Barrels Of Bitumen Research Articles

Sunnyside bitumen-impregnated sandstone reservoirs at Bruin Point, southwest Uinta Basin, Utah

The south flank of the Uinta Basin in northeast Utah is the high Tavaputs Plateau that dips gently northward towards the basin center and is deeply dissected by the Green River and its tributaries. Where not removed by canyon incision, bitumen-impregnated sandstones in the Green River Formation (lower Eocene) occur along nearly the full length of the plateau. The bituminous sandstones encompass an area greater than 600 square miles and hold an estimated 11.6 to 14.0 billion barrels of bitumen, but the net thickness of bituminous sandstone and the OOIP rarely exceed 70 feet and 80 thousand barrels per acre (MBO/ac), respectively. However, in an exceptional 4.6 square mile area centered on Bruin Point (elev. 10,184 ft) on the southwest basin rim, the net thickness of bituminous sandstone and OOIP are measured in hundreds of feet and MBO/ac, respectively. The estimated bitumen in place in just this small area is 1.16 billion barrels. Bruin Point is an erosional remnant of a structural-stratigraphic trap formed by the superposition of a subtle flexure on a thick stack of deltaiclittoral sandstones. In the 1970s and 1980s, this unique area was extensively investigated to characterize the reservoirs and delineate the hydrocarbon resource. Over 117 test wells with cores were drilled and analyzed. As many as 32 stacked bituminous sandstone bodies were encountered, 15 of which hold nearly all the bitumen. The sandstones were deposited in constantly shifting deltaic lobes and along inter-delta shorelines. They are encased in marsh and floodplain mudstone and littoral-lacustrine calcareous mudstone and bioclastics. The sandstones are poorly sorted, fine-grained feldspathic arenites up to 115 ft thick in distributary channels, but less than 10 ft thick in beach deposits. Average porosity and permeability are 23% and 570 md, respectively, but values vary widely between, and even within, depositional settings. The bitumen at Bruin Point is heavy (8.6o API) and highly viscous (106 cP). Just 25 miles to the north, these same amalgamated deltaic sandstones are the reservoirs in the Greater Monument Butte conventional oil field. Although many operators have attempted to exploit the Bruin Point site for liquid hydrocarbons using both in situ steam flood and mining with solvent extraction, so far only small-scale mining of the bituminous sandstones for road construction has been commercially successful. This paper presents seven cores, several exceeding 1000 ft in length, that graphically display the distribution of bitumen resource as related to stratigraphic heterogeneity and location within the Bruin Point sector of the Sunnyside deposit.

Optimized transportation of bitumen, a case study for Nigeria

Nigeria meets the bulk of her bitumen demand through importation despite her vast raw deposits. The country is now looking towards its local production by harnessing these vast deposits to change this narrative. The exploration of her abundant deposits of bitumen will however require high-temperature sustenance capable pipelines to ensure uninterrupted flow. Hitherto, this is not a challenge with the transportation of her light crude due to the favorable ambient temperature greater than 25 °C. The solution lies in either with heated pipelines or an optimized insulated pipeline at an extra cost. The goal of this study is to determine a cost estimate for Agbabu Nigeria bitumen transportation. The optimum thickness of pipeline insulation is determined numerically using COMSOL Multiphysics Version 5.5 software heat transfer – pipe flow module. The pipeline span of 150 km with a flow rate of 5 Million Metric Tonnes Per Annum (MMTPA) and needs to be maintained at 68 °C. The calculated cost of insulation is compared with existing data of a heated pipeline. The optimized insulation thickness for the bitumen average flow temperature of 68 °C through the pipe subjected to an ambient temperature of 25 °C is 0.105 m. The transportation of a barrel of bitumen will cost USD 1.25 for an optimized insulation pipeline and USD 1.44 for a heated pipeline. This study provides a decision base for an economical means of transporting the country’s vast bitumen resources.

The development of a process simulation model for energy consumption and greenhouse gas emissions of a vapor solvent-based oil sands extraction and recovery process

The solvent extraction process (SEP) is a promising technology for bitumen production from oil sands. This paper investigates the energy requirements and greenhouse gas (GHG) emissions in a propane-based super-heated vapor solvent extraction process as an alternative to in situ techniques, steam assisted gravity drainage, and cyclic steam simulation. A vapor solvent-based extraction model of 25,000 barrels per day of bitumen was developed to evaluate energy and GHG emissions. The energy- and emissions-intensive units were identified and a sensitivity analysis was conducted to study the impact of key operating parameters on the plant's overall emissions. Uncertainty analysis was performed on the most sensitive parameters. The results show that SEP natural gas and electricity consumption are 60.5–89.9 MJ/barrel and 19.7–19.9 kWh/barrel of bitumen, respectively. The GHG emissions range from 24.8 to 29.1 kg CO2 eq./barrel of bitumen. The demethanizer unit, responsible for more than 90% of the electrical energy, is the most GHG emissions-intensive unit. GHG emissions are mostly influenced by the solvent-to-oil ratio. On the whole, the SEP emissions footprint is promising; however, the results must be extended to upgrading and refining emissions in order to understand the full life cycle GHG emissions of the transportation fuels produced.

The development of a techno-economic model for the extraction, transportation, upgrading, and shipping of Canadian oil sands products to the Asia-Pacific region

The diversification of Canadian oil sands markets is imperative for the long-term economic growth of oil sands products. To ensure a competitive place in the global market, supply chain costs of oil sands must be as low as possible. This study conducts a comparative techno-economic analysis of potential pathways for the transportation of Canadian oil sands products (synthetic crude oil and diluted bitumen) to seaport destinations in the Asia-Pacific region. We developed data-intensive techno-economic models to estimate total supply chain costs from the production site in Alberta to ports in China, Japan, and India. Four pathways were developed using production (steam assisted gravity drainage), transportation (production-upgrader-port in Vancouver), upgrading, and shipping operations. A sensitivity analysis was conducted to identify cost ranges with their occurrence probability measures and evaluate the effect of key parameters for each stage of operation. Supply chain costs (C$ per barrel of bitumen) to China, Japan, and India are from 61–87, 60–86, and 62–90, respectively. Overall supply chain costs of dilbit (a blend of bitumen and diluent) and synthetic crude oil (SCO) are affected most by production and upgrading costs. The production and upgrading costs are influenced by capital cost, while pipeline lifetime and capacity highly impact transportation (pipeline) and shipping costs, respectively. The developed models can be used to predict total supply chain costs of different pathways in Canadian oil sand markets.

Impact of the Prairie Evaporite dissolution collapse on McMurray stratigraphy and depositional patterns, Shell Albian Sands Lease 13, northeast Alberta

Abstract The Cretaceous McMurray Formation in NE Alberta contains nearly a trillion barrels of bitumen, a significant portion of which is being developed via surface mining and in-situ thermal methods. The focus of this report is the structure and stratigraphy of the Cretaceous McMurray Formation and its relationship to the configuration of the underlying Devonian section in the area of Shell Canada’s Albian Sands Lease (Township 95, ranges 9 and R10W4M), a joint oil sands mining venture between Shell Canada (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). The structural and stratigraphic relationships between the two intervals has been the source of several recent investigations due to industry related incidents that demonstrated the integrity of the underlying Devonian succession can be compromised by vertical pathways associated with faults, sinkholes, or other features. Key findings of this work include the following: The present morphology of the Pre-Cretaceous unconformity is primarily due to structural deformation (differential subsidence) related to dissolution and collapse of the underlying Prairie Evaporite Formation and overlying Devonian units of the Beaverhill Lake Group rather than erosion relief. Two types of collapse structures are recognized: a) large scale sag folds that are 1-to-10 kilometres in extent; and b) small scale breccia pipes that are 10- to-100 metres in diameter. The sag folds are interpreted to have formed in response to the dissolution of halite. The breccia pipes, which postdate the sag folds, represent sinkhole features that formed in response to the dissolution of gypsum. Rather than onlapping the unconformity, Lower McMurray strata thin and converge across structural highs and thicken and diverge across structural lows, demonstrating much of the dissolution driven subsidence was contemporaneous with the deposition. The subsidence produced up to 80 metres of accommodation and involved the coherent sagging and faulting of large intact segments of the underlying Devonian section. The arrangement of major stratigraphic packages indicates subsidence features shifted locations through time rather than persisting through the entire Lower McMurray. Changes in sedimentation style between sand-rich fluvial packages to mud-rich lacustrine dominated packages within the lower McMurray reflect changes in relative rates of subsidence. Sand-rich fluvial units are localized in settings with low-to-moderate subsidence rates, while mud-rich fluvial-lacustrine units are localized in settings with moderate-to-high subsidence rates. The Middle-to-Upper McMurray section is composed of four high relief unconformity bound units that display flat/horizontal stratal relationships with the underlying structure of the Pre Cretaceous unconformity. In contrast to the Lower McMurray, stratigraphic relationships indicate it was largely impacted by falls and rises in relative sea-level (cycles of negative and positive accommodation) rather than dissolution driven subsidence that, while still active, had begun to wane.

Geology of bitumen and heavy oil: An overview

On a world-wide basis there is an estimated 5.6 trillion barrels of bitumen and heavy-oil resources which occur in over 70 different countries, with most of the heavy-oil in Venezuela and most of the bitumen in Canada. The most common plate-tectonic settings in which the heavy-oil and bitumen are found are in continental multi-cyclic marginal basins and in continental rift basins.Heavy oil and bitumen resources are largely a result of natural degradation of formerly conventional oil accumulations. The natural degradation for most is biologic in origin, with the result that the majority of heavy-oil and bitumen deposits is characteristically in younger rocks (Cretaceous and younger) and at shallow depths (usually <200m, up to 2000m maximum). At a deposit-scale it is necessary for communication to have been established between the surface and subsurface to facilitate the biologic contamination of the pre-existing light petroleum reservoirs. Communication is through loss of caprock integrity, associated with major erosion (creation of unconformities), faulting, fracturing; and, for carbonate host-rocks, karstification. Two cases are discussed to illustrate these geologic processes: 1) the influence of the sub-Cretaceous unconformity on the Cretaceous oil-sands in the Western Canada Sedimentary Basin; and, 2) the influence of faulting, fracturing and karstification on the Grosmont carbonate-bitumen deposit of northeastern Alberta.

Electrocoagulation for the Treatment of Oil Sands Tailings Water

Title: Electrocoagulation for the treatment of oil sands tailings water The Canadian oil sands industry has been receiving widespread International criticism on environmental issues, among which is its use of water resources. A major process to recover the valuable bitumen (a heavy, viscous form of petroleum) from the oil sands resource is surface mining. A by-product of mining operations is large volumes of toxic tailings water which are stored in large dykes, the infamous ‘tailings ponds’, covering a total area greater than 175 sq. km. These have led to significant environmental damage because of land displacement, the contamination of natural waters, and impact on wildlife such as waterfowl that land into the water surface. Large volumes of fresh water are withdrawn to make up for the water being stored as tailings water. On average about 3 barrels of fresh water are withdrawn per barrel of bitumen produced, the main source of fresh water being the Athabasca River. The local communities and stakeholders have expressed concerns about fresh water withdrawal rates, potentially creating water shortage issues. The nature of contaminants in tailings wastewaters makes the treatment processes costly in order to minimize environmental impact, hence the operators are forced to store the water as ponds. Tailings water is a complex mixture of contaminants, very fine clay particles that take decades to settle, toxic organic compounds such as naphthenic acids and polycyclic aromatic hydrocarbons (PAH’s), silica, and heavy metals including nickel, vanadium, arsenic and mercury. Since the start of mining operations in 1967, the oil sands industry is yet to implement a method to treat tailings water, alleviate the use of tailings ponds, and significantly increase recycle rates. Electrocoagulation (EC) is one technology that could address these issues. Prior research on various other wastewaters has shown that EC can remove several contaminants including fine suspended solids, toxic organic matter, silica, and heavy metals [1] which are the common contaminants in oil sands tailings water. In its simplest form, EC uses an electrochemical cell to generate coagulating agents in the wastewater by electrochemical reactions, resulting in flocculation of contaminated particles which separate out by settling or flotation. Currently, coagulation and flocculation of most industrial wastewaters are performed by the use of chemicals like metal salts. However, EC has many advantages over the chemical method. The electric field used in EC enhances the flocculation process by setting the charged colloidal particles in motion resulting in the coagulation of even very fine suspended solids [2]. This will be advantageous when applied to tailings water because the most difficult to remove contaminant it contains are the very fine, slow settling clay particles. In addition, EC simultaneously removes heavy metals by precipitation as the pH increases during the process. Furthermore, hydrogen gas bubbles generated at the cathode by water reduction reaction will float the flocculated particles to the water surface, thus providing better separation of contaminants. Another major advantage is that no chemicals are required, minimizing secondary pollution. The high conductivity of tailings water is an advantage, as it will provide low electrolytic solution resistance, leading to low energy requirement. Increased contaminants removal rates, the avoidance of chemical addition, and lower energy consumption suggest that EC could reduce the environmental impact and cost of water treatment for treating tailings water. The main research objectives are to investigate the effectiveness of EC for the treatment of tailings water and by removing several contaminants simultaneously. The potential to eliminate tailings ponds by using EC have been explored. Experiments with EC have been conducted on real industrial samples of tailings water and on synthetic wastewater samples prepared in the lab. Contaminant removals have been assessed by measuring various water quality parameters such as turbidity, total suspended solids, “Chemical Oxygen Demand (COD)” and “Total Organic Carbon (TOC)” both of which quantifies the amount of oil present, and the concentrations of heavy metals. Moreover, special attention has been given to the removal of fine particles by the use of water contaminated with fine kaolin clay, the most burdensome of all the contaminants. Also, the effect of different electrochemical reactor designs have been explored. The results are very promising, several contaminants are being removed simultaneously, with removal rates as high as 90%. The results gathered demonstrate that some of the different types of reactor designs tested not just improve contaminant removal rates but also reduce energy consumption significantly.

Alberta’s Oil Sands: Hard Evidence, Missing Data, New Promises

Pitched battles are a regular occurrence in northern Alberta, Canada, as development of the province’s oil sands continues to expand. One ongoing battle—with another salvo launched in February 2011 with the leak of a European Commission report1—concerns how dirty oil sands are, relative to other fuels. Another concerns the influence of the oil sands industry in monitoring its own activity.2 In an effort to cut through the rhetoric of health advocates, industry representatives, environmentalists, government officials, and local residents, the Royal Society of Canada (RSC) selected and covered expenses for an expert panel to winnow out the facts. In a report issued 15 December 20103 the panel cited substantial evidence that efforts to extract oil from the Alberta deposits have degraded air, land, and water quality to varying degrees. The extent of the degradation is sometimes controversial; water quality data, in particular, are subject to differing interpretations and attributions of causality. However, the panel says that, based on publicly available evidence, there appear to be no significant human health threats to the general population either now or from development anticipated in the next decade or so. But the panel also warns that their conclusions come with a major caveat: there are major gaps in health and environmental data, risk assessments, government oversight, information transparency, industry efforts, and disaster preparedness. The health of the region could hinge on these gaps being addressed, particularly since, according to Travis Davies, a spokesman for the Canadian Association of Petroleum Producers, 97% of projected oil extraction and processing is still to come. After the RSC panel reviewed reams of publicly available information on factors such as health status, air and water pollution, greenhouse gas emissions, land disturbance, and energy and water consumption, it concluded that “[t]he claim by some critics of the oil sands industry that it is the most environmentally destructive project on earth is not supported by the evidence. However, for Canada and Alberta, the oil sands industry involves major environmental issues on many fronts which must be addressed as a high priority.”3p293

Drilling Challenges in the Bitumen-Saturated Grosmont Formation

Summary The Upper Devonian Grosmont formation, located in the West Athabasca oil sands deposit, contains an estimated 318 billion barrels of bitumen. The reservoir is a heavily karsted and fractured, bitumen-saturated dolomite with up to 38% porosity and permeabilities commonly measured in the darcies. These properties make the Grosmont an excellent candidate for steam assisted gravity drainage (SAGD). Grosmont SAGD development will be exposed to similar operating conditions as McMurray SAGD projects, and will have similar logistics, well construction and materials challenges. However, there are many additional challenges, including severe loss circulation, that further complicate well design. This paper presents the challenges experienced by Laricina Energy in drilling Grosmont wells at Saleski and Burnt Lakes over the last three seasons. It will also address additional areas for future research and development in the drilling of vertical and horizontal wells.

Technology for Producing Petrochemical Feedstock from Heavy Aromatic Oil Fractions

NOVA Chemicals’ olefins and polyolefins business in Alberta is primarily based on ethane as feed. Historically, Alberta’s competitive advantage in the petrochemical industry has been the plentiful supplies of low cost natural gas and associated ethane feedstock. The growing production of oil from oil sands and the accompanying heavy oil fraction presents a new opportunity for growth and feedstock diversification in the petrochemical industry, provided that these heavy oils can be transformed economically into feed to petrochemical plants. With an estimated quantity of approximately 2.5 trillion barrels of bitumen in the ground, the Alberta oil sands are one of Canada’s major energy resources. At present, this enormous quantity translates into as much as 173 billion barrels of economically viable oil, second only in size to Saudi Arabia. Thus oil sands are a significant hydrocarbon source not only for Canada, but also for the world. Over the past number of years NOVA Chemicals has systematically studied catalytic technologies that can be used to convert heavy oil sands derived fractions into olefins, aromatics-rich products, and other high demand petrochemicals. Work was carried out in collaboration with external academic institutions and with the support of the Alberta government focusing on selection and development of specialized catalysts and process technologies. The work has resulted in the development of two novel, breakthrough processes and a number of catalysts, which not only allow significant feedstock flexibility to the petrochemicals producer but also considerably decrease the amount of emissions produced and energy consumed per ton of produced high demand petrochemicals due to application of catalysis. This paper presents the process configuration and research results from studies undertaken and shows that it is feasible to produce petrochemical feedstock or basic petrochemicals from heavy oil fractions derived from oil sands at competitive costs via two different catalytic processes. Examples of experimental results of catalysts testing are presented for both processes.

Athabasca oil sands: reservoir characterization and its impact on thermal and mining opportunities

Abstract The heavy oil deposits of Canada are a large resource with an estimated 1.7×10 12 barrels of bitumen in place. The Lower Cretaceous McMurray Formation in the Athabasca area of northern Alberta contains about 900×10 9 barrels of bitumen in place. This resource can be developed through surface mining and thermal in situ techniques. This paper examines the size of this resource in a global context and highlights its position relative to the North American market. The regional geology of the Western Canada Sedimentary Basin and the Athabasca area will also be reviewed. Understanding the regional reservoir distribution of the McMurray Formation is critical to understanding oil sands opportunities. Fluvial estuarine point bar reservoirs are a large portion of the resource that can be developed. Examples will be shown from the type outcrop location, where the stratigraphy can be organized into a hierarchy that subdivides channel-fills into bedsets, storeys, bars and barsets. Inclined heterolithic strata (IHS) surfaces can be identified. Considerable resource delineation drilling has occurred in the basin. The regulator for the Athabasca area specifies minimum drilling densities before project approvals are granted. Regional 2D seismic lines and project-specific 3D and 4D seismic datasets have also been acquired, to reduce the reservoir uncertainty and improve resource definition in this complex depositional environment. These techniques provide a unique opportunity to analyse a complex depositional system with abundant well and core control, outcrop data and seismic information. To determine preliminary deposition environments, software techniques have been successfully used to interpret large datasets quickly. Laser imaging of mine faces has also been used to record stratigraphy and determine the mined volume of ore. The importance of detailed reservoir characterization studies and their impact on thermal in situ recovery mechanisms will also be discussed. Understanding reservoir facies distributions and lateral relationships affects any recovery process, but has an even greater significance in a heavy oil reservoir.

Development of Wear Resistant Nanostructured Duplex Coatings by High Velocity Oxy-Fuel Process for Use in Oil Sands Industry

Oil sands deposits in Northern Alberta, Canada represent a wealth of resources attracting huge capital investment and significant research focus in recent years. As of 2005, crude oil production from the current oil sands operators accounted for 50% of Canada's domestic production. Alberta's oil sands deposits contain approximately 1.7 trillion barrels of bitumen, of which over 175 billion are recoverable with current technology, and 315 billion barrels are ultimately recoverable with technological advances. A major problem of operating machinery and equipment in the oil sands is the unpredictable failure from operating in this highly aggressive environment. One of the significant causes of that problem is premature material wear. An approach to minimize this wear is the use of protective coatings and, in particular, a cermet thin coating. A high level of coating homogeneity is critical for components such as bucketwheels, draglines, conveyors, shovels, heavyhauler trucks etc. that are subjected to severe degradation through abrasive wear. The identification, development and application of optimum wear solutions for these components pose an ongoing challenge. Nanostructured cermet coatings have shown the best results of achieving the degree of homogeneity required for these applications. In this study, WC-17Co cermet powder with nanocrystalline WC core encapsulated with 'duplex' Co layer was used to obtain a nanostructured coating. To apply this coating, high velocity oxy-fuel (HVOF) thermal spraying technique was used, as it is known for producing wear-resistant coatings superior to those obtained from plasma-based techniques. Mechanical, sliding wear and microstructural behavior of the coating was compared with those of the microstructured coating obtained from spraying WC-10Co-4Cr cermet powder by HVOF technique. Results from the nanostructured coating, among others, showed an average of 25% increase in microhardness, 30% increase in sliding wear resistance and a significant increase in the dry sand abrasion wear resistance when compared with the microstructured coating.

The Effect of Oil Sands Bitumen Extraction Conditions on Froth Treatment Performance

Abstract Further development of oil sand deposits requires processing poorer quality oil sands while maximizing bitumen recovery, minimizing the water and solids content of the product bitumen, and minimizing overall energy consumption. Bitumen recovery requires two stages: extraction and froth treatment. This work focuses on the effect of process conditions in the Clark Hot Water Bitumen Extraction Process on froth treatment effectiveness. Laboratory approximations are used to represent the two commercialized froth treatment processes in Alberta:the "Syncrude Process," which is dilution with an aromatic solvent followed by centrifugation; and,the "Albian Process," which is dilution with a paraffinic solvent followed by gravity settling. Parameters considered are oil sand quality, extraction shear, extraction temperature, NaOH addition during extraction, froth treatment temperature, and froth treatment residence time. It was found that reduced extraction temperature results in lower bitumen recovery at least for low quality oil sands. Higher shear extraction may improve bitumen recovery, but decreases froth treatment effectiveness. For paraffinic solvent-based froth treatments, the addition of NaOH during extraction may be required to obtain optimum froth treatment of low quality oil sands. Introduction The Canadian oil industry is producing about 1 million barrels of bitumen and synthetic crude oil per day from oil sands and the production is expected to rise to 2 million barrels per day by 2012(1). Currently, both in situ and surface mining operations contribute almost equally to the total production. However, the production of synthetic crude from surface-mined oil sands is expected to take the lead in the next decade(2). Expansions of existing oil sand facilities are already underway and the addition of new facilities are planned within the next decade. There are two main stages to oil sand processing: extraction and froth treatment. The most common extraction process is hot water bitumen extraction. The oil sand is conditioned with hot water, either in a process vessel (conditioning drum) usually with NaOH added, or more recently in a pipeline (hydrotransport) usually with a smaller amount of NaOH added. During conditioning, the slurry is aerated and, ideally, the bitumen separates from the sand, and attaches to and spreads on the air bubbles. Water is added to the slurry, which is subsequently sent to a separation vessel. The bitumen- coated air bubbles are carried upwards to form a froth that is rich in bitumen. The froth also contains free water, emulsified water, and suspended solids(3, 4). The froth is collected in two stages yielding a primary and a secondary froth. For high-quality oil sands, a typical primary froth composition is approximately 66 wt% oil, 25 wt% water, and 9 wt% solids. A typical secondary froth has lower oil content (approximately 24 wt%) and higher water and solids contents (59 wt% and 17 wt%, respectively). Poorer quality oil sand froths have lower oil content and higher water and solids contents(5).

Diethylaminoethyl-cellulose clean-up of a large volume naphthenic acid extract

The Athabasca oil sands of Alberta, Canada contain an estimated 174 billion barrels of bitumen. During oil sands refining processes, an extraction tailings mixture is produced that has been reported as toxic to aquatic organisms and is therefore collected in settling ponds on site. Investigation into the toxicity of these tailings pond waters has identified naphthenic acids (NAs) and their sodium salts as the major toxic components, and a multi-year study has been initiated to identify the principal toxic components within NA mixtures. Future toxicity studies require a large volume of a NA mixture, however, a well-defined bulk extraction technique is not available. This study investigated the use of a weak anion exchanger, diethylaminoethyl-cellulose (DEAE-cellulose), to remove humic-like material present after collecting the organic acid fraction of oil sands tailings pond water. The NA extraction and clean-up procedure proved to be a fast and efficient method to process large volumes of tailings pond water, providing an extraction efficiency of 41.2%. The resulting concentrated NA solution had a composition that differed somewhat from oil sands fresh tailings, with a reduction in the abundance of lower molecular weight NAs being the most significant difference. This reduction was mainly due to the initial acidification of tailings pond water. The DEAE-cellulose treatment had only a minor effect on the NA concentration, no noticeable effect on the NA fingerprint, and no significant effect on the mixture toxicity towards Vibrio fischeri.

Avoiding an Oil Crunch

G lobal resources of conventional petroleum are limited. Competent geologists, geochemists, and geophysicists have identified and explored the Earth's sediments in which favorable circumstances existed for the creation and containment of hydrocarbons. They know that vast areas of the globe have no resources of oil, and the amounts of conventional oil that will ultimately be produced can be estimated. New exploratory and production technologies have been continually improved. During the past 5 years, the pace of change has quickened. Improved computerized seismic programs and guided drilling have been highly effective. Marine formations located in deep water on the continental shelves off western Africa, Brazil, and in the Gulf of Mexico have been drilled and found to be productive. Nevertheless, some knowledgeable petroleum geologists assert that conventional oil is being consumed faster than new reserves are being found.[*][1] An example of what will occur on a global scale is provided by events in the United States. Production peaked there in 1970. Imports of foreign oil have risen since 1982. They now supply more than half of U.S. consumption of petroleum and its products. In spite of huge investments in exploration using new technology, U.S. reserves of oil have diminished. In 1998, the costs of finding oil soared while rates of replacement of production dropped.[†][2] Reserves declined to 18.2 billion barrels in 1998. Consumption last year was more than 4 billion barrels. Global consumption is growing. The world will become increasingly dependent on supplies from the Persian Gulf. In a few years, production there will supply 38% or more of global consumption. Then history might be repeated with huge price increases, supply interruptions, and attendant economic hardships. The United States and other advanced countries are conducting research that could eventually result in less dependence on oil. Those efforts are commendable and merit governmental funding. However, it is unlikely that the research will lead to substantially decreased consumption of oil for a decade or more. To insure against an oil crunch, the United States could help create large sources of nonconventional petroleum. Great resources, technical capability, reliable equipment, and experience exist in the Canadian province of Alberta, where a vast area of tar sands contains about 1.7 trillion barrels of bitumen. Some of this has already been converted into more than a billion barrels of high-grade crude oil. With current techniques, more than 300 billion barrels of oil could be produced from the bitumen of these tar sands. This is more than the oil reserves of Saudi Arabia. At present, the largest installation for extracting bitumen and converting it to a premium clean crude oil is operated by the Syncrude Corporation. Facilities are located at Mildred Lake 30 kilometers north of Fort MacMurray, which is about 600 miles north of the U.S.-Canadian border. First production there occurred in July 1978. In 1979, 18 million barrels of Syncrude Sweet Blend (SSB) were produced at an operating cost of $25 Canadian. As a result of persistent incremental process improvements, production in 1998 was 76 million barrels with operating costs of $13.57 Canadian ($8.85 U.S.). The cost of finding and developing new oil in the lower 48 states in 1998 was about $12.00 per barrel. Many projects are planned, under way, or recently completed in Alberta. Some of them involve bitumen in sands that are deeply buried. Its viscosity is being reduced by steam heating and the resultant fluids are brought to the surface. This process has been improved, and deep sands will become an important source of bitumen. Alberta's technical ability to substantially increase the production of high-quality oil is evident, as is a desire to export more of it. Delicately conducted negotiations by U.S. authorities might ultimately lead to substantially increased U.S. imports of Canadian oil products. This would diminish the probability that Persian Gulf states would choose to conduct an economic squeeze of the United States. [1]: #fn-1 [2]: #fn-2

UTF Project Status Update, May 1997

Abstract The Underground Test Facility (UTF) is producing from three tunnel drilled 500 m long horizontal well pairs which have produced effectively at their peak rates and reached recoveries of almost 55% OOIP. Two new pairs of 750 m and 300 m horizontal wells have been drilled from the surface and were started up in April 1996. Start-up performance and well control methods have been successful. Another 750 m horizontal well pair is to be drilled from surface in the spring of 1997 and started up in the fall of 1997. Its purpose is to test methods of operating a well pair next to a depleted reservoir without losing steam to it. Net revenue from the UTF Project has funded the costs of adding three surface well pairs and related plant facilities since September 1994. The UTF Project is owned by AOSTRA with nine industry participants, including Gibson Petroleum Company Limited who was appointed Project Operator in October 1995. Introduction This is the third in a series of papers presenting the development status of the Steam Assisted Gravity Drainage (SAGD) process at the Underground Test Facility (UTF) situated 70 km northwest of Fort McMurray, Alberta (Figure 1.1). The first paper(1), presented in 1991, covered the initiation of the UTF Project from 1984 to May 1991. It discussed the rationale for starting the UTF, the basic SAGD process, the facilities (shaft, tunnels, underground drill rig, Phase B plant), the results of the three Phase A well pairs, and the drilling and design of the three Phase B well pairs which had not yet started up. The second Paper(2) reviewed the start-up and performance of the three Phase B well pairs and facilities which had produced 500,000 barrels of bitumen at that time, May, 1994. It also discussed the economics of a potential 30,000 bpd commercial SAGD recovery project. The current paper looks at the continuing performance of the Phase B wells and facilities which have produced over 2,400,000 barrels of bitumen; the design and April 1996 start-up of two pairs of SAGD wells drilled from the surface (Phase D) which have produced over 170,000 barrels of bitumen; the design of a third surface well pair to be drilled in the spring of 1997 to test the methods of placing and operating a new well pair next to a depleted reservoir without adverse effects; the features of a produced water recycle plant scheduled for start-up in the fall of 1997; and concludes with a brief discussion of some commercial aspects related to the economics of the SAGD process at the UTF and the marketing of bitumen. The UTF Project is currently owned by the Alberta Oil Sands Technology and Research Authority (AOSTRA) and funded jointly by AOSTRA (25%) and nine industry participants (8 113% each). In addition to Gibson, the industry participants are: Amoco Canada Petroleum Company Limited, Chevron Canada Resources Limited, China National Petroleum Co. (Canada) Ltd., Imperial Oil Resources, Japex Oil Sands Limited, Petro-Canada, Shell Canada Limited, and Suncor Inc.

Hydrocarbon resource evaluation in the Woodford shale using well logs

In the U.S. mid-Continent and west Texas areas, typically black, organic-rich shales include the Antrim, Chattanooga, and Woodford formations of Lower Mississippian and Upper Devonian ages. The Woodford shale in west Texas and southeast New Mexico is believed to be the source of at least 10% of the oil in the region. In southern and central Oklahoma, the Woodford shale is a carbonaceous shale, dark brown to black in color, with locally interbedded thin intervals of chert, siliceous shales, and siltstones. In the main oil-producing region of central and southern Oklahoma, 22 billin barrels of bitumen and 16 billion barrels of hydrocarbons have been expelled from the Woodford Formation. Locally, potential hydrocarbon production occurs directly from this Woodford section and is controlled by the presence of natural fracture systems, particularly in intervals of high carbonate, silt, and/or chert content. Well log responses in the Woodford shale include excessively high, natural radioactivity, a non-definite spontaneous potential, high formation resistivity, and low bulk density. The last two are caused by the presence of kerogen in the pore space. Natural gamma-ray spectral logging and associated interpretive techniques have proven useful particularly in locating the natural fracture systems from which the Woodford shale sequence often produces after initial completion or recompletion attempts. Field case examples illustrate these concepts.

Development of a new method for the extraction of bitumen from tar sands using sonication and sodium silicate

The authors believe that the new process described can stand by itself. Also, it can be utilized to modify existing commercial tar sand operations. The process requires pilot plant study before scale-up to commercial operation. The following conclusions can be drawn. 1. Tar sand recovery using sodium silicate and sonication represents a new extraction process. 2. The bitumen recovered is low in ash, virtually free of metal and asphaltenes. 3. The bitumen recovered is upgraded to 15° API (raw bitumen was 7.6° API) for a 95% cumulative recovery (based on carbon content). 4. The asphaltene and preasphaltene separate as solid agglomerates to the bottom. 5. The solid agglomerates are highly enriched with strategic metals (e.g., Ti, Fe, V, Ni, etc.). 6. Clean sand and intact clay can be easily and essentially recovered in full. 7. The process mechanism utilizes the principle of membrane-mimetic chemistry and ultrasonic irradiation. 8. Self-propagated surfactants are formed during the reaction. 9. Kinetic studies reveal the S-shape characteristic rate curve for 95% cumulative recovery of bitumen. 10. An economic analysis for a pilot plant with a capacity of 1000 barrels of bitumen per day indicates that the process is commercially attractive.

Multi‐Stage Air Flotation of Tar Sand Wastewater

In 1980, the Department of Energy’s Laramie Energy Technology Center conducted a steam-driven tar sand recovery experiment near Vernal, Utah. This experiment yielded 1,150 barrels of bitumen and 6,250 barrels of process water, which was highly contaminated with emulsified oils and dissolved organics. The process waters were successfully treated by bench-scale, continuous-flow air flotation (AF), but significant amounts of very dilute sludge were generated. The present study investigated the effects of adding a second flotation stage to the AF system to thicken stage I sludge, produce a clean effluent suitable for recycling, and thereby increase the hydraulic efficiency of the system. Key stage II operating variables were polymer dose, air flowrate, and liquid residence time. These were optimized to minimize sludge volume and maximize effluent quality and volume. Total organic carbon and total suspended solids removals in the stage II system were 96 and 99%, respectively. Overall sludge production equalled about 2% of the total influent flow.

Bitumen Upgrading- Its Importance to the In-Situ Producer

Abstract This paper explores the substantial effect on the producing operation of the selection and design of upgrading and utilities plant8 in an in-situ oil sands scheme. Oil sands bitumen contains large amounts of impurities which have to be removed in converting (upgrading) to synthetic crude. This upgrading increases the hydrogen-carbon ratio and removes the Sulphur and nitrogen present in the crude bitumen. There are a number of processes which are suitable for bitumen upgrading. Two of the most promising processes are described, including schematic process flow diagrams and yield slates. The energy requirements of such an i1lrtegrated producing-upgrading-utility complex are immense, but can be significantly reduced by complete process integration of the facilities. Among the major energy consumers in the upgrading-utility complex are the hydrogen plant and electric power generating equipment. The nonlinear relationship of synthetic crude price to conversion (upgrading bitumen feed to synthetic crude) to overall (produced bitumen to synthetic crude) recovery is demonstrated. Economic factors are examined qualitatively in the last part of the paper. Introduction IN-SITU RECOVERY of bitumen from the oil sands is a highly energy- intensive process, both- for in-situ steam stimulation or flooding and for in-situ combustion. The bitumen to synthetic crude upgrading processes produce a variety of by-products which can serve as fuel. These heavier or residual fractions, such as coke or pitch, serve to reduce the fuel deficiencywhich is expected to be common to in-situ recovery operations. This gives rise to a fundamental economic optimization problem. The higher the upgrading product yield, the less residual material there is available for internal fuel needs. This deficiency in fuel must be made up either from an outside source or by producing additional bitumen. In other words, the selection land design of an upgrading process, and the associated utilities, has a direct bearing on the size of the producing operation. It is therefore essential that the recovery efficiency of the upgrading process be selected to provide maximum economic synthetic crude per barrel of bitumen produced. Bitumen recovered from the oil sands is a viscous material with substantial amounts of impurities which make it an undesirable feedstock for conventional oil refineries. Table 1 shows a set of properties of Athabasca bitumen'. The salient properties are the high Viscosity, high impurities content (sulphur, nitrogen, oxygen), high metals content and small fraction of the bitumen vaporized in the operating temperature range of commercial distillation towers. The Conradson carbon number (CCR), which is an indication of the coking tendency of the oil, is quite high. Bitumen cannot be economically upgraded in present-day commercially available catalytic reactors due to high concentration of metals and high CCR. The usual approach is therefore to thermally convert the residual fractions of the bitumeninto lower-boiling hydrocarbons which are low in CCR and metals content (primary upgrading). This conversion produces saleable liquids, which are further processed (secondary upgrading) to 'final synthetic crude and byproducts (gas, coke, pitch) which can serve as fuel.