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| Fig. 1: Heavy crude oil with API gravity less than 20. (Source: K. R. Alnoaimi) |
The recovery of heavy crude oil is commonly practiced in countries such as USA, Canada and Venezuela. According to the International Energy Agency (IEA), the estimated volumes of heavy oil worldwide are about 6 trillion barrels, of which 2.5 trillion barrels are in Canada, 1.5 trillion barrels are in Venezuela, 1 trillion barrels are in Russia and 100 to 180 billion barrels are in the USA. [1] The increasing demand for energy in the world makes recovery of this oil essential. Accordingly, many technologies for extracting this complex mixture out of the ground have been explored. The technologies that use heat are referred to as thermal recovery techniques.
Heavy oil is a complex mixture that does not flow easily. This is shown in Fig. 1. Its viscosity ranges from 10,000 cp to 10,000,000 cp (centipoise). The API (American Petroleum Institute) gravity, or density, of this component is defined as less than 20. The API gravity is related to the conventional specific gravity ρ by
Water, for example, which has ρ = 1 has an API gravity of 10. The recovery of oil with such extreme properties is difficult, as is processing such oil. Heavy oil is a hydrocarbon compound, yet it is deficient in hydrogen compared to lighter hydrocarbons. Oil refineries prefer receiving oil with 32-36 API because heavier oil requires more refining and produces a smaller volume of petroleum products such as jet fuel or gasoline. Heavy oil is in this sense of lower quality. The process of increasing its quality involves either by increasing the number of hydrogen atoms or decreasing the number of carbons in the structure.
Heat is the primary element used for heavy oil recovery. The technologies typically involve injecting hot fluids into the oil reservoirs in order to increase the temperature of that reservoir and reduce oil viscosity. The effect of heat on viscosity significant. As can be seen in Fig. 2, heating the crude can lower its viscosity by several orders of magnitude.
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| Fig. 2: A viscosity-temperature plot of heavy oil measured in my lab. |
There are many empirical relations that describe the viscosity of heavy oil at different temperatures. They generally provide good estimates. As the viscosity of oil decreases, its mobility increases. The oil mobility is the ratio of the effective permeability to the oil flow to its viscosity. This is given by
where λ0 is the oil mobility in mD/cp, k0 is the oil effective permeability in mD and μ0 is the oil viscosity in cp.
After the viscosity of oil is reduced and the mobility is increased, the displacement of oil by another fluid becomes easier. In fact, the oil may even drain by gravity to bottom layers if the viscosity reaches small values. Therefore, the heavy oil would become much lighter and easier to drive to producer wells.
A typical reservoir formation consists of a matrix and possible fractures along given zones. The types of heat dissipating through each are different. Heat dissipation is attributed to several heat transfer mechanisms but majorly by either conduction or convection. Heating by conduction occurs when energy is transferred in a form of heat due to a temperature gradient between adjacent particles within a substance. When steam, for example, is injected in the formation matrix, its heat is transferred to the molecules it contacts, which, in turn, conduct the heat to neighboring molecules and so on. The heat transfer rate, however, decreases with distance and this is the reason behind the negative sign in the equation shown below which shows the heat transfer by conduction:
Here μλ is the local heat flux in W m-2, λ is the thermal conductivity of the material in W m-1 K-1, T is temperature in °K and x is the distance in m.
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| Table 1: Thermal conductivities of some common materials. [2] |
The thermal conductivity differs from a material to another and in definition it is a measurement of how much heat a material can conduct. Table 1 shows the thermal conductivity values of some common materials. The process of heat transfer by conduction is slower than heating by convection. Heating by convection occurs when steam flows in the fractures within the reservoir, heat is then transferred by the movements of particles within the steam to heat the volumes occupied by the steam. Since steam is injected through pumps to the subsurface, the process of heat transfer is said to be forced convective heating. Such a process accelerates the rate of heat exchange between the fluid and the rock. The following equation shows the heat transfer equation by convection:
Here uT is the convective heat flux in kJ/m2 d, u is the volumetric flux in m/d, ρ is the steam density in kg/m3, C is isobaric specific heat in kJ/kg K, T is steam temperature in °K and Tr is the reservoir temperature in °K.
During every convection heat transfer process, transfer by conduction occurs as well. This process is shown in Fig. 3.
To illustrate the heat balance equation clearly, several important quantities need to be introduced. The total heat injected, Qi, requires knowledge of mass injected, steam quality, latent heat of vaporization and temperatures of steam and reservoir. Steam quality determines the capacity of heat stored in the water vapor phase. Latent heat of vaporization is how much extra heat steam can hold compared to water at the same temperature. (For numerical examples of overall heat balance calculations see reference [3,4].)
After calculating the amount of heat injected into the reservoirs, the heat loss amount must be estimated in order to know how much energy went into heating the oil. There are many models that predict heat loss analysis, one of which is presented by Pratz. [4] In a typical steam drive process, steam is generated in surface and is injected from the wellhead to the intended zone of production in the reservoir. The process involves flow transportation through several units. The distribution of heat can be controlled by understanding the mechanism by which heat is transferred. For example, if steam is injected into insulated surface lines then heat is most likely to be lost from steam by convection to the pipe wall and by conduction between the pipe wall and the insulation wall. If the surface lines are uninsulated, then loss by radiation governs the process and so on. Without going into much detail, the heat transfer rate of any mechanism is calculated through the estimation of the heat transfer coefficient.
The combination of conductive and convective heat transfer coefficients is the overall heat transfer coefficient that is the reciprocal of the overall specific thermal resistances of system. The higher the heat transfer coefficient, i.e. the more heat is transferred, the less the thermal resistance is. Usually in practice the resistance of one component dominates the total thermal resistances of the system. If the dominant resistance is determined, then, the calculations can be simplified greatly by cancelling out the other terms that have negligible effects. For most cases, the rate of heat loss is considered steady-state per unit length of pipe and is directly proportional to the difference in temperature between steam and the surrounding medium but inversely to the overall specific thermal resistance of the system. [4] Therefore, for a given reservoir, it is possible to calculate the amount of heat injected followed by heat loss analysis to determine how much heat is lost, and thus, know how much heat is in the reservoir. These calculations clarify important numbers such as how much steam to inject, at what rates, for how long and at what quality. The calculations also clarify important numbers in heat loss analysis such as rate of heat lost to the formation whether by convective or conduction mechanisms, diffusion or conductivity, and how fast the loss is. For more details with real numbers in case studies, look at Pratz who did several heat loss analyses at different injection conditions after calculating the cumulative heat injected in to the reservoirs. [4]
The last important point to mention is the temperature profile in the reservoir and how steam temperature propagates gradually in the productive zone and the overburden and underburden. It can be seen in Fig. 4 that at day 1 the temperature around the injector is at steam temperature and it starts to decrease as it moves away from the well in both directions until it reaches the original reservoir temperature. After 10 days, more areas are heated and this can be observed by the increase of the temperatures near the injector. After 100 days, the temperature profile looks more uniform and if the injection lasts for another 100 days, the profile will become more constant.
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| Fig. 3: A cartoon showing the heat transfer mechanisms in molecules. |
After knowing the temperature of the heated zone, the oil viscosity can be measured at that temperature either by the empirical formulas or in the lab together with some rock properties from rock samples extracted from the same zone. The oil flow rate is, then, estimated based on the knowledge of these data using the Darcy law
where Q is the oil flow rate in m3/s, k is the effective permeability of oil in m2, A is the cross-sectional area to flow in m2, is the pressure differential between two points in Pascal, is the oil viscosity in Pa.s and L is the length in which pressure drop is occurring. This analysis allows the engineer to predict the amount of oil recovered for given time of steam injection.
Oil reservoirs differ from a place to another in terms of geological structures as well as subsurface conditions such as temperature and pressure. Therefore, the technologies used in the oil industries for heat injection in any reservoir depend on the reservoir's nature and type. For example, steam flood process is used for shallow reservoirs while in-situ combustion process is used for deep ones. Proper analysis and sufficient study of the reservoir conditions leads to a better technology screening. The most common thermal technologies used are steam flood, cyclic steam stimulation, hot water flood and in-situ combustion processes. These technologies are in particular used for heavy oil recovery. Every technology has distinctive features and hence is used to serve different purposes. [3]
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| Fig. 4: Temperature profile during steam flood process across the productive, overburden and underburden zones. |
Cyclic steam stimulation, also known as "huff-and-puff" involves the injection of steam into a reservoir for some time and then shutting in the well for sufficient time. This enables steam to soak, and therefore, heats the reservoir and mitigates oil mobility. After some time, the well is allowed to flow and production is resumed. This process may be repeated for several times until certain volumes of injected fluid are produced or the reservoir pressure is decreased.
Steam flooding process involves steam injection through injection wells to an oil reservoir. The areas around the injection wells are heated up to steam temperature. The steam front starts condensing to hot water which still conducts heat to the system at lower level than steam and drives oil toward production wells. The process becomes more efficient if thermal communications are established between the injection and production wells. The oil production, then, becomes more fluent as its viscosity is significantly reduced.
In a similar fashion to steam flooding, hot water is injected through injection wells to oil reservoirs. Heat decreases oil viscosity and the water displaces it to production wells. The process, however, is less efficient compared to steam flooding because it carries less heat than steam, and therefore, produces less oil.
Unlike steam flooding, in-situ combustion, generates heat in the reservoir subsurface by burning some of the oil in place. This would produce a combustion zone that heats the oil. This process causes less heat to be lost to surface units and surrounding formations, and makes the heat control process more efficient than surface heat generation. The combustion occurs by ignition when an igniter is lowered into the injection well and oxygen or air is injected into that well. When ignition occurs the source is removed and air injection continues to keep the combustion front burning.
In conclusion, the recovery of heavy oil is a difficult task but is unavoidable especially when the prices of oil are high. The volumes of heavy oil in the ground are huge and must be well produced. It is majorly heat that reduces the viscosity of the heavy crude oil. This explains why the existing technologies of recovering heavy oil are thermal. Nevertheless, they involve high energy consumptions and so proper strategies of heat loss control must be studied before field implementation. Technical and economical screenings of thermal technologies are essential. Information about the black box, the reservoir, is important and detailed engineering calculations are required for heat loss prediction.
© Khalid Rashid Alnoaimi. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
[1] Oil and Gas Technologies for the Energy Markets of the Future (International Energy Agency, Paris, 2005), p 75.
[2] K. J. Horai, Geophys. Res. 76, 1278 (1971).
[3] R. M. Butler, Thermal Recovery of Oil and Bitumen (Prentice-Hall, 1991).
[4] M. Prats, Thermal Recovery (Society of Petroleum Engineers AIME, 1986).