Source Rock Facies Research Articles

AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES

The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.

Main controlling factors for hydrocarbon reservoir formation and petroleum distribution in Cratonic Area of Tarim Basin

The Cratonic Area of the Tarim Basin is located in the central part of the basin, developing primarily with Cambrian marine source rocks and secondly Middle to Upper Ordovician marine and Carboniferous-Permian transitional facies source rocks. The source rocks were matured in the changeable period and space, forming multiple hydrocarbon generating centers during the periods. The Cratonic Area experienced multiple tectonic orogenies, forming several palaeouplifts. The matching condition between effective hydrocarbon generating centers and the palaeouplifts in various periods is the main control factor for the formation and distribution of hydrocarbon reservoirs. The palaeouplifts have experienced multiple hydrocarbonfilling phases, several periods of modifications and even breakdown. The palaeouplifts and the adjacent slopes around the effective hydrocarbon generating center compose the most favorable places for hydrocarbon accumulation. The hydrocarbon phase is related with the evolution of the hydrocarbon generating center. In the Tarim Basin’s Cratonic Area, reservoirs were mostly formed during late Hercynian. The originally formed hydrocarbon reservoirs which are adjacent to source kitchens and in the good preservation condition are the most favorable prospecting targets. Hydrocarbon is richly accumulated under the regional caprock, surrounding the faulted trends, and over and below the unconformity surfaces. Reservoirs in the Carboniferous sandstone, Ordovician karstic weathered crust and carbonate rock inside the buried hill compose the main intervals for hydrocarbon accumulation. Carboniferous and Silurian sandstone pinchout reservoirs and carbonate lithologic reservoirs with rich fractures and pores are the main targets for further prospecting.

Hydrocarbon system analysis in a rift basin with mixed marine and nonmarine source rocks: The South Viking Graben, North Sea

The South Viking Graben of the North Sea is a prolific oil and gas province that has recoverable reserves of approximately 176 x 109 Sm3 (standard cubic meters) (6.2 tcf) gas, 58 x 106 t (412 million BOE) natural gas liquids, and 12.5 x 106 Sm3 (78 million bbl) of black oil contained in the main fields Sleipner Vest, Sleipner Ost, and Volve. These fields are located primarily within Block 15/9 in the Norwegian sector and extend into neighboring Blocks 15/6 and 16/7. The principal source of black, nonvolatile oil is the Late Jurassic Draupne Formation, which has a predominance of marine algal organic matter. The lower section of the Draupne Formation together with the Heather Formation are organically leaner and contain a mixture of marine algal and terrigenous organic matter, resulting in a potential to generate both oil and gas. The Middle Jurassic Hugin and Sleipner formations contain humic coals and coaly shales with potential to generate gas and some light liquids. These coals contain, on average, 80-90% vitrinitic woody material with occasional enrichment of resinite. High resinite concentrations can lead to an overprediction of oil potential, as they contribute significantly to the hydrogen index (HI) but generate primarily low molecular weight aromatic compounds. All source rock facies types have reached maturities sufficient to generate oil and gas. Basin modeling suggests that onset of oil and gas generation started during the latest Cretaceous-early Paleocene. These source rocks have continued to yield oil and gas to the present day in many parts of the catchment area for the Sleipner fields. Detailed geochemical analyses identified five main oil and condensate families. Family A comprises condensates and oil located in the northernmost part of Sleipner Vest and Dagny, generated from a marine, clastic source with a predominance of type II algal organic matter. Family B is condensates in the middle to southern part of Sleipner Vest, generated from a source, or a contribution from several source facies, with mixed terrigenous higher plant organic matter and marine algal material. Family C consists of condensates reservoired in the Jurassic of Sleipner Ost (except well 15/9-A15), generated from a mixed algal/terrigenous source but with a higher contribution of hydrocarbons from a marine algal source as compared with the Sleipner Vest family B. Family D comprises condensates in the Jurassic-Triassic of Loke and Gungne, in well 15/9-A15 from the crest of the Sleipner Ost structure, as well as condensates within the Paleocene sands of Sleipner Ost. These condensates have a mixed terrigenous higher plant and marine algal signature and are derived from pre-upper Draupne Formation sources. Family E is the black oil present in the Jurassic Volve field, derived from a marine, calcareous shale with type II to II-S organic matter. The source rock for this oil is unique in the greater Sleipner area and is likely located in the isolated subgraben between the northern parts of Sleipner Vest and Sleipner Ost. The hydrocarbon gases are broadly similar and are interpreted to have been generated from coals and coaly shales of the Sleipner and Hugin formations, as well as those parts of the pre-upper Draupne section that have a predominance of terrigenous higher plant organic matter.

ABSTRACT: Predicting Deltaic Source Rock Facies Using Sequence Stratigraphy

ABSTRACT: Predicting Deltaic Source Rock Facies Using Sequence Stratigraphy

Compound-specific carbon isotope analysis of natural and artificially generated hydrocarbons in source rocks and petroleum fluids from offshore Mid-Norway

Stable carbon isotope signatures of individual hydrocarbon components provide important information on the source rock facies of oils as well as their asphaltene fractions, despite maturity variations and secondary processes such as phase fractionation and biodegradation. Our study is based upon petroleum fluids and source rock samples from offshore Mid-Norway, where the main source rock is the marine shales of the Upper Jurassic Spekk Formation. An alternative source is provided by coals and coaly shales of the Lower Jurassic Åre Formation. In terms of maturity the source rock samples are distributed throughout the main phase of oil generation. In this study compound-specific carbon isotope analysis has been performed on thermal extracts and kerogen pyrolysates of the source rocks, as well as on the oils and the pyrolysis products of their asphaltenes. We demonstrate that trends of absolute isotope data and specific isotopic fingerprints after normalizing the data are useful for petroleum-source rock correlations. The carbon isotope ratios of the n-alkanes separate the Åre from the Spekk Formation samples in both thermal extracts and kerogen pyrolysates, becoming less negative with increasing terrestrial input. The Spekk samples also tend to become isotopically heavier with increasing maturity, while the Åre samples do not show any systematic difference with increasing maturity. The carbon isotope ratios of the n-alkanes also discriminate between the oils as well as the asphaltenes from the fluids. The individual components generated by pyrolysis of kerogens are isotopically heavier than those from the thermal extracts. This is expected from models of kinetic isotope effects which predict that the isotopically lightest products are generally released at an earlier stage in the maturation process. A similar isotopic difference is also observed between the pyrolysis products of asphaltenes and the original oils derived from the same source rock type. However, in a sample where the oil and its asphaltene fraction originate from two different source rocks, the opposite relationship between the carbon isotope composition of the oil and its asphaltene fraction is observed. Bulk isotope data of kerogen concentrates, pyrolysates and the residue after pyrolysis of the source rock samples as well as bulk isotope data of whole oils are also presented. We show that besides separating Åre from Spekk, the bulk carbon isotope values of the Spekk samples are considerably heavier than the n-alkanes from the thermal extracts, whereas those of the Åre samples are almost equal.

GEOCHEMICAL CHARACTERIZATION OF LOWER TOARCIAN SOURCE ROCKS FROM NW GERMANY: INTERPRETATION OF AROMATIC AND SATURATED HYDROCARBONS IN RELATION TO DEPOSITIONAL ENVIRONMENT AND MATURATION EFFECTS

The characterization of crude oils in terms of source rock facies and depositional environment, as well as their maturity and alteration stage, is a crucial element in exploration studies. The present contribution has implications for oil‐oil and oil‐source rock correlations. In the past, numerous parameters have been used for this purpose most of which are based on the analysis of saturated and aromatic hydrocarbons (including sulphur aromatics) and also on stable isotope signatures and elemental compositions. Recently, molecular indicators based on dibenzothiophene (DBT), phenanthrene (PHE) and their methyl derivatives methyldibenzothiophene (MDBT) and methylphenanthrene, as well as pristane (PRI) and phytane (PHY), have also been proposed (Hughes et al., 1995). These studies have attempted to infer a crude oil's source rock facies and lithology, and to classify the source rock's depositional environment. In the present study, the above compounds have been quantified by solvent extraction, liquid chromatography and capillary gas chromatography in 98 core samples of the Lower Toarcian Posidonia Shale Formation, a source rock in NW Germany. Most samples, cored between depths of 7m and 70 m, came from the Hils Half‐Graben in the Lower Saxony Basin. With a few exceptions from one borehole, the samples were unweathered marls or calcareous shales. The rocks contained mainly marine organic matter (Type II kerogen), the thermal maturity of which ranged from early mature to postmature (corresponding to 0.48‐1.44% mean vitrinite reflectance), therefore encompassing the range over which effective petroleum generation had occurred. We found that the influences of organic matter type and maturity on the molecular distributions of the above compounds were not obvious when interpreted in terms of a DBT/PHE vs PRI/PHY diagram. However, Principal Component Analysis (PCA) of our data‐set showed that alkylphenanthrene concentrations are strongly controlled by maturity, while the concentrations of PRI, PHY, and 1‐MDBT display a distinct source effect.

Application of diamondoids to distinguish source rock facies

Diamondoid distributions in solvent extracts from marine siliciclastic shales, marine carbonates, and coals of a wide variety of maturities were determined by GC–MSD. For this sample set, published diamondoid maturity parameters did not change systematically throughout the oil window. It was found that several novel diamondoid ratios were indicative of source. It was possible to distinguish between terrigenous, marine carbonate and marine siliciclastic facies. The proposed dimethyl diamantane facies ratios are virtually unaffected by maturity, while the ethyl adamantane ratio appears to be affected by maturity in the late gas-window range.

Geochemical characteristics and applications of 18α(H)-neohopanes and l7α(H)-diahopanes

Distributions and geochemical significances of 18α(H)-neohopanes and of 17α(H)-diahopanes in oils from west Xialiaohe depression of the Bohai Bay Basin have been studied. Relative abundance of 18α(H)-neohopanes and of 17α(H)-diahopanes can be effectively used as maturity parameters, in a range of medium-high mature stage, based on consideration on sedimentary-organic facies of source rocks. With a dual geochemical significance of maturity and sedimentary-organic facies, neohopane and diahopane parameters can be well used in oil-source correlation and in petroleum population division. Formation, primary concentration and preservation of precursors of rearranged hopanes are closely related to depositional conditions such as Eh-pH and clays content. A series of probable diahopanes (series D) was detected in the oils, which exhibits a similar distribution pattern and geochemical behavior as that of 17α(H)-diahopanes (series B).

The Miocene petroleum system of the Sava Depression, Croatia

The Sava Depression, located on the southern margin of the Pannonian Basin, contains a number of small oil and gas fields. The depression is filled principally with Neogene sediments resting on Palaeozoic crystalline basement. Rifting occurred in Early to Middle Miocene times. Geochemical data imply that Middle to Upper Miocene pelites are good oil-prone source rocks. Most of the oil and oil–gas fields are situated at depths of 370 to 2300 m. Weathered basement rocks and Miocene conglomerates and sandstones are reservoir rocks and the fields are mostly structural and/or structural–stratigraphic traps. Oils from the fields correlate well with the identified source rock facies and maturity level and we propose short migration distances. Sava oil properties show variations in bulk and specific parameters that can be attributed to post-generative processes.

Production, preservation and prediction of source-rock facies in deltaic settings

This article hypothesizes that production and preservation of source-rock type facies in deltaic systems, both landward and seaward of a coastline, is mutually exclusive, time-successive and related to the dynamics of relative sea level. Sedimentologic research in the Holocene Mississippi and Rhône delta complexes suggests that rheotrophic peats and associated organic-rich beds preferably accumulate in the accommodation space created behind landward stepping shorelines in a transgressive systems tract (TST). Such a setting also allows for a sufficient supply of recharging fresh nutrient-rich groundwater into the peat forming mires [Kosters, E.C., Suter, J.R., 1993. Facies relationships and systems tracts in the late Holocene Mississippi Delta Plain. Journal of Sedimentary Petrology 63 (4) 727–733.]. Independently carried-out quantitative paleoecological studies in the same delta systems (and in addition in the Orinoco and Po deltas) suggest that in a progradational setting (highstand systems tract/HST), seasonally discharged nutrient- and sediment-laden river waters on the shelf may give rise to anoxia or dysoxia. Subsequent overfertilization of the shelf leads to accumulation of organic-rich mud belts on the shelf [VanderZwaan, G.J., Jorissen, F.J., 1991. Biofacial patterns in river-induced anoxia. In: Tyson, R.V., Pearson, T.H. (Eds.), Modern and Ancient Continental Shelf Anoxia. Geological Society of London, Special Publication no. 58, pp. 65–82.]. Thus, production and preservation of source-rock type facies landward of a shoreline (as peats and related sediments) is preferred in a TST, when accommodation space and nutrient supply are landward of the shoreline. Vice versa, production and preservation of such facies seaward of a shoreline (as organic-rich shelf muds) occurs preferentially in a highstand systems tract. In that situation, accommodation space is on the shelf, where river-fed nutrients are supplied as well. This hypothesis suggests further potential for application of sequence stratigraphic concepts for improved understanding of the occurrence of source-rock type facies.

Depositional and Tectonic Setting of the Lower Silurian Hydrocarbon Source Rock Facies, Central Saudi Arabia

The Lower Silurian Qalibah Formation consists of two members, the (upper) Sharawra Member and the (lower) Qusaiba Member. The Qusaiba is the main hydrocarbon source rock for the known Paleozoic hydrocarbon accumulations in central Saudi Arabia. The Qusaiba Member is composed mostly of claystone and shale with interbeds of siltstone and sandstone. Depositionally, the Qusaiba Member is interpreted to represent the delta-toe clays, whereas the Sharawra Member was deposited as pro-delta sandstones of an immense fluviodeltaic system that dominated the Silurian-Carboniferous of Arabia. The Qalibah Formation accumulated syndepositionally in at least two rapidly subsiding depocenters. One depocenter was located in central and southern Arabia, and the other depocenter was located in northwestern Saudi Arabia. The former trough began subsiding during the Late Ordovician following the Taconic uplift. The latter trough began subsiding during the Early Silurian. At least 10,000 ft (3100 m) of Upper Ordovician- Lower Devonian strata accumulated in the trough located in central and southern Saudi Arabia. About 3300 ft (1000 m) of Lower Silurian sediments accumulated in the depocenter found in northwestern Saudi Arabia. The development of these troughs documents a period of crustal extension probably related to the rifting of the Lower Paleozoic continental margin of Saudi Arabia. The Qusaiba Member organic-rich facies occurs near the base of the unit and has up to 8% total organic carbon content. The development of favorable source rock facies in the Qusaiba is observed along the flanks of the depositional thicks associated with the lower Qusaiba Member. The basal Qusaiba Member organic-rich facies was produced during periods of elevated primary productivity of organic matter within the water column in an open-marine, nonsilled basin setting. Deposition of the basal organic-rich facies of the Qusaiba Member occurred as a condensed sequence along a sediment-starved continental margin. The basal Qusaiba Member organic-rich facies accumulated in normally to partly oxygenated bottom-water settings; however, the sediments below the sediment/water interface were probably preserved in an anoxic setting. Geochemical data also demonstrate that the organic-rich Qusaiba Member sediments found in the depositional thicks have characteristics consistent with a more oxidized sediment column. Geo chemical data also show that the basal Qusaiba Member organic-rich facies deposited more distally to these depocenters are more dysoxic to anoxic in their characteristics. The organic-rich facies of the basal Qusaiba Member found in depositional thicks was produced under conditions that either reworked the organic-rich sediments, thereby oxidizing them, or diluted the organic matter, resulting in less preservation of potential source rock.

’NW European Gas Atlas’ – new implications for the Carboniferous gas plays in the western part of the Southern Permian Basin

The ‘Northwest European Gas Atlas’ comprises maps on characteristics (e.g. molecular and isotopic compositions) of natural gases in northwest European gas fields, on the distribution and facies of source and reservoir rocks, on maturities, and other relevant geological information. The mapped area includes the entire Southern Permian Basin from the Southern North Sea to central Poland. Palaeozoic source rocks in the Dinantian, Namurian and Westphalian have been identified in the western part of the Southern Permian Basin. They contain kerogens of marine (Type I and II) and continental origin with TOC contents as high as 12%. There are two Carboniferous production provinces in this area: C1 in the Southern North Sea and C2 in the area along the border between The Netherlands and Germany. The natural gas in most of the C1 production province has methane contents of more than 80%; in most of the C2 province even more than 85%. Nitrogen is the second most abundant constituent in both provinces. Carbon dioxide plays a significant role only locally in the areas of intrusive rocks. Isotope data show that the source of the natural gases in the C2 province is a terrestrial rock (Westphalian). In the C1 province, the gases are of mixed origin: a low maturity terrestrial source rock (Westphalian) and a more mature marine source rock (?Namurian).

99/00155 Depositional environments and oil potential of Jurassic/Cretaceous source rocks within the Seychelles microcontinent

Organic-rich shale and claystone are present within the Lower Cretaceous Abu Gabra Formation of the Muglad Basin, representing excellent oil source rocks. The source rock potential of Abu Gabra organic-rich whole rock samples from two oilfields in the Muglad Basin was investigated using bulk and quantitative pyrolysis techniques. The analytical program included TOC, pyrolysis (SRA), pyrolysis GC, bulk kinetics, elemental analysis and kerogen microscopy. The results were used to characterize the kerogen composition and type of petroleum generated from these Abu Gabra organic-rich sediments to clarify the structural variability of the organic matter in the Abu Gabra source rock. The investigated Abu Gabra organic-rich sediments proved to contain excellent quality lacustrine kerogens. The samples have moderate to high hydrogen index (HI) values (267–837 mg HC/g rock), consistent with predominantly oil-prone Types I and II kerogen with a minor contribution of Type II–III kerogens. This is supported by the abundant liptinitic materials (i.e., lipid-rich structured algae, structureless (amorphous) alginite, and sporinite) and high atomic hydrogen-to-carbon (H/C) ratio. However, pyrolysis GC analysis proved that all the investigated Abu Gabra samples contain homogeneous Type I kerogen that produces mainly waxy oil.Bulk Kinetic experiments on these samples indicate that the source rock facies derived from a homogenous organic matter, spans an extremely narrow distribution of activation energy (Ea) ranges from 49 kcal/mol to 51 kcal/mol. The magnitude order of frequency factors (A) also show a narrow distribution range from 1012 to 1013/s. Based on the discrete simulated model using 3.3 °C/My heating rate, the average of predicted geological temperature is 0.73% Ro where the peak generation of 0.85% Ro, thus shows a typical characteristic of Type I Kerogen.

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

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

Depositional environments and oil potential of Jurassic/Cretaceous source rocks within the Seychelles microcontinent

The Seychelles microcontinent became isolated between the Somali, Mascarene and Arabian basins of the Indian Ocean as a result of the Mesozoic fragmentation of Gondwana. Major rifting events occurred during the Triassic-Middle Jurassic and Late Cretaceous (Cenomanian-Santonian and Maastrichtian) during which shaly source rock facies accumulated in principally marginal marine:deltaic environments. Between these times, post-rift passive margin deposition De Wit et al., 1988hin restricted to open marine environments produced shaly source rocks during late Middle Jurassic-Early Cretaceous, Campanian-Maastrichtian and Paleocene times. Recent geochemical analysis of cuttings from the Seagull Shoals-l well has identified an oil-prone liptinitic (Type II) coaly shale De Wit et al., 1988hin early Middle Jurassic abandoned deltaic deposits. This coaly source rock is regionally developed, having also been identified in the Majunga and Morondava basins of Madagascar. Oil-prone Type II organic matter has also been identified in the Owen Bank A-1 well De Wit et al., 1988hin restricted marine shales of late Middle Jurassic age. These shales are part of a thick post-rift source rock sequence that extends into the Early Cretaeous and is in part correlative De Wit et al., 1988h the proven Late Jurassic Uarandab Shale of Somalia. Analysis of Campanian marine shales from Reith Bank-1 well identified significant dilution of total organic carbon content in composite, compared to picked, well cuttings samples. This finding supports a published inference that these post-rift shales have source rock potential. The very limited drilling of the various Jurassic:Cretaceous source rock sequences in Seychelles (only three penetrations, all De Wit et al., 1988hin a 13 km radius) indicates that they span the entire maturity window and that some have generated hydrocarbons. However, the petroleum system associated De Wit et al., 1988h the Triassic-Early Cretaceous rift:drift sequence has been tested only by three invalid wells at the western extremity of the Seychelles Plateau, whilst that associated De Wit et al., 1988h the Late Cretaceous rift:drift sequence remains untested. ©1998 Elsevier Science Ltd. All rights reserved.

Using kerogen FTIR parameters for determination of organic facies

FTlR spectrum data can not only be used to indicate kerogen type end maturity, but also to determine organic facies of source rock. Aliphatic chain structure indices (ACSI) and an aromatic structure index (ASI) are introduced to divide sedimentary organic facies of different source rocks into three types: swamp, swamp-lacustrine and lacustrine facies. The indices also reveal the fine difference of the organic matters, such as kerogen types, petroleum potential and nature of hydrocarbon products.

Biodegradation of seep oils in the Wessex Basin — a complication for correlation

Abstract A detailed organic geochemical investigation of seep oils from the Dorset coast has revealed notable variation in both the extent and pathways of biodegradation. All the seep samples analysed from Mupe Bay, Stair Hole (near Lulworth Cove) and Osmington Mills have had their n -alkanes and acyclic isoprenoid alkanes removed, but some samples are more extensively degraded, with partial loss of steranes and/or hopanes. At Mupe Bay (conglomerate matrix samples; see Parfitt & Farrimond 1977 this volume) the hopanes have been preferentially attacked, whilst at Stair Hole the steranes appear heavily degraded although there has been no alteration to the hopane distribution. 25-Norhopanes were not detected in any of the samples. Biological marker distributions of seep oils which have suffered no hopane or sterane biodegradation are compared with those of three reservoired oils from the area (Wytch Farm and Kimmeridge fields). Molecular parameters indicate significant variation in source rock facies and maturity within the oils of the Wessex Basin.

Petroleum geochemistry of the Frøy field and Rind discovery, Norwegian Continental Shelf. Implications for reservoir characterization, compartmentalization and basin scale hydrocarbon migration patterns in the region

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 Frøy 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 Frøy 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-αα-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 Frøy 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 Frøy 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 Frøy 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 Frøy 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-αα-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 Frøy 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 Frøy structure, contains petroleum of slightly higher maturity than found elsewhere in the Frøy field. The results further suggest that the faults in the Frøy field including the main E-W trending fault separating the northern and the southern parts of the of the Frøy 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 Frøy field except for the N-S trending fault which separates a small block to the west from the Frøy 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.

Fluid Inclusion Record of Early Oil Preserved at Jabiru Field, Vulcan Sub-Basin

Oil trapped in fluid inclusions in a sample of Plover Formation sandstone from the main oil zone in Jabiru-1A has been subjected to detailed geochemical comparison with production oil from the well. Fluorescence microscopy of the sandstone showed that predominantly blue-fluorescing oil inclusions occur in 69% of quartz grains, both within quartz overgrowths and on healed fractures within detrital quartz grains. There are some notable similarities and differences between the fluid inclusion oil and the production oil. Similarities include the n-alkane profiles (both maximising at n-Cis with slight odd over even predominance at high molecular weights), n-alkane to isoprenoid ratios and Pr/Ph ratios (2.7±0.04). Hopane and sterane biomarker maturity ratios are at or close to equilibrium values, typical of peak oil generation conditions. The fluid inclusion oil differs from the production oil in containing relatively lower amounts of rearranged hopanes, Ts, C29TS, C27 steranes and diasteranes. These differences are interpreted to be due to lower maturity rather than source rock facies variation. Aromatic hydrocarbon ratios confirm a small but consistently lower maturity for the fluid inclusion oil. For example, the calibrated methylphenanthrene index shows an equivalent reflectance of 0.84% for the fluid inclusion oil, compared to 0.92% for the production oil. These geochemical data suggest that the oil trapped in fluid inclusions in Jabiru-1A is from the same source rock but was generated at a lower maturity than the average of the oil now in the reservoir, and was trapped soon after initial charge mainly by thin quartz overgrowths. Further charge to the Jabiru structure was of progressively higher maturity oil.

Geochemical comparison of oil-bearing fluid inclusions and produced oil from the Toro sandstone, Papua New Guinea

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 [ R c] = 1.02%) than the reservoired oil at Iagifu-7X ( R c = 0.84%) and condensate at P'nyang-2X ( R c = 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.