A Multi-Scale Evaluation of Polymer Injectivity and Fracture Behavior in the Burgan Field

This paper provides a comprehensive analysis of polymer injectivity in the Burgan field, the world’s largest sandstone oil field, particularly the Wara reservoir. Polymer flooding in the Wara formation is a strategic objective for the field plan to reach the Kuwait oil production target. The study provides 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 HPAM polymer viscoelasticity under reservoir conditions (55°C, 162,000 ppm TDS). Step-rate tests in the field determined fracture initiation pressures, and long-term injectivity tests were performed in three wells at multiple rates. Field pressure responses were analyzed alongside coreflood results using the Unified Viscoelastic Injectivity Model (UVIM) coupled with a PKN fracture model. Fluids flow-back analysis assessed polymer degradation, and 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 fractures were indeed occurring. This conclusion was drawn by comparing polymer injectivity at various polymer concentrations with water injectivity. Polymer injectivity was found independent of polymer concentration—indicating potential in-situ fracture formation due to polymer viscoelasticity. Laboratory coreflood experiments confirmed these findings, demonstrating that when the injection velocity exceeds 40 ft/day, the polymer’s extensional viscosity increases due to viscoelastic effects. As a result, the calculated pressure surpasses the fracture pressure of 2500 psi (as measured in step-rate tests). The UVIM fracture model estimated a fracture extension of approximately 80 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 a high permeability contrast reservoir.
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 lab to field scale. The findings are vital for enhancing polymer flooding efficiency and improving field-scale implementation, contributing significantly to the petroleum industry’s understanding of polymer-induced fracture behavior