Alvopetro Energy Ltd. completed drilling the 183-A3 well on 100% owned Murucututu natural gas field in October. The well was drilled to a total measured depth of 3,540 metres and based on open-hole logs, the well encountered potential net natural gas pay in both the Caruaçu Member of the Maracangalha Formation and the Gomo Member of the Candeias Formation, with an aggregate 127.7 metres total vertical depth of potential natural gas pay, using a 6% porosity cutoff, 50% Vshale cut-off and 50% water saturation cutoff. The potential net pay was spread over five sequences (four in the Caruaçu and one in the Gomo).

Alvopetro completed the well using 10 sliding sleeves targeting each of the five sequences. The sliding sleeves were used so that each interval can be selectively isolated and more effectively and selectively stimulated. Each sleeve was successfully opened, and acid was injected sequentially to establish communication with each of the targeted intervals.

Three sleeves in sequence 3 of the Caruaçu formation were selectively tested to verify fluids and permeability. Results from sequence 3 confirms lower permeability and as such these sleeves were closed to isolate this sequence. Following this, all the remaining 7 sleeves were opened, acidized, and commingled for production.

During swabbing operations, the company initially recovered completion fluids but continued to see water influx into the wellbore. The majority of the produced fluid represents completion fluids, but the results indicate that at least one interval is producing formation water. The main benefit of the sliding sleeves is that the company can now close sleeves to isolate zones with water production and target those zones that are primarily producing natural gas.

However, one limitation of the sliding sleeves is that the ports on each sleeve have very limited contact to the reservoir, on an unstimulated basis, as compared to perforations. During the final 7.25 hour flow period the well produced an average rate of 8.5 e3m3/d (300 Mcfpd) with a final stabilized rate of 4.9 e3m3/d (175 Mcfpd). The starting flowing wellhead pressure was 1,661 psi (11,445 kPa) with final flowing wellhead pressure of 114 psi (783 kPa).

During the final flow period the well produced 2,572 cubic metres of gas and no condensate or water. After isolating any zones dominated by water, reservoir access and production from the natural gas dominated zones can be optimized with additional perforations or stimulations. The well will now be put on production to adjacent production facility while it finalize operational plan to isolate water zones and then optimize those zones with the highest capability.