Effects of Microemulsion and Shut-in Time on Well Performance: A comparative Field, Laboratory and Simulation Study

• Author / Creator

  Soleiman Asl, Taregh

• Montney Formation is well-known as a world-class unconventional resource, covering approximately 130,000 km2 located on the border between the provinces of Alberta and British Columbia. In last decade, horizontal drilling and hydraulic fracturing technologies have been the key to unlock the hydrocarbon production from these unconventional resources. However, the oil recovered through the hydraulic fracturing is low, and only between 5-10 % of the Original Oil in Place (OOIP) is recovered. Using EOR methods in unconventional resources is necessary to recover the remaining oil.
  In this research, we analyzed flowback and post-flowback production data from a horizontal well in the Montney Formation, which was fractured with water containing a microemulsion additive as an EOR while fracturing method. This well was shut-in for 7 months after 5 months of post-flowback production. Oil and gas rates were significantly increased after the shut-in (700% increase), suggesting a reduction in matrix-fracture damage.
  To investigate the reasons behind this enhancement, we performed a series of imbibition oil-recovery tests to investigate how the presence of (i) capillary suction (ii) osmotic pressure (iii) salts precipitation reduces formation damage at the fracture-matrix interface, resulting in improved oil displacement from matrix during the tests. Next, we measured dynamic liquid-liquid contact angles for oil droplets on the rock surface by gradually adding ME to the aqueous phase to mimic the mixing of injected fracturing fluid with reservoir brine.

  In addition to the experiments, to further investigate the effects of the shut-in on the spontaneous imbibition oil recovery, we simulated three-phase production using the actual reservoir geological model. We attempt to match the production data before and after the shut-in period. To match the data, we had to account for the reduction in oil and gas relative permeabilities due to water blockage by using transmissibility multipliers for the fracture-matrix interblocks. Additionally, we perform sensitivity analysis to determine the optimum shut-in time for this well. The objective functions for determining this optimum shut-in time are net present value (NPV) and cumulative hydrocarbon production.

  Combined analyses of field, laboratory and simulation results suggest that: (i) imbibition of fracturing water containing ME solution during extended shut-in periods reduces phase trapping near fracture face; (ii) osmotic pressure is a key driving force for improved oil recovery during imbibition oil-recovery, (iii) capillary pressure is an additional driving force if the aqueous phase preferentially wets the rock surface and (iv) extended soaking time of the well, enhances the hydrocarbon relative permeability and decreases the water blockage at fracture-matrix interblock.

• Subjects / Keywords

  • Capillary Pressure
  • Microemulsion
  • Shut-in
  • Osmosis

• Graduation date

  Fall 2020

• Type of Item

  Thesis

• Degree

  Master of Science

• DOI

  https://doi.org/10.7939/r3-m698-2y85

• License

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