Polymer injection into unconsolidated sand-packs saturated with either brine or model medium-heavy oil was investigated using a bore-hole simulator (BHS). The high-pressure vessel of this apparatus enables fluid injection under radial or spherical flow regimes into porous specimens having diameter 40 cm and height up to 60 cm and at typical reservoir axial and radial stresses, i.e. up to 40 and 60 MPa respectively. We found that injectivity into heavy oil saturated sand-pack drops steeply to a minimum and then increases again rapidly before leveling off to a plateau. This behavior is in stark contrast with water or polymer injection into water saturated sand-packs, where constant injectivity is established after a rather short transient increase. The behavior of polymer injection into the oil saturated sand-pack strongly supports the idea of the stimulation of the near-wellbore area even though post-mortem visual observations of the porous sample it did not reveal open hydraulic fractures.