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Mullins O.C.,Gushor Inc. | Andrews A.B.,Gushor Inc. | Pomerantz A.E.,Gushor Inc. | Dong C.,Gushor Inc. | And 6 more authors.
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2011

Understanding asphaltene gradients and dynamics of fluids in reservoirs had been greatly hindered by the lack of knowledge of asphaltene nanoscience. Gravitational segregation effects on oil composition, so important in reservoir fluids, are unresolvable without knowledge of (asphaltene) particle size in crude oils. Recently, the "modified Yen model" also known as the Yen-Mullins model, has been proposed describing the dominant forms of asphaltenes in crude oils: molecules, nanoaggregates and clusters. This asphaltene nanoscience approach enables development of the first predictive equation of state for asphaltene compositional gradients in reservoirs, the Flory-Huggins-Zuo (FHZ) EoS. This new asphaltene EoS is readily exploited with "downhole fluid analysis" (DFA) on wireline formation testers thereby elucidating important fluid and reservoir complexities. Field studies confirm the applicability of this scientific formalism and DFA technology for evaluating reservoir compartmentalization and especially connectivity issues providing orders of magnitude improvement over tradional static pressure surveys. Moreover, the mechanism of tar mat formation, a long standing puzzle, is largely resolved by our new asphaltene nanoscience model as shown in field studies. In addition, oil columns possessing large disequilibrium gradients of asphaltenes are shown to be amenable to the new FHZ EoS in a straightforward manner. We also examine recent developments in asphaltene science. For example, important interfacial properties of asphaltenes have been resolved recently providing a simple framework to address surface science. At long last, the solid asphaltenes (as with hydrocarbon gases and liquids) are treated with a proper chemical construct and theoretical formalism. New asphaltene science coupled with new DFA technology will yield increasingly powerful benefits in the future. Copyright 2011, Society of Petroleum Engineers.

Fustic M.,University of Calgary | Fustic M.,Nexen Inc. | Fustic M.,Statoil | Bennett B.,Gushor Inc. | And 2 more authors.
Marine and Petroleum Geology | Year: 2012

The Lower Cretaceous McMurray Formation is the primary host of the Athabasca oil sands deposit, one of the largest petroleum deposits in the world. Regional studies show that within the McMurray Formation, bitumen-saturated reservoir sands are encountered within the western, central and northeastern sections of the northeastern Athabasca deposit, while the southeastern part of the deposit has never been charged by petroleum, and that, the lateral contact between petroleum- and water-saturated reservoir sands is in some instances characterized by rapid changes in bitumen saturation, even between closely spaced wells. In the literature, a number of petroleum entrapment schemes have been proposed to explain how the bitumen accumulated through different trapping mechanisms, however controversy remains. This paper investigates the concept of inter-compartmental petroleum "fill and spill" charge and entrapment in a setting where compartments are clearly defined by mud-filled channel deposits. Classical molecular maturity parameters based on gas chromatography - mass spectrometric analysis of hydrocarbon compounds that are extracted from the bitumen show notable changes in composition between the geologically defined reservoir compartments. Relatively higher maturity sourced oil resides in the western compartment while maturity decreases to the eastern most compartment suggesting that the eastern compartment was filled by petroleum of lower maturity which has been displaced via fill and spill as petroleum migration from an increasing maturity source enters compartments to the west. Oil saturation and hydrocarbon geochemistry results also suggest the oil charge was very limited locally and individual compartments located towards the eastern edge of the Athabasca may not have seen the multiple charges evident in the oil sands to the west. The concept of inter-compartmental fill-and-spill provides new insights regarding the often overlooked intra-formational geological controls on reservoir charge in the McMurray Formation. The concept explains that apparently sharp lateral oil-water contacts are in fact due to mud-filled channel deposits which at least locally serve as lateral seals. This concept should be applicable to other meandering fluvial belt reservoirs worldwide and suggests a necessity to revise existing stratigraphic trap schemes by including the point bar stratigraphic play type of trap as one of the trapping mechanisms. Additionally, geochemical gradients can be used as a tool for defining the presence and extent of individual compartments as well as the level of fluid communication as an aid to well placements. © 2012 Elsevier Ltd.

Fustic M.,Nexen Inc. | Fustic M.,Statoil | Bennett B.,Gushor Inc. | Adams J.,University of Calgary | And 5 more authors.
Bulletin of Canadian Petroleum Geology | Year: 2011

To optimize SAGD well-pair placement and improve thermal recovery operations, geochemical bitumen composition logs are used to identify barriers and baffles to fluid flow, which may compartmentalize McMurray Formation reservoirs in the Athabasca Oil Sands. SAGD steam chamber growth and cumulative steam oil ratios are sensitive to both vertical permeability and bitumen viscosity variations, which are commonly encountered in the oil sands reservoirs. In the McMurray Formation, tidally influenced meandering channel deposits are commonly vertically stacked, forming reservoir columns up to 80 m thick. In many instances, inclined heterolithic strata (IHS), consisting of interbedded sand and silt deposited on point bars, comprise barriers to vertical steam chamber growth at multiple horizons of a reservoir. Thus, the identification, characterization, and delineation of IHS intervals is a critical step for evaluating the reservoir development potential, and designing an optimal reservoir development strategy. While siltstone beds are routinely identified in cores and geophysical logs, thin siltstone beds that can act as a barrier to fluid flow are not discernible in seismic reflection data and have proven difficult to correlate between adjacent delineation wells. In this study, geochemical bitumen analysis is used to determine the integrity and continuity of siltstone beds within IHS in order to assess their potential impact on SAGD steam chamber growth. First, high-resolution molecular composition profiles are obtained from gas chromatography - mass spectrometry analyses of bitumen extracted from cores. The continuity of biodegradation-susceptible aromatic hydrocarbon concentrations measured through vertical profiles of a reservoir were used to determine if siltstone-prone intervals observed in log and core data acted as barriers or baffles to fluid flow over geological time. Integration of the bitumen molecular composition data with geological cross-sections fosters predictions of the lateral extent of the identified barriers. Furthermore, inferences about reservoir charging and in-reservoir fluid mixing histories are also made. Geochemical log data indicate that thickness of a heterogeneous low permeability interval is not necessarily the critical attribute of a barrier to fluid flow. Integration of both sedimentological information and bitumen geochemical data is useful for the identification of barriers and baffles to fluid flow in oil sand reservoirs. The method can be applied prior to positioning of SAGD well-pairs and thus could represent an important step for development planning of heterogeneous reservoirs. © 2011 by the Canadian Society of Petroleum Geologists.

Larter S.,Gushor Inc. | Larter S.,University of Calgary | Huang H.,University of Calgary | Adams J.,University of Calgary | And 4 more authors.
Organic Geochemistry | Year: 2012

Existing scales widely used to describe the extent of biodegradation of petroleum have insufficient resolution to usefully characterize many heavy oil and bitumen occurrences, including the volumetrically dominant heavily and severely biodegraded oil accumulations in the foreland basins of western Canada and Venezuela. In these and other deposits, existing classifications or descriptions of the biodegradation level may vary only slightly, yet oil may vary in viscosity by orders of magnitude. The " Manco" biodegradation scale proposed here is based on integrating the extent of degradation of various members of compound classes not included in previous biodegradation scales. They include alkyl aromatic and alkyl thiophenic compounds that show variable extent of alteration in samples degraded to uniform levels on standard scales, but which may show variation in local degradation systematics related to biodegradation mechanisms and extent of oil mixing. The Manco scale uses a combination of a consideration of the extent of alteration within a compound class together with a consideration of biodegradation across a range of compound classes. It can be reliably used as a basis for interpreting geochemical changes in heavily biodegraded oil suites and can also be used to differentiate biodegraded oil samples likely to be amenable to cold production from those requiring production strategies such as steam or chemical flooding. As with other biodegradation scales, the scale may also provide evidence for the influx of later, higher quality oil into a reservoir fluid that had been previously biodegraded. © 2012 Elsevier Ltd.

Larter S.,University of Calgary | Huang H.,University of Calgary | Bennett B.,Gushor Inc. | Snowdon L.,Gushor Inc.
Society of Petroleum Engineers - SPE Canadian Unconventional Resources Conference 2012, CURC 2012 | Year: 2012

While light tight oil reservoirs such as found in Bakken and Cardium style plays can be stimulated by fracturing, significant oil production from true shale reservoirs dominated by clay size fraction sediments may not be feasible, even when reservoirs are fractured, if current oil storage models in source rocks are valid. We look at the source rock knowledgebase and the gaps in our understanding relevant to assessing oil production from shale sections. Despite over four decades of study of petroleum source rocks by geochemists, our mechanistic understanding of them remains at best qualitative and inadequate for quantitative reservoir characterisation purposes. Past studies emphasised molecular chemistry details and gross mass balance studies at large scale, but only few detailed mechanistic studies of actual physical process and transport function during generation and primary migration are available. Empiricism and generality dominate current concepts and most R&D peaked in the 1980s when Oil Company R&D spending was at its highest, but declined after that. Today there are many areas of uncertainty, but reassuringly, research is starting again and crucially, abundant core samples, which were largely absent before, are now also available. There has also been a revolution in the understanding of shale sedimentology which forces us to reexamine many of our earlier precepts about source rock formation and suggests that in the absence of naturally fractured silica or carbonate intervals within source rocks, such as found in the Monterey Fm., very small scale collateral silt and sand horizons may be locally important small scale reservoirs in typical shales. The bulk of the oil storage in source rocks however is in kerogen, where dominantly diffusive rather than Darcy flow processes operate and where fracturing may have little impact on productivity. We look at the technical barriers, both theoretical and analytical, to understanding true shale dominated reservoir oil production potential. Copyright 2012, Society of Petroleum Engineers.

Lei Q.,Gushor Inc. | Lei Q.,University of Calgary | Wang J.,Gushor Inc. | Wang J.,University of Calgary | And 2 more authors.
Society of Petroleum Engineers - International Oil and Gas Conference and Exhibition in China 2010, IOGCEC | Year: 2010

Today, heavy oil and oil sands are starting to play a more important role. To manage and develop these resources, especially for thermal recovery processes, numerical modeling is often used to design the operating and well placement strategies. Relative permeability curves are one of the most important parameters for modelling these systems. This is especially important in systems where the saturation of each phase changes over a wide range as is the case in steam-based recovery processes such as Steam-Assisted Gravity Drainage (SAGD). Initially, before SAGD, the pore space of the oil sands reservoir is mainly occupied by bitumen with oil saturation typically between 80 and 90%. After steam is injected into the reservoir, the oil is heated and mobilized and drains under gravity and is replaced by first steam condensate and then, as the chamber propagates further into the reservoir, steam and solution gas. This means that the reservoir undergoes a series of large changes in phase saturations as the recovery process evolves in the reservoir. Thus, the interactions of the phases and their flow characteristics, that is, the relative permeability curves, are an essential component of the physics of SAGD. However, for modelling SAGD, due to limited relative permeability curve data, it is often adopted from analogs or previously history-matched curves. Given the heterogeneity of oil sands reservoirs, careless adoption of relative permeability curves will lead to serious risk of unexpected performance. The objective of this study is to investigate the impact of the endpoints of the oil-water relative permeability curves on SAGD performance by using numerical reservoir simulation. The results reveal that SAGD performance is sensitive to the values of the endpoints of the oil-water relative permeability curves. Given the range of variability of the results, it is recommended that relative permeability uncertainty analysis is always done during the simulation assessment of a targeted oil sands resource. Also, it is recommended that curves are obtained from multiple core samples of the target reservoir to reduce uncertainty and to assess the degree of heterogeneity of the endpoints. Copyright 2010, Society of Petroleum Engineers.

Jiang C.,Gushor Inc. | Bennett B.,Gushor Inc. | Larter S.R.,Gushor Inc. | Adams J.J.,Gushor Inc. | Snowdon L.R.,Gushor Inc.
Journal of Canadian Petroleum Technology | Year: 2010

This paper describes and discusses laboratory experiments showing that reliable determinations of viscosity usually cannot be made on high viscosity samples of heavy oil or tar sand bitumen that have been solvent extracted from core or cuttings samples with toluene or otherwise contaminated or diluted with this solvent. The toluene solvent cannot be quantitatively removed without damaging the bitumen sample because of the concomitant evaporation of volatile materials that act as natural solvents in the bitumen. Only small amounts of natural or contaminant solvent are sufficient to effectively control the sample viscosity. Viscosity values determined on residual bitumen after solvent removal may be either lower or higher than the nominally correct value depending on whether excessive residual toluene solvent remains in the sample or excessive volatile material has been removed from the sample during the evaporation. On the other hand, the impact of solvent on the density (i.e., API gravity) of a sample is linear and there are several advantages to using solvent plus bitumen mixtures to determine density for high viscosity samples.

Gushor Inc. | Date: 2012-08-15

Techniques for sampling a subsurface reservoir include lowering a downhole logging tool comprising one or more samplers, a cleaner system, and a sample probe bit into a borehole until at least one sampler is positioned correctly in a subterranean reservoir; advancing the cleaner system into the reservoir cleaning mud filtrate and contaminated reservoir material away into a mud column; advancing the sample probe bit into the reservoir; and solvent is injected into the reservoir from the solvent reservoir.

The invention relates to an apparatus and method to obtain a bitumen or heavy oil sample from an oil reservoir sample, such as a core sample, to enable measurement of physical properties such as viscosity, API gravity, or chemical properties such as sulphur content of the obtained bitumen or heavy oil sample. The analyses performed on the samples obtained in accordance with the invention are effective in assisting oil field operators in making timely drilling and production decisions at the oil reservoir or for routine laboratory extraction of oils and bitumens. The invention also permits the collection of samples from simulated thermal recovery operations and also allows the collection of bitumens and oils for online analysis of live oil physical properties.

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