COLD HEAVY OIL PRODUCTION WITH SAND IN THE CANADIAN HEAVY OIL INDUSTRY: Oil Sands Reports: CHOPS Study

SPE articles can be found at: The Society of Petroleum Engineers

SPE articles:

SPE 68220 “Field Pilot Test of Thermal Stimulation of Rubble Reservoir Using Down-hole Induction Heaters”

SPE 62550 “Electromagnetic Heating Methods for Heavy Oil Reservoirs”

SPE 79032 “CHOPS in Jilin Province, China”

SPE 79018 “PVT and Viscosity Measurements for Lloydminster-Aberfeldy and Cold Lake Blended Oil Systems”

Unitar Conference articles: Seventh Unitar Conference Manuscript No. 061 “Electrical Induction Heating of Heavy Oil Wells Using the Triflux System”

5th Unitar/UNDP International Conference on Heavy Crude and Tar Sands “Visco-Skin Effect in Heavy Oil Reservoirs”

We have found the following papers to be of assistance in understanding and quantifying the results from different installations:

SPE 20070 Mechanics of Bubble Flow in Heavy Oil Reservoirs

• M. R. Islam & A. Chakma Gathers-up data from Arrhenius, Berry, Brown, Dumore, Elkins, Gibbs, Hagerdorn, Hunt, Kennedy, Levart, Olson, Smith, Stewart, Ward and Wieland to define reservoir flow characteristics. production is dependent on number of bubbles produced due to pressure decline. They are micro-bubbles that do not coalesce to impede flow (Smith & Ward).
• Lab vs field inconsistencies attributed to effect rate of pressure decline has on bubble size with faster decline in lab, finer bubbles, having better recoveries than observed in the field.
• It is not clear if interpretation should be recovery, rate or both. Figure 10 shows the effect decline rate has on oil recovery as %IOIP. Figure 13 shows % recovery for microbubbles at 20% vs conventional 15% for continuous gas injection.
• Dumore found that dispersion of gas bubbles in cores remained as disconnected agglomerations of gas bubbles whereas free gas was in a network of channels.
• Tests of oil flow and micro-bubble methane gas were run through capillary and packed sand core. Oil viscosity ranged from 10 to 5000 cP. None of the graphs showed the pressure drop value for zero gas fraction but by using laminar flow piping pressure drop formulae the generated values fit the curve reasonably well out to 0.3 volume fraction (VF). At 0.1VF the measured value was 65% of theoretical crossing over at 0.25 VF. Mixture viscosity is given by µ = µL f *µg (1-f) where f is the liquid volume fraction at a pressure of 600 kPa. With such a low system pressure the differential pressure across the capillary tube, at the low gas fractions (higher viscosity), may have influenced the calculated viscosity.
• Hagerdorn and Brown equation for viscosity vs liquid volume fraction is verified.
• Relative permeability curves for gas oil mixtures are given in figure 14.

SPE JCPT March 2003 Volume 42 No. 3 A Case Study of Foamy Oil Recovery in the Patos-Marianza Reservoir, Driza Sand, Albania

D.B. Bennion, M Mastmann, M. L. Moustakis.

• Viscosities for insitu 11 API oil as related to pressure and GOR are given.
• This testing is based on re-constituted oil rather than dispersing micro-bubbles in a flowing stream.
• Comparisons are given for the effect rate of pressure reduction has on viscosity.
• Depletion rate formation volume factor and pressure relationship are given.
• Solution gas oil ratios are graphed against pressure.
• Observation is made that oil viscosity impedes coalescing of gas bubbles which causes an expandable mobile oil characteristic.

SPE 78968 THE EFFECT OF CLAY FRACTION ON HEAVY OIL DEPLETION TEST

L. Andarcia, A. M. Kamp, M. Huerta, G. Rojas.

• Gas bubble nucleation sites, size and phase distribution are studied with respect to clay fraction.
• Gas relative permeability decreases as clay fraction increases which likely indicates that gas remains “trapped” within the liquid phase creating internal drive rather than external drive from the gas component.
• Increasing clay fraction increases the gas nucleation sites thereby enhancing the internal drive characteristics.

HEAVY OIL RESERVOIR MECHANISMS SEMINAR

M. Metwally of PANCANADIAN PETROLEUM LIMITED Oct. 1995

• Several case histories in the Lloyd minster area.“The observed primary production of many heavy oil reservoirs is many folds the production predicted by Darcy’s model”.
• During early production considerable amounts of sand is produced.
• Injection test indicated that an two fold increase in permeability combined with an open fracture of 60 M described a well after producing 39,000 M3 of fluid and 560 M3 of sand.
• Tracer surveys showed that communication between wells at flow velocities of 7 M/min. were repeatedly measured.
• Sand production rate characterized.
• Foamy oil pressure rebound is described as pressure decline causes generation and expansion of gas within the foam. Time dependent rates is characterized.
• Pressure drop from flow within a horizontal well is given.
• Foamy oil mobility and pressure rebound and increased permeability as a result of sand production are the main attributes for higher than projected heavy oil production.

SPE 79081 PVT and Viscosity Measurements for Lloyd Minster-Aberfeldy and Cold Lake Blended Oil Systems

Ted W. J. Frauenfeld, Geral Kissel Shibing (Wendy) Zhou.

• Pressure Volume and Temperature relationships aimed for Vapex operations with limited information on Methane.

VISCOSITY, DENSITY AND GAS SOLUBILITY DATA FOR OIL SAND BITUMEN SATURATED WITH N2, CO2, CH4, CO2, AND C2H6.
AOSTRA JOURNAL of RESEARCH, Vol. 2, Number 2, 1985
Anil K. Mehrota and William Y. Svrcek U of C.

• Experimental data for Wabasca bitumen and gas saturated bitumen are given and contrasted to other bitumens.
  Compositional analysis for Athabasca, Peace River and Wabasca bitumen is given.
• Viscosity for dead- bitumen is given for Peace River, Athabasca, Wabasca and Marguerite.
• Viscosity, density and solubility at pressures from 2.9 to 10 Mpa and temperatures from 23 to 110° C are given for the above mentioned saturated bitumens. Values are for reconstituted oils without micro bubbles.
• This data would be applicable for external drive pressures.