Summary In this presentation we will review a workflow for the evaluation of high-quality fluid samples, incorporating geochemistry measurements and integration with other fluids data for a comprehensive fluid characterization. Case studies will be discussed to illustrate the utility of geochemical data acquisition during reservoir appraisal and development to support Field Development Planning.

Summary A geochemical assessment of reservoir continuity is presented for an oilfield in the U.S. Gulf of Mexico. The field produces from several zones within the lower Miocene section. The distribution and extent of these units are complex introducing, together with the existence of potentially sealing faults, large uncertainties with regards to reservoir continuity. Crude oils from the different producing zones collected from four wells across the field were investigated using bulk fraction characterization, stable carbon isotope analyses, whole oil high-resolution gas chromatography and gas chromatography–mass spectrometry of the saturate and aromatic fractions. The results of these analyses offer insights for a better reservoir characterization at a field scale, supporting the presence of separate units both vertically within the investigated wells and laterally within the same unit. This contribution summarizes the main findings of this work.

Frequent drilling challenges for high-inclination well paths in the overburden Laffan and Nahr-Umr shales involve stuck pipe incidents and caving, leading to sidetracking in extreme cases. Advanced geomechanics studies including both an anisotropic wellbore stability model and shale stability analysis were conducted on acquired cores to better understand these problematic intervals for improving drilling efficiency and reducing costs by mitigating wellbore instability. The study analyzed the preferential directions of deformation and failure (i.e., anisotropic) in the shales and their time-dependent behavior in reacting with drilling fluid. Shale samples were preserved to avoid changes in mechanical properties due to the high clay content and low permeability. Two overburden shale intervals were analyzed to determine strength and elastic anisotropy. Dynamic anisotropic elastic properties were obtained via ultrasonic wave propagation. Strength anisotropy was evaluated using the plane of weakness model that assumes a heterogeneous media composed of a matrix rock and plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). The test results showed a drop of compressive strength from 50% to 70% for samples with inclination from 38 to 62 degrees, which increases the chance of formation collapse of the laminated shales at such wellbore deviation. The anisotropic analysis proved that the stress field is higher when anisotropic properties are considered, which leads to higher propensity for failure. Shale stability tests demonstrated that most of the instabilities identified in the Laffan and Nahr-Umr formations were mechanical in nature. The optimal mud weight is strongly dependent on the well trajectory to account for the plane of weakness and strength anisotropy. Combing data from laboratory tests with advanced sonic logs enabled a more robust evaluation of the formation anisotropy at the well scale, which improved both stress predictions and mud-weight window predictions along the well trajectory. This anisotropic well-centric model helped for determining more appropriate mud weights and salinities for upcoming directional wells. By obtaining core samples in the shale formations, the operator was able to test and characterize the anisotropic behavior and also analyzed the time-dependent behavior. These results were combined with advanced sonic logs to better understand and mitigate wellbore instability induced from the plane of weakness.

The radiometric dating of geological events was a crucial achievement leading to the establishment of the geological time scale. The dating of the timing of petroleum charge into, and the determination of petroleum residence times in a geological trap would also be significant, as it would remove ubiquitous speculation concerning the history of reservoir charging in any basin setting. A thorough review of prior strategies to estimate the residence time of petroleum fluids in subsurface reservoirs revealed that few if any methods currently used provide useful estimates of the residence age of fluids. This paper is focused on the age dating of petroleum residence time in reservoirs based on the compositional alterations of reservoired fluids caused by natural radiation. This preliminary paper sets out the geochemical landscape and constraints on radiation-based age dating proxies. We report results on the propagation of radiation through reservoir rocks, which indicate that gamma radiolysis is a primary route to crude oil alteration. Gamma ray radiolysis experiments on crude oils at both natural and elevated radiation doses have been completed and the changing crude oil composition observed using LC, GC-MS and NMR. Reservoir fluids are naturally immersed in radioactive subsurface media that cause systematic alteration to crude oil composition with time, but the chemical changes are small in most natural settings. The degree of radiolysis of individual petroleum compounds was found to depend on chemical class, molecular size, initial compound concentration and the nature of the oil matrix, indicating that a proxy system for dating of petroleum charge times and oil residence times in petroleum traps will likely depend on case-specific calibrations. We define the apparent gamma ray radiolysis susceptibility (kGy−1) of different compounds. Large alkanes, such as high molecular weight normal alkanes (>C22) or hopanes, have high radiolysis susceptibility and show the most rapid decrease in component concentration with increasing radiation dose. In contrast, condensed aromatic hydrocarbons and diamondoid hydrocarbons are more resistant to decomposition through radiolysis. While assessing the decrease in concentration of a compound through radiolysis is a practical objective, it is more difficult to assess the production of new, unique radiolysis products given the great diversity and low concentrations of individual compounds produced. However, monitoring the production of specific functional groups during radiolysis of crude oils, using NMR spectroscopy, was found to be a feasible proxy analytical target. Analysis of newly generated carbon-carbon double bonds in bulk crude oils may represent an optimal approach for development as a radiolysis proxy. We propose a route to assessing in-reservoir crude oil radiation dose.

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Summary Fundamentals of geochemical fingerprinting in the oil industry have been described by several authors and while detailed workflows vary between users the overall approach of combining gas chromatography with software supported interpretation remains common. The primary applications of geochemical fingerprinting include production back-allocation, support of wider reservoir continuity studies or time-lapse geochemistry. Our methodology is based on analysis of whole oil (black oil, gas condensate, heavy oil) or organic extracts from rock/sediment for the determination of ratios of heights of neighbouring chromatographic peaks. This novel approach using geochemical fingerprinting in combination with a new data processing technology is presented through a selection of diverse case studies and demonstrates that it can be applied with confidence to even the most challenging production back-allocation and reservoir continuity cases. Numerous tests and calibrations with various oil companies have been carried out to improve the methodology and increase the overall accuracy, robustness and global applicability.

Steam-assisted thermal recovery methods are commonly applied for the production of heavy (10-200 API) and extra heavy ( 10,000 cP) oil. Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are two of the procedures most frequently used, with operating temperatures generally up to 250 °C and 330 °C, respectively. Under these conditions, chemical transformations involving thermolysis and aquathermolysis impact the oil properties and also lead to the generation of acid gases, such as hydrogen sulfide (H2S) and carbon dioxide (CO2). Since H2S is a highly poisonous and corrosive gas, understanding and predicting the generation of H2S during thermal recovery operations of heavy and extra heavy oil is instrumental to provide sustainable recovery of the giant fossil fuel reserves of Alberta. Here we review laboratory and field data regarding the production of H2S from heavy and extra heavy oil under thermal recovery conditions; and present some results of the production of sulfur containing compounds and transformations of sulfur compound classes in the polar fraction of oil pyrolyzates analyzed by FT-ICR-MS.

Summary In this work, we introduce the practical application based on geochemical proxies to monitor in situ upgrading operations of bitumen. The neoformation of novel compounds such as alkylanthracenes and alkylbenzothiophenes in simulated thermal recovery experiments and their observed formation in oils from current thermal recovery pilots show that some molecular changes are suitable to monitor steaming chamber progression and temperature from analysis of produced oils, as well as monitoring more dramatic changes under high temperature in situ upgrading conditions. Furthermore, the combination of geochemical baseline studies with these thermal proxies may additionally allow production allocation to track the vertical progression of steam chamber growth during thermal recovery of heavy oil and oil sands. A case study from the Alberta basin is shown to demonstrate the approach based on geochemical proxies in combination with geochemistry baseline studies to monitor thermal recovery operations of oil sands.

Although the effects of biodegradation on the composition and physical properties of crude oil have been well studied, effects of in-reservoir petroleum biodegradation on molecular and isotopic compositions of crude oils are not yet clearly understood. The Alberta Basin, in western Canada, is one of the world's largest petroleum accumulations and constitutes an ideal example of a natural suite of sequentially biodegraded oils. The basin hosts moderately to severely biodegraded petroleum, regionally distributed and in single, more or less continuous, oil columns. In this study, a series of oil samples from the Alberta heavy oil and oil sands provinces, with varying degrees of biodegradation, were analyzed to assess the impact of progressive biodegradation on the molecular and C, H, N, and S isotopic compositions of oils. The results of the molecular characterization of the hydrocarbon fraction of the studied oils show that the oils have suffered biodegradation levels from 2 to 10(+) (toward the Alberta-Saskatchewan border) on the Peters and Moldowan scale of biodegradation (abbreviated PM 2 to PM 10) and from tens to hundreds on the Manco scale. Within single reservoirs, increasing biodegradation was observed from top to bottom of the oil columns at all sites studied. The whole oil stable isotopic compositions of the samples varied in the ranges delta C-13 = -31.2% to -29.0%, delta H-2 = -147% to -133%, delta N-15 = 0.3-4.7% and delta S-34 = 0.4-6.4%. The maximum differences between delta values of samples (Delta) within single oil columns were Delta C-13 = 1.4%, Delta H-2 = 7%, Delta N-15 = 1.7% and Delta S-34 = 1.0%. Regional variations in the isotopic compositions of oil samples from different wells (averaged values from top to bottom) were 1.2% for delta C-13, 12% for delta H-2, 4.1% for delta N-15 and 5.5% for delta S-34 and hence generally significantly larger variations were seen than variations observed within single oil columns, especially for N and S. It appears that even severe levels of biodegradation do not cause observable systematic variations in carbon, nitrogen or sulfur isotope composition of whole oils. This indicates that sulfur and nitrogen isotopic compositions may be used in very degraded oils as indicators for oil charge from different source rock facies. (C) 2013 Elsevier Ltd. All rights reserved.

Summary The molecular evidence based upon the biodegradation resistant compounds and stable isotopes (N and S) suggests the Grosmont bitumen is predominantly charged from the Exshaw Formation derived oils. The uniform profiles exhibited by the molecular parameters (and concentration data) based upon the biodegradation resistant compounds suggests the fluids in reservoir units UGM3 and UGM2 are derived from a genetically related source charge feedstock that filled the reservoir. The open network created by the palaeokarstic weathering system may have provided the migration conduits along the Devonian / Cretaceous unconformity with similar fluids filling downwards either side of the shale barriers into the reservoir units of the Upper Grosmont Formation. Subsequently, within their respective compartments, isolated locally by the shale barriers, the oils underwent biodegradation according to local conditions that are unique to units UGM3 and UGM2. Acknowledgements The authors wish to thank Michele Asgar-Deen and Mike Ranger for geological insights and also Fuqing Song for diligent preparation of the geochemical data.

Summary A detailed knowledge of the distribution of fluids in reservoirs containing biodegraded extra-heavy oil, such as the oil sands deposits of Alberta, is essential for the development of efficient recovery strategies. This work presents results from two case studies that demonstrate the application of petroleum geochemistry tools for reservoir characterization, including assessing lateral and vertical distribution of oil quality, compartmentalization studies and the estimation of fluid physical properties based on oil molecular composition.

The relative contributions of the various putative source rocks to the Alberta oil sands have been debated for decades. This regional study of produced oils of north-central Alberta characterizes Lower Cretaceous tar sands oil quality and identifies charge mixing using bulk oil sulfur content, S and N values, as well as biodegradation ultra-resistant source finger-printing using FTICRMS of high molecular weight fractions. Molecular concentrations, metals and S contents and isotopic signatures clearly show that the westernmost Peace River oil sands bitumen is mostly derived from Gordondale Fm. source rocks whereas eastern Peace River bitumens closely resemble biodegraded Exshaw oil as do the Athabasca and Cold Lake deposits. Analysis of this wide spectrum of components clearly differentiates mixed source oils.

Oil-source rock or oil-oil correlation is one of the most challenging steps in the analysis of complex petroleum systems. It is generally based on molecular fingerprints (biomarkers) and whole oil or oil fraction carbon isotopic composition. When biomarkers are unaltered by post expulsion processes, they can constitute a powerful tool for correlation but effects on biomarker concentrations in mixed oil charge scenarios and even destruction of biomarkers at severe biodegradation levels, may drastically affect the viability of the approach. Biodegradation is by far the most important process responsible for the variations in the composition and oil properties across the Alberta heavy oils and oil sands. In this study, continuous petroleum columns from the Alberta oil sands containing progressively biodegraded oil (from level 5PM to 8PM) are studied using molecular and isotopic analyses, with the purpose of evaluating the effect of biodegradation in the C, N, S and H isotopic compositions of bulk oil and fractions of different polarities to assess the viability of these proxies as oil correlation parameters. The results show that even though the total hydrocarbon fraction is highly depleted by biodegradation to different degrees, this process does not cause observable systematic carbon isotope changes in either the whole bitumen or in fractions of different polarities. δN values in bulk bitumen also do not show any trend with biodegradation, as may have been expected from the observed destruction of carbazoles studied in the polar fractions of the oils, which change both concentration and distribution with biodegradation levels. Organic sulphur compounds in the aromatic hydrocarbon fraction are also progressively removed down the oil columns, yet δS values of bulk oil remain essentially constant. Locally however, lower δS values suggest secondary incorporation of 32S-enriched sulfur. Finally, it is observed that S and N isotopic compositions of bitumen and heavy oils from the main studied pools in the basin differ consistently displaying what appears to be a regional trend. The lack of significant changes of the bulk isotopic composition of related oils with very different degrees of biodegradation suggests that the observed isotopic variations are source charge related. We conclude that S and N isotopic compositions can be used in biodegraded oils as stable source proxy signatures