smart science solutions Wormhole Stabilization

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smart science solutions Wormhole Stabilization

  1. 1. Wormhole Stabilization Bernard Tremblay Ray Exelby
  2. 2. Objectives <ul><li>Develop a method of strengthening wormholes for post cold production recovery methods </li></ul><ul><li>Test method in the lab </li></ul>
  3. 3. <ul><li>85 % to 95% of OOIP remaining in reservoir after Cold Flow (Production) </li></ul><ul><li>Several oil companies have suggested injecting solvents (methane/propane) into oil reservoirs after cold production </li></ul><ul><li>Some proposed processes are based on cyclic solvent stimulation of wormholed reservoirs (ex: Metwally, JCPT Vol 37, No 2, 1998) </li></ul><ul><li>Other processes are based on using cold production wells as injector and producers (ex: Miller et al., JCPT Vol 42, No 2, 2003) </li></ul><ul><li>In these processes wormholes are assumed to be open (sand-free) </li></ul>Post Cold Production
  4. 4. Wormhole Stabilization Method <ul><li>Reinforce Sand surrounding Wormholes </li></ul><ul><li>Principle: </li></ul><ul><ul><li>First flood with Water Based-Polymer Gel </li></ul></ul><ul><ul><li>(Gel coats sand grains and fills pores) </li></ul></ul><ul><ul><li>Immediately Afterwards Flood with Heavy Oil </li></ul></ul><ul><ul><li>(Some water-based gel coats the sand grains but </li></ul></ul><ul><ul><li>oil pushes gel further until pores are free of gel) </li></ul></ul>
  5. 5. Regions around Open Channel <ul><li>1: open channel </li></ul><ul><li>2: gel-reinforced region </li></ul><ul><li>3: dilated region (un-reinforced) </li></ul><ul><li>4: un-dilated (formation) region </li></ul>r o r gel r w 1 2 3 4
  6. 6. Wormhole Stabilization Experiment <ul><li>Water-wet sand saturated with Plover Lake oil </li></ul><ul><li>Injected 1.6 pore volumes of 7 wt% Maraseal (polyacrylamide) gel </li></ul><ul><li>Immediately afterwards, 2.1 pore volumes of Plover Lake oil injected </li></ul><ul><li>flooded with propane ( 150 pore volumes (@ P res 780 kPaa) </li></ul><ul><li>(55 kPa below dew point pressure) </li></ul><ul><li>flooded with 1 pore volume of Plover Lake oil </li></ul><ul><li>removed screen at end of sand pack </li></ul><ul><li>measured oil, water and sand </li></ul>41 cm 6.3cm sand pack wormhole (open channel) in the field
  7. 7. 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)
  8. 8. Oil Production Rate Loss <ul><li>Sand in zone 3 is dilated (12.5 darcies) compared to zone 4 (3 darcies) </li></ul><ul><li>Net reduction in oil production rate only 24 % </li></ul>r o r gel r w 1 2 3 4
  9. 9. Erosion Test <ul><li>For un-cemented oil sand, an arch (borehole or wormhole) collapses at critical pressure gradient (pressure drawdown) </li></ul><ul><li>Critical pressure gradient at surface of cavity one order to two orders of magnitude larger than at the surface of open channel in field </li></ul>41 cm injection production cavity
  10. 10. Oil and Sand Production <ul><li>First sand production occurs after 22 hours (11.6 MPa/m pressure gradient at surface of cavity) </li></ul>
  11. 11. Yield Stress (Cohesive Strength) <ul><li>Gel-reinforced oil sand three times stronger than un-reinforced oil sand </li></ul><ul><li>Permeability reduction as in previous experiment (without propane) </li></ul>oil sand shear vane pulley torque shaft pressure vessel
  12. 12. 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
  13. 13. Numerical Simulations: STARS <ul><li>First 5 m 3 of 7 wt% Maraseal SM (polyacrylamide) Gel (1,000 cP) was injected (3.6 hours) </li></ul><ul><li>Then 6.8 m 3 of heavy oil (10,000 cP) injected (11.5 hours) </li></ul><ul><li>Total duration of fluid injection (15 hours) </li></ul>
  14. 14. Numerical Simulation: Gel Placement <ul><li>Fluid rates required to maintain injection pressure of 1,000 kPa </li></ul>
  15. 15. Conclusions: <ul><li>Results: </li></ul><ul><ul><li>Initial wormhole stabilization treatment successfully applied in a sand pack </li></ul></ul><ul><ul><ul><li>Permeability reduced by 46 % but </li></ul></ul></ul><ul><ul><ul><li>Oil Production Loss only 24% </li></ul></ul></ul><ul><ul><ul><li>Sand resistant to erosion at field pressure gradients </li></ul></ul></ul><ul><ul><ul><li>Cohesive strength (yield stress) three times greater for gel-reinforced oil sand compared to oil sand </li></ul></ul></ul><ul><ul><li>Wormhole Stability Visualization Experiment Recommended before Going to Field </li></ul></ul>For gravity drainage cyclic-solvent type process using existing cold production wells wormhole stabilization method is needed to keep wormholes open
  16. 16. ACKNOWLEGEMENTS: <ul><li>BP Exploration (Alaska) Inc. </li></ul><ul><li>Canadian Natural Resources Limited </li></ul><ul><li>Canetic Resources Inc. </li></ul><ul><li>Husky Oil Operations Limited </li></ul><ul><li>Nexen Inc. </li></ul><ul><li>Shell International Exploration & Production B.V. </li></ul><ul><li>Total E&P Canada Ltd. </li></ul>

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