A Multiscale Evaluation of Polymer Injectivity and Fracture Behavior in the Wara Reservoir in the Burgan Field

Summary This paper provides a comprehensive analysis of polymer injectivity in the Wara reservoir in the Burgan field in Kuwait. Polymer flooding in the Wara reservoir is a strategic objective for the field plan to reach the Kuwait oil production target. The study presents and analyzes corefloods, rheological polymer measurements, fracture pressure field measurements, and long-term polymer field injectivity tests. All the data have been critically evaluated using analytical models to assess the polymer injectivity and potential fracture initiation and extension. Laboratory measurements of polymer bulk and in-situ viscosity were conducted using viscometers, while corefloods assessed the viscoelasticity of hydrolyzed polyacrylamide (HPAM) polymers under reservoir conditions 55°C, 162,000 ppm total dissolved solids (TDS). Step-rate tests in the field determined fracture initiation pressures, and long-term injectivity tests were performed at multiple rates. Field pressure responses were analyzed alongside coreflood results using the unified viscoelastic injectivity model (UVIM) coupled with a Perkins-Kern-Nordgren (PKN) fracture model. Geomechanical studies provided insights into fracture direction. This integrated approach ensured a thorough understanding of fracture initiation and polymer behavior. Initial predictions suggested that no fractures would occur during polymer injection. However, detailed analyses revealed that (assuming that severe mechanical degradation of the polymer did not occur) fractures were indeed present. This conclusion was drawn by comparing the polymer injectivity at various polymer concentrations with that of water injectivity. Polymer injectivity was found to be independent of polymer concentration, indicating potential in-situ fracture formation/extension due to polymer viscoelasticity. Laboratory coreflood experiments confirmed these findings, demonstrating that when the injection velocity exceeds 6–10 ft/day, the polymer’s extensional viscosity increases due to viscoelastic effects. As a result, the calculated pressure increases toward surpassing the fracture pressure of 2,500 psi (as measured in step-rate tests). The UVIM fracture model estimated a fracture extension of approximately 90 ft from the well. These findings are crucial for the effective planning of field-scale polymer flooding. The analysis indicates a need to clearly define the objective and design of polymer flooding within the high-permeability contrast Wara formation. This study provides critical insights into polymer injectivity and fracture management in the world’s largest sandstone oil field. It offers a novel, data-driven workflow for optimizing polymer flooding, addressing fracture risks from laboratory to field scale. The results suggest a correlation between rheo-thickening at elevated velocities and the onset of polymer-induced fracture behavior, offering a basis for improved understanding and potential optimization of polymer flooding practices.