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Field tests of electromagnetic heating of oil

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Below are the field cases in which applied power was reported together with the oil production increase, so that we can evaluate and compare the energy gains of the different processes tested.

Southwest Texas proprietary lease

Data reported by Gill[1]

  • Year: 1983
  • Type of heating: distributed heating LF (60 Hz)
  • Depth of reservoir: 3,000 ft
  • Oil type: paraffinic and asphaltic, 11°API
  • Initial production: 0 B/D
  • Final production: 76 B/D with 150 kW applied and 10 B/D with 12 kW
  • Energy gain: 20 × 76/150 = 40 and 20 × 10/12 = 17.

Eastern Utah (small independent company)

Data reported by Gill[1]

  • Year: 1983
  • Type of heating: distributed heating LF (60 Hz)
  • Depth of reservoir: 2,800 ft
  • Oil type: paraffinic and asphaltic, 22°API
  • Initial production: 4 BOPD, 25 BWPD
  • Final production: 50 BOPD and 10 BWPD with 60 kW
  • Energy gain: 20 × 46/60 = 15.

Oil shales, Avintaquin Canyon, Utah

Data reported by Sresty[2]

  • Year: 1980
  • Type of heating: distributed HF (5 to 20 kW at 13.56 MHz) applied to electrode systems inserted in the formation surface deposits (1 m3 excited)
  • Final production: 20 gal during a time not specified
  • Energy gain: cannot be computed.

Tar sands, Asphalt Ridge, Utah

Data reported by Sresty[2]

  • Year: 1981
  • Type of heating: distributed HF (40 to 75 kW at 13.56 MHz) applied to electrode systems inserted in the formation surface deposits (25 m3 excited)
  • Initial production: 0
  • Final production: 8 bbl over a 20-day test period
  • Energy gain: 20 × (8/20)/40 = 0.2.

Comments The EG calculation assumes that the power reported is the 60 Hz power of the HF power supply.

South Central Oklahoma

Data reported by Gill[1]

  • Year: 1983
  • Type of heating: distributed heating LF (60 Hz)
  • Depth of reservoir: 7,200 ft
  • Oil type: 11°API
  • Initial production: 20 BOPD, with concurrent diluent injection
  • Final production: 50 B/D with 56.6 kW and 80 B/D with 100 kW
  • Energy gain: 20 × 30/56.6 = 10.6 and 20 × 60/100 = 12.

Rio Panon, Brazil (Petrobras)

Data reported by Pizarro and Trevisan[3]

  • Year: 1987
  • Type of heating: distributed LF 60 Hz (well to well)
  • Depth of reservoir: about 1,000 ft
  • Net pay zone thickness: 28 ft
  • Permeability: 4 darcies
  • Porosity: 27%
  • Oil type: density 0.9612
  • Viscosity: 2,500 cp at reservoir conditions
  • Bottomhole temperature: 37.7°C
  • Bottomhole pressure: 284 psi
  • Initial production: 1.2 B/D
  • Final production: 6.3 B/D at 20 kW and 12.6 kW at 30 kW
  • Energy gain: 20 × (5.1)/20 = 5.1 and 20 × 11.4/30 = 7.6.

Comments Test stopped after 70 days of heating because of voltage control system problems.

Sparky formation, Frog Lake, Canada (Well Owned by Mazzei Oil and Gas Ltd.)

Data reported by Vinsome et al[4]

  • Year: 1988
  • Type of heating: distributed LF (2 to 60 Hz) with isolated sections of casing and production tubing with downhole temperature control)
  • Depth of reservoir: 1,270 ft
  • Net pay zone thickness: 18 ft
  • Porosity: 0.25 to 0.35
  • Oil type: 11.5°API
  • Viscosity: 10,000 cp
  • Initial production: 18.8 B/D
  • Final production: 75.4 B/D with average power of 15 kW
  • Energy gain: 20 × (56.6)/15 = 75.5.

Lloydminster heavy oil reservoirs (tests at Wildemere, Northminster and Lashburn)

Data reported by Davison[5]

  • Year: 1989/1990
  • Type of heating: distributed LF (60 Hz) with isolated casing and downhole temperature control, and tubing heating at Lashburn
  • Oil type: 11.4°API
  • Initial production: 25 B/D (Lashburn)
  • Final production: 69 B/D with 15.5 kW (reservoir heating) and 50.3 B/D with 24 kW (wellbore heating)
  • Energy gain: 20 × 44/15.5 = 56.7 (reservoir heating) and 20 × 25.3/24 = 21 (borehole heating).

Comments Failure of the projects at Northminster and Lashburn because of casing insulation failures and because of reservoir problems at Wildemere.

Wells JOC-570 and 571, Jobo Field (Near Morichal Eastern Venezuela) of Lagoven-PDVSA

Data

  • Year: 1992/1993
  • Type of heating: distributed heating LF (less than 60 Hz one phase with isolated sections of casing and production tubing with downhole temperature control)
  • Depth of reservoir: 3,800 ft
  • Net pay zone thickness: 44 ft
  • Resistivity: 500 ohm/meter, 22% water
  • Initial production: JOC-570 125 B/D (with concurrent diluent injection)
  • Final production (JOC-570 with 50 kW and concurrent diluent injection): 470 B/D with a 9 strokes per minute (SPM) pump, and 240 B/D with a 6 SPM pump
  • Energy gains (JOC-570): 20 × (470–125)/50 = 138 and 20 × (240–125)/50=46
  • Initial production: JOC-571 175 B/D (with concurrent diluent injection)
  • Final production: JOC-571 200 to 350 B/D average and 275 B/D after heating at 30 kW for a very few days)
  • Energy gain: JOC-571 20 – (275–175)/30 = 67.

Comments Both wells were badly sanded, and operations were suspended. There was a history of short circuits and power supply problems (casing isolation failure suspected).

Dagang oil field, China, Well Zao 1269-2

Data reported by Cheng et al.[6]

  • Year: 1995
  • Type of heating: LF distributed resistive heating in metallic cable along hollow pump rods (cable length 2,850 ft) LF
  • Depth of reservoir: 5,898 ft
  • Oil type: heavy
  • Bottomhole temperature: 87°C
  • Initial production: 31.5 B/D
  • Final production: 94.5 B/D with 44.8 kW applied
  • Energy gain: 20 x 63/44.8 = 28.

Comments Several wells were reported with no applied power specifications.

Frog Lake, 80 km North of Lloydminster, Alberta, Canada

Data reported by McGee et al.[7]

  • Year: 1995
  • Type of heating: distributed resistive LF (60 Hz) in vertical wells and from horizontal to vertical wells
  • Depth of reservoir: 1,500 ft
  • Net pay zone thickness: 9 to 15 ft
  • Permeability: 2 darcies
  • Porosity: 35%
  • Oil type: 10–14°API
  • Bottomhole temperature: 20°C
  • Bottomhole pressure: 2,758 KPa.

Comments Various types of problems affected the results—mainly sanding. Cable base systems, to deliver current to bottom of vertical wells, required a pump location several joints above the pay-zone. This required use of a tail pipe below the pump, which became filled with sand over time. Problems with downhole thermocouple measurements (possibly short circuits) led to the elimination of this downhole measurement. The tubing was used for current transport, but then, the wellhead operated at high voltages. The response of vertical wells suggested production increases. Horizontal well production did not increase but rather decreased because of the pump inability to produce the fluids accumulated, since the elements of the electrical system added to the original completion restricted the available space. The tests proved the possibility of a floating electrical connection between wells.

Tia Juana Field (Western Venezuela), Well LSE 4622 of Maraven-PDVSA

Data

  • Year: 1997
  • Type of heating: concentrated resistive LF (30 kW fed by three-phase 480 volt rms) rated at 200°F with downhole temperature control
  • Depth of reservoir: 1,040 ft
  • Net pay zone thickness: 100 ft
  • Permeability: 2 darcies
  • Porosity: 35%
  • Oil type: asphaltic 10°API
  • Viscosity: 19,000 cp at 110°F
  • Bottomhole temperature: 110°F
  • Bottomhole pressure: 350 psi
  • Initial production: 20 B/D
  • Final production: 40 B/D
  • Energy gain: 20 × 20/30=13.3.

References

  1. ↑ 1.0 1.1 1.2 Gill, W. 1979. The Electrothermic System for Enhanced Oil Recovery. First Intl. Conference on the Future of Heavy Crude and Tar Sands, Ch. 52, 469-473. New York City: McGraw-Hill Book Co. Inc.
  2. ↑ 2.0 2.1 Sresty, G.C., Snow, R.H., and Bridges, J.E. 1982. The IITRI RF Process to Recover Bitumen from Tar Sand Deposits—A Progress Report. Proc., Second UNITAR Intl. Conference on Heavy Crude and Tar Sands, Caracas, 7–17.
  3. ↑ Pizarro, J.O.S. and Trevisan, O.V. 1990. Electrical Heating of Oil Reservoirs: Numerical Simulation and Field Test Results. J Pet Technol 42 (10): 1320–1326. SPE-19685-PA. http://dx.doi.org/10.2118/19685-PA.
  4. ↑ Vinsome, K., McGee, B.C.W., Vermeulen, F.E. et al. 1994. Electrical Heating. J Can Pet Technol 33 (4). PETSOC-94-04-04. http://dx.doi.org/10.2118/94-04-04.
  5. ↑ Davison, R.J. 1995. Electromagnetic Stimulation of Lloydminster Heavy Oil Reservoirs: Field Test Results. J Can Pet Technol 34 (4). PETSOC-95-04-01. http://dx.doi.org/10.2118/95-04-01.
  6. ↑ Cheng, Y.M., Guo, C.Z., and Gong, L. 1995. A Mathematic Model of Electrical Heating in Hollow Pump Rod and Its Application. Presented at the SPE International Heavy Oil Symposium, Calgary, Alberta, Canada, 19-21 June 1995. SPE-30317-MS. http://dx.doi.org/10.2118/30317-MS.
  7. ↑ Mcgee, B.C.W., Vermeulen, F.E., and Yu, L. 1999. Field Test of Electrical Heating With Horizontal and Vertical Wells. J Can Pet Technol 38 (3): 46-53. http://dx.doi.org/10.2118/99-03-04.

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See also

Electromagnetic heating of oil

Electromagnetic heating process

Electrical engineering considerations for electromagnetic heating of oil

Modeling fluid flow with electromagnetic heating

PEH:Electromagnetic_Heating_of_Oil

Category

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