulf coast u s a and jurassic sandstones offshore norway in the wealden basin temperature data from fluid inclusions are used to determine that oil migration occurred in the cretaceous and that the reservoir rocks have been uplifted to varying degrees at a time after migration distribution of oil inclusions indicates that generation and migration of oil was principally in the western part of the basin the geochemistry of oil inclusions in calcite cements from the mishrif formation dubai are used to determine the type and maturity of entrapped oil temperature data from oil and water inclusions are used to relate reservoir diagenesis to burial history and the migration of oil in deep smackover reservoirs oil contains h 2 s the origin of the h 2 s is examined by study of fluid inclusions containing h 2 s in jurassic sandstones offshore norway fluid inclusion studies show that silica cementation is related to burial depth whereas a later calcite cementation originated from invasion of a hot fluid

kerogen facies and maturity of the kimmeridge clay formation in southern and eastern england abstract the upper jurassic kimmeridge clay formation of southern and eastern england was deposited under anoxic or dysaerobic conditions in a stratified shelf sea anoxic conditions developed in the intra shelf weald and central channel basins of southern england and the cleveland basin of eastern england with generally dysaerobic conditions in the flanking shelf areas only in the basin margins such as in northern scotland were oxic bottom water conditions prevalent the maturity and distribution of the kerogen facies which can be explained in terms of the palaeogeography and burial history of the upper jurassic of southern and eastern england are discussed along with the effects of their variation on commonly used geochemical parameters relationships to clay mineralogy are also examined kerogens are largely type ii amorphous sapropels of marine origin with variable amounts of terrestrially derived type iii material type iii kerogens predominate in the basin margin areas whereas type ii kerogens are restricted to the basin centres over the intermediate shelf areas mixed type ii type iii kerogens are prevalent both the sedimentation rate and differential organic matter preservation can be demonstrated to be the major controls on the kerogen facies of the kimmeridge clay formation variations in the kerogen facies appear to be responsible for the often spurious and scattered maturity measurements from the kimmeridge clay formation using vitrinite reflectance spore coloration and rock eval pyrolysis parameters the results often conflicting with geological models for the post jurassic burial history this appears to be due to the highly variable content of terrestrial and recycled type iii kerogens from older sediments in the mudstones causing the conventional maturity indices to often not reflect the true maturity of the autochthonous marine type ii kerogens

tectonic development of the mid norway continental margin abstract the area reviewed covers the mid norway continental margin between latitudes 62 n and 68 n main structural elements as defined at the base cretaceous level are the trondelag platform underlying the inner shelf the more and voring basins located beneath the outer shelf and slope and the more platform and the outer voring plateau forming a base of slope trend of highs sediments contained in the mid norway basin range in age from late palaeozoic to cenozoic the basement was consolidated during the caledonian orogenic cycle devonian and early carboniferous wrench movements along the axis of the arctic north atlantic caledonides are thought to have preceded the namurian onset of crustal extension rifting processes were intermittently active for some 270 my until crustal separation between greenland and fennoscandia was achieved during the early eocene during the evolution of the norwegian greenland sea rift system a stepwise concentration of tectonic activities to its axial zone the area of subsequent continental separation is observed during the late palaeozoic to mid jurassic a broad zone was affected by tensional faulting during the late jurassic and cretaceous the trondelag platform was little affected by faulting whilst major rift systems in the more and voring basins subsided rapidly and their shoulders became concomitantly upwarped during the latest cretaceous and early palaeogene terminal rifting phase only the western more and voring basins were affected by intrusive and extrusive igneous activity following the early eocene crustal separation and the onset of sea floor spreading in the norwegian greenland sea the voring segment of the mid norway marginal basin subsided less rapidly than the more segment during the early and mid tertiary minor compressional deformations affected the voring basin and to a lesser degree the more basin tensional forces dominated the late palaeozoic to early cenozoic evolution of the mid norway basin and effected strain mainly in the area where the crust was weakened by the previous lateral displacements the lithosphere thinned progressively and the effects of the passively upwelling hot asthenospheric material became more pronounced massive dyke invasion of the thinned crust preceded its rupture

geochemical comparison of oil bearing fluid inclusions and produced oil from the toro sandstone papua new guinea abstract a detailed study was carried out to compare the geochemistry of the crude oil in the lower cretaceous toro sandstone reservoir in the iagifu 7x well with oil trapped in fluid inclusions in this sandstone in the iagifu 7x and p nyang 2x wells in the papuan fold belt the drill stem test dst oils and the oils trapped in fluid inclusions show different source and maturity dependent geochemical parameters biomarkers suggest that the dst oils at iagifu 7x were derived from clay rich mixed marine terrestrial source rocks deposited under oxic conditions probably middle to late jurassic mudstones the fluid inclusion oils were derived from a less terrestrially influenced marine source rock deposited under less oxic conditions the fluid inclusion oils contain 1 2 7 trimethylnaphthalene and oleanane biomarkers indicative of angiosperm input and a cretaceous or younger source rock these oils are more mature calculated reflectance rc 1 02 than the reservoired oil at iagifu 7x rc 0 84 and condensate at p nyang 2x rc 0 84 source and thermal maturity parameters for all three fluid inclusion samples are similar suggesting that they were derived from similar source rock facies furthermore samples with predominantly blue vs white fluorescing oil inclusions have no discernible geochemical maturity difference suggesting that the use of fluorescence colours as a qualitative guide to the maturity of the trapped oil is not valid in this case fluid inclusion oils were trapped prior to charge of the reservoir with oil at the iagifu 7x and gas condensate at the p nyang 2x wells the fluid inclusion oils therefore represent an early oil charge from a deeply buried probably cretaceous source rock which started migrating into the toro sandstone during the miocene at iagifu this early oil was probably diluted by a larger volume of jurassic oil generated at the end of the miocene the absence of fluid inclusions with compositions like the currently reservoired oil is interpreted to be due to oil charging an already oil saturated zone when diagenesis is likely to have been inhibited at the p nyang well the transition from oil as represented by the oil inclusions to gas condensate was most likely caused by gas displacement

finite fault simulation of broadband strong ground motion from the 2010 mw 7 0 haiti earthquake abstract because of the socioeconomic environment in the small island nation of haiti no seismic recording stations were operating in the source region at the time of the 2010 m w 7 0 earthquake the lack of strong motion instruments has hindered the estimation of the amplitude duration and frequency content of the ground shaking caused by the seismic event in this study synthetic broadband strong ground motions are generated in the vicinity of the 2010 haiti earthquake the low frequency components of the synthetic motions are simulated using a slip model compatible with seismological observations geologic field data and space geodetic measurements the computations are carried out using the discrete wavenumber representation method and the generalized transmission and reflection coefficient technique the high frequency ground motion components are generated using the stochastic modeling approach and the specific barrier model the two independently derived ground motion components are subsequently combined using matched filtering at a crossover frequency of 1 hz to generate broadband ground motion time histories and response spectra for the city of port au prince and other sites in the vicinity of the earthquake finally the synthetic strong ground motions are compared against peak ground motion estimates inferred from the u s geologic survey shakemap of peak ground accelerations ground motion prediction equations and observed structural damage the synthetic time histories and response spectra generated in this study should be seen as plausible but not necessarily unique ground motions that capture the primary features of the 2010 haiti earthquake

petroleum geochemistry of the froy field and rind discovery norwegian continental shelf implications for reservoir characterization compartmentalization and basin scale hydrocarbon migration patterns in the region abstract petroleum geochemistry provides an excellent tool for understanding reservoir characteristics with respect to oil flow and tracing out elements of basin scale migrational patterns and reservoir compartmentalization organic geochemical characterization has been carried out on 580 core extracts and 9 oils from 11 wells of the froy field and rind discovery in the south viking graben two different drainage areas and source rock systems have been identified for the hydrocarbons in the froy field and the rind discovery on the basis of differences in maturity and gas to oil ratio in addition to facies differences like c 28 sterane content and the ratio of bisnorhopane to bisnorhopane plus norhopane results show that the rind discovery contains oil of higher maturity compared to the oil from froy field the petroleum in the rind discovery has a more terrestrial character and is interpreted to have been derived from source rocks other than the draupne formation in its typical anoxic distal development a likely candidate is the heather formation in addition a small contribution of immature oil has been identified in a separate small sub compartment in the froy field the petroleum in this sub compartment shows a high pristane to phytane ratio and a very prominent odd to even predominance well 25 14 drilled northeast of the froy field penetrates a water bearing hydrostatic structure the detailed geochemical characterization including petroleum inclusion studies have shown that this structure never received oil or gas nor did it have any communication with the froy field hence it is inferred that this structure never communicated with the hydrocarbon producing basin one of the two compartments in the rind discovery is hydrostatic and contains petroleum of a comparatively large maturity span whilst residual core bitumen in a high pressured neighboring compartment has a very small maturity span and contains presently only water as producible phase the ratios of the 20s to 20s 20r isomers of c 29 steranes the ratio of c 20 to c 20 c 28 triaromatic steroids and the c 28 triaromatic steroid to c 28 triaromatic steroid c 29 monoaromatic steroid ratio in the latter compartment have almost uniform values indicating a single oil pulse i e a short filling history whereas in the other compartment these ratios vary over a large range indicating a longer filling history as both compartments contain petroleum with the same source rock facies signatures it is suggested that these at some time were part of the same migration system communication between these compartments is inferred to have been disrupted before seal failure occurred in the structure which was penetrated by well 25 15r2 the analyses carried out indicate a high degree of chemical homogeneity in the petroleum of the froy field reservoir which in comparison with the rind discovery is more similar to extracts from typical anoxic developed distal shales of the upper jurassic source rock in the viking graben i e the kimmeridge equivalent draupne formation however the upper reservoir units in the northern well 25 5 a7 contain extracts with lower maturity and more terrestrial characteristics compared with the extracts in the deeper reservoir sections in addition well 25 5 1 which penetrates the highest point of the froy structure contains petroleum of slightly higher maturity than found elsewhere in the froy field the results further suggest that the faults in the froy field including the main e w trending fault separating the northern and the southern parts of the of the froy field did not adversely affect lateral communication during filling to conclude there is no petroleum geochemical evidence to suggest that intra reservoir faults have caused significant compartmentalization of the froy field except for the n s trending fault which separates a small block to the west from the froy field main reservoir thus with respect to petroleum production it is concluded that primary sedimentological features are more important in terms of exerting a first order control for determining the vertical and lateral flow of hydrocarbons in this reservoir than faults

calculation of petroleum masses generated and expelled from source rocks abstract an algebraic scheme for calculating the masses of petroleum formed in mature source rocks has been constructed the scheme exploits routine geochemical measurements and a basic understanding of the behaviour of sedimentary organic matter at elevated temperatures under both laboratory and subsurface conditions application of these techniques to data from a wide range of source rock types has led to the following general conclusions 1 1 major oil and gas generation from kerogen occurs between 120 and 150 c in the subsurface gas generation continues to temperatures 160 c 2 2 oil prone source rocks with average initial potential 5 kgt 1 of rock and average organic carbon contents 1 5 expel 60 90 of the total oil generated 3 3 oil expulsion from leaner source rocks is less efficient most of the oil generated remains in the source rock it is subsequently converted to lighter components at higher temperatures and expelled in the vapour state 4 4 the major loss of organic carbon from rich oil prone source rocks during generation and expulsion means that the petroleum potential and organic carbon content of mature source rocks are much less than their initial immature values hence the algebraic scheme must be used to calculate the initial values before expelled petroleum masses can be determined