Abstract The Alaska North Slope oil-rock correlation study was organized because several oil companies requested oil and rock samples for geochemical analyses that were recovered during the exploration drilling in the National Petroleum Reserve in Alaska (NPRA). Samples acquired with public funds could not be given to private organizations unless some guarantees could be provided that the information acquired from these samples could be made available to the public. For this reason, in August 1981, we sent out over 40 invitations to research laboratories in industry, government, and academia. Requirements to participate in this study included: (1) participation in an AAPG-sponsored research conference, (2) presentation of the data interpretations at the 1983 Annual AAPG Meeting in Dallas Texas, and (3) contribution of a manuscript, to include all acquired data and interpretations, that would be included in a symposium volume. If a research group wished to participate, they were to write a letter of intent that included their proposed analytical program and a statement indicating that the requirements would be adhered to by their group. Even with these stringent requirements, 30 research groups wished to participate. A balanced cross section of research groups are participating and are as follows: 15 from oil companies, 7 from commercial laboratories, 7 from government laboratories, and 1 university laboratory. These groups are listed in Table 1. In January 1982, each research group was sent 8 oils and 15 rocks recovered from NPRA drilling and 1 oil from the Prudhoe Bay field. Each group then proceeded to analyze these samples as they indicated in their letter of intent.

Abstract The North Slope petroleum province consists of a Mississippian to earliest Cretaceous continental platform sequence and an overlying Cretaceous to Quaternary successor basin sequence. Both sequences are highly deformed along a foreland fold and thrust belt to the south but are relatively undeformed along a passive margin to the north. Most oil and gas accumulations in this province occur along the east-plunging Barrow arch—a structural axis separating the foreland basin from the passive margin. Preliminary evaluation of geologic and geochemical information indicated that four rock units, the Shublik Formation, Kingak Shale, pebble shale unit, and Torok Formation, are likely source rocks for the oils considered in this study. Together, these four rock units represent 140 Ma (Middle Triassic to late Early Cretaceous) of continuous marine deposition totaling more than 20,000 ft of rock in the southern part of the province while they are interrupted by one or more unconformities and range from several hundred to several thousand feet in thickness to the north. These rocks consist of an estimated 90% shale and siltstone and 10% sandstone deposited in a variety of sedimentary environments and at various rates of sedimentation. The Shublik Formation and pebble shale unit represent relatively slow rates of sedimentation in a shelf environment that was periodically anoxic. The Torok Formation and Kingak Shale represent relatively high rates of deposition along a shelf-slope-basin depositional profile in water depths calculated to be 1,000 to 3,000 ft or greater. Source rock characteristics may vary along the profile of deposition. Analysis of basin development suggests that North Slope oil and gas formed between the time of sufficient source rock burial (~100 Ma) and the time of tilting of oil-water contacts in oil fields in the Prudhoe Bay region (~40 Ma). Sediment loading and subsidence associated with northeastward basin fill made the Prudhoe Bay region the focus of migrating hydrocarbons. Later, during Tertiary time, regional eastward tilting changed migration directions from the Prudhoe area to the Barrow area.

Abstract Petroleum source-rock richness, type, and thermal maturity for four rock units under the Alaskan North Slope are determined from four geochemical analyses (organic-carbon content, C l5 + hydrocarbon content, elemental analyses, and vitrinite reflectance) of samples from 84 wells and 16 outcrops. Contour maps of organic-carbon content indicate that the average richness for the Shublik Formation, Kingak Shale, pebble shale unit, and Torok Formation is 1.7,1.5, 2.4, and 1.2 wt%, respectively. The organic-carbon content of the Shublik Formation, Kingak Shale, and pebble shale unit increases from west to east and downdip in the Prudhoe Bay area. Elemental analyses of kerogen plotted on a van Krevelen diagram indicate: (1) the Shublik Formation is Type II/III in the west but Type I in the Prudhoe Bay area; (2) the Kingak Shale is Type II/III across the Slope but Type II in the Prudhoe Bay area; (3) the pebble shale unit and Torok Formation both tend toward Type III even though the former is higher in organic-carbon content. Contour maps of vitrinite reflectance drawn on the pebble shale unit unconformity and at the top of the Torok indicate all four units are immature to marginally mature over the Barrow arch and mature to overmature in the Colville trough. Carbon isotope data for the saturated and aromatic fractions of the C 15 + hydrocarbons from rock extracts suggest possible source-rock correlations with similar data for four North Slope oil types (Umiat, Simpson, pebble shale, and Kingak), but no obvious correlation of the Barrow-Prudhoe oil type with any of the four source rocks.

Abstract A cooperative Alaskan North Slope oil-rock correlation study was undertaken by 30 private, government, and academic institutions from seven countries. The interpretations reported by all participants were based on independent analyses of the same 9 oil samples and 15 rock samples. Reports by 26 of the participants, plus two supporting papers and this summary paper, are included in this volume. A variety of analytical techniques were used, but certain analyses (organic carbon, pyrolysis assay, solvent extraction, liquid chromatography, carbon isotopes, gas chromatography, and gas chromatography-mass spectrometry) were common to the analytical programs of a majority of the participating laboratories. The results on the same samples reported by different laboratories were generally comparable, except for certain of the more subjective or method-dependent procedures. Statistical comparison of selected results showed that most labs are internally consistent but that the variability among laboratories is greater than expected. Most of the laboratories classified the 9 oils into two oil types, resembling oils from either Prudhoe Bay or Umiat fields, but a number of variations were proposed involving mixing, oil subtypes, and multiple or no oil types. Most of the laboratories conducted a separate geochemical evaluation of the hydrocarbon source potential of the 15 rock samples. Correlation among oils and rocks was difficult owing to the apparent non-source rock character of many of the rock samples. Nevertheless, oil-rock correlations were proposed by 21 of the 26 participating laboratories that contributed reports. Seventeen laboratories indicated the Triassic Shublik Formation as the main source of the Prudhoe-type oil, with eight of those calling upon contribution from the Jurassic Kingak Shale. The pebble shale unit was selected as the source of the Umiat-type oil by 14 labs, with seven labs indicating the Cretaceous Torok Formation as a co-source.

Abstract Routine geochemical techniques are used to study 15 rock samples and 9 crude oils from the North Slope of Alaska. Results indicate that the Cretaceous pebble shale unit, the Jurassic Kingak, and the Triassic Shublik formations may contain locally effective or expended oil source beds but most often contain primarily gas-generating organic matter. Organic facies variations occur within formations, and many of the rock samples have matured beyond the oil preservation limit. This makes oil-rock correlation difficult, if not impossible. Some of the oils analyzed are biodegraded, making typing and correlation even more difficult. Most oil samples, however, appear to fall into two groups: a Prudhoe Bay type, possibly related to Kingak and Shublik source beds, and an Umiat type, which may have originated in pebble shale or even Torok source beds. The Simpson oils are possibly mixtures of both basic types, and the Dalton oil may be largely but not entirely indigenous to the Lisburne limestone. Despite the presence of thick, organic-rich, and thermally mature shales throughout the study area, oil convertibilities are very low and none of the samples analyzed represent a significant source sequence. This may explain the almost complete absence of oil production in the National Petroleum Reserve area. The source or sources of the Prudhoe Bay oil accumulation were not identified by the samples analyzed in this study.

Abstract Fifteen rock and 9 oil samples from the North Slope of Alaska were analyzed by Shell Development Company as part of a joint oil-source rock correlation study sponsored by the U.S. Geological Survey (USGS). When sample size and/or organic richness permitted, the following rock and oil analyses were made: C 10 -C 3 5 saturate hydrocarbons by gas chromatography, C 7 composition by gas-liquid chromatography, 3,4, 5-ring naphthene distribution, and carbon isotope abundance measurements by mass spectrometry. Topped oils were analyzed for their gross composition (C 15 +). Vitrinite reflectance, visual kerogen, total organic carbon, and pyrolysis FID were determined for the rock samples. About one-half the rock samples are either at too high a maturity or are too lean in organic carbon to be viewed with total confidence for oil-source rock correlation interpretations, particularly in light of the limited number of samples in this study. At least two oils are thought to be transformed. Carbon isotopic ratios from oil and rock samples in this study indicate that the Triassic Shublik Formation is the source rock for one or more of the North Slope oils.

Abstract A source-to-petroleum correlation between five possible source units and a group of nine oils representative of the Alaskan North Slope has been attempted. A program was pursued to examine the utility of a stable carbon isotopic comparison of source kerogen-kerogen pyrolyzates with the petroleums. Of the sediment spot horizons studied, only the Echooka was without discernible source potential. The remaining sediments showed varying degrees of source richness. Unfortunately, half the sediments proved to be unsuitable for kerogen pyrolyzate production, being of advanced thermal maturity and partially to fully spent. This included the majority of the pre-Cretaceous examined. Using the pebble shale-Torok Formation as a datum, maturity increased rapidly to the south, in the direction of the Colville Trough, and less rapidly east to west. Three limiting groups of oils were recognized using isotopic and compositional information. These groups were best typified by the Put River, Simpson, and Seabee petroleums, each showing a progressive I3 C enrichment. Additionally, other oils showed characteristics suggestive of mixing phenomena. The Put River oil was believed to be representative of the major economic oil type of North Alaska. Despite large kerogen-kerogen pyrolyzate differentials, no convincing isotopic match was observed between the pebble shale or Torok formations and either the Put River or Simpson oils. Similarly, the limited Kingak Formation data showed equivocal correlation with the oils and again large kerogen-kerogen pyrolyzate differentials. It is therefore possible that direct correlation of source and petroleum on a whole kerogen 6 l3 C basis may be fallible. All three Shublik specimens were spent; however, two showed residual kerogen carbon isotopic values consistent with possible correlation with the Prudhoe oil type. Although the petroleums provided a good basis for correlation, it was regrettable that additional sediments of appropriate maturity and representative of regional plus stratigraphic facies variation were not available for this study.

Abstract Nine oils and 16 core samples were analyzed as part of the Alaskan North Slope Oil-Rock Correlation Study organized by the U.S. Geological Survey (USGS). Carbon isotopic measurements and gas chromatographic analyses were performed on whole oils, oil fractions, and rock extracts. Preliminary screening and more detailed analyses were made on the kerogens to determine their quality as sources of petroleum, maturity, and isotopic composition. Oil analyses suggest that there are three different genetic oil types. The Barrow-Prudhoe oils were defined by Magoon and Claypool (1981). They are characterized by their relatively high sulfur content, low API gravity and pristane/phytane ratio, and light carbon isotopic composition. The Simpson-Umiat oil type is identified by its low sulfur content, higher API gravity and pristane/phytane ratio, heavier carbon isotopic composition, and anomalously high concentrations of cyclic and aromatic light hydrocarbons. The third type is not an oil but represents compounds that oils, primarily Simpson-Umiat type, have extracted from immature sediments during migration. This third component was called Torok-Nanushuk and is noted by an anomalous light hydrocarbon distribution and relatively heavy carbon isotopic composition. It is possible to describe each of the oil samples in terms of mixing these three oil types in varying proportions. The Put River D-3 oil is typical of the petroleum found at the Prudhoe Bay field and contains mainly Barrow-Prudhoe type mixed with a small Simpson-Umiat component. The South Barrow No. 19 is comprised of pure Barrow-Prudhoe oil. It has lost a significant proportion of its light hydrocarbons, and the influence of a Simpson-Umiat component may have been obscured. The Fish Creek No. 1 oil is severely biodegraded but can be classified as Barrow-Prudhoe from its isotopic composition. Maturity parameters indicate that the Dalton No. 1 oil is an immature equivalent of the Barrow-Prudhoe oils. The oil from the Simpson Core Test is considered to best represent the Simpson-Umiat genetic type although it too lost all light hydrocarbons. The severely degraded Cape Simpson oil is believed to be a mixture of Simpson-Umiat and Barrow-Prudhoe. Umiat No. 4 oil is representative of the Simpson-Umiat type with a large component extracted from immature, Cretaceous reservoir rocks. Various parameters suggest that the Seabee condensate is of similar maturity to the Umiat oils and probably is the result of phase separation. It too has a substantial quantity of the extracted Torok-Nanushuk component. Finally, the South Barrow No. 20 oil is a slightly biodegraded mixture of all three oil types, but it is not possible to define the proportions clearly. From the samples used in this study, the pebble shale samples are considered to have the highest potential for oil generation because they are comprised predominantly of amorphous or herbaceous organic matter. The Torok samples contain mainly coaly fragments and are considered gas prone. One sample of Kingak contains an abundance of herbaceous organic material. Other examples of Kingak, Shublik, and Fortress Mountain units are overmature and contaminated with nonindigenous hydrocarbons. Because most of the extracts were either contaminated or generated from immature samples, rock/oil correlations were based on the carbon isotopic composition of kerogen isolates, oils, and oil fractions. From the suite of samples used in this study, only the Shublik could serve as a source for any of the oils. Evidence suggests, but does not conclusively prove, that the Shublik is indeed a major source of the Barrow-Prudhoe oils. There are sufficient data to show extensive lateral and vertical variation in organic facies in die pebble shale and Kingak unit and that these could also be major source contributors to producing oil fields. The pebble shale unit is believed to be the source of the Simpson-Umiat oils.

Abstract Analysis of 9 Alaskan North Slope oils, using 12 correlation parameters, generally confirms the type classifications and geographic distributions reported by Magoon and Claypool (1981). Five of the 9 oil samples were characterized as Barrow-Prudhoe type oils and 4 as Simpson-Umiat type. Two Barrow-Prudhoe oils and one Simpson-Umiat oil were severely biodegraded; their characterizations were less firm than those for the undegraded oils. Three Barrow-Prudhoe oils and one Simpson-Umiat oil showed significant modifications that could be explained by lateral variations in the source beds. The differences were deemed sufficient to permit subtype classifications for these 4 oils. In addition to being a subtype, one of the Umiat oils appeared to be the separated light fraction of a full-range Umiat type oil. Organic carbon analysis of 15 core samples from various formations showed the Triassic Shublik, Jurassic Kingak, Neocomian pebble shale, and Cretaceous Torok formations to be organic rich. Six samples were too mature for use in oil-rock correlation. Based primarily on gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) data, the primary sources for the Barrow-Prudhoe type oil are believed to be shales within the Shublik and Kingak formations. Hydrous pyrolysis of immature samples from Cretaceous horizons confirmed that the immaturity of some of these samples was not a factor in their poor correlation with Barrow-Prudhoe type oil. Oil-rock correlation data for the Simpson-Umiat oils suggest that the Neocomian pebble shale is the primary source for this oil type.

Abstract Organic geochemical analyses of 9 crude oils and 15 core samples from the North Slope of Alaska were performed in conjunction with an interlaboratory oil-source rock correlation study initiated by the U.S. Geological Survey (USGS). Correlation parameters employed included data derived from capillary gas chromatography of C l5 + aliphatic hydrocarbons; GC-MS-DS analysis for sterane, diterpane, and triterpane biomarkers; and stable carbon isotopic analysis of aliphatic, aromatic, NSO, asphaltene, and kerogen fractions. Of the 9 oils analyzed, the 5 oils from Point Barrow, Dalton, Fish Creek, and Prudhoe Bay areas (the Prudhoe group of oils) represent one distinct family. Two of these oils are biodegraded. The remaining 4 oils from Umiat and Cape Simpson areas form a less well-defined family. This latter group of oils has a range in maturity (e.g., biomarker parameters show Cape Simpson oils to be less mature than Umiat) and includes two biodegraded oils and one condensate. Six of the 15 possible source rocks are thermally overmature with respect to oil generation (R 0 > 1.6%) and have low quantities of extractable C 15+ hydrocarbons. Thus, these samples did not contain sufficient geochemical information for a reliable source rock-oil correlation study. Samples that can be used for correlation purposes represent the following formations: pebble shale unit (4 samples), Torok (3 samples), Kingak and Shublik (1 sample each). Stable carbon isotope compositions, isoprenoid ratios, and terpane distributions suggest that the extracts from the pebble shale show the highest degree of correlation with the Umiat-Cape Simpson oils. Comparison of the Umiat-Cape Simpson oils with the Torok and Kingak samples shows good correlation when some geochemical parameters are considered and poor correlation when others are considered. None of the above rock samples correlate well with the Prudhoe group of oils. The Shublik Formation sample is only marginally reliable for correlation because of its high thermal maturity: R 0 =1.6%. However, comparison of several geochemical parameters (in particular carbon isotope ratios, isoprenoid ratios, and diterpane distributions) suggest that this formation may have sourced the Prudhoe group of oils. A better correlation study would be possible if less mature Shublik samples were available because sterane and triterpane biomarkers would have been better preserved. Because of the small number of samples analyzed, positive or negative correlations must be tentatively regarded since organic inhomogeneities within stratigraphic units can result in variations in geochemical parameters. This is especially evident in the isotopic and biomarker variations observed in the pebble shale samples.

Abstract Chemical analyses of 9 oils and organic matter in 15 rocks from the North Slope suggest that the oils comprise at least two chemically distinct types. Type A oils, including oils from Prudhoe Bay to Point Barrow, can be distinguished from Type B oils, including oils from Umiat Field to Point Barrow, by distinctive 5 a, 20R sterane carbon number distributions, sulfur, vanadium, and nickel concentration, V/(V + Ni) ratios, hopane and aromatic hydrocarbon distributions, and carbon isotope ratios. Of the 9 oils of this study, at least 4 are degraded. Of the 15 rocks provided by the U.S. Geological Survey for this study, 7 are post-mature. These sample problems limited the results of this work. Those samples having R 0 values below 1.4% are all Lower Cretaceous except one, which is Jurassic. Although 12 samples have TOC values greater than 1.0%, only three samples (two pebble shale and one Kingak) contain indigenous extract yields above 500 ppm. Of these, only one pebble shale sample and the Kingak sample have over 200 ppm indigenous extractable hydrocarbons. None of the 15 rocks examined appear to be the single source for any of the 9 oils, although several similarities between the oils and the organic matter in some of the rocks do exist, particularly for Type B oils. Analysis of the molecular composition of the oils suggests (particularly for the Type A oils) that they may have been sourced by more organic fades. If this is the case, then no single source rock may correspond chemically to the oils studied. Based upon the correlations that are possible on this limited number of samples, Lower Cretaceous (particularly pebble shale), Jurassic, and Triassic rocks are all potential sources. In addition, the probability of lateral changes in organic fades requires that other geographically distinct potential sources also be considered as possible contributors. In summary, the very limited number of samples available for study from within the oil window does not allow a definitive conclusion as to the source for these oils. However, it is probable that the pebble shale, Kingak, and Shublik formations have all made contributions in various geographic areas.

Abstract Nine oil and 15 rock samples from the Alaskan North Slope have been analyzed for the purpose of determining which, if any, of the sampled formations sourced the sampled oils and determining the extent of agreement of results among the participating laboratories. Results from chromatography of the gasoline-range hydrocarbon fractions of the oil samples did not lead to meaningful correlations because most of the oils contained insufficient gasoline-range hydrocarbons. Hydrocarbon distributions derived from C 15 + chromatography of the oils were not useful for correlation owing to the significant degree of biodegradation suffered by some samples. Stable carbon isotope compositions and sterane and triterpane distributions suggest that the oils represent at least two families and appear to provide the best means for correlating the oils to the rocks.

Abstract Fifteen rock samples and 9 crude oils from 16 wells of the North Slope of Alaska have been investigated by organic geochemical techniques in order to assess the source rock potential for oil in Cretaceous formations and to find the tentative origin of oils accumulated in reservoirs ranging from Mississippian-Pennsylvanian to Cenomanian-Albian. Vitrinite reflectance as well as organic geochemical data (chloroform extract, gas analyses, T max ) show that the older formations analyzed (Kingak, Shublik, and Sadlerochit) are generally too mature to have generated the oils. Among the rock samples examined, only sediments from the pebble shale unit, the Torok, and the Kingak formations have maturities in agreement with oil genesis. In the two main formations, namely pebble shale and Torok, a maturity suite ranging from immature to mature sediments has been characterized. Quality of the kerogen, assessed by Rock-Eval pyrolysis, has been found to be at least fair in the Torok Formation and pebble shale unit. Surprisingly, hydrogen indexes (HI) often do not exceed 80. The genetic potential, measured by Sx + S 2 from Rock-Eval pyrolysis data, peaks at 4 mg/g of rock but is generally within the 0.5 to 2.5 range. Cretaceous formations of North Slope Alaska are at least moderate source rocks (S x + S 2 = 2-6 mg/g rock). Basic organic geochemistry data (Rock-Eval, chloroform extract, and gas yield) demonstrated that the pebble shale unit is a better (fair to good) source rock than the Torok Formation (poor source rock). Detailed organic geochemistry by gas chromatography and computerized gas chromatography-mass spectrometer have allowed a maturation assessment of kerogen by molecular measurements on steranes and terpanes. Maturities of dispersed organic matter, assessed by molecular parameters, have been compared to maturities based on vitrinite reflectance measurement data. The vitrinite reflectance scale generally matched the organic geochemical classification; however, some discrepancies have been observed in Torok samples within the 0.5 to 0.6% R 0 range. Maturity of oils, assessed by molecular measurements on steranes and terpanes, is variable. Comparison of maturities of oils to maturities of indigenous chloroform extracts provides a tool to approach migration of hydrocarbons. The moderate maturity of Umiat oil and Seabee condensate suggests a migration of limited extent which is, in addition, in good agreement with a Torok origin. The striking discrepancy between the maturity of pebble shale sediments in the Walakpa No. 1 well and the maturity of South Barrow oils indicates that the oils accumulated in pebble shale and Sag River sandstones originate from much deeper source rocks. Geochemical characteristics of alkanes and aromatics from the Torok and the pebble shale source rocks are closely related. Oil-to-source rock correlations are, in some cases, difficult to establish because crude oil properties obviously reflect molecular changes through migration (amount of alkanes, of tricyclic and tetracyclic terpanes, of ββ steranes, etc.). A combined review of isotopic, molecular, and geological data has, however, allowed the finalizing of a diagnosis regarding the origin of each crude oil including those that have been recognized as biodegraded oils.

Abstract Nine oils and 15 rock samples from across the National Petroleum Reserve in Alaska (NPRA) were analyzed by standard geochemical techniques in order to characterize the Alaskan North Slope oils and to attempt to determine the origin of these oils through direct crude oil-source rock correlation. Results of this study indicate four genetic oil types. One major oil type (Type I) includes the oils from Prudhoe Bay, South Barrow, and Fish Creek. These oils are reservoired in rocks of the Sadlerochit Group, pebble shale units and Sag River Sandstone, and Nanushuk Group, respectively (ranging in age from Permian to Cretaceous). Type I oils have the following geochemical characteristics: high sulfur content (0.9-1.8%), C19/C23 tricyclic terpane ratios 0.7 to 0.13, pristane/phytane ratios 1.3 to 1.5, farnesane/C^ isoprenoid ratios 0.9 to 1.0, and stable carbon isotope ratios for the saturated hydrocarbons from δ 13 C —28.4 to —29.4 and for the aromatic hydrocarbons between δ l3 C —28.7 and —29.3. The oils of Type I contain biomarkers that are similar in distribution to the extractable organic matter from the Kingak Shale and Shublik and Echooka formations rocks. However, a large (4-5 per mil) difference in stable carbon isotopes exists between the aromatic hydrocarbon fractions from the oils and the Kingak and Echooka rocks. This difference is too large to result from migration alone and suggests that the Kingak and Echooka rocks are not the major source of Type I oils regardless of some genetic similarities in organic matter. The best overall geochemical correlation exists between the oils of Type I and rocks of the Shublik. A second major North Slope oil type (Type II) includes oils from the Simpson and Umiat fields. The Simpson oils were encountered in shallow core tests and as a seep in a seismic-test hole. The Umiat oil is from Cretaceous reservoirs of the Nanushuk Group. The Simpson-Umiat Type II oils have the following geochemical characteristics: low sulfur <0.2%, C19/C23 tricyclic terpane ratios >1.2, pristane/phytane ratios 2.1 to 2.2, farnesane/Cl6 isoprenoid ratios 0.6 to 0.7, and 6 t5 C ratios for the saturated hydrocarbons between —28.1 and —28.7 and for the aromatic fraction between —26.7 and —27.7. These Type II oils have many geochemical characteristics similar to the extractable organic matter from the Torok Formation and the pebble shale unit. However, the poor source rock quality of the organic matter in the Torok suggests that these rocks are poor oil sources but may have generated some gas. A third genetic oil type (Type HI) is represented by the oil-show in the Dalton test well obtained from rocks of the Lisburne Group of Mississippian to Permian age. The Dalton oil is geochemically similar in many respects to Type I oils, but dissimilarities in sulfur, hydrocarbon, and asphaltic contents indicate probable genetic source differences. Geochemically, the Dalton oil resembles oils derived from carbonate rocks. Organic-rich carbonate units within the Lisburne are suspected as the source of the Dalton oil. A fourth oil type (Type IV) is represented by the condensate from the Seabee well reservoired in the Torok Formation of Cretaceous age. Geochemical comparison data on this sample are minimal (carbon isotopes only) because of its narrow boiling range. The carbon isotopes for the hydrocarbons from the Seabee condensate are most like carbon isotopes for hydrocarbons from the Torok and the pebble shale unit.

Abstract As a tool in petroleum exploration, oil-to-oil correlation offers a means of detecting the migration of oil within or between formations. Oil-to-source rock correlations identify specific source beds that generated the petroleum. In order to accomplish these tasks, a variety of techniques have been used, including gas chromatographic analysis of various hydrocarbon boiling point ranges, mass spectral group type analysis, carbon isotope ratios, and gas chromatographic-mass spectral analysis of biological marker hydrocarbons. This report deals with a comparison of the results of these techniques in an attempt to correlate 9 oils and 15 source rock samples from five different formations from the National Petroleum Reserve in Alaska. Oils were compared to each other using the above-mentioned chemical parameters in an attempt to subdivide them into groups. Source rock samples were first evaluated to determine if they were capable of generating oil, prior to their comparison to the crude oils. Although individual data types allowed some differentiation of the oils, the data yielded no consistent grouping of oils or pairing of oils with source rocks. Additional work will be necessary in order to determine the source of the North Slope oils.

Abstract Fifteen sediments, 8 oils, and a condensate from the North Slope of Alaska have been investigated with a range of geochemical techniques. In addition to organic carbon determination and Rock-Eval pyrolysis, the sedimentary rock extracts, the oils, and the condensate have been extensively examined with computerized gas chromatography-mass spectrometry (GC-MS), including the application of high-resolution (- 2,500) mass spectrometry. In this way, information on the distributions of aliphatic and aromatic biological marker hydrocarbons and of phenanthrene, methylphenanthrene, and dimethylphenanthrene isomers was aquired. Additional information on bulk composition was derived from the GC-MS analysis of the aromatic hydrocarbon fractions of the oils and the condensate with low electron energy (12 eV) mass spectrometry. These results were integrated with carbon, hydrogen, and sulfur isotope data. The results could be best explained by a model, which envisages that most of the oil presently accumulated in the North Slope of Alaska derived from the Jurassic Kingak Shale. In the Coastal Plain, this shale presently lies within the zone of oil generation, but in the Northern Foothills of the Brooks Range it is overmature and hence below it. In the model, most of the oil from this shale has migrated laterally and northward into the Sadlerochit Sandstone (Permian) and Lisburne Limestone (Mississippian) reservoirs around the Barrow arch. Minor contributions from the units overlying and underlying the Kingak Shale are also predicted (Neocomian pebble shale unit and Permo-Triassic Shublik Formation). Only when the deeper reservoirs were full did oil, following the same migration pathway, migrate further upward into younger and shallower reservoirs. Thus, the increase in oil maturity with decreasing reservoir depth is explained. This maturity trend was apparent from the oils’ sulfur contents, carbon and sulfur isotope compositions, bulk compositions (percent hydrocarbons, percent asphaltenes), and the distributions of their methylphenanthrene isomers (methylphenanthrene index). The most mature oils are also the shallowest oils and may therefore have migrated the longest distance. Any increase in the relative amounts of lighter and less polar components could either be the result of increased maturation, increased migration, or both. Not only have the distributions of biological marker compounds been considered, but also their absolute concentrations (Mg/g C org , ppm in hydrocarbon fractions) by the addition of a known amount of an internal standard. This has shown that die concentrations of these components in the Ci 5 + hydrocarbon fractions of sedimentary rock extracts decrease sharply with the onset of petroleum generation and that in immature rocks these are an order of magnitude greater than the concentrations of the same components in the hydrocarbon fractions of the oils. That the most unstable components (fastest decrease in concentration) considered (monoaromatic steroid hydrocarbons) suggest a correlation of the oils with immature sediments, while more stable components of the oils (e.g., the hopanes) match better with those of shales well within the zone of petroleum generation, implies that expulsion of components from shales occurs over a wide range of maturities. This in turn suggests oil accumulations could be averaged mixtures of organic fluids representing a range of maturities. The decreases in concentrations of the biological markers with the onset of petroleum generation mean their distributions could exaggerate the contributions of immature sources to a given oil pool. Such a case is thought to exist in the North Slope of Alaska. Although the shallower oils are more mature on a number of measurements, the biological markers suggest the reverse. If the shallower oils were more mature, they should have lower concentrations of biological markers. The addition of small amounts of immature oil, from either the pebble shale unit or Torok Formation in the region where the oils have accumulated, may have had a major influence on the biological marker patterns without contributing significantly to the vast bulk of the oils. Magoon and Claypool (1981) proposed a division of the North Slope oils into two families: Simpson-Umiat and Barrow-Prudhoe. This was mainly based on carbon and sulfur isotopic compositions and sulfur content. It now appears that both families came from similar sources but that the Simpson-Umiat oils are products of a later generation than the Barrow-Prudhoe oils. The Simpson-Umiat oils are therefore more mature and have migrated further into shallower reservoirs, where the addition of small amounts of immature oils from different sources is also more likely. The condensate derived from highly mature sources. It was found in the Northern Foothills, and the most favored source is the deep Kingak Shale (>4,000 m) in this region.

Abstract The major objective of the U.S. Geological Survey-sponsored cooperative North Slope Alaska oil-rock correlation study was to establish, using a diversity of geochemical techniques, which formation(s) served as source(s) of the crude oils from the North Slope of Alaska. A second objective was to allow intercomparison and calibration of geochemical technologies among the university, petroleum industry, government, and private geochemical laboratories participating in the study. Two major groups of oils were identified. Group I includes oils from the Umiat and Simpson areas. These oils are generally low in sulfur, nitrogen, and asphaltenes, have medium gravities, have nickel/vanadium ratios ≥ and pristane/phytane ratios >1.5, and are high in diasteranes. Group II includes oils from the Barrow, Fish Creek, and Prudhoe Bay areas. These oils are generally high in sulfur, nitrogen, and asphaltenes, have low gravities, have nickel/vanadium ratios <1 and pristane/phytane ratios <1.5, and are moderate in diasteranes. Both groups of oils are of mixed but predominantly marine source input and are quite mature thermally. The triterpane patterns of the Group I oils contain certain C 30 pentacyclics, are low in tricyclics, and have hopane > norhopane. The Group II oils are devoid of the C 30 pentacyclics found in Group I oils, high in tricyclics, and have norhopane > hopane. The Kingak Shale appears to be the principal source of the Group I oils. However, the Group I, Seabee No. 1 condensate is believed to originate in the Torok Formation. The Group II oils have their principal source in the Shublik Formation but have to varying degrees the Kingak as a co-source. The Barrow pebble shale sandstone oil has major Kingak input; the Barrow Sag River Sandstone, Fish Creek, and Prudhoe Bay oils have minor Kingak input. The Dalton area oil produced from the Lisburne Group, included in Group II because of its overall similarity to these oils, is believed to be indigenous to the Lisburne.

Abstract Using inspection properties alone it was possible to divide 7 of the 9 oil samples into one of the two groups defined by Magoon and Claypool. The Umiat No. 4, Simpson Core Test, and the Cape Simpson Area oils fall in the Simpson-Umiat group while the Put River, Dalton No. 1, Fish Creek No. 1, and the South Barrow No. 19 oils fall in the Barrow-Prudhoe group. The Barrow No. 20 oil is considered to be a mixture of both types, whereas the Seabee No. 1 condensate is anomalous and may represent an entirely different group. Gas chromatographic-mass spectrometry (GC-MS) and stable carbon isotope ratios of the whole oil and the oil fractions show concurrence with the above grouping but suggest there may be more of a mixing or continuum of properties than is implied by the concept of grouping. Three of the oils, Dalton, Fish Creek, and the Cape Simpson area, have undergone varying degrees of biodegradation and have lost their normal alkanes. The Simpson Core Test sample shows evidence of heavy biodegradation (presence of normethyl hopanes), but n -alkanes are still present. This suggests an earlier period of biodegradation followed by subsequent topping up with normal oil. A similar process is suggested to explain the composition of the Dalton oil. The majority of the sediment samples had good organic carbon contents (TOC > 1.0 wt%) but poor hydrocarbon source potentials. This and the general high maturity suggest that oil or gas generation has already occurred in most of the sediments examined, the shallower Torok and pebble shale samples excepted. The presence of inert carbon and the humic nature of most of the samples may be partially responsible for the low potentials observed. The very small amounts of extracted hydrocarbons recovered from the Kingak and Torok in Seabee No. 1 and the Shublik and Echooka formations in Inigok No. 1 were similar in nature and considered to be nonindigenous, probably contaminants.