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 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.

Abstract Samples of 6 oils, a condensate, 15 sediments from NPRA, and one Prudhoe Bay oil (Put River D-3) were evaluated to distinguish oil types, determine sources of the oils, and characterize the samples geochemically. Carbon isotope ratios were determined for all samples and fractions. Two distinctive groups of oils were recognized, with evident mixing between them. The Prudhoe Bay oil was distinguishable from these and was assigned to a third group. The D-3 oil showed the same unique features as other Prudhoe oils. The Dalton, Fish Creek, and South Barrow No. 19 oils comprise the most homogeneous group among the NPRA oils. This group is characterized by clustering of all carbon isotopic values (range 0.4 per mil, PDB), an average of -29.7 for aromatics, and of -29.5 for saturates. Aromatics that are isotopically lighter than saturates represent a rare occurrence in petroleums. The second group is represented by two oils from the Cape Simpson area, with average delta values of -28.1 for aromatics and -29.0 for saturates. The overall range of values increases to 1.2 per mil, with aromatics isotopically heavier than saturates. Published data suggest that the Cape Simpson oils are not an end-member group but are a mixture of the Fish Creek and an “Umiat” oil, which occurs in southeastern NPRA. The South Barrow No. 20 oil is also interpreted as a mixture of the two types. Source rock evaluation consisted of Rock-Eval, vitrinite reflectance, pyrolysis/light hydrocarbon gas chromatography (PGC), Soxhlet extraction, liquid chromatography, and carbon isotope ratio determinations on kerogen and extract fractions. The pebble shale had the best hydrocarbon generation potential based on Rock-Eval, but the hydrogen index values were low (less than 200), considering maturation level. This suggests that the pebble shale is not a prolific oil source in the area sampled. However, PGC data indicate that the Kingak is a major source rock. The high maturity of the Shublik, Echooka, and two of three Kingak samples, shown by vitrinite reflectance (R c) values greater than 1.44%, prevents adequate assessment by Rock-Eval. Pyrolysis-GC indicated that the Shublik and Kingak originally contained oil-prone kerogen, whereas the Torok and Echooka did not. The pebble shale probably contains a mixture of kerogen types. Vitrinite reflectance indicates that the Torok Formation and pebble shale are approaching optimum maturity for oil generation in most locations, as is the Kingak in one well. Carbon isotope ratios of kerogens and rock extracts suggest a Shublik source for Fish Creek group oils. Kerogen from two Shublik samples has a mean delta value of -29.1, similar to the oil. Kerogens from all other formations range from -23.8 to -25.5, insufficiently similar to any of the oils to represent feasible sources. Thus, the actual source of the Cape Simpson oils is not represented among the sediment samples.

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 Nine crude oil and 15 core samples from the North Slope were analyzed by geochemical methods to identify relationships between the oils and their source rocks. Based on bulk geochemical parameters, the crude oils can be separated into the two groups reported by Magoon and Claypool (1981): a Barrow-Prudhoe group and a Simpson-Umiat group. One exception to this classification is an oil produced from the Cretaceous Kongakut Formation at South Barrow that has some features of each type and may be a mixture of the two. Standard geochemical techniques were used to evaluate the oil-source potential of rocks from Cretaceous to Permian age. These data identify the pebble shale unit of the Cretaceous Kongakut Formation, the Jurassic Kingak Shale, and the Triassic Shublik Formation as having the most favorable oil-source potential. Gas chromatography-mass spectrometry (GC-MS) of steranes and terpanes was used to correlate oils with potential source rocks. Based on these results, both the pebble shale unit and the Cretaceous Torok Formation are suggested as possible sources of the oil from the Umiat Basin and Simpson shelf. A positive correlation could not be made for source rocks of the Barrow-Prudhoe oils, although based on pristane/phytane ratio the Triassic Shublik Formation is suggested as a possible source.

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.