Heavy Oil

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Heavy oil is a type of petroleum that is different from conventional  petroleum insofar as they are much more difficult to recover from the subsurface reservoir. Heavy oil, particularly heavy oil formed by biodegradation of organic deposits, are found in shallow reservoirs, formed by unconsolidated sands. This characteristic, which brings about difficulties during well drilling and completion operations, may become a production advantage due to higher permeability.

Heavy oil has a much higher viscosity (and lower API gravity) than conventional petroleum, and recovery of these petroleum types usually requires thermal stimulation of the reservoir. When petroleum occurs in a reservoir that allows the crude material to be recovered by pumping operations as a free-flowing dark to light colored liquid, it is often referred to as conventional petroleum. During the past two-to-three decades the term black oil has been introduced into the petroleum lexicon. This has only served to confuse the somewhat already confusing terminology applied to petroleum, heavy oil, and tar sand bitumen since the term refers to color rather than to any meaningful properties or to recovery behavior.
Very simply, heavy oil is a type of crude oil which is very viscous and does not flow easily. The common characteristic properties (relative to conventional crude oil) are high specific gravity, low hydrogen to carbon ratios, high carbon residues, and high contents of asphaltenes, heavy metals, sulfur, and nitrogen. Specialized recovery and refining processes are required to produce more useful fractions, such as naphtha, kerosene, and gas oil.
Heavy oil is an oil resource that is characterized by high viscosities (ie, resistance to flow) and high densities compared to conventional oil. Most heavy oil reservoirs originated as conventional oil that formed in deep formations, but migrated to the surface region where they were degraded by bacteria and by weathering, and where the lightest hydrocarbons escaped. Heavy oil is deficient in hydrogen and has high carbon, sulfur, and heavy metal content. Hence, heavy oil requires additional processing (upgrading) to become a suitable refinery feedstock for a normal refinery.

See also Crude Oil Components

There are large resources of heavy oil in Canada, Venezuela, Russia, the United States, and many other countries. The resources in North America alone provide a small percentage of current oil production (approximately 2%), and existing commercial technologies could allow for significantly increased production. Under current economic conditions, heavy oil can be profitably produced, but at a smaller profit margin than for conventional oil, due to higher production costs and upgrading costs in conjunction with the lower market price for heavier crude oils. In fact, heavy oil accounts for more than double the resources of conventional oil in the world and heavy oil offers the potential to satisfy current and future oil demand. Not surprisingly, heavy oil has become an important theme in the petroleum industry with an increasing number of operators getting involved or expanding their plans in this market around the world.
However, heavy oil is more difficult to recover from the subsurface reservoir than conventional or light oil. A very general definition of heavy oils has been and remains based on the API gravity or viscosity, and the definition is quite arbitrary, although there have been attempts to rationalize the definition based upon viscosity, API gravity, and density. For example, heavy oils were considered to be those crude oils that had gravity somewhat less than 20° API with the heavy oils falling into the API gravity range 10° to 15°. For example, Cold Lake heavy crude oil has an API gravity equal to 12° and tar sand bitumen usually have an API gravity in the range 5° to 10° (Athabasca bitumen= 8° API). Residua would vary depending upon the temperature at which distillation was terminated but usually vacuum residua are in the range 2° to 8° API.

Heavy oil has a much higher viscosity (and lower API gravity) than conventional petroleum and recovery of heavy oil usually requires thermal stimulation of the reservoir. The generic term heavy oil is often applied to a crude oil that has less than 20° API and usually, but not always, sulfur content higher than 2% by weight Furthermore, in contrast to conventional crude oils, heavy oils are darker in color and may even be black.
The term heavy oil has also been arbitrarily (incorrectly) used to describe both the heavy oils that require thermal stimulation of recovery from the reservoir and the bitumen in bituminous sand (tar sand) formations from which the heavy bituminous material is recovered by a mining operation. Extra heavy oil is a nondescript term (related to viscosity) of little scientific meaning which is usually applied to tar sand bitumen, which is generally incapable of free flow under reservoir conditions. The general difference is that extra heavy oil may have properties similar to tar sand bitumen but, unlike tar sand bitumen, has some degree of mobility in the reservoir or deposit Extra heavy oils can flow at reservoir temperature and can be produced economically, without additional viscosity-reduction techniques,
through variants of conventional processes such as long horizontal wells, or multilaterals. This is the case, for instance, in the Orinoco (Venezuela) or in offshore reservoirs off the coast of Brazil, but once outside of the
influence of the high reservoir temperature, these oils are too viscous at the surface to be transported through conventional pipelines and require heated pipelines for transportation. Alternatively, the oil must be partially
upgraded or fully upgraded or diluted with a light hydrocarbon (such as aromatic naphtha) to create a mix that is suitable for transportation.

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In the context of the current section, the methods outlined in this book for heavy oil recovery focus on heavy oil with an API gravity of less than 20° with a variable sulfur content that may bear a general relationship to the API gravity However, it must be recognized that some of the heavy oil is sufficiently liquid to be recovered by pumping operations and some is already being recovered by this method. Recovery depends not only on the characteristics of the oil but also on the characteristics of the reservoir—including the temperature of the reservoir and the pour point of the oil (see also chapter: Evaluation
of Reservoir Fluids). These heavy oils fall into a range of high viscosity and the viscosity is subject to temperature effects , which is the reason for the application of thermal methods to heavy oil recovery.

Finally, the formation of stable emulsions of water and oil is a phenomenon frequently found in the production of heavy oils. Emulsions are formed during simultaneous flow of oil and water, although it is also supposed to occur while still in the reservoir. The flow of the mixture of liquids through devices and equipment that impose a high shear rate, such as in pumps and valves, in pipe singularities and even along lines, will induce emulsion formation. Gas and solid particulates are additional factors that increase the shear rate, intensifying emulsification. The shear rate is a
strong factor in emulsion formation, but rheology and fluid properties also play important roles. In addition, the tendency of heavy oil to form foam (foamy oil) must also be taken into account during the release of dissolved
gas, in a type of gas and liquid limiting compressible emulsion. All such characteristics will influence the flow in the reservoir, wellbore, and flow lines as well as having an impact on other processes, such as separation.
Finally, some heavy oils found in offshore fields have a high content of organic acids. The acidity rate, measured by TAN (total acid number), is particularly important to refining processes. Currently refineries need to take precautions to prevent acidic corrosion of the equipment as well as contributing to the precipitation of organo-metallic salts, causing buildups in processing equipment.

The term tar sand, also known as oil sand (in Canada), or (more correctly) bituminous sands, commonly describes sandstones or friable sand (quartz) impregnated with viscous bitumen (a hydrocarbonaceous material soluble in carbon disulfide). Significant amounts of fine material, usually largely or completely clay, are also present. The degree of porosity varies from deposit to deposit and is an important characteristic in terms of recovery processes. The bitumen makes up the desirable fraction of the tar sand from which liquid fuels can be derived . However, the bitumen is usually not recoverable by conventional petroleum production techniques . Furthermore, the properties and composition of the tar sands and the bitumen significantly influence the selection of recovery and treatment processes and vary among deposits. In the tar sands that are recognized as being water-wet (rather than bitumen-wet) in the Athabasca deposit, a layer of water surrounds the sand grain, and the bitumen partially
fills the voids between the wet grains. On the other hand, the Utah tar sands lack the water layer and the bitumen is directly in contact with the sand grains without any intervening water. Typically, more than 99% w/w of the
mineral matter is composed of quartz and clay minerals. The Utah deposits range from largely consolidated sands with low porosity and permeability to, in some cases, unconsolidated sands. High concentrations of heteroatoms
tend to increase viscosity, increase the bitumen–sand reactions and bitumen– minerals reactions making processing more difficult.
Tar sands are sedimentary rocks containing bitumen, a viscous hydrocarbonaceous mixture. Tar sand deposits may be divided into two major types: (1) a breached reservoir where erosion has removed the capping layers from a reservoir of relatively viscous material, allowing the more volatile petroleum hydrocarbons to escape; and (2) deposits that formed when liquid petroleum seeps into a near-surface reservoir from which the more volatile constituents escaped. In either type of deposit, the lighter, more volatile constituents have escaped to the environment, leaving the less volatile constituents in place which are altered by contact with air, bacteria,
and groundwater. Because of the very viscous nature of the bitumen in tar sands, tar sands cannot be processed by the typical petroleum production techniques.

Tar sand deposits occur throughout the world and the largest deposits occur in Alberta, Canada (the Athabasca, Wabasca, Cold Lake, and Peace River areas), and in Venezuela. Smaller deposits occur in the United States, with the larger individual deposits in Utah, California, New Mexico, and Kentucky.
The term bitumen (also, on occasion, referred to as native asphalt, and extra heavy oil), which is the organic component of tar sand, includes a wide variety of reddish brown to black materials of semisolid, viscous
to brittle character that can exist in nature with no mineral impurity or with mineral matter contents that exceed 50% by weight. Bitumen is frequently found filling pores and crevices of sandstone, limestone, or argillaceous sediments, in which case the organic and associated mineral matrix is known as rock asphalt However, bitumen from different
deposits (eg, deposits in the United States and Canada, exhibit a variety of properties).

Bitumen is a naturally-occurring material that is found in deposits where the permeability is low and passage of fluids through the deposit can only be achieved by prior application of fracturing techniques.

Tar sand bitumen is a high-boiling material with little, if any, material boiling below 350°C (660°F) and the boiling range is approximately the same as the boiling range of an atmospheric residuum.

Post Author: AONG manager

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