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Reserves estimation of heavy oil
Discovered resources of heavy and extraheavy crude oil are estimated to be approximately 4,600 billion bbl, two-thirds of which are in Canada and Venezuela.[1] Bitumen and tar sands are excluded from this estimate. Published data on reserves estimates (RE) from this resource by primary drive mechanisms are sparse. Meyer and Mitchell[2] estimated worldwide ultimate recovery from heavy and extraheavy crude oils to be 476 billion bbl, which is 10% of the Briggs et al.[1] estimate of the discovered resource initially in place. Estimated primary reserves estimates (RE) ranges from 8 to 12% oil-in-place (OIP) for the Orinoco area of Venezuela, where stock-tank gravities range from 8 to 13°American Petroleum Institute (API).[3] Estimated primary RE ranges from 3 to 8% OIP[4] for the Lloydminster area of western Canada, where stock-tank gravities range from 13 to 17°API.
Case study
Primary RE vs. API gravity for heavy crude oil “pools” in Alberta and Saskatchewan is plotted on Fig. 1[5]. Data are from 69 “pools” with OIP > 106 m3 (6.3 million STB). The trend line is not weighted by resource size and is shown only for reference; the regression coefficient, 0.21, is too small to infer a statistically significant correlation between RE and oil gravity. Of interest, however, is that the trend line is consistent with REs shown on Table 1 for “average” sandstone for 15°API and slightly-higher-gravity oils. Also interesting (lack of correlation notwithstanding) is the large number of heavy-oil reservoirs with significantly greater REs than would be predicted using “conventional” solution gas drive calculations. Reportedly, such REs are attributed to two mechanisms:
![Fig. 1 - Observed oil RE as related to oil gravity for 69 pools in Alberta and Saskatchewan (after Cronquist[5])](/w/images/thumb/4/40/Vol5_Page_1545_Image_0001.png/286px-Vol5_Page_1545_Image_0001.png)
Fig. 1 - Observed oil RE as related to oil gravity for 69 pools in Alberta and Saskatchewan (after Cronquist[5])
Table 1
![Fig. 1 - Observed oil RE as related to oil gravity for 69 pools in Alberta and Saskatchewan (after Cronquist[5])](/File:Vol5_Page_1545_Image_0001.png)
Although there are reports of REs that range from 5 to 20% OIP,[6][8] no general correlations are available that relate specific rock/fluid properties and REs for heavy oil; thus, for volumetric methods, reserves engineers typically rely on analogy. The performance of wells in heavy oil reservoirs is erratic, however, and is influenced by varying production practices, varying volumes of sand production, and frequent downtime, among other factors, so that analogy estimates are subject to considerable uncertainty.
Reserves estimates based on performance also are subject to considerable uncertainty. Production rates for single wells usually are erratic, thereby precluding meaningful trend analysis. Many engineers generate normalized production curves from groups of wells producing from zones comparable to those being analyzed.
Summary
The producing mechanisms for heavy oil are poorly understood; an optimum production strategy has yet to be developed; a priori prediction of the efficiency of the production mechanisms for heavy oil currently is impossible. Although progress is being made on computer modeling,[9] it may be several years before sufficient data are compiled for reliable estimates of RE and/or reserves from heavy oil.
References
- ↑ 1.0 1.1 Briggs, P.J., Baron, P.R., Fulleylove, R.J. et al. 1988. Development of Heavy-Oil Reservoirs. J Pet Technol 40 (2): 206-214. SPE-15748-PA. http://dx.doi.org/10.2118/15748-PA.
- ↑ Meyer, R.F. and Mitchell, R.W. 1987. A Perspective on Heavy and Extra Heavy Oil, Natural Bitumen, and Shale Oil. Paper presented at the 1987 Twelfth World Petroleum Congresses, Houston.
- ↑ Martinez, A.R. 1987. The Orinoco Oil Belt, Venezuela. J. of Petroleum Geology 10: 125.
- ↑ Adams, D.M. 1982. Experiences With Waterflooding Lloydminster Heavy-Oil Reservoirs. J Pet Technol 34 (8): 1643-1650. SPE-10196-PA. http://dx.doi.org/10.2118/10196-PA.
- ↑ 5.0 5.1 Cronquist, C. 2001. Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate. Richardson, Texas: SPE.
- ↑ 6.0 6.1 Dusseault, M. 1993. Cold Production And. Enhanced Oil Recovery. J Can Pet Technol 32 (9). PETSOC-93-09-01. http://dx.doi.org/10.2118/93-09-01.
- ↑ Maini, B.B., Sarma, H.K., and George, A.E. 1993. Significance of Foamy-oil Behaviour In Primary Production of Heavy Oils. J Can Pet Technol 32 (9). PETSOC-93-09-07. http://dx.doi.org/10.2118/93-09-07.
- ↑ Maini, B.B. 2001. Foamy-Oil Flow. J Pet Technol 53 (10): 54-64. SPE-68885-MS. http://dx.doi.org/10.2118/68885-MS.
- ↑ Kumar, R. and Pooladi-Darvish, M. 2002. Solution-Gas Drive in Heavy Oil: Field Prediction and Sensitivity Studies Using Low Gas Relative Permeability. J Can Pet Technol 41 (3). PETSOC-02-03-01. http://dx.doi.org/10.2118/02-03-01.
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See also
Cold heavy oil production with sand
PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate