Bitumen formation

In a general sense, however, the term heavy oil is often appHed to a petroleum that has a gravity <20° API. The term heavy oil has also been arbitrarily used to describe both the heavy oil that requires thermal stimulation for recovery from the reservoir and the bitumen in bituminous sand (also known as tar sand or oil sand) formations, from which the heavy bituminous material is recovered by a mining operation. Extra heavy oil is the subcategory of petroleum that occurs in the near-soHd state and is incapable of free flow under ambient conditions. The bitumen from tar sand deposits is often classified as an extra heavy oil. 

Many of the reserves of bitumen in tar sand formations are available only with some difficulty, and optional refinery methods are necessary for future conversion of these materials to Hquid products, because of the substantial differences in character between conventional petroleum (qv) and bitumen (Table 1). 

The API gravity of tar sand bitumen varies from 5 to ca 10°API, depending on the deposit, and the viscosity is very high. Whereas conventional cmde oils may have a high (>100 MPa-s(=cP)) viscosity at 40°C, tar sand bitumen has a viscosity on the order of 10-100 kPa-s(10 -10 P) at formation temperature (ca 0—10°C), depending on the season. This offers a formidable obstacle to bitumen recovery and, as a result of the high viscosity, bitumen is relatively nonvolatile under conditions of standard distillation (Table 4) (12,13), which influences choice of the upgrading process. 

In principle, the nonmining recovery of bitumen from tar sand deposits is an enhanced oil recovery technique and requires the injection of a fluid into the formation through an injection weU. This leads to the in situ displacement of the bitumen from the reservoir and bitumen production at the surface through an egress (production) weU. There are, however, several serious constraints that are particularly important and relate to the bulk properties of the tar sand and the bitumen. In fact, both recovery by fluid injection and the serious constraints on it must be considered in toto in the context of bitumen recovery by nonmining techniques (see PETROLEUM, ENHANCED OIL RECOVERY). 

If the viscous bitumen in a tar sand formation can be made mobile by an admixture of either a hydrocarbon diluent or an emulsifying fluid, a relatively low temperature secondary recovery process is possible (emulsion steam drive). If the formation is impermeable, communication problems exist between injection and production weUs. However, it is possible to apply a solution or dilution process along a narrow fracture plane between injection and production weUs. 

Small concentrations of volatile components in a liquid mixture may accumulate in the vapor space of a container over time and appreciably reduce the flash point relative to the reported closed-cup value. This may be the result of degassing, chemical reaction or other mechanism. An example is bitumen [162]. Similarly, if a tank truck is not cleaned between deliveries of gasoline and a high flash point liquid such as kerosene or diesel oil, the mixture might generate a flammable atmosphere both in the tmck tank and the receiving tank. Contamination at the thousand ppm level may create hazards (5-1.4.3 and 5-2.5.4). Solids containing upward of about 0.2 wt% flammable solvent need to be evaluated for flammable vapor formation in containers (6-1.3.2). 

Optionally, the pH of the aqueous phase of the broken emulsion, after doing the job, can be adjusted to become alkaline. The salts of the polymers are converted into inactive species and the aqueous phase of the broken emulsion can be reinjected into ahydrocarbon-containing formation to recover additional hydrocarbons or bitumen [1187] as an improved oil-recovery process. 

Polyalkylene polyamine salts are prepared by contacting polyamines with organic or inorganic acids. The polyamines have a molecular weight of at least 1000 Dalton and ranging up to the limits of water solubility [1185]. In a process of demulsification of the aqueous phase of the broken bitumen emulsions, the pH is adjusted to deactivate the demulsifier so that the water may be used in subsequent in situ hot water or steam floods of the tar sand formation. 

Isaacs and Smolek [211 observed that low tensions obtained for an Athabasca bitumen/brine-suIfonate surfactant system were likely associated with the formation of a surfactant-rich film lying between the oil and water, which can be hindered by an increase in temperature. Babu et al. [221 obtained little effect of temperature on interfacial tensions however, values of about 0.02 mN/m were obtained for a light crude (39°API), and were about an order of magnitude lower than those observed for a heavy crude (14°API) with the same aqueous surfactant formulations. For pure hydrocarbon phases and ambient conditions, it is well established that the interfacial tension behavior is dependent on the oleic phase [15.231 In general, interfacial tension values of crude oiI-containing systems are considerably higher than the equivalent values observed with pure hydrocarbons. 

In n-octane/aqueous systems at 27°C, TRS 10-80 has been shown to form a surfactant-rich third phase, or a thin film of liquid crystals (see Figure 1), with a sharp interfacial tension minimum of about 5x10 mN/m at 15 g/L NaCI concentration f131. Similarly, in this study the bitumen/aqueous tension behavior of TRS 10-80 and Sun Tech IV appeared not to be related to monolayer coverage at the interface (as in the case of Enordet C16 18) but rather was indicative of a surfactant-rich third phase between oil and water. The higher values for minimum interfacial tension observed for a heavy oil compared to a pure n-alkane were probably due to natural surfactants in the crude oil which somewhat hindered the formation of the surfactant-rich phase. This hypothesis needs to be tested, but the effect is not unlike that of the addition of SDS (which does not form liquid crystals) in partially solubilizing the third phase formed by TRS 10-80 or Aerosol OT at the alkane/brine interface Til.121. 

Using a "home made" aneroid calorimeter, we have measured rates of production of heat and thence rates of oxidation of Athabasca bitumen under nearly isothermal conditions in the temperature range 155-320°C. Results of these kinetic measurements, supported by chemical analyses, mass balances, and fuel-energy relationships, indicate that there are two principal classes of oxidation reactions in the specified temperature region. At temperatures much lc er than 285°C, the principal reactions of oxygen with Athabasca bitumen lead to deposition of "fuel" or coke. At temperatures much higher than 285°C, the principal oxidation reactions lead to formation of carbon oxides and water. We have fitted an overall mathematical model (related to the factorial design of the experiments) to the kinetic results, and have also developed a "two reaction chemical model". 

We propose that the complicated dry oxidation of bitumen can be represented as the sum of contributions from two classes of oxidation reaction. One class of reactions is the partial oxidation that leads to deposition of coke and formation of "oxygenated bitumen", with very little production of carbon oxides and water. This class of reactions is concisely summarized by... 

The moist sulfide readily oxidises in air exothermally, and may reach incandescence. Grinding in a mortar hastens this [1]. The impure sulfide formed when steel processing equipment is used with materials containing hydrogen sulfide or volatile sulfur compounds is pyrophoric, and has caused many fires and explosions when such equipment is opened without effective purging. Various methods of purging are discussed [2], Formation of pyrophoric FeS in bitumen tanks is considered as a cause of spontaneous ignition and explosion in the head space [3], A detailed study of formation of possibly pyrophoric sulphides from rust in crude oil tankers has been made [4],... 

Gray, M. R., and McCaffrey, W. C., Role of Chain Reactions and Olefin Formation in Cracking, Hydroconversion, and Coking of Petroleum and Bitumen Fractions. Energy Fuels, 2002. 16(3) pp. 756-66. 

Bituminous sand a formation in which fhe bifuminous material (see Bitumen) is found as a filling in veins and fissures in fractnred rocks or impregnating relatively shallow sand, sandstone, and limestone strata a sandstone reservoir that is impregnated with a heavy, viscons black petroleumlike material that cannot be retrieved throngh a well by conventional production techniqnes. 

By far the most widespread use of NMR in an on-line production environment is the utilization of downhole exploration tools by petroleum service companies such as Schlumberger, Halliburton, and Baker Hughes. Articles on these unilateral NMR systems are found in the patent databases, " academic literature, and on-line resources provided by the exploration companies. The references provided here are just a few examples in a very prolific field. The technique is applied in high-temperature and pressure situations and currently is used down to a depth of about 10 km (6 miles) to produce a picture of water/oil content in the adjacent rock formations as well as to derive permeability, diffusivity, and hydrocarbon chemistry information. Mobile unilateral NMR systems such as the NMR-MOUSE are also being developed in order to take benchtop NMR systems into the field to perform analysis of geological core samples at the drill site. NMR analyzers are also being developed to determine the bitumen content and properties in tar sand production and processing. " " ... 

Recovery of oil sand bitumen by steam injection involves either cyclic or continuous injection of steam at high pressure into a well. In cyclic injection, steam is injected into the oil sand formation for a period of time ranging from weeks to months. The steam spreads or floods the formation creating heat or pressure. The steam is then turned off, and the well is sealed for weeks to months. When the well is reopened, a mixture of water and bitumen can be withdrawn. 

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