Albert G. Holba’s research while affiliated with ConocoPhillips and other places


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Publications (17)


Figure 1. Location map for North Alaska Super Basin and hydrocarbon accumulations. The super basin area is the Arctic Alaska petroleum province defined by Bird and Houseknecht (2011). Oil field (green) and gas field (red) outlines are courtesy of IHS Markit. DeLorme World Basemap is ©2020 Garmin Ltd. or its Subsidiaries. All rights reserved. ANWR = Arctic National Wildlife Refuge; NPRA = National Petroleum Reserve in Alaska; TAPS = Trans-Alaska Pipeline System.
Figure 2. Generalized structural cross section from the Brooks Range across the North Slope to the Beaufort Sea showing source rocks and thermal maturity (modified from Houseknecht et al., 2020). Line of cross section is shown in Figure 1.
Figure 3. Locations of oil fields, selected producing units, oil samples (dots), source-rock samples (stars), exploration wells (asterisks), and the Prudhoe Bay field tar mat (lighter green shading in Prudhoe Bay Unit). Numbered wells are identified in Tables 2-4. Wells outside of this area are shown in Figure 8. Cross section AA9 is shown in Figure 5. Field outlines are courtesy of IHS Markit. DeLorme World Basemap is ©2020 Garmin Ltd. or its Subsidiaries. All rights reserved. CRU = Colville River Unit.
Figure 4. Generalized stratigraphic column for the Prudhoe Bay and Kuparuk River area of the central Alaskan North Slope. Modified from Bird (2001b) and Tudor, Pickering, Holt & Co. (2012). BCU = Base Cretaceous unconformity; Fm = Formation; HRZ = highly radioactive zone; Kuparuk A = Kuparuk Formation unit A sandstone; Kuparuk C = Kuparuk Formation unit C sandstone; LCU = Lower Cretaceous unconformity; SS and ss = Sandstone.
Figure 5. Generalized structural cross section through Kuparuk River, West Sak, Borealis, Orion, Polaris, Lisburne, and Prudhoe Bay fields. The line of cross section is shown in Figure 3. HRZ = highly radioactive zone; Kuparuk A = Kuparuk Formation unit A sandstone; Kuparuk C = Kuparuk Formation unit C sandstone; LCU = Lower Cretaceous unconformity; V.E. = vertical exaggeration.

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North Alaska Super Basin: Petroleum systems of the central Alaskan North Slope, United States
  • Article
  • Full-text available

June 2021

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5,226 Reads

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4 Citations

AAPG Bulletin

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Albert G. Holba
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Effects and impact of early-stage anaerobic biodegradation on Kuparuk River Field, Alaska

November 2004

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55 Reads

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17 Citations

Geological Society London Special Publications

Albert G. Holba

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Lisa Wright

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Rick Levinson

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[...]

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Mark Scheihing

Anaerobic processes have only recently been recognized as an important mechanism in the biodegradation of crude oils. They are normally invoked to explain extensively biodegraded oils with little or no possibility of contact by oxygenated waters from an active aquifer. This work with Kuparuk Field indicates that early stages of anaerobic biodegradation can be subtle and easily missed, yet have economic impact. Kuparuk River Field, North Slope of Alaska, comprises two reservoir intervals: vertically stratified and imbricated lower shoreface sandstones (A sands), and overlying shallow marine sandstones with complex permeability structure (C sands). The vertical and lateral distribution of viscous oil (less than 20° API) shows a strong relationship to structure and faulting in the Kuparuk Field. Multiple mechanisms for the origin of tars and viscous oils can be proposed, including early aerobic biodegradation, anaerobic biodegradation, inorganic oxidation and gas deasphalting. This geochemical study, integrated with stratigraphic, structural and production data, was undertaken to help understand the origin and distribution of tar and viscous oil in the field. Obvious depletion of n -alkanes and other paraffins, classically regarded as indicative of early biodegradation, is not observed in examined samples. However, Kuparuk viscous oils show slight to extreme selective depletion in long-chain alkyl aromatic (LCAA) hydrocarbon families (e.g. alkylbenzenes and alkyltoluenes). This is interpreted as indicative of an early stage of anaerobic microbial degradation that likely destabilized the oil to promote subsequent precipitation of asphaltenes as tar. Depletions in LCAAs in core samples in the field are linked to decreased hydrocarbon/nonhydrocarbon ratio and to an increase in the high molecular weight (>C 50+ ) components of Rock-Eval 6 pyrolysates. Using a calibration curve constructed from oil Rock-Eval 6 pyrolysis, the API gravity of core oil plus bitumen can be estimated. Tar-plugged formations with depleted LCAAs have estimated API gravities <8°. Portions of the Kuparuk reservoir with higher iron content tend to show greater depletions in LCAA. Anaerobic biodegradation is likely mediated by dissimilatory iron-reducing bacteria. Biodegradation likely destabilizes the oil with respect to asphaltene precipitation such that later arrival of petroleum leads to tar in the reservoir. Increased tar and depleted LCAAS correspond to intervals with lower productivity indices, thus indicating a significant impact on petroleum producibility.


Application of tetracyclic polyprenoids as indicators of input from fresh-brackish water environments

March 2003

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404 Reads

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197 Citations

Organic Geochemistry

C30 tetracyclic polyprenoids (TPP) are most prominently observed in samples derived from low salinity, i.e. fresh to brackish lacustrine environments, and are generally present in low levels in samples derived from saline, i.e., marine and saline lacustrine, environments. A near-shore facies of the Chonta Formation, Peru, that has no marine palynomorphs but abundant Chlorococcalean (Green) algal nonmarine palynomorphs, has high levels of TPP, suggesting Green algae (or Chlorophyta) are a possible source for the TPP compounds. The ratio between a C30 TPP compound and 27-norcholestanes is useful for assessing this nonmarine algal input. Moderate elevations of TPP, above what is common in marine derived samples, were found in ostensibly marine source rocks and oils from certain basins of western and northern South America (Middle Magdalena, Colombia; Maracaibo, Venezuela; and Trinidad basins). This is likely due to transport from the nonmarine to the marine environment because of an influx of fresh water into the near-shore marine environment. Alternatively, oils from these basins may have inputs from near-shore shallow marine algae with chemistry similar to that found in lacustrine settings. The TPP ratio, in conjunction with other environmental indicators such as 4-methyl steranes or hopane/sterane ratio, is useful for differentiating marine and nonmarine influences in pre-salt oils and source rocks of West Africa. The TPP ratio, used with other environmental indicators (gammacerane, C29 steranes, C30 steranes) and age diagnostic biomarkers (dinosteranes, 4-methylsteranes), can be useful in differentiating among nonmarine source facies. For example, in the Turpan-Hami basin, China, Permian saline lacustrine and Jurassic lacustrine deltaic facies can be discriminated.



Carbon isotopic composition of organic acids in oil field waters, San Joaquin Basin, California, USA

April 2001

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138 Reads

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63 Citations

Geochimica et Cosmochimica Acta

The carbon isotopic compositions of short-chain organic acids (C2-C5) in oilfield waters of the San Joaquin Basin exhibit a wide range of values, from +0.57 to −27.33‰ (PDB). Most, however, are in the range of −15 to −25‰. The bulk isotopic compositions of individual acids generally become isotopically depleted (more negative) with increasing carbon number (chain length) but are consistently more enriched than the isotopic composition of coproduced oils. Relationships between carbon number and isotopic composition of the acids suggest intramolecular isotopic fractionation.Calculated carboxyl carbons (COOH) are isotopically more enriched, typically by 10 to 38‰, than aliphatic carbons (CH). Calculated aliphatic carbon isotopic compositions cluster around two values, −23 and −28‰, consistent with the isotopic composition of coproduced oils derived from two different sources, Miocene Monterey–sourced oils (−22 to −25‰) and Eocene Kreyenhagen–sourced oils (−28 to −30‰). We suggest that the isotopic composition of the aliphatic carbons in the organic acids reflects the carbon isotopic composition of the coproduced oils (or their source kerogen).Isotopic compositions of carboxyl carbons fall within a range of −12.8 to +8.0, consistently heavier than aliphatic carbons. We interpret the enrichment of carboxyl carbons to be inherited from either biological precursors in the source rock kerogen or due to exchange with carbon in dissolved HCO3. The carbon isotopic enrichment of carboxyl carbons is at odds with theories that attribute organic acids to the inorganic oxidation of hydrocarbons in the subsurface.


Evolution of the Cretaceous organic facies in Columbia: Implications for oil composition

April 2001

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86 Reads

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26 Citations

Journal of South American Earth Sciences

Cretaceous source rocks in Colombia are characterized by significant variations in organic matter input and depositional environments. Organic matter input, sedimentary environments, redox conditions and lithology of the source rocks as interpreted from bulk properties, trace elements, biomarker and isotopic composition of oils correspond to changes in the organic facies geographically and through time. Marginal marine/tidal Aptian–Albian units found in the Putumayo and Upper Magdalena Basins contain marine algal/bacterial and higher-plant organic matter. Coeval units in the Middle Magdalena Basin (MMB) and the Eastern Cordillera contain less terrestrial input because they were deposited on a broad platform that locally developed evaporites. Cenomanian–Coniacian marine-shelf shales and marls in the Putumayo, Upper and MMBs contain marine organic matter deposited on a marl/carbonate-prone shelf resulting in a type II kerogen. Upper Cretaceous offshore and lower shoreface mudstones preserved in the present-day position of the Eastern Cordillera and Llanos Basin contain higher-plant terrestrial input derived from the Guyana Shield, mixed with marine organic matter. Although similar to the oils generated from Lower Cretaceous rocks, Upper Cretaceous-derived oils can be distinguished by the presence of oleanane and other angiosperm biomarkers.


Evidence for biodegradation and evaporative fractionation in West Sak, Kuparuk and Prudhoe Bay field areas, North Slope, Alaska

March 2001

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2,687 Reads

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131 Citations

Organic Geochemistry

Oils from the West Sak, Kuparuk, and Prudhoe Bay fields on the North Slope of Alaska display geochemical evidence for a complex petroleum filling history that includes multiple sources and alteration by evaporative fractionation and biodegradation. Source-specific biomarkers in West Sak oils indicate generation from the same source rocks in approximately the same proportions as Prudhoe Bay field oil, consistent with the hypothesis that oil spilled from the deeper Prudhoe accumulation and remigrated about 10 miles laterally and 5000 feet vertically into the West Sak Field. West Sak oils are moderately biodegraded but exhibit anomalously high concentrations of gasoline-range saturate and aromatic compounds interpreted as a secondary gas/condensate charge that arrived after biodegradation of the spilled Prudhoe oil. The shallowest West Sak oils have less secondary gas/condensate charge, lower API gravities, and reduced concentrations of methylcyclopentane, benzene, cyclohexane, 3-methylhexane, heptane, methylcyclohexane, and toluene relative to the deepest West Sak zone A oils. The carbon isotopic compositions of these C6 and C7 compounds in the shallowest West Sak reservoirs are heavier than those of the deepest West Sak oil reservoirs by up to 3‰ and the isotopic compositions of saturate compounds are altered more than those of aromatic compounds. The heavier isotopic compositions of C6 and C7 compounds in the shallow West Sak reservoirs are interpreted to result from a kinetic isotope shift caused by light biodegradation of the secondary gas/condensate charge. West Sak field solution gas is also interpreted as biodegraded, based upon its dryness (>98% methane), relatively high isobutane/n-butane ratio, the presence of isotopically heavy carbon dioxide and isotopically light methane, and propane that is isotopically heavier than either ethane or butane. The isotopic compositions of methane and carbon dioxide in West Sak gas suggest that biogenic methane was generated during CO2 reduction under anaerobic conditions. The isotopic compositions of C6 and C7 compounds in the deepest, least biodegraded West Sak oils are nearly identical to those of the underlying oils from the Kuparuk Field but differ from the Prudhoe Bay Field oils. The Kuparuk Field is therefore postulated as the source of the secondary gas/condensate charge observed in oils from the West Sak Field. Ratios of toluene/heptane and heptane/methylcyclohexane in Kuparuk oils provide independent evidence for loss of gas and condensate from the Kuparuk reservoir by the process of evaporative fractionation, and the oils subjected to the most evaporative fractionation are isotopically heavier in the C6–C7 range. The isotopic compositions of West Sak zone A C6 and C7 hydrocarbons suggest that a slight (∼0.8‰) isotopic fractionation resulted from evaporative fractionation of the gas/condensate charge from the Kuparuk Field oil accumulation. North/northeast-striking faults that connect the Kuparuk and West Sak reservoirs provide a potential migration pathway for the secondary gas/condensate charge through 3000 feet of intervening shale. This model of West Sak oil biodegradation, subsequent secondary gas/condensate charge, and further biodegradation has implications for development of North Slope West Sak oil reserves, because heavily biodegraded West Sak oils that lack a secondary gas/condensate charge may be too viscous to develop by conventional waterflooding methods.



Tetracyclic polyprenoids: Indicators of freshwater (lacustrine) algal input

March 2000

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295 Reads

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81 Citations

Geology

Because of the great variety of lacustrine-source depositional characteristics and biological consortia, identification of a universally applicable indicator of freshwater or brackish-water organic input for crude oils and rock extracts has proven elusive. Tetracyclic polyprenoid compounds (TPP) are present in relatively high concentrations in oils and associated source rocks deposited under freshwater or brackish-water conditions, but typically are present in relatively low concentrations in samples from marine or coal-forming depositional environments. A TPP ratio, constructed from the gas chromatography tandem mass spectrometry peak areas of a C30 tetracyclic polyprenoid divided by the sum of the peak areas of the C26 27-norcholestanes, revealed great specificity in identifying freshwater or brackish-water algal input, particularly in crude oils.


Application of new diterpane biomarkers to source, biodegradation and mixing effects on Central Llanos Basin oils, Colombia

July 1999

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58 Reads

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72 Citations

Organic Geochemistry

Llanos Basin oils have been commonly attributed to the prolific Upper Cretaceous age source formations outcropping in the Eastern Cordillera. Recently, however, variable oleanane indices have been reported for Llanos oils, suggesting a contribution from Tertiary source sequences largely on the basis of the presence of high relative abundance of oleanane, a Tertiary age-diagnostic biomarker. A homologous series of 25-norhopanes in many central Llanos Basin oils indicates that heavy biodegradation is particularly common to the initial oil charging reservoirs from Upper Cretaceous marine sources. One homologue, 20S-25-norhomohopane [C30 25-norhopane], co-elutes with oleanane and may thus contribute to the peak attributed to oleanane. Also, confusing the source identification is the possibility that some Cretaceous facies also contain oleanane. Three plant diterpanes, which may be isomers of fichtelite and are common to the Central Llanos oils, have been observed in an Eocene source rock sample, but not in Cretaceous rocks or oils, providing additional strong evidence for a Tertiary contribution to some Llanos Basin oils. In mixed oils with low to moderate oleanane contents and with a strong, co-eluting C30 25-norhopane, the fichtelite isomers are the more reliable indicators of Tertiary source input.


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Citations (17)


... Oil-prone source rocks are present in the Upper Cretaceous succession, mainly in condensed facies of the Hue Shale and Seabee Formation, and geochemical evidence indicates that these source rocks contributed to several oil accumulations along the Barrow Arch (Lillis et al. 2015;Botterell et al. 2021;Masterson and Holba 2021). The succession also hosts several productive oil reservoirs, including turbidite sandstone in the Seabee Formation and marginal-marine to non-marine sandstone in the Schrader Bluff and Prince Creek formations. ...

Reference:

Colville Foreland Basin and Arctic Alaska Prograded Margin Tectono-Sedimentary Elements, Northern Alaska and Southwestern Canada Basin
North Alaska Super Basin: Petroleum systems of the central Alaskan North Slope, United States

AAPG Bulletin

... The Inshore West Coast Basins are observed to straddle all of the five terranes which compose Scotland, from the Hebridean terrane in the far northwest to the Southern Uplands terrane in the south (Fyfe et al. 1993;Holdsworth et al. 2000;PESGB 2017).26 (Owens and Marshall 1978;Fyfe et al. 1993;Waters et al. 2011 (Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011 (Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011 (Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Emeleus & Bell 2005 (Fyfe et al. 1993;Stoker et al. 1993;BGS 2020;BGS 2021) Morton (1992a), Hesselbo et al. (1998) and Morton (2004) Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Carruth 2003;BP 2011;Ritchie et al. 2011 Where multiple licences overlie, the most recent licence is shown (Percival et al. 1987;BP 1990;Mustang Oil 1990;Chevron 1991;Pentex 1992;British Gas 1995 (Scotped 1982;BP 1990;Mustang Oil 1990;Chevron 1991;Fynegold Petroleum 1991;Pentex 1992;Naylor and Shannon 2011;Dunnahoe 2016;InfraStrata 2017;NDR 2020 (BP 1990;Chevron 1991;Pentex 1992;British Gas 1995;Raey 2004;Mancal Energy 2008) Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011 Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011) Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011;Naylor & Shannon 2011) Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011;Naylor & Shannon 2011) Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Ritchie et al. 2011 (Fyfe et al. 1993;Stoker et al. 1993;Hudson & Trewin 2002;Husmo et al. 2003;Ritchie et al. 2011;Bonte et al. 2014 (Sellwood 1972;Paleoservices 1977;Tate & Dobson 1989;Morton 1989;Ebdon & Jacovides 1990;Searl 1992;Sovereign 1993;Scotchman & Thomas 1995;Robertson 1996;Hesselbo et al. 1998;Ruffell & Shelton 1999;Ainsworth & Boomer 2001;Morton 2004;Simms & Jeram 2007;Brookfield 2008 (Parnell 1992, Fyfe et al. 1993, Garcia et al. 2014, Providence 2016 (Parnell 1992, Fyfe et al. 1993, Garcia et al. 2014, Providence 2016 List of Tables Table 1 -Distribution of source rocks, reservoir rocks and seal rocks across the Northwest European Continental Shelf Fyfe et al. 1993;Stoker et al. 1993;Jackson et al. 1995;Wassams & Cordingley, 1999;Ritchie et al. 2011;Bunce 2018 (Harris and Hudson 1980;Harris 1984;Andrews 1985;Ambler 1989;Morton 1989;Andrews and Walton 1990;Trueblood 1992;Morton 1992b;Butterworth et al. 1999;Vincent and Tyson 1999;Scotchman 2001;Hudson and Trewin 2002;Barron et al. 2012;Muirhead et al. 2017). .......237 ...

Jurassic non-marine source rocks and oils of the Porcupine Basin and other North Atlantic margin basins
  • Citing Article
  • January 1999

... The gammacerane is believed to be formed by reduction of tetrahymanol originated from bacterivorous ciliates, implying a strong reduction and highsalinity environment [119,120]. The ETR has been taken to distinguish Jurassic reservoired oil from Triassic as an age-related parameter [121,122]. ETR is relatively less affected by thermal maturity and biodegradation due to the high thermal stability of C 28 TT, C 29 TT, and Ts to ensure a more accurate interpretation of the parent source. Holba et al. [121] found that the ETR of Triassic oils exceeds 2.0, whereas the Jurassic ETR has lower ratios corresponding to major mass extinction that occurred at the end of the Triassic, which may have altered the principal biological sources of tricyclic terpanes, mostly less than 1.2. ...

Triassic Source Facies in High Paleo-Latitude Petroleum Systems

... Early research indicates that the extended tricyclic terpane ratio (ETR) serves as an age-related indicator to distinguish crude oils originating from Triassic, Lower Jurassic, and Middle−Upper Jurassic marine source rocks. 78 ETR, as elucidated by Hao et al., 48,49 Tan et al., 42 and He et al., 13 is also as an indicator to reflect the salinity of water columns. A strong association between ETR and both Pr/Ph and G/C 30 H ratios (Figure 10a,b) indicates that within the Subei Basin ETR closely relates to redox and/or saline conditions during or immediately following the deposition of hybrid shale. ...

Extended tricyclic terpanes as age discriminators between Triassic, Early Jurassic and Middle-Late Jurassic oils

... Organic-rich mudstones have been identified, from shallow boreholes, exploration wells and outcrop, to be present throughout the Jurassic successions in the SOHB and MB (Fig. 16) (Thrasher 1992;Morton 1993;Scotchman et al. 1998;Butterworth et al. 1999;Scotchman 2001). During the Jurassic these basins periodically became restricted, allowing for preservation of organic material within an anoxic environment (Morton 2004). ...

Jurassic non-marine source rocks and oils of the Porcupine Basin and other North Atlantic margin basins
  • Citing Chapter
  • January 1999

Geological Society London Petroleum Geology Conference series

... Throughout the literature, it is uncommon to find geochemistry studies aimed at the quantification of individual Smarkers by GC−MS. 38−41 The results are mainly expressed as the sum of classes 10,7,12,42,43 or in area percentage values 3,25,44 because of the commercial limitations and the high cost associated with acquiring the standards. However, GC−MS is not sufficiently selective for S-markers since coelutions with matrix compounds with the same m/z might interfere. ...

The ratios of dibenzothiophene to phenanthrene and pristan to phytan as indicators of depositional environment and lithology of petroleum source rocks
  • Citing Article
  • September 1995

Geochimica et Cosmochimica Acta

... C 26 -C 30 regular steranes are moderately dominated by C 27 homologs (C 27 /C 29 ααα 20R steranes mostly >1; Fig. 4a,b), while % C 26 + C 30 steranes compose <11% of total regular steranes (Fig. 4a). There are three different series of C 26 steranes in geological samples, namely 24-norcholestanes, 27norcholestanes and 21-norcholestanes (Holba et al., 1998a(Holba et al., , 1998bAboglila et al., 2011). Only trace amounts of a 24-norcholestane isomer (?) and 27-norcholestanes are present in the samples, the latter inferred to be dominated by the βαα isomer. ...

24-Norcholestanes as age-sensitive molecular fossils
  • Citing Article
  • September 1998

Geology

... Biomarker and carbon isotopic ratios in Kuparuk River field oils are almost identical with distal Shublik source-rock extracts (Figures 15, 17; Tables 3, 4). The average API gravity of 23°, sulfur content of 1.6%, and asphaltene concentration of 19% in Kuparuk River field oils are consistent with derivation from distal Shublik source rock that averages 2% sulfur content ( Figure 18; Tables 2, 4; Masterson et al., 2001;Holba et al., 2004). The simplest charge model for Kuparuk River field is vertical migration of Shublik-sourced oil from directly beneath the field (Masterson, 2001). ...

Effects and impact of early-stage anaerobic biodegradation on Kuparuk River Field, Alaska
  • Citing Article
  • November 2004

Geological Society London Special Publications

... In this study, C 30 tetracyclic polyprenoids (TPP) was detected in varying abundance in all thirty-four lacustrine source rock samples from the Wenchang Formation in the Zhu Ⅲ depression (Figs 4 and 5). C 30 TPP is a diagnostic indicator for freshwater or slightly brackish water algae input, especially for some green algae (Holba et al., 2000;Peters et al., 2005). In sedimentary layers where green algae blooming in the Sub-Andean Basin of South America, high contents of C 30 TPP have been observed, suggesting that green algae are likely the biological source of C 30 TPP Fig. 4. Mass spectra of C 30 tetracyclic polyprenoids (TPP) detected in the Wenchang semi-deep lacustrine source rocks in the Zhu Ⅲ depression. ...

Tetracyclic polyprenoids: Indicators of freshwater (lacustrine) algal input
  • Citing Article
  • March 2000

Geology

... The pentacyclic triterpanes 29-5 d and 30-5 c have been observed in a number of other oils sourced by terrestrial organic matter, often, but not always, accompanied by 18α(H)oleanane. These include: certain North Slope Alaska crudes (Hughes and Holba, 1988;Eickhoff et al., 2014); oils sourced in the Cretaceous Mowry shale of the Rocky Mountain Overthurst Belt (Seifert and Moldowan, 1981); Greater Ekofisk oils from the North Sea (Hughes et al., 1985); oils apparently sourced by the Upper Jurassic Dingo Claystone formation in the Barrow Sub-basin of Western Australia (Volkman et al., 1983); oils from freshwater lacustrine source rocks in the Shanganning and Chaidamu Basins in China (Philp et al. 1989); and, in particular, certain oils (e.g. Perch and Dolphin) from Late Cretaceous/Tertiary source rocks of the Gippsland Basin in Australia (Philp and Gilbert, 1986). ...

Relationship between crude oil quality and biomarker patterns
  • Citing Article
  • December 1988

Organic Geochemistry