Traditionally, in the Cerro Negro area up until 1995, conventional rod pumping units and progressive cavity pumps were used in vertical and inclined wells with production rates ranging between 200 and 600 b/d. With the incorporation of the horizontal drilling technologies in unconsolidated sands for the construction of wells with high productivity indexes (4-6 b/d/psi), the evaluation of electrical submersibles pumps (ESP) begun as an alternative to handle high production volumes of 8 degrees API bitumen characterized by its viscosity of 5500 cp at a reservoir temperature of 130°F. To aid production, a dual well completion design was used, parallel to the production tubing a second tubing with a smaller diameter was installed to allow diluent (32°API) injection at the bottom of the wells, diluting the bitumen from 12.5 to 13.5 °API, an decreasing its viscosity to a range of 500-800 cp . Additionally, buy lowering the viscosity gas separation was aided before the intake of the pump. At the beginning of the project, ESP's with nominal capacities of 4000 b/d of flow were installed in re-entry wells, diluent injection was done using ½" coiled tubing attached to the production tubing parallel the power cable, reaching production rates in the order of 800 to 1000 b/d of bitumen. Subsequently, in new horizontal wells, ESP's with capacities of 8000 and 6000 b/d of flow were installed, and two different diluent injection string designs were used. The first design used was two 1/2"coiled tubing strings assembled with the power cable, with this system diluent was injected at the pump level; the second design was regular 1,5- 1,9" cs-hydrill tubing strapped to the production string, allowing diluent injection below the pump, at the top of first slots in the horizontal liner This second system was selected as standard together with ESP with a nominal capacity of 6000 b/d. Bitumen production rates ranging from 1500 to 2000 b/d of bitumen are obtained by injecting 400 to 600 b/d of diluent, decreasing friction losses and obtaining an average of 30% of pump efficiency. Additionally, the use of the system has increased the run life of the pumps, actually 33 months. To improve the efficiency of the ESP pumps new devices are being tested, an inducer was installed in substitution to the down hole gas separator. Simulations indicate that this device, placed at the intake of the pump, will permit gas handling through the pump, decreasing the fluid column weight.