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smart science solutions Wormhole Stabilization
 

smart science solutions Wormhole Stabilization

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    smart science solutions Wormhole Stabilization smart science solutions Wormhole Stabilization Presentation Transcript

    • Wormhole Stabilization Bernard Tremblay Ray Exelby
    • Objectives
      • Develop a method of strengthening wormholes for post cold production recovery methods
      • Test method in the lab
      • 85 % to 95% of OOIP remaining in reservoir after Cold Flow (Production)
      • Several oil companies have suggested injecting solvents (methane/propane) into oil reservoirs after cold production
      • Some proposed processes are based on cyclic solvent stimulation of wormholed reservoirs (ex: Metwally, JCPT Vol 37, No 2, 1998)
      • Other processes are based on using cold production wells as injector and producers (ex: Miller et al., JCPT Vol 42, No 2, 2003)
      • In these processes wormholes are assumed to be open (sand-free)
      Post Cold Production
    • Wormhole Stabilization Method
      • Reinforce Sand surrounding Wormholes
      • Principle:
        • First flood with Water Based-Polymer Gel
        • (Gel coats sand grains and fills pores)
        • Immediately Afterwards Flood with Heavy Oil
        • (Some water-based gel coats the sand grains but
        • oil pushes gel further until pores are free of gel)
    • Regions around Open Channel
      • 1: open channel
      • 2: gel-reinforced region
      • 3: dilated region (un-reinforced)
      • 4: un-dilated (formation) region
      r o r gel r w 1 2 3 4
    • Wormhole Stabilization Experiment
      • Water-wet sand saturated with Plover Lake oil
      • Injected 1.6 pore volumes of 7 wt% Maraseal (polyacrylamide) gel
      • Immediately afterwards, 2.1 pore volumes of Plover Lake oil injected
      • flooded with propane ( 150 pore volumes (@ P res 780 kPaa)
      • (55 kPa below dew point pressure)
      • flooded with 1 pore volume of Plover Lake oil
      • removed screen at end of sand pack
      • measured oil, water and sand
      41 cm 6.3cm sand pack wormhole (open channel) in the field
    • Permeability Reduction and Critical Pressure Gradients: [ % reduction in permeability ] K abs = absolute permeability; K o = oil permeability; dP/dr = radial pressure gradient 9.5 no propane injected 7.2 [40 %] 12.1 15.1 Expt 2 11.6 5.3 [ 46 % ] 9.8 12.2 Expt 1 dP/dr (critical) (MPa/m) K o (post-propane) (darcies) K o (post-gel) (darcies) K o (pre-gel) (darcies) K abs (darcies)
    • Oil Production Rate Loss
      • Sand in zone 3 is dilated (12.5 darcies) compared to zone 4 (3 darcies)
      • Net reduction in oil production rate only 24 %
      r o r gel r w 1 2 3 4
    • Erosion Test
      • For un-cemented oil sand, an arch (borehole or wormhole) collapses at critical pressure gradient (pressure drawdown)
      • Critical pressure gradient at surface of cavity one order to two orders of magnitude larger than at the surface of open channel in field
      41 cm injection production cavity
    • Oil and Sand Production
      • First sand production occurs after 22 hours (11.6 MPa/m pressure gradient at surface of cavity)
    • Yield Stress (Cohesive Strength)
      • Gel-reinforced oil sand three times stronger than un-reinforced oil sand
      • Permeability reduction as in previous experiment (without propane)
      oil sand shear vane pulley torque shaft pressure vessel
    • Numerical Simulation: Fluid Placement 12.5 darcies Dilated Region Permeability 0.5 m Dilated Region Radius 500 kPa Initial Reservoir Pressure 1,000 kPa Injection Pressure 7.5 m Boundary Radius 200 m Wormhole Length 8 Number of Wormholes 5 cm Open Channel Radius 15 % Residual Water Saturation 18.2 ˚C Reservoir Temperature 15% Initial Gas Saturation 15,000 cP Dead Oil Viscosity 3 darcies Permeability (formation) Table 2 – Physical Parameters Used in Simulations
    • Numerical Simulations: STARS
      • First 5 m 3 of 7 wt% Maraseal SM (polyacrylamide) Gel (1,000 cP) was injected (3.6 hours)
      • Then 6.8 m 3 of heavy oil (10,000 cP) injected (11.5 hours)
      • Total duration of fluid injection (15 hours)
    • Numerical Simulation: Gel Placement
      • Fluid rates required to maintain injection pressure of 1,000 kPa
    • Conclusions:
      • Results:
        • Initial wormhole stabilization treatment successfully applied in a sand pack
          • Permeability reduced by 46 % but
          • Oil Production Loss only 24%
          • Sand resistant to erosion at field pressure gradients
          • Cohesive strength (yield stress) three times greater for gel-reinforced oil sand compared to oil sand
        • Wormhole Stability Visualization Experiment Recommended before Going to Field
      For gravity drainage cyclic-solvent type process using existing cold production wells wormhole stabilization method is needed to keep wormholes open
    • ACKNOWLEGEMENTS:
      • BP Exploration (Alaska) Inc.
      • Canadian Natural Resources Limited
      • Canetic Resources Inc.
      • Husky Oil Operations Limited
      • Nexen Inc.
      • Shell International Exploration & Production B.V.
      • Total E&P Canada Ltd.