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Accurate determination of the concentrations of volatile and semi-volatile phenols in oils is required to reliably quantify the solute levels that are likely to be loaded into oilfield production waters following partition redistribution. We show, from a gas chromatography–mass spectrometry analysis of a North Sea crude oil, that significantly different concentration data for several C0–C3 alkylphenols may be obtained, depending upon whether the response of the fragmentation ion or the molecular ion is used, and whether the data are corrected for the relative response factor (RRF) of individual phenols. We also show how a comparison of concentration data for individual phenols obtained both with and without RRF correction can enable the recognition of co-elution. The accurate quantification of phenols in oils can be used to predict more effectively the requirement for production water-treatment facilities and can provide more reliable inventories of these toxic compounds discharged into the environment. T...

Oil sands are surface exposed in river valley outcrops in northeastern Alberta, where flat slabs (tablets) of weathered, bitumen-saturated sandstone can be retrieved from outcrop cliffs or from riverbeds. Although the average yearly surface temperature of this region is low (0.7°C), we found that the temperatures of the exposed surfaces of outcrop cliffs reached 55 to 60°C on sunny summer days, with daily maxima being 27 to 31°C. Analysis of the cooccurrence of taxa derived from pyrosequencing of 16S/18S rRNA genes indicated that an aerobic microbial network of fungi and hydrocarbon-, methane-, or acetate-oxidizing heterotrophic bacteria was present in all cliff tablets. Metagenomic analyses indicated an elevated presence of fungal cytochrome P450 monooxygenases in these samples. This network was distinct from the heterotrophic community found in riverbeds, which included fewer fungi. A subset of cliff tablets had a network of anaerobic and/or thermophilic taxa, including methanogens, Firmicutes , and Thermotogae , in the center. Long-term aerobic incubation of outcrop samples at 55°C gave a thermophilic microbial community. Analysis of residual bitumen with a Fourier transform ion cyclotron resonance mass spectrometer indicated that aerobic degradation proceeded at 55°C but not at 4°C. Little anaerobic degradation was observed. These results indicate that bitumen degradation on outcrop surfaces is a largely aerobic process with a minor anaerobic contribution and is catalyzed by a consortium of bacteria and fungi. Bitumen degradation is stimulated by periodic high temperatures on outcrop cliffs, which cause significant decreases in bitumen viscosity.

Quantitative data from petroleum systems in China (Liaohe basin) and Canada (Athabasca tar sands) support the theory that 25-norhopanes are produced during biodegradation of petroleum in the subsurface. Within a single oil column, both case histories showed increasing severity of degradation, indicated by destruction of hopanes and production of 25-norhopanes downward to the oil–water contact. In the Athabasca samples between the [Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Prentice Hall, Englewood Cliffs, New Jersey, p. 363] scale of biodegradation levels 5–9, concentrations of C28 20S triaromatic steroids and other biodegradation-resistant compounds increased by 35%, reflecting a concentration effect as a consequence of removal of more degradable compounds. Over the same interval, the concentrations of C28 17α 25-norhopane and C29 17α 25-norhopane increased by an order of magnitude, thus requiring that the balance be met by their net production during degradation. A detailed molecular investigation of the Athabasca bitumen revealed that C30 17α hopane degrades faster than C29 17α hopane, whilst the rate of formation of both C29 17α 25-norhopane and C28 17α 25-norhopane are similar, complicating a straightforward interpretation of demethylation of hopanes to form 25-norhopanes. Hopane degradation in the Athabasca tar sand may also occur without the production of 25-norhopanes. The results show that even within a single petroleum accumulation, a number of mechanisms control changes in the abundance and composition of hopanes and 25-norhopanes.

Nitrogen compounds are ubiquitous in fossil fuels and yet our understanding of their origins in the geosphere is limited. In this study, high hydrogen pressure pyrolysis was performed on sample material representing potential contributors to sedimentary organic matter (algae, bacteria and archaea) and sediments representing early diagenetic accumulations from Lake Pollen (Norway) and Priest Pot (UK). Previous workers demonstrated the structurally conservative nature of high hydrogen pressure pyrolysis in that the technique maximizes the yields of covalently bound hydrocarbon biomarkers from organic matter without adversely affecting their stereochemistry (Love et al., 1995). Release of covalently bound biomarkers in high yields from kerogen via catalytic hydropyrolysis. In this study, the types and distributions of organic nitrogen compounds in the hydropyrolysates were characterised under similar conditions to such experiments where biomarker hydrocarbons undergo minimal rearrangement. Compounds identified by gas chromatography–mass spectrometry included alkyl-substituted indoles, carbazoles, benzocarbazoles, quinolines and benzoquinolines. Indoles are present in all hydropyrolysates, suggesting a common origin. A potential source of indoles is represented by tryptophan which was shown to degrade through a series of alkylated intermediates to indole. Carbazole, quinoline and benzoquinoline were also found in the hydropyrolysates of algae, bacteria and archaea. The presence of these petroleum-related nitrogen compounds in hydropyrolysates generated from biomass suggests an early origin for petroleum nitrogen compounds. A potential source of naturally occurring nitrogen compounds such as that in the alkaloids has yet to be realised. Benzocarbazoles were absent from hydropyrolysates of algae, bacteria and archeae, but present in those from recent sediments, suggesting their presence may be related to processes occurring during early diagenesis at, or immediately below, the sediment–water interface. In sediments from Lake Pollen, changes in the benzocarbazole ratio [a]/([a ]+[ c]) ratio coincides with the interval described as a transition from fjord to lake environment, suggesting that benzocarbazoles are sensitive to changes in depositional environment and may have potential to act as a marker for environmental conditions.

An instrument has been constructed for monitoring the partition coefficients of phenol and cresols between crude oil and water under sub-surface conditions. The device has the capacity for introducing methane gas into crude oil, thereby allowing measurements under live oil (solution gas-containing) conditions. The partition coefficients of phenol and cresols have been measured in crude oil: water substrates under “live” oil and “dead” oil (without solution gas) conditions over a temperature range 25–150 °C. Over the range investigated it is seen that the introduction of gas (crude oil saturated at 100 bar with methane) into the system resulted in an approximate doubling of partition coefficients compared to the equivalent dead oil: brine systems. The partition coefficient data obtained using the device may be employed in a number of petroleum exploration and production activities such as the determination of residual oil saturation of a water-flooded petroleum reservoir. Partition coefficient measurements may help in predicting toxic organic solute loadings in oilfield discharge waters.

Solvent-extracted Kimmeridge Clay Formation kerogen was heated to 315°C for 72 h in the presence of excess water (H2O) or heavy water (D2O). Hydrocarbons generated from the kerogen during the D2O experiments contained variable amounts of deuterium atoms [0 to as high as 12 deuterium atoms per molecule in the compounds we examined (mean of

Three rapid methods for the isolation and determination of alkylphenols from crude oils are described. Two of the methods are based on a novel approach involving the preconcentration of crude oil p...

Solid phase microextraction (SPME) techniques coupled with gas chromatography—isotope ratio mass spectrometry (GCIRMS)were used to determine the stable carbon (δ13C) isotopic compositions of aromatic hydrocarbons (BTEX: benzene, toluene, ethylbenzene and xylenes) and phenol in a small suite of co-produced oils and waters from a North Sea oilfield. The δ13C patterns and the compound profiles observed are consistent with the theory that the concentrations and distributions of BTEX and alkylphenols in oilfield waters can simply be explained by partition equilibrium between oil and water. The large difference in δ13C signatures for phenol compared with benzene and toluene (7–8 %o vs. PDB) in both the oil and water phases strongly suggests that, at least for BTEX and phenols, reversible chemical reactions controlled by master geochemical variables (such as fO2) do not appear to be important at the temperatures of most oilfields.

Summary The subsurface microbiology of an Athabasca oil sands reservoir in western Canada containing severely biodegraded oil was investigated by combining 16S rRNA gene- and polar lipid-based analyses of reservoir formation water with geochemical analyses of the crude oil and formation water. Biomass was filtered from formation water, DNA was extracted using two different methods, and 16S rRNA gene fragments were amplified with several different primer pairs prior to cloning and sequencing or community fingerprinting by denaturing gradient gel electrophoresis (DGGE). Similar results were obtained irrespective of the DNA extraction method or primers used. Archaeal libraries were dominated by Methanomicrobiales (410 of 414 total sequences formed a dominant phylotype affiliated with a Methanoregula sp.), consistent with the proposed dominant role of CO2-reducing methanogens in crude oil biodegradation. In two bacterial 16S rRNA clone libraries generated with different primer pairs, > 99% and 100% of the sequences were affiliated with Epsilonproteobacteria (n = 382 and 72 total clones respectively). This massive dominance of Epsilonproteobacteria sequences was again obtained in a third library (99% of sequences; n = 96 clones) using a third universal bacterial primer pair (inosine-341f and 1492r). Sequencing of bands from DGGE profiles and intact polar lipid analyses were in accordance with the bacterial clone library results. Epsilonproteobacterial OTUs were affiliated with Sulfuricurvum, Arcobacter and Sulfurospirillum spp. detected in other oil field habitats. The dominant organism revealed by the bacterial libraries (87% of all sequences) is a close relative of Sulfuricurvum kujiense – an organism capable of oxidizing reduced sulfur compounds in crude oil. Geochemical analysis of organic extracts from bitumen at different reservoir depths down to the oil water transition zone of these oil sands indicated active biodegradation of dibenzothiophenes, and stable sulfur isotope ratios for elemental sulfur and sulfate in formation waters were indicative of anaerobic oxidation of sulfur compounds. Microbial desulfurization of crude oil may be an important metabolism for Epsilonproteobacteria indigenous to oil reservoirs with elevated sulfur content and may explain their prevalence in formation waters from highly biodegraded petroleum systems.

Methanogenic degradation of polycyclic aromatic hydrocarbons (PAHs) has long been considered impossible, but evidence in contaminated near surface environments and biodegrading petroleum reservoirs suggests that this is not necessarily the case. To evaluate the thermodynamic constraints on methanogenic PAH degradation we have estimated the Gibbs free energy values for naphthalene, phenanthrene, anthracene, pyrene and chrysene in the aqueous phase, and used these values to evaluate several possible routes whereby PAHs may be converted to methane. Under standard conditions (25 °C, solutes at 1 M concentrations, and gases at 1 atm), methanogenic degradation of these PAHs yields between 209 and 331 kJ mol(-1). Per mole of methane produced this is 27-35 kJ mol(-1), indicating that PAH-based methanogenesis is exergonic. We evaluated the energetics of three potential PAH degradation routes: oxidation to H(2)/CO(2), complete conversion to acetate, or incomplete oxidation to H(2) plus acetate. Depending on the in situ conditions the energetically most favourable pathway for the PAH-degrading organisms is oxidation to H(2)/CO(2) or conversion into acetate. These are not necessarily the pathways that prevail in the environment. This may be because the kinetic theory of optimal length of metabolic pathways suggests that PAH degraders may have evolved towards incomplete oxidation to acetate plus H(2) as the optimal pathway.

The use of a polar aminocyano-bonded silica HPLC column (PAC) for the class separation of nitrogen compounds in crude oils is described. Elution of deasphalted oils with solvents of a composition gradient yielded well-defined pyrrole and pyridine nitrogen fractions which were characterized by gas chromatography in conjunction with flame ionization detection (FID), nitrogen phosphorous detection (NPD), and mass spectrometry (MS). Comparison is made with two open column chromatography methods previously reported in the literature

Darcy s law shows that the primary control on gravity-driven bitumen speed within oil sands reservoirs is oil mobility, the quotient of oil effective permeability and viscosity. The controlling factors on oil effective permeability are absolute permeability and oil relative permeability which in turn depends on oil saturation. The controlling factors on oil viscosity are temperature and composition which in turn is set by the amount of solution gas, reservoir geology, charge rate, biodegradation and diffusion of light end components, availability of water for biodegradation, and temperature history. The absolute permeability, rock type (relative permeability), fluid saturations, and compositions are all heterogeneous in oil sands reservoirs with differing variability in vertical and lateral directions. Current thermal recovery processes such as SAGD use straight wells that are convenient for drilling and planning but are not optimized with respect to oil mobility distribution. This research examines what the optimum SAGD wellpair trajectory would be in a fully heterogeneous reservoir. The research not only reveals that the optimal well trajectory may not be straight but that injectors and producers need not be parallel to each other.

SUMMARY Snorre is a leaky commercial oilfield that supports ~300 m oil column in the Tampen Spur area of the North Sea. The field contains undersaturated oil with no gas cap. Pervasive evidence of oil and gas leakage into the cap-rock is well documented (Leith and Fallick 1997, Bond 2000). Oil migration may alter the wetting state of the cap-rock. Today, the reservoir sands are ~12 MPa overpressure. Log derived pore pressure for the Shetland Group mudstone cap-rock indicates a normal compaction state. This pressure disequilibrium between the reservoir and the cap-rock suggest that reservoir overpressure may have postdated compaction and geologically recent. Phase behaviour models of the petroleum fluids indicate that a gas cap should exist in the trap if the reservoir was normally pressured. The observed oil column is in equilibrium with the average column height potential of the cap-rock estimated from pore size distribution data. This may imply that the cap-rock is at maximum supportable column height today. In addition, subsequent petroleum charge has leaked into the cap-rock possibly at a rate similar to the reservoir charge rate. These data suggest that the Snorre field capped by oil-wet cap-rock is a case example of a dynamic seal.

Methanogenesis was investigated in formation waters from a North Sea oil rimmed gas accumulation containing biodegraded oil, which has not been subject to seawater injection. Activity and growth of hydrogenotrophic methanogens was measured but acetoclastic methanogenesis was not detected. Hydrogenotrophic methanogens showed activity between 40 and 80 degrees C with a temperature optimum (ca. 70 degrees C) consistent with in situ reservoir temperatures. They were also active over a broad salinity range, up to and consistent with the high salinity of the waters (90 g l(-1)). These findings suggest the methanogens are indigenous to the reservoir. The conversion of H(2) and CO(2) to CH(4) in methanogenic enrichments was enhanced by the addition of inorganic nutrients and was correlated with cell growth. Addition of yeast extract also stimulated methanogenesis. Archaeal 16S rRNA gene sequences recovered from enrichment cultures were closely related to Methanothermobacter spp. which have been identified in other high-temperature petroleum reservoirs. It has recently been suggested that methanogenic oil degradation may be a major factor in the development of the world's heavy oils and represent a significant and ongoing process in conventional deposits. Although an oil-degrading methanogenic consortium was not enriched from these samples the presence and activity of communities of fermentative bacteria and methanogenic archaea was demonstrated. Stimulation of methanogenesis by addition of nutrients suggests that in situ methanogenic biodegradation of oil could be harnessed to enhance recovery of stranded energy assets from such petroleum systems.

Methanogenic degradation of crude oil hydrocarbons is an important process in subsurface petroleum reservoirs and anoxic environments contaminated with petroleum. There are several possible routes whereby hydrocarbons may be converted to methane: (i) complete oxidation of alkanes to H2 and CO2, linked to methanogenesis from CO2 reduction; (ii) oxidation of alkanes to acetate and H2, linked to acetoclastic methanogenesis and CO2 reduction; (iii) oxidation of alkanes to acetate and H2, linked to syntrophic acetate oxidation and methanogenesis from CO2 reduction; (iv) oxidation of alkanes to acetate alone, linked to acetoclastic methanogenesis and (v) oxidation of alkanes to acetate alone, linked to syntrophic acetate oxidation and methanogenesis from CO2 reduction. We have developed the concept of a ‘window of opportunity’ to evaluate the range of conditions under which each route is thermodynamically feasible. On this basis the largest window of opportunity is presented by the oxidation of alkanes to acetate alone, linked to acetoclastic methanogenesis. This contradicts field-based evidence that indicates that in petroleum rich environments acetoclastic methanogenesis is inhibited and that methanogenic CO2 reduction is the predominant methanogenic process. Our analysis demonstrates that under those biological constraints oxidation of alkanes to acetate and H2, linked to syntrophic acetate oxidation and methanogenesis from CO2 reduction offers a greater window of opportunity than complete oxidation of alkanes to H2 and CO2 linked to methanogenic CO2 reduction, and hence is the process most likely to occur.

Abstract A defining characteristic of heavy and super heavy oilfields is the large spatial variation in fluid properties, such as oil viscosity, commonly seen within the reservoirs. Traditional heavy oil and tar sand exploration and production strategies rely significantly on the characterization of key reservoir heterogeneities and assessment of fluid saturations. While it is important to understand how these properties vary, the spatial distribution of fluid properties can often dominate production behaviour but surprisingly, are usually ignored! Heavy oil and tar sands are formed by microbial degradation of conventional crude oils over geological timescales. Constraints such as oil charge mixing, reservoir-temperature dependant biodegradation rate and supply of water and nutrients to the organismsultimately dictate the final distribution of API gravity and viscosity found in heavy oil fields. Large-scale lateral and smallscale vertical variations in fluid properties due to interaction of biodegradation and charge mixing are common, with up to orders of magnitude variation in viscosity over the thickness of a reservoir. These variations are often predictable and can be integrated into reservoir simulation models in a manner similar to specifying geological heterogeneity. In this work, we describe and illustrate quantitative geological controls on fluid property variations and show how petroleum geochemistry can be used to rapidly produce high resolution fluid property images of tar sand and heavy oil reservoirs. The impact of viscosity variations in a heavy oil reservoir on production depends on recovery method. Numerical thermal reservoir simulations reveal that oil viscosity heterogeneity (i.e. a vertical viscosity profile in the reservoir) lowers the oil production volumes from steam assisted gravity drainage (SAGD) in geologically realistic reservoirs compared to results from equivalent models run with uniform average viscosity profiles. Similar results are found for the cyclic steam stimulation (CSS) process. In cases with viscosity profiles, the relatively high viscosity at the base of the reservoir slows the growth of the steam chambers relative to that in uniform viscosity reservoirs. We also describe how the chemical fluid heterogeneities can be used to predict oil viscosity from well cuttings and/or core or to de-mix produced oils into zonal contributions from different parts of the production well. Introduction There are over six trillion barrels of heavy oil and tar reserves on Earth, but average recoveries remain tantalizingly low (5 to 15% for cold heavy oil production and 40 to 85% for steam assisted gravity drainage operations)(1). We consider that a defining characteristic of heavy and super heavy oilfields is the large spatial variation in fluid properties, such as oil viscosity, commonly seen within the reservoirs. Traditional heavy oil and tar sand exploration and production strategies rely significantly on characterization of key reservoir heterogeneities and distributions of porosity and permeability and assessments of fluid saturations. While these reservoir characteristics are important controlling factors, variations in fluid properties can often dominate production behaviour, but are usually ignored. According to Darcy's law, reservoir permeability and fluid viscosity contribute equally to controlling the net flowrate of oil during production under a given fluid potential gradient.

Fluid inclusions are tiny pockets of fluid trapped within minerals (Goldstein and Reynolds, 1994). Fluid inclusions hosted within diagenetic phases of reservoir rocks and carrier beds contain samples of palaeopetroleum and palaeowater and can yield valuable and otherwise unobtainable information about the evolution of petroleum composition through time, the timing of petroleum emplacement, reservoir filling history and palaeo-compartmentalisation. It may also be possible to determine the temperature and pressure at which the included petroleum was trapped, with implications for the assessment of pressure regimes in the geological past.

Nature, 411, 1034–1037 (2001). Figure 2 inadvertently contained plotting errors for oils from the Tampen Spur and Viking Graben data sets and the plotting of pristane/(n-heptadecane + pristane) for the Barents Sea data set rather than pristane/n-heptadecane as described. The corrected figure is shown below with all the offshore data now correctly plotted as depth from sediment surface.

In order to study the generation of oxygen-rich species which may act as CO 2 precursors, the interaction of sedimentary organic matter and water during hydrous pyrolysis has been investigated using 18 O labelled water. Model compound experiments were conducted with a series of compounds (3,4-dimethylphenol, dodecanoic acid and xanthene) in order to assess their levels of simple homogeneous exchange of oxygen with hot water. While dodecanoic acid underwent extensive oxygen exchange (98%), dimethylphenol underwent restricted oxygen exchange (13%) and xanthene showed no exchange. A comparison of the dimethylphenol model compound experiments in H 2 18 O with dimethylphols generated by Kimmeridge Clay kerogen, under identical conditions, showed marked differences in levels of 18 O incorporation (approx. 13% for the model compound and 40% for the kerogen-derived products) suggesting neogenic phenol formation during hydrous pyrolysis. The implications of this inferred water oxygen addition to sedimentary organic matter during kerogen degradation will undoubtedly affect mass balance calculations of the generation of oxygen-rich species from sedimentary organic matter and thus have a potential impact on mass balance assessments of the generation of CO 2 and its precursors in petroleum basins. The results also have major implications for oxygen mobility between organic matter and water in hydrothermal systems and possibly for lower temperature reactions in petroleum systems.

13 C n.m.r. spectra of kerogen concentrates isolated from several different subbituminous to high-volatile bituminous coal macerals have been obtained by a combined cross polarization/magic-angle spinning technique. The samples comprise three vitrinites, two sporinites, two alginites and one fusinite, all of Upper Paleozoic age. It is shown that this technique can be used to differentiate the maceral types by providing characteristic spectral fingerprints. Aromaticities decrease in the order fusinite vitrinite sporinite alginite, as expected with the rank range studied. Furthermore, fine spectral details provide general information on the nature and distribution of discrete structural moieties and their variations with both type and rank.

The chemical characterization of kerogen (typing) is a routine part of petroleum exploration programmes1. Traditionally, kerogen has been characterized on the basis of microscopy2 and bulk chemical methods3, procedures derived from the coal characterization literature1,4. These methods do not today, however, provide adequate resolution of the complex mixture of kerogen components encountered in source rocks from petroleum-bearing sedimentary basins5. Here we report an improved classification approach for kerogens at all maturity levels. The method is based on a quantitative pyrolysis–gas chromatography approach using a polymeric internal standard, polymethylstyrene, to directly determine the absolute concentrations of specific kerogen pyrolysis products. In particular, cross-plots of normal hydrocarbon, aromatic hydrocarbon and total hydrocarbon yields of kerogen pyrolysis are used to recognize eight separate nodes of kerogen composition

A series of six fossil resins and four modern resins have been analysed using microscope-based spectral fluorescence methods, in addition to a preliminary study of the chemical composition of these samples using infrared spectroscopy and pyrolysis-gas chromatography. This study illustrates problems encountered during the measurement of spectral fluorescence of resins and resinite kerogens using conventional microscopy methods. Most notable, alteration of fluorescence significantly influences spectral measurements. Further, fossilized resins within rocks are complex mixtures of resinite and bitumen. Pre-extraction of resinites prior to petrographic analysis resulted in somewhat more uniform spectral fluorescence results. Spectral fluorescence of recent resins used in this study could be used to distinguish angiosperm from gymnosperm derived resinite kerogens. Distinction of plant class source of resinite kerogens, however, is more difficult using this method and is considered genarally unreliable.

Many detailed chemical parameters have been proposed as indicators of thermal maturity in oil and gas source rocks. Certain classical maturity parameters involving carbon preference indices and compound class ratios, such as hydrocarbons/extract yield and extract yield/total organic carbon, are less commonly used today, having been complemented with detailed molecular parameters. Among these parameters, the molecular distributions of metalloporphyrins, cyclic hydrocarbons, low-molecular-weight hydrocarbons, and gases are most commonly used. Recent instrumental advances have allowed the routine measurement of molecular ratios in geochemical organic matter, stimulating the development and use of biological markers, such as steranes, hopanes, and metallated tetrapyrroles, as thermal maturity indicators. Increased chromatographic resolution of source rock hydrocarbons has also led to the use of low-molecular-weight hydrocarbons, methylphenanthrenes, and aromatized steranes as maturity indicators. In this paper, we discuss these developments, emphasizing the applications and the pitfalls of using molecular maturity indicators.

The majority of the world's petroleum resources are contained in heavy oil and oil sand reservoirs. Average recoveries from heavy oil and oil sand reservoirs are typically low ranging from 5 to 15 percent for cold heavy oil production and from 30 to 85 percent for steam-based in situ processes. There are two reasons for this: first, geological heterogeneity in the form of variable porosity and permeability properties and secondly, fluid heterogeneities in the form of variable saturations, fluid compositions and thus viscosity. Geological heterogeneities refer to spatial variations of porosity, permeability, relative-permeability curves, shale and mud layers, etc. Fluid heterogeneities refer to spatial variations of the fluid composition and properties such as viscosity and density. Given that the permeability often varies by less than an order of magnitude whereas the oil viscosity varies by up to two orders of magnitude in a bitumen reservoir, the controlling variable on recovery of these resources is often fluid compositional variations. Due to the large viscosity contrast between oil and water at native reservoir conditions water is often the most mobile phase within a bitumen reservoir. This research identifies preconditioning techniques that can be used to alter reservoir or fluid (oil or water) properties prior to thermal recovery reducing adverse reservoir factors and improving recovery, environmental impact and process economics. We describe here a simulation study of one application related to modifying the variation of oil viscosity in the reservoir prior to steam injection. The methods make use of mobile water within the reservoir, to distribute viscosity-reducing agents before steam injection, and represent another means of geotailoring recovery processes to the features of the reservoir. The main benefit is that recovery process performance, both in terms of oil production rate and thermal efficiency, is improved.

Biodegradation of crude oil in subsurface petroleum reservoirs is an important alteration process affecting most of the world's oil deposits. The process preferentially removes light components from conventional oil to form heavy oil and oil sand, which are more difficult to produce and are more costly to refine. Although reservoir temperature is a key control on biodegradation, large variations in oil properties have been documented in accumulations from similar depths within a play area. Data from the Liaohe Basin, NE China and other basins in China and elsewhere, indicate that biodegradation is most active in a narrow zone at or near the base of the oil column in contact with the water leg. The availability of nutrients from mineral dissolution within the water leg is also thought to have a significant impact upon the degree of biodegradation. Thus, the level of biodegradation increases with water leg thickness. Charge history and in-reservoir mixing of continuously charged oil with residual biodegraded oil also have a significant impact on oil physical properties. The conceptual biodegradation model proposed combines geochemical and geological factors to provide a coherent approach to estimate the impact of degradation on petroleum and to help reliably predict biodegradation risk at the prospect level. Our geochemical approach can be used to locate sweet spots (areas of less degraded oil), optimize the placement of new wells and completion intervals and help with production allocation from long production wells.