Athabasca Tar Sand Research Articles

Isolation of Aromatics from Athabasca Tar-Sand with the Use of Ranaspumin Proteins and Tangential Flow Filtration System

Isolation of Aromatics from Athabasca Tar-Sand with the Use of Ranaspumin Proteins and Tangential Flow Filtration System

Isolation of Aromatics from Athabasca Tar-Sand with the Use of Ranaspumin Proteins and Tangential Flow Filtration System

Isolation of Aromatics from Athabasca Tar-Sand with the Use of Ranaspumin Proteins and Tangential Flow Filtration System

Effect of operating pressure on the performance of THAI-CAPRI in situ combustion and in situ catalytic process for simultaneous thermal and catalytic upgrading of heavy oils and bitumen

According to the analysis of the 2020 estimates of the International Energy Agency (2020), the world will require up to 770 billion barrels of oil from now to 2040. However, based on the British Petroleum (BP) statistical review of world energy 2020, the world-wide total reserve of the conventional light oil is only 520.2 billion barrels as at the end of 2019. That implies that the remaining 249.8 billion barrels of oil urgently needed to ensure a smooth transition to a decarbonised global energy and economic systems is provided must come from unconventional oils (i.e. heavy oils and bitumen) reserves. But heavy oils and bitumen are very difficult to produce and the current commercial production technologies have poor efficiency and release large quantities of greenhouse gases. Therefore, these resources should ideally be upgraded and produced using technologies that have greener credentials. This is where the energy-efficient, environmentally friendly, and self-sustaining THAI-CAPRI coupled in situ combustion and in situ catalytic upgrading process comes in. However, the novel THAI-CAPRI process is trialled only once at field and it has not gained wide recognition due to poor understanding of the optimal design parameters and procedures. Hence, this work reports the first ever results of investigations of the effect of operating pressure on the performance of the THAI-CAPRI process. Two experimental scale numerical models of the process based on Athabasca tar sand properties were run at pressures of 8000 kPa and 500 kPa respectively using CMG STARS. This study has shown that the higher the operating pressure, the larger the API gravity and the higher the cumulative volume of high-quality oil is produced (i.e. a 2300 cm3 of ≈24 oAPI oil produced at 8000 kPa versus the 2050 cm3 of ≈17.5 oAPI oil produced at 500 kPa). The study has further shown that despite presence of annular catalyst layer, the THAI-CAPRI process operates stably. However, it is found that a more stable and safer operation of the process can only be achieved at optimal pressure that should lie between 500 kPa and 8000 kPa, especially since at the lower pressure, should the process time be extended, it will not take long before oxygen breakthrough takes place. The simulations have shown in details that at higher pressures, the catalyst bed is easily and rapidly coked and thus the catalyst life will be very short especially during actual field reservoir operations. Since the oil drainage flux into the HP well at field-scale is different from that at laboratory-scale, and at field-scale, the combustion front does not propagate inside the HP well, it will be practically very challenging to regenerate or replace the coke-deactivated annular catalyst layer in actual reservoir operations. Therefore, it is concluded that during field operation designs, an optimum pressure must be selected such that a balance is obtained between the combustion front stability and the degree of catalytic upgrading, and between the catalyst life and its effectiveness.

Molecular Size and Size Distribution of Petroleum Residue

The size of residue molecules is crucial to catalyst design and petroleum use. An Athabasca tar sand vacuum residue was fractionated into 13 narrow fractions and an end-cut by supercritical fluid e...

Exothermicity Characteristics of Wolf Lake Heavy Oil, Athabasca Tar Sand and Clair Medium Heavy Oil

Abstract High pressure accelerating rate calorimetry (ARC) tests have been performed on three different crude oils at their respective reservoir pressures. The experiments on medium heavy Clair oil and heavy Wolf Lake oil used clean silica sand, incorporating 3% kaolinite, to represent the reservoir matrix, whereas Athabasca Tar Sand was used in its preserved, virgin state. The Clair oil and Wolf Lake oil tests involved high initial water saturations in the reservoir, representative of a post-waterflooded or a post-steam injection state. A second test on Athabasca Tar Sand used a lower oil (bitumen) saturation, but without an adjustment of the original brine saturation. Although the medium Clair oil exhibited high exothermicity throughout the temperature range, the temperature detected for the onset of low temperature oxidation (LTO) was much higher than that for Athabasca Tar Sand. The calculated activation energies also indicate that Athabasca Tar Sand is very reactive in the LTO region. Furthermore, the overall continuity exhibited by the measured exotherms indicates that all three oils are potentially good candidates for in situ combustion as an oil recovery method. Introduction The most important factor governing the selection of any improved oil recovery (IOR) process is, ultimately, the availability of a suitable fluid to inject into the reservoir. For an increasing number of reservoir situations, air injection is gaining increasing attention for both heavy and light oil recovery. The most recent heavy oil projects are in the Cambay Basin, India(1), using conventional ISC, and the first field pilot at Christina Lake, using the advanced THAI (Toe-to-Heel Air Injection) process(2). There have also been significant developments in high pressure air injection into light oil reservoirs, as evidenced by economically viable air injection projects in the Williston Basin, and project feasibility studies for Barrancas, Argentina(3) and Cantun, Mexico(4). There are many economic and technical benefits derived from air injection – excellent displacement efficiency, mobilization of extra oil ahead of the combustion zone, reservoir pressurization, oil swelling from produced CO2, flue gas stripping, injection gas substitution and, for high pressure hot reservoirs, additional enhancing factors such as spontaneous ignition and near miscibility effects. The accelerating rate calorimeter (ARC) was first advocated as a technique for screening reservoir oil candidates for air injection by Yannimaras et al.(5) The technique was developed as a method for studying the reaction kinetics by following the reactions adiabatically, especially at high pressure. Moreover, the method can provide insights to explain the occurrence of low temperature oxidation (LTO) and high temperature oxidation (HTO). To date, investigations using the ARC technique have focused mainly on light oil applications. In this paper, results are presented for heavy crude oils and also Athabasca Tar Sand, to see if the measures of oxidation reactivity obtained are relevant when considering the application of air injection processes using conventional ISC or THAI. Experimental ARC Equipment The main apparatus consists of a pressure shell, inside which the calorimeter ‘bomb’, or test cell, is placed (Figure 1). The cylindrical test cell is surrounded by a top guard heater, as well as side and bottom guard heaters.

In Situ Upgrading of Athabasca Tar Sand Bitumen Using Thai

Downhole upgrading of virgin Athabasca Tar Sand bitumen has been investigated in a series of 3-D experiments using THAI—‘Toe-to-Heel Air Injection’. The THAI process uses combinations of vertical injection wells and horizontal producer wells, arranged in a direct, or staggered line drive. 3-D experiments were performed to investigate THAI as a primary recovery method, and also as a secondary recovery method. The latter followed a prior THSF—‘Toe-to-Heel Steam Flood’. Oil recovery efficiencies for THAI, using primary and secondary operation modes, were respectively, 80% and 67% OOIP. The THSF recovery was much lower, only 23% OOIP, owing to the low steam temperature in the sandpack. Downhole upgrading of the Athabasca Tar Sand bitumen was very significant, with the API gravity of the produced oil increasing by an average of 8° API, compared to the original bitumen. The produced oil viscosity was also dramatically reduced, to less than 200 mPa s, with a minimum value of 50 mPa s. SARA analysis was used to assess the quality of the produced oil. The original bitumen contained only 15.5% saturates, but the amount in the produced oil was increased to 72%. The high oil recovery factor and partial in situ upgrading achieved by the THAI process could therefore have important economic implications for the future of heavy oil and bitumen production. The first field pilot of the THAI process is scheduled to take place at Christina Lake, Alberta, Canada, in 2006.

25-Norhopanes: Formation during biodegradation of petroleum in the subsurface

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 C 28 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 C 28 17α 25-norhopane and C 29 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 C 30 17α hopane degrades faster than C 29 17α hopane, whilst the rate of formation of both C 29 17α 25-norhopane and C 28 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.

Upgrading Athabasca Tar Sand Using Toe-to-Heel Air Injection

Abstract The unique operation of the THAI (Toe-to-Heel Air Injection) process, enables very high oil recovery and substantial in situ upgrading. Both thermal upgrading (non-catalytic) and also catalytic upgrading, in which a catalyst is emplaced along the horizontal producer well, were investigated. 3D physical model experiments were conducted on virgin Athabasca tar sand bitumen to investigate dry and wet combustion performance. These results were compared against those from a steamflood test, which was subsequently followed by air injection. Excellent ignition, very stable combustion propagation and thermal upgrading of nearly 10 ° API were achieved using Athabasca tar sand. Additional upgrading was achieved using an in situ catalyst. THAI has the extra advantage that some hydrogen is generated in situ, providing further significant upgrading via hydroconversion. There are also substantial environmental benefits because of the large reductions in sulphur and heavy metals in the produced oil. Furthermore, oil is produced without "displacement delay," immediately ahead of the combustion front. The oil recovery using THAI was greater than 75% OOIP. Introduction The world's conventional crude oil production is expected to reach its peak in the second decade of this century and enter a permanent decline phase(1). The composition of the oil barrel is getting heavier, and diluent blending "stop-gaps," assisted by very limited coker upgrading capacity will, eventually, be insufficient to cope with the increasing demand for light oil. Historically, heavy oil trades at a substantial discount to that of premium light crude oil. Therefore, it has lower economic value and also market potential, unless new technology is developed to upgrade it to lighter oil, in an economic manner. The Athabasca Tar Sand deposit of northeastern Alberta, Canada, is one of the largest reserves of bitumen in the world. These are estimated to be 212.9 ??109 m3 (1,339 ?109 bbl)(2). Although about 10% of the bitumen reserves are mineable, the rest of the Athabasca Tar Sands have to be exploited by in situ recovery technology. A number of in situ oil recovery methods, such as steam assisted gravity drainage (SAGD)(3) and in situ combustion (ISC)(4, 5), have been extensively studied, both in the laboratory and in field tests. In situ combustion (ISC) is a thermal EOR method, in which a small fraction of the oil (or coke) in the oil layer is burned in order to mobilize the unburned fraction. Due to the strong exothermic oxidation reactions between hydrocarbon (or coke) and oxygen, the temperature of the oil-bearing matrix in the combustion zone is 500 to 700 °C, which is much higher than in steam flood processes (150 to 250 °C). High temperatures are very favourable for tar sands and heavy oil reservoirs, because not only is the oil viscosity reduced by several orders of magnitude, but the heavy residue is also thermally cracked to lighter compounds.

Mapping of the McMurray Formation for SAGD

Abstract The McMurray formation in north-eastern Alberta contains a substantial fraction of the world's currently identified oil resources. The areal extent of the deposit is in the order of 300 km north-south and 100 km east-west. It has been estimated(1) that over 40 billion barrels (6.35 × 109 m3) are potentially recoverable with steam assisted gravity drainage (SAGD) from dual well pairs. This is in addition to the substantial reserves already accessible from surface mining operations in locations with minimal overburden. The success of potential SAGD projects is greatly dependent upon the proper identification of regions with adequate pay, limited shale barriers, and controllable bottom water and/or top gas/water. The fluvial/estuarine nature of the formation greatly limits the predictability of trends when viewed in a local context. However, when regional behaviour is coupled with geostatistical techniques, an improved understanding of these critical parameters is possible. This paper applies a computerized log analysis technique to obtain the porosity, oil saturation and permeability from the McMurray formation utilizing digitized logs. Additional analysis is performed to obtain regions of effective net pay and other performance indices. This information is then presented through the use of regional mapping with a geostatistical approach. Introduction The Athabasca tar sand deposit is located in the northeast corner of Alberta, Canada. The major accumulation within this deposit is contained within the McMurray formation of early Cretaceous age. By various estimates, the OOIP of the McMurray formation exceeds 120 e09 m3 (750 billion bbls)(2). The commercial extraction projects currently operational in this region are based on surface mining techniques. However, only a small fraction of the resource is suitable for mining operations(2). The vast majority of the region is covered by overburden deposits that exceed any currently economic surface mining technique. These more deeply buried regions may prove to be amenable to the steam assisted gravity drainage (SAGD) process or some variant(3). Several pilot/demonstration plants have shown promising results with this technology, originally developed by the Alberta Oil Sands Technology Research Authority (AOSTRA) for the underground test facility (UTF)(4). The intention of this paper is to provide an overview of some of the computerized mapping techniques that are applicable to determining the extent of the possible SAGD resource in the McMurray formation. Reservoir Requirements for SAGD The SAGD process consists of a pair of parallel horizontal wells with a 3 8 m vertical separation. During normal operation, steam is injected into the upper/injection well, while oil and steam condensate are produced from the lower/production well. The energy transferred from the condensing steam heats the formation, greatly lowering the viscosity of the oil. This enables the oil to flow via gravity to the underlying production well. The process appears to be quite robust from a theoretical perspective. The two principal governing factors, conduction heat transfer into the cold reservoir and gravity flow of fluid to the production well, are only moderately influenced by many reservoir characteristics. A number of previous studies have explored the theoretical range of applicability of the SAGD process to generic heavy oil reservoirs(5, 6).

Coliquefaction of Coal and Waste Plastics under Milder Hydrogen Pressures.

Under direct coal liquefaction conditions, coprocessing of-100 mesh Tanitoharum coal with plastics, using 1:1 Athabasca tar sand bitumen/tetralin mixture as the solvent, and red mud + S as the catalyst, was carried out in a 500-m1 autoclave. At 430°C with plastics/ (coal + plastics) weight ratio of 1/4 under 4MPa initial pressure of a simulated coke oven gas (H2/N2 : 1/1 volume ratio), a synergistic effect between the coal and the mixed plastics of PP, PS and PE (1/1/1 weight ratio) was observed and oil yield was higher by 8% than that calculated from results of liquefaction for each of the coal and the mixed plastics.

96/03747 Magnesium oxide catalyzed steam gasification of naphthalene

5 different histidine-requiring strains of Salmonella typhimurium were used to test the mutagenic activity of 7 different fractions of Athabasca tar-sand. None of the 7 fractions (bitumen, maltenes, asphaltenes, saturated, monoaromatic, diaromatic and polyaromatic hydrocarbons), showed positive mutagenic response in any of the Salmonella typhimurium strains. We have tested a wide range of concentrations. The results obtained so far are consistent with the lack of mutagenic activity of all investigated fractions in the absence and in the presence of metabolic activation.Assuming that there might be an association between the absence of mutagenic activity and the complexity of the tar-sand fractions, we investigated the effect of the polyaromatic hydrocaron fraction on the mutagenicity of the carcinogenic agent 2-aminoanthracene. The data obtained indicate clearly that the polyaromatic hydrocarbon fraction suppresses the mutagenic activity of 2-aminoanthracene.

96/03736 Coal gasifier with injection bed for prevention of slag jam

5 different histidine-requiring strains of Salmonella typhimurium were used to test the mutagenic activity of 7 different fractions of Athabasca tar-sand. None of the 7 fractions (bitumen, maltenes, asphaltenes, saturated, monoaromatic, diaromatic and polyaromatic hydrocarbons), showed positive mutagenic response in any of the Salmonella typhimurium strains. We have tested a wide range of concentrations. The results obtained so far are consistent with the lack of mutagenic activity of all investigated fractions in the absence and in the presence of metabolic activation.Assuming that there might be an association between the absence of mutagenic activity and the complexity of the tar-sand fractions, we investigated the effect of the polyaromatic hydrocaron fraction on the mutagenicity of the carcinogenic agent 2-aminoanthracene. The data obtained indicate clearly that the polyaromatic hydrocarbon fraction suppresses the mutagenic activity of 2-aminoanthracene.

Catalytic effect of Athabasca tar sand matrix on thermal decomposition of bitumen, hexene and hexane

The thermal decomposition of dichloromethane extracted Athabasca tar sand bitumen and Athabasca tar sand itself was studied in a stream of 30 ml/min helium at temperatures in the range 350–550°C. The volatile products obtained were analyzed by gas chromatography. It was observed that the products were mostly comprised of n-paraffins. Elemental analysis of the residues obtained from thermal decomposition indicated that decomposition was complete between 450°C and 500°C. The catalytic effect of sand, obtained by dichloromethane extraction of Athabasca tar sand, on the thermal decomposition of hexane and hexene was investigated at several temperatures. It was observed that the extracted sand had no catalytic effect on the decomposition of hexane and hexene up to 450°C, but catalyzed the thermal decomposition at 500°C or higher. The catalytic effect of the sand was fairly significant in the case of hexene. The products obtained from hexene decomposition were comprised of more than C 6 hydrocarbons. Hexane decomposition products contained C 6 or less than C 6 hydrocarbons.

History Matching the Steam/Foam Injection Process In a Thick Athabasca Tar Sand Reservoir

Abstract Throughout the life of the Gregoire Lake In-Situ Steam Pilot (GLISP), a number of steps (i.e., steam stimulation, steam flooding, steam/foam injection, surfactant concentration reduction, pressure cycling, injection rate reduction and air/steam injection) were taken to develop and optimize the steam/foam injection process. After completing the project, a history match study was initiated to understand the process mechanisms and sensitive parameters. The ultimate purpose was to establish a steam/foam forecast model for the Athabasca tar sands. This paper presents the history match results and highlights the important process considerations that led to the final match. The model was validated by obtaining satisfactory predictions for other pilot producers. Overall, the empirical foam model was found to be adequate for field scale steam/foam simulation. The history match results confirmed that the communication path in the upper low oil saturation zone had a strong impact on the GLISP production performance and supported some of the operational decisions made by the project team during the pilot operation. The results also suggested that the steam/foam injection strategy could be further optimized. Introduction The Gregoire Lake In-Situ Steam Pilot (GLISP), a joint venture between AOSTRA. Amoco Canada and Petro-Canada (Phase A only) with Amoco being the operator, was the first steam/foam project conducted in the thick Athabasca tar sands. It successfully demonstrated the diversion of steam to the lower tar rich zone and resulted in improved bitumen recovery. The detail field history has been published by Sander et al.(1)This paper presents the most recent history match results based on techniques established in prior simulation studies.(2,3&4) A pilot well layout map is shown in Figure 1. The pilot consists of one injector (H6) and three producers (H3, H4 and H5) drilled in an inverted 4-spot pattern with an injector to producer distance of 46m. Three temperature observation wells (HO7, HO8 and HO9) were also drilled to obtain temperature information. The project was operated from October 1986 to July 1991. It was originally designed to create horizontal fractures in the rich tar zone to optimize steam flood heating. However, it was later found that a multiple fracture system was induced(5) and had led to steam overriding in the upper low oil saturation zone. A steam/foam diversion was thus initiated in October 1988 to mitigate the problem. Subsequently, additional tests were conducted to evaluate and optimize the process. The following summarizes the key pilot activities:Initial steam cycling to preheat the reservoir (October 1986 to July 1987).Steamflooding and occasional steam stimulation at production wells (July 1987 to September 1988).Steam/foam injection to mitigate the steam override effects (October 1988 to July 1989).Foam concentration reduction to optimize operating costs (August to December 1989).Injection pressure cycling, injection rate changes and air/steam injection to optimize the steam-oil ratio (January 1990 to July 1991). The objective of this paper was to match, as much as possible, the injection well bottomhole pressure, producer fluid rates and the observation well temperatures, with special emphasis given to the steamflood and foam injection periods.

Thermal decomposition of Athabasca tar sand and bitumen

A study has been made of the thermal cracking of Athabasca tar sand and bitumen in an inert atmosphere of He at temperatures between 350°C and 550°C. The products were collected in a cold water trap and analysed by gas chromatography (G.C.). ESR studies were also made of the residue. The G.C. analysis showed that n-paraffinic hydrocarbons from C 5 to at least C 21 were present in the liquid product. At temperatures greater than 400°C, the concentration of n-paraffins (C 10C 21) decreased with the increase in their molecular weight. No significant effect of the inorganic matrix of tar sand was noticed on the products obtained when compared with the products obtained from bitumen. The number of spins/g of the stable organic free radical in the residue was directly related to the formation of n-paraffins. The maximum amount of n-paraffins was formed when tar sand and bitumen were cracked at 450°C. The residue obtained from tar sand at temperatures greater than 450°C gave a broad resonance at g ≅ 2.267 and width, ΔH pp = 1400 G. The physical structure of the residue obtained on the thermal cracking of tar sand and bitumen was found by reflected light microscopy and found to depend on the cracking temperature.

Fluid catalytic cracking of Alberta tar sand bitumen

Fluid catalytic cracking (FCC) is currently being studied as a method to produce premium value gasoline from petroleum gas oil. In the present investigation, the effect of prehydrotreatment of heavy vacuum gas oil (VGO) of the atmospheric distillation residue (feed material) from Athabasca tar sand bitumen on the yields of light and middle fractions during FCC is reported. Also, the behavior of coke formation during FCC of VGO is examined. Hydrotreatment of feed material was done in a 500-mL autoclave using Ni-Mo/Al 2 O 3 catalyst at 390 and 390°C under an initial hydrogen pressure of 85 kg/cm 2 (gauge) whith a reaction time of 90 min

Electron spin resonance study of the thermal decomposition of solvent extracted Athabasca tar sand bitumen

The concentration of free radicals (spins/g) in the bitumen extracted from Athabasca tar sand depended on the polarity of the solvent used for extraction. Non-polar solvent extracted bitumen had a higher number of spins than polar solvent extracted bitumen. Similar behavior was observed with the VO 2+ ion in bitumen. Extracted bitumen had a higher number of spins than the intact tar sand. This observation was different from that with Utah tar sand. Clean sand also gave an electron spin resonance signal, the intensity of which depended on the polarity of the solvent used. The shape of the signal also depended on the solvent. Increases in the concentration of free radicals were observed at temperatures which were lower than the thermal decomposition temperatures of most of the reactions. The variation in the concentration of radicals in bitumen, tar sand and residual sand depended on the heating rate. At 500°C prolonged heating gave an increase in the concentration of free radicals due to the formation of free carbon (coke) and to a decrease in the recombination of radicals. A possible mechanism is discussed to explain the effect of heating on the free radical formation in bitumen or in tar sand.

Determination of the macroscopic structure of heavy oils by measuring hydrodynamic properties

The molecular weight, bulk-phase diffusivity, and intrinsic viscosity of fractionated samples of Athabasca tar sand bitumen vacuum bottoms and of a blend of vacuum resid from Western Canadian crudes has been measured. The diffusion coefficient and intrinsic viscosity of samples of each material of similar molecular weight were found to be in general agreement. Multisubunit structural models are proposed to describe the hydrodynamic characteristics of these materials. These models are rigid structures assembled from identical spherical subunits. The experimental diffusivity values were found to be in excellent agreement with those predicted for multilayer structures containing 6--24 subunits. The results indicate that the effective size of these materials appears to be considerably smaller when measuring intrinsic viscosity than when measuring solute diffusivity. The authors propose that association dissociation phenomena are responsible for these observations.

Reservoir Characterization for Chevron's HASDrive Field Trial, Athabasca Oil Sands Area, Northeastern Alberta, Canada: ABSTRACT

Chevron is currently field testing an in-situ thermal recovery process termed Heated Annulus SteamDrive (HASDrive) on the Lower Cretaceous Athabasca tar sand deposit at the Alberta Oil Sands Technology Research Authority (AOSTRA) Underground Test Facility (UTF) site. The HASDrive process applies heat through a subsurface horizontal pipe to the base of the bitumen-rich reservoir sands of the McMurray Formation. A vertical steam-injection well aids in mobilization of the heavy crude and sweeps hydrocarbons toward a horizontal subsurface producing well. To evaluate the HASDrive technology, a geologic model was developed to predict the distribution and geometry of reservoir sands and intervening shales. Core studies indicated deposition took place in an estuarine environment, with sands representing tidal channel deposits and shales relating to tidal flat sedimentation. A thorough program of conventional and special core analysis was done on samples from five wells. Special core analysis consisted of miscibly cleaning samples prior to determination of brine permeability. Vertical and horizontal permeability were determined for massive to cross-bedded sandstone as well as four types of shale-bearing sandstone. Of these four, thin shale beds and shale breccia were more effective in reducing permeability and may form barriers to fluid flow. Thin discontinuous shale laminae ormore » shaly wisps merely impede flow. Interactive workstation programs used core and log data petrophysical parameters as input to build a simulator grid of 2,600 blocks in 10 layers to represent a field trial area of approximately 2,000 m{sup 2}. Potential barriers capable of preventing or reducing the flow rate were identified, incorporated into the model, and treated as dimensionless shales (i.e., shaly beds with negligible thickness). The simulator model was then used to the match history of field trial fluid production.« less

Characterization of Athabasca tar sand malthenes by diffuse reflectance infrared spectrometry

Separation par chromatographie a permeation de gel des fractions des maltenes de sables asphaltiques d'Athabasca. Ces fractions sont ensuite etudiees par analyse elementaire et spectrometrie IR a reflexion diffuse