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===Steam-assisted gravity drainage===
===Steam-assisted gravity drainage===
Steam-assisted gravity drainage (SAGD), used in horizontal wells, involves steam injection for viscosity reduction and gravity segregation for flow.<ref name="r11" /> Prototype wells were drilled from an underground mine from 1984 to 1986, and the first commercial projects began production in Canada in 2001.
[[Steam assisted gravity drainage|Steam-assisted gravity drainage]] (SAGD), used in horizontal wells, involves steam injection for viscosity reduction and gravity segregation for flow.<ref name="r11" /> Prototype wells were drilled from an underground mine from 1984 to 1986, and the first commercial projects began production in Canada in 2001.
===Cold production===
===Cold production===

Revision as of 16:03, 27 January 2014

Heavy oil is defined as liquid petroleum of less than 20°API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12°API gravity and greater than 10,000 cp are sometimes used to define oil sands.[1][2][3][4] The oil in oil sands is an immobile fluid under existing reservoir conditions, and heavy oils are somewhat mobile fluids under naturally existing pressure gradients. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation. Many heavy oil reservoirs are located in unconsolidated sandstones.

Importance of heavy oil

World conventional oil (light oil greater than 20°API) supply rates will peak eventually and enter into decline because of increasing world demand, inexorable reservoir production rate decline, and the indisputable fact that few new sedimentary basins remain to be exploited. Many believe that this will occur between 2005 and 2010.[5][6] Thereafter, light oil production will decline gradually at a rate that may be slowed but not reversed by the introduction of new technologies such as gravity drainage and pressure pulsing. Fig. 1 shows world oil production predictions. Simply put, conventional oil is running out because new basins are running out. Furthermore, exploitation costs are large in deep, remote basins (deep offshore, Antarctic fringe, Arctic basins). Only larger finds will be developed, and recovery will be less than for "easy" basins.

Nevertheless, the world will never run out of oil for several reasons. First, conventional oil comprises a small fraction of hydrocarbons in sedimentary basins. Table 1 shows relative hydrocarbon resource size. Second, as technology evolves, other energy sources (ethanol, hydrogen cycle) will displace oil, just as oil displaced coal. Third, even if all the organic carbon (oil, gas, coal, kerogen) in basins is consumed, oil can be manufactured from wood or assembled from its elements, given a sufficiently high commodity price. To put the available heavy-oil resource into context, in Canada alone it is so large (~400 × 109 m3) that, at a US and Canadian consumption rate of 1.2 × 109 m3/yr, there is enough heavy oil to meet 100% of this demand for more than 80 years if the overall extraction efficiency is approximately 30%.

The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record.[7] Commodities have never been cheaper, efficiency is increasing, and new ideas such as deep biosolids injection may generate new sources of energy or may recycle energy.[8] It is interesting to read the predictions of doomsayers[9] in the context of continued technological advances. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine.[10]

These predictions relate to heavy oil for the following reasons. First, new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas new technologies can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years).

Historical production technologies

Before 1985, heavy-oil production was based largely on thermal stimulation, ΔT, to reduce viscosity and large pressure drops, Δp, to induce flow. Projects used:

  • Cyclic steam stimulation (huff 'n' puff)
  • Steam flooding
  • Wet or dry combustion with air or oxygen injection


  • Combinations of the above methods

Until recently, these technologies used arrays of vertical to mildly deviated wells (< 45°). Some methods have never proved viable for heavy oil. These include:

  • Solvent injection
  • Biological methods
  • Cold gas (i.e., CH4, CO2, etc.) injection
  • Polymer methods
  • In-situ emulsification

Also, all high-pressure methods experienced advective instabilities such as:

  • Viscous fingering
  • Permeability channeling
  • Water or gas coning
  • Uncontrolled (upward) hydraulic fracture propagation

Marginally economical nonthermal production with vertical wells was used in Canada, but wells typically produced less than 10 m3/d, recovery was less than 5 to 8% original oil in place (OOIP), and small amounts of sand usually entered the wellbore during production.

Newer technologies for recovering heavy oil

Steam-assisted gravity drainage

Steam-assisted gravity drainage (SAGD), used in horizontal wells, involves steam injection for viscosity reduction and gravity segregation for flow.[11] Prototype wells were drilled from an underground mine from 1984 to 1986, and the first commercial projects began production in Canada in 2001.

Cold production

Cold production is nonthermal heavy-oil production without sand. Economical rates are achieved by exploiting the large drainage area of long horizontal wells completed with slotted liners. In Canada, economic success in oils less viscous than approximately 1500 cp is common, even though production rates may drop by 40% per year and the OOIP recovery is less than 10%. This technology has found major application in the Faja del Orinoco in Venezuela, where multilateral branches are added to further increase the well drainage area.[12]

Cold heavy oil production with sand

Cold heavy oil production with sand (CHOPS) exploits the finding that sand ingress can enhance the oil rate by an order of magnitude or more in heavy-oil UCSS. Pressure-pulsing technology (PPT) is a flow rate enhancement method introduced in heavy-oil fields that used CHOPS between 1999 and 2001.[13] The approach, applicable to any liquid-saturated porous medium, involves applying repeated tailored pressure pulses to the liquid phase. This has the effect of suppressing advective instabilities such as viscous fingering or permeability channeling, overcoming capillary barriers, and reducing pore-throat blockage.

Vapor-assisted petroleum extraction

Vapor-assisted petroleum extraction (VAPEX) is, in terms of physics and flow processes, the same process as SAGD, except that a condensable and noncondensable gas mixture (e.g., CH4 to C4H10) is used to reduce the oil viscosity.[14] VAPEX approaches can be integrated with SAGD approaches, such as by cycling between steam and miscible gases, the use of a mixture, injection of heated gas ("warm" VAPEX), etc. As with SAGD, all VAPEX variations use gravitationally stabilized flow to avoid advective instabilities and achieve higher recovery.

Toe-to-heel air injection

Toe-to-heel air injection (THAI), essentially, is in-situ combustion but with horizontal wells so that the combustion products and heated hydrocarbons flow almost immediately downward into the horizontal production well, rather than having to channel through long distances and experience gas override and fingering.[15]

Hybrid modes of heavy-oil technologies

Proven and emerging technologies will be used more and more in hybrid modes to achieve better recovery and investment returns. For example, CHOPS gives high early production rates, but SAGD gives better overall hydrocarbon recovery, suggesting phased or simultaneous use of the methods. Also, different technologies will be found to be suitable for different reservoirs and conditions. SAGD and other thermal methods are very inefficient in reservoirs less than 15 m thick, whereas CHOPS and pressure pulsing technology (PPT) have been successful economically in such cases. All these technologies will benefit from improvements in thermal efficiency, process control, and cost reductions.[16]

Key heavy oil deposits

Typical Canadian reservoirs

Heavy-oil development with CHOPS takes place in the Canadian heavy-oil belt (Fig. 2) in reservoirs that may range from extensive 3- to 5- m thick blanket sands to 35-m-thick channel sands with sinuous traces no wider than a kilometer. All reservoirs are UCSS with φ ~ 28 to 32% and k~ 0.5 to 15 darcy, depending on grain size. The highest k values are for occasional gravel seams found in river channel deposits; most reservoirs have average permeabilities of 1 to 4 darcy. It is impossible to obtain undisturbed specimens from these reservoirs because gas exsolution causes irreversible core expansion (the high oil viscosity impedes gas escape).[2] Therefore, porosities are back-calculated from well logs, and permeabilities are back calculated from grain-size correlations and a limited number of well tests.

With the exception of a few geologically older fields, all the heavy oil unconsolidated sandstone (UCSS) reservoirs in Alberta and Saskatchewan are found in the Lower and Middle Mannville group, an undeformed and flat-lying Middle Cretaceous clastic sequence comprising:

  • sands
  • silts
  • shales
  • a few coal seams
  • thin (< 0.5 m) concretionary beds

The depositional environment ranged from channel sands laid down in incised valleys carved several tens of meters into underlying sediments, to estuarine accretion plains formed by lateral river-channel migration on a flat plain, to deltaic, shallow marine, and offshore bar sands. The UCSS mineralogy ranges from quartz arenites (> 95% SiO2 ) to litharenites and arkoses. The more mature sands at the base of the Mannville group tend to be more quartzose.

A typical CHOPS stratum is a 10-m-thick fine- to medium-grained UCSS (D50 of 80 to 150 μm, k = 2 darcy) with So~ 88%, Sw~ 12%, and Sg= 0 at a depth, z, of 400 to 800 m. Initial pressure, po , is on the order of 3 to 7 MPa, and reservoirs are most often underpressured. Taking γ¯ as mean overburden unit weight (γ¯=ρ¯z), generally po~ 0.7 to 0.9γ¯z.

Heavy oil accumulations in the Faja del Orinoco

Fig. 3 shows the Faja del Orinoco in Venezuela, which contains one of the richest accumulations of heavy oil in the world, approximately 250 ×109 m3 (similar in scale to the Canadian deposits).

The host Oficina formation is a fluvial and marine-margin deposit. Apparently, there were a number of large estuarine accretion plains and deltaic complexes (at least four) formed by rivers that drained the Guyana shield to the south. The focal area of deposition changed with sea level in response to sedimentation, the formation of the mountains to the north, and the subsidence of the eastern Venezuelan basin. The deposit is a unitary sequence of strata with general east-west continuity. Individual sand bodies range in thickness up to 40 to 45 m, although the majority of "discrete" oil-bearing beds are 8 to 12 m thick, with sharp lower boundaries from lateral erosional migration of channels and more gradational upper boundaries. Good permeability interconnectivity is shown by a high oil-saturation state in the vertical sequence of strata. Some sand bodies are thick channel sands of almost uniform properties over many meters; others contain multiple laminae of silt and have poor vertical flow properties. In general, the upper beds are of lower quality than the lower beds.

The Faja del Orinoco is a remarkably rich deposit, far richer locally than the Canadian deposits, although smaller in total reserves. Many sequences 100 to 150 m thick contain 60% net pay (i.e., 110 to 120 m of total pay), averaging greater than 80% oil saturation. The lower two to three zones have high permeability (3 to 15 darcy), are 20 to 30 m thick, and are laterally extensive. These reservoirs will be developed more extensively with the existing and emerging technologies mentioned previously.


  1. National Energy Board,
  2. 2.0 2.1 Alberta Energy Utilities Board,
  3. Saskatchewan Energy and Mines,
  4. Statistics Canada,
  5. Campbell, C.J. and Laherrère, J.H. 1998. The End of Cheap Oil. Sci. Am. 278 (3): 78–83.
  6. Deffeyes, K.S. 2001. Hubbert’s Peak: The Impending World Oil Shortage, 208. Princeton, New Jersey: Princeton University Press.
  7. Simon, J.L. 1996. The Ultimate Resource, second edition, 734. Princeton, New Jersey: Princeton University Press.
  8. "Slurry Fracture Injection," Terralog Technologies Inc.,
  9. Ehrlich, P.R. 1968. The Population Bomb. New York City: Ballantine Press.
  10. Report on the Limits to Growth. 1972. Washington, DC: Intl. Bank for Reconstruction and Development.
  11. Butler, R. 1998. SAGD Comes of Age! J Can Pet Technol 37 (7): 9–12. JCPT Paper No. 98-07-DA.
  12. Santos, R., Robertson, G., and Vasquez, M. 2001. Geologic Reality Altered Cerro Negro Development Scheme. Oil Gas J. 99 (4).
  13. Dusseault, M., Davidson, B., and Spanos, T. 2000. Pressure Pulsing: The Ups And Downs of Starting a New Technology. J Can Pet Technol 39 (4). PETSOC-00-04-TB.
  14. Oduntan, A.R. et al. 2001. Heavy Oil Recovery Using the VAPEX Process: Scale-Up Issues. Proc., CIM Petroleum Society 51st Annual Technical Meeting, Calgary, paper 2001-127.
  15. Greaves, M. et al. 2001. New Heavy Oil Technology for Heavy Oil Recovery and In Situ Upgrading. J. Cdn. Pet. Tech. 40 (3): 38.
  16. Greaser, G.R. and Ortiz, J.R. 2001. New Thermal Recovery Technology and Technology Transfer for Successful Heavy Oil Development. Presented at the SPE International Thermal Operations and Heavy Oil Symposium, Porlamar, Margarita Island, Venezuela, 12-14 March 2001. SPE-69731-MS.

Noteworthy papers in OnePetro

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See also

Cold heavy oil production with sand

PEH:Cold Heavy-Oil Production With Sand