Gary H. Isaksen

Multiple Controls on Petroleum Biodegradation and Impact on Oil Quality

Biodegradation of oils in nature is important in reservoirs cooler than approximately 80°C. Oils from shallower, cooler reservoirs tend to be progressively more biodegraded than those in deeper, hotter reservoirs. Increasing levels of biodegradation generally cause a decline in oil quality, diminishing the producibility and value of the oil as API gravity and distillate yields decrease; in addition, viscosity, sulfur, asphaltene, metals, vacuum residua, and total acid numbers increase. For a specific hydrocarbon system (similar source type and level of maturity), general trends exist for oil-quality parameters vs. present-day reservoir temperatures of <80°C. However, other controls on biodegradation may also have significant effects, making predrill prediction of oil quality difficult in some areas. It has long been observed that fresh, oxygenated waters in contact with reservoir oil can cause extensive aerobic biodegradation. More recently, it has been recognized that anaerobic sulfatereducing and fermenting bacteria also can degrade petroleum. Highly saline formation waters may inhibit bacterial degradation and effectively shield oils from oil-quality deterioration. The timing of hydrocarbon charge(s) and the post-charge temperature history of the reservoir can have major effects on oil quality. Reservoirs undergoing current charging with hydrocarbons may overwhelm the ability of bacteria to degrade the oil, resulting in better-than-anticipated oil quality. Fresh charge to reservoirs containing previously degraded oil will upgrade oil quality. Calibrated methods of oil-quality risking, based on a detailed evaluation of reservoir charge and temperature history and local controls on biodegradation, need to be developed on a play and prospect basis.

Control of hydrocarbon seepage intensity on level of biodegradation in sea bottom sediments

Offshore surface geochemical surveys, which target the surface expression of potential migration pathways for sampling such as fault scarps or diapiric features, have become a commonly-applied approach in the petroleum industry. Results of such surveys help to reduce risk on key exploration play elements and are used to evaluate prospects and to predict hydrocarbon phase and expected properties. Based on geochemical surveys conducted by ExxonMobil in many basins worldwide, there is an interrelation of the seep intensity (concentration) and level of biodegradation. Results from offshore west Africa, where many active macroseeps show moderate-to-severe biodegradation, and a frontier basin offshore United Kingdom (Rockall Trough), where active microseeps show no evidence of biodegradation, are compared. The specific biochemical controls on the difference in biodegradation-proneness are not known, although it appears that a certain threshold of oil concentration is needed to sustain an active bacterial community, or to exceed clay-adsorption capacities that may protect microseeps from biodegradation. It is notable that the 25-norhopane series, often considered an indication of severe biodegradation in reservoir oils, has not been recognized in even ultra-severely biodegraded seeps. This suggests that different biodegradation pathways may be followed in marine surface seeps versus those in subsurface hydrocarbon accumulations, a likely scenario in light of the fact that physiologically diverse bacterial communities are prevalent under different physiochemical conditions.

Central North Sea hydrocarbon systems: Generation, migration, entrapment, and thermal degradation of oil and gas

The high-pressure and high-temperature (HPHT) areas of the central North Sea constitute an important hydrocarbon province. This includes the deep, Mesozoic reservoirs in United Kingdom quadrants 22, 23, 29, and 30. This study was undertaken to better understand oil and gas compositional histories in HPHT hydrocarbon systems and to help identify new exploration opportunities. The Late Jurassic Kimmeridge Clay Formation has been the source for both oil and gas over the entire area, with additional gas charge from the humic coals of the Middle Jurassic Pentland Formation in the western graben areas. The southern Forties Montrose high, with its southward-plunging Mesozoic terraces, is host to numerous oil and gas fields with temperatures ranging from 90 to 180°C and formation pressures whose gradient to the surface exceeds 0.8 psi/ft (0.192 MPa/m). Several of these oil accumulations have undergone in-reservoir thermal cracking, resulting in a lighter, single-phase fluid, together with a pyrobitumen residue in the pore volumes. With several traps at or near their leak-off pressure, the likelihood of top seal failure and gas leakage is prevalent. Such top seal failure is intermittent and, in some instances, is associated with gas chimneys. The main causes of pressure increase in Mesozoic sediments are thought to be volume increases associated with gas generation from source rocks, clay dehydration, and thermal cracking of oil. Top seal failure because of pressure buildup by salt diapirism and the buoyancy of large hydrocarbon columns has resulted in a series of compositionally fractionated oils and gases. A new technique is presented, whereby the geochemical character of a shallow (Tertiary) oil reservoir that has undergone fractionation can help lower the risk of detecting the presence of hydrocarbon at depth in potential, deep (Mesozoic) reservoirs. Gary Isaksen coordinates geoscientists and technical programs in ExxonMobils Upstream Geoscience companies. Isaksen holds B.Sc. and M.Sc. degrees and a Ph.D. from the University of Bergen, Norway. Since he joined Exxon in 1985, he has worked on hydrocarbon system analyses in numerous sedimentary basins worlwide as well as the application of petroleum geochemistry to development and production.

Controls on the oil and gas potential of humic coals

Abstract Humic coals are highly heterogeneous, both with respect to maceral content and chemical composition. Although the oldest known humic coals, albeit gas-prone, are of Devonian age, the majority of humic coals capable of generating and expelling non-volatile oil are of Cretaceous and Tertiary age from Australia, New Zealand and southeast Asia. In contrast, the Middle-Jurassic humic coals of the Sleipner and Hugin Formations in the South Viking Graben of the North Sea are primarily gasprone, but have the capability to expel aliphatic-rich volatile oil. These coals have TOC contents up to 80% and hydrogen indices (HI) ranging from 200 to 400. They are vitrinite-rich, with some containing up to 45% inertinite. Liptinite concentrations are generally around 10–20%, chiefly as spores, pollen and abundant resinite. The main control on the oil potential of humic coals is the concentration of long-chain aliphatic hydrocarbons in the coal matrix. Although the aliphatics have a high H/C ratio, the inference on hydrogen content from the Rock-Eval pyrolysis HI value can be misleading. For HI values below 500 mg HC/g OC there is no relation between HI and the potential of the coals to generate non-volatile oil. Consequently, the HI is a poor indicator of the non-volatile oil potential of humic coals. A more robust indicator is the relative amount of C8+ aliphatic groups. Also, the “bulk” measure of liptinite content may also prove misleading when assessing the oil potential of coals. High resinite concentrations can lead to an overprediction of the non-volatile oil potential, as they contribute significantly to the HI value but will generate primarily volatile, aromatic-rich oils. Expulsion from the Sleipner and Hugin coals appears to have occurred in a gaseous phase with preferential release of short chain alkanes.

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.

Source rock quality and hydrocarbon migration pathways within the greater Utsira High area, Viking Graben, Norwegian North Sea

The greater Utsira High area is located within the southern part of quadrants 24 and 25 and the northern part of quadrants 15 and 16 in the Norwegian North Sea. In this part of the Viking Graben the main exploration play is the submarine fan sands of Paleocene and Eocene age. These sands (Balder, Heimdal, and Ty formations) pinch out to the east in blocks 25/8 (Jotun field) and 25/11 (Balder and Grane fields) and along the western margin of the Utsira High to form a combination of stratigraphic and structural traps. Marine sands of Middle and Late Jurassic age, typically present in rotated fault blocks, constitute another important play. Geochemical analyses show that the Upper Jurassic Draupne Formation has a good potential for oil generation along the entire western margin and northern nose of the Utsira High. Both upper and lower Draupne source intervals along the western graben margin, however, contain more terrigenous kerogen than in the eastern part of the graben. Such change in organic facies within the Draupne source interval naturally results in a higher proportion of gas generation and the possibility for generating a more waxy crude than typically encountered in the Viking Graben. Detection and characterization of oil and gas shows within the Tertiary section permit mapping of migration entry points from the Jurassic source rocks and help delineate secondary and tertiary migration pathways within the Paleocene-Eocene play.

Organic geochemistry and geohistory of the Triassic succession of Bjørnøya, Barents Sea

Abstract The Triassic outcrops of Bjornoya provide an important reference for regional characterization of potential hydrocarbon source rocks of this age in the southwestern Barents Sea. The organic matter in both the Urd and Skuld Formations is dominated by woody and herbaceous material, with elevated contents of algal/bacterial organic matter present in the Urd Formation. Minor amounts of oil is likely to have been generated from these shales. These rocks have been deeply buried and are at a present-day thermal maturity corresponding to vitrinite reflectance of 1.2%, i.e. full realization of the kerogens oil potential. One-dimensional basin modeling suggests that these Triassic rocks have been buried to near 5 km depth and expelled oil and gas during the Late Cretaceous to Early Tertiary. Bulk geochemical data show good agreement with visual observations of bitumen staining in thin sections. This staining has a biomarker distribution characterized by a homologous series of tricyclic terpanes. GC/MS/MS analyses showed this tricyclic series to extend from C 21 to C 46 .

Biomarker Analysis in Petroleum Exploration

The accumulation of economic volumes of petroleum (oil and/or gas) in the subsurface requires that several essential geological elements and processes be present in time and space.i Source rocks generate and expel petroleum when sufficient thermal energy is imparted to the sedimentary organic matter (kerogen) to break chemical bonds. This heating is induced usually by burial by overburden rock. Once expelled, petroleum migrates either along faults and/or highly permeable strata. Accumulations form only when high porosity strata (reservoir rocks) are charged with migrating petroleum and the petroleum is prevented from further migration. These petroleum traps are formed only when geologic movements result in subsurface topographies (structural and stratigraphie) that block migration and when the reservoir rocks are covered by low permeability strata (seal rocks). The mere presence of these geologic elements is insufficient to form petroleum reserves. Traps must be available at the time of oil expulsion and once charged, their integrity must be preserved until exploited. These elements and processes constitute the Petroleum System (Figure 1).

Modification of the petroleum system concept: Origins of alkanes and isoprenoids in crude oils: Discussion

In their recent paper, Collister et al. (2004) presented a statistical analysis of C10–C28 n-alkane and C16–C21 regular isoprenoid distributions of oils and rock extracts from the Timan-Pechora basin. They found that all unaltered to moderately biodegraded samples could be described as mixtures of six end-member compositions that were assigned to five unique biological sources and to one reservoir process (biodegradation). Because the end members appeared to yield no indications of thermal maturation, Collister et al. surmised that these hydrocarbons were generated not from the thermal cracking of kerogen, but from the liquefaction of biopolymers. If this theory is true, our current paradigms of oil generation and source rock potential need to be changed drastically because it suggests that a significant quantity of liquid hydrocarbons can be generated directly from unaltered biological precursors instead of the thermal cracking of kerogen. We respectfully disagree with the conclusions and hypotheses reached by Collister et al. We regard their interpretation of the statistical analysis of the hydrocarbon distribution data to be flawed and their hypotheses concerning the generation of C10+ n-alkanes and isoprenoids during diagenesis from biopolymers to be incorrect. The mathematical procedure (polytopic vector analysis) used by Collister et al. has the ability to extract end-member spectra from mixed systems. They found that six end members were needed to explain most of the variance in the data. This is not a unique solution, however, because the inclusion of additional end members will always improve the overall goodness of fit. Whether these six end-member fluids truly are representative of specific biological precursors, geologic processes, or are merely mathematical constructs cannot be resolved from the statistical analysis alone. Although Collister et al. claim that five of the end members bear the signature of specific biological sources and …

Interpretation of molecular geochemistry data by the application of artificial intelligence technology

This paper describes the application of fuzzy logic and Dempster-Shafer theory, elements of artificial intelligence technology, to the interpretation of molecular geochemistry data with respect to key exploration parameters, such as thermal maturity, organic facies (organic matter type and depositional environment of the source rock(s)), geological age, and the degree of biodegradation. The interpretation guidelines for the assessment of these exploration parameters are given as fuzzy rules, membership functions, and the predictive power of individual fuzzy rules. In this manner, any uncertainty or imprecision associated with molecular parameters is accounted for in the interpretation guidelines. The entire interpretation process is automated within the BIAS (Biomarker Interpretation Advisory System) computer program.