Arnd Wilhelms

The controls on the composition of biodegraded oils in the deep subsurface—part 1: biodegradation rates in petroleum reservoirs

Abstract Biodegradation rates in oilfields have been assessed conservatively using whole oil-column minimum rate estimates, diffusion-controlled oil column compositional gradient modelling and mixed oil kinetic models. Biodegradation rate constants (first order) are around 10−6–10−7 yr−1 for hydrocarbons in the degradation zones these corresponding well with zero order field-wide minimum rate estimates of about 10−8 kg hydrocarbons/kg oil/year for the whole oil column. With biodegradation induction times of around 1–2 Ma to perturb an entire oil column for light oil reservoirs and 10–20 Ma for heavy oil reservoir degradation the results indicate that where we see continuous gradients in the oil columns, degradation must have been occurring episodically for many millions of years. To remove the n-alkanes from an oil (i.e. about 10% of an oil) around ca 15 Ma is needed for a heavy oil (ca 5 Ma for a light N. Sea oil). The timescales of oilfield degradation and filling are thus very similar and consequently the degree of biodegradation will be substantially controlled by oilfield charge history. Assessment of mixed degraded/non-degraded oil occurrence provides an independent confirmation that these rates are realistic and that timescales of degradation and field charging are similar. The maximum effective rate constant of degradation, ultimately controlled by the limiting effect of diffusion of alkanes to the oil water contact (OWC) (ca 10−4 yr−1 for a 130 m thick oil column first order rate constant) is well above the estimated rate constants indicating oil biodegradation rate is not limited by electron donor supply (i.e. hydrocarbons) but by supply of nutrients or oxidants. This suggests that diffusive transport of nutrients and electron acceptors in the aquifer to the site of biodegradation may be adequate to maintain the low rate biosphere.

Application of diamondoids to distinguish source rock facies

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

Biodegradation, gas destruction and methane generation in deep subsurface petroleum reservoirs: an overview

Plate tectonics forms and destroys sedimentary basins, accumulating organic carbon and converting it into mobile petroleum which may be concentrated in reservoir traps in which, if temperatures are below 80°C, it may become biologically degraded (biodegraded). The biodegradation process produces altered, denser, heavy oils and methane as a primary product. Much of the world’s oil is biodegraded under anaerobic conditions, with methane being a major by-product of the action of the deep biosphere on petroleum when sulphate is not present as an oxidant. A review of the literature relating to destruction of wet gas and the systematics of methane generation during subsurface oil biodegradation concludes that large biodegrading oil fields may be major source systems of dry gas.

Shaken but not always stirred. Impact of petroleum charge mixing on reservoir geochemistry

Abstract Essentially all petroleums are mixtures with different components charged from source rocks at different temperatures. This heterogeneous charge is the basis for compositional differences in reservoirs that are the basic elements of reservoir geochemical approaches. Because many classical petroleum geochemical tracers of source facies and maturity, such as the cyclic biomarker hydrocarbons, show several orders of magnitude variation in concentration in petroleum systems these compounds do not reliably track facies or maturity signals in mixed oil situations. Light hydrocarbon and aromatic hydrocarbon parameters are more reliable in this sense but, as mixtures are the norm, the concept of the maturity of oils needs revising. We suggest an alternative approach is needed which tracks the maturity/petroleum mass fraction relationships for reservoired oils (mass fraction maturity) and allows the bracketing of source kitchen maturity. We strongly advise against using compound ratios in reservoir geochemical studies without having knowledge of the compounds concentration range variations within the petroleum system being studied.

Xanthones-novel aromatic oxygen-containing compounds in crude oils

Abstract Xanthone and its alkylated homologues were determined to be present in 64 of 69 investigated oils from offshore Norway (Central Graben, Viking Graben, Haltenbanken). This is the first description of xanthones in crude oils. These compounds were identified by comparison with authentic standards by coinjection, based on mass spectra and relative retention times on two different GC columns. The elution order of the four methylxanthones was established as 1-4-2-3 by using a BPX-5 column. About 2/3 of the oils contain concentrations of xanthone lower than 5 μg/g oil, but some oils are clearly enriched in the parent compound. The highest amount of xanthone in the sample set was 38 μg/g oil. The relative abundance of xanthone, the sum of the methylxanthones and the sum of the C 2 -xanthones is mainly controlled by maturity. Partitioning processes may effect changes in the distribution of methylxanthones as observed for a biodegradation sequence from the Gullfaks field. Molecular dynamics calculations support the observation of a better preservation of the shielded isomers (1- and to a lesser extent 4-methylxanthone) in the oil phase compared to the non-shielded isomers (2- and 3-methylxanthone). The ratio of these two different isomer groups may be useful as an indicator of secondary migration distances, as demonstrated for an oil sequence from the Tampen Spur and Haltenbanken oils. However, biodegradation could also cause an increase of the shielded isomers relative to the non-shielded isomers due to sterical hindrance by the methyl groups restricting access to the oxygen functionalities. The origin of xanthones in crude oils and source rocks is not known but they could be generated as diagenetic products, formed by oxidation of xanthenes in the reservoir, or originate by geosynthesis from aromatic precursors.

A quantitative study of aromatic hydrocarbons in a natural maturity shale sequence—the 3-methylphenanthrene/retene ratio, a pragmatic maturity parameter

Abstract The aim of this study is to illustrate the use of multivariate statistical methods in identifying potential maturity parameters. A study of the quantitative aromatic hydrocarbon results from a natural maturity sequence through a thick (> 3000 m) organic lean shale followed by multivariate statistical treatment of the data was performed. The study series consists of low TOC (ca. 0.5 wt.%) and Rock-Eval S2 (generally below 1 mg HC/g rock) shales showing a continuous maturity increase from Tmax values of 410°C to ca. 490°C. This trend is mirrored by a concomitant decrease in the hydrogen index from values of around 150 mg HC/g TOC to ca. 40 mg HC/g TOC. Based on the production indices and GC MS analysis of the saturated hydrocarbon biomarkers no indications of migrated hydrocarbons or major facies variations were found in the studied samples. In essence this shale sequence represents a near perfect natural maturity series. The 3-methylphenanthrene/retene ratio shows an exponential increase with maturity and is proposed as a very sensitive maturity indicator extending into the late oil window. This maturity ratio has since been successfully applied to both source rock extract (kerogen type III, II/III and II) and oil studies.

Application and implication of horizontal well geochemistry

This paper describes the application of horizontal well geochemistry for the first time. Closely spaced samples, taken along a horizontal or deviated well path, allow the identification of reservoir compartments. Significant variations in geochemical parameters are related to the field filling and, if they persist over geological time and over tens of metres, should reflect barriers to diffusion and, by inference, possibly also to fluid flow. Two different approaches have been chosen: (a) closely spaced head space gas samples; (b) wet cuttings-based techniques. Case studies are presented documenting the detection of sealing faults between different reservoir compartments at the time of sampling. This novel approach has several advantages: (i) the need for costly pressure measurements is reduced; (ii) high sample density allows better spacial definition of barriers compared to both seismic and pressure measurements; (iii) detection of sub-seismic barriers; (iv) it allows detection of compartments even in cases where no pressure differences exist; (v) the technique works in wells drilled with oil-based mud systems. The strong variations in the geochemical signal over short distances has implications for the filling of reservoirs. The data suggest that reservoir filling is far more complex than previously envisaged.

correction: Biodegradation of oil in uplifted basins prevented by deep-burial sterilization

This corrects the article DOI: 35082535