In the MG field located in the South east of the State of Kuwait, the 3rd Sand Upper deposits are found at depths of nearly 4000 ft and feature a more complex geological structure when compared to the greater Burgan deposits. Furthermore, the 3rd Sand upper deposits feature multiple successive layers with different lithology with low reservoir pressure (1500 psi) & temperature (135F). To achieve economic well production from such formation, conventional stimulation techniques have been applied & showed minor none economical production. Accordingly, the 3rd Sand upper reservoir are kept undeveloped looking for solutions. Conventional Hydraulic fracturing Techniques are well known as a reliable method for increasing well productivity from the tight & heterogeneous reservoirs. However, it will not be applicable in the 3rd Sand upper reservoirs mainly due to; 1) the operational challenge of placing successfully huge fracturing treatment to achieve the desired longest possible fracture geometry, 2) the difficulties of flowing back the huge quantities of the guar based fracturing fluids in such low pressure-low temperature reservoir. Failure place sufficiently massive treatment or flow back of fracturing fluids will reduce the effective fracture half length & compromise the full production potential. Recently, the Channel-Fracturing technique has been successfully applied in 5 wells in MG field with same reservoir challenges explained above. The Channel-Fracturing techniques changed the concept of the hydraulic fracturing & overcome its disadvantages. Whereas the conventional fracturing treatments rely mainly on the placing as huge as possible proppant mass & its associated carrying fluids, the Channel- Fracturing technique concept relies on creating open-flow channels utilizing less proppant quantities. Pulses with proppant are separated by pulses of clean fluid, which creates proppant clusters inside the fracture &holding the walls of the fracture open. The channel-Fracturing techniques will ensure longer effective fracture half-length and, consequently, production rates. In addition, to the reduced required proppant quantities which reduced the placement risk & material cost, one of those wells was customized massive Channel-Fracturing treatment for the first candidate well in the field to place 350KLB of proppant equivalent to 800 KLB of a conventional treatment to achieve +/- 500ft of effective fracture half-length laterally in the 3 Sand upper reservoir. The Treatments has been executed successfully throughout the whole campaign as designed without any pre mature sand screen out or completion failure due to pressure build up. Then the well opened to flow & showed a natural flow of 200% compared to the estimated gain. The treatment bottom hole pressures analysis clearly identified a signature of a successful treatment. The successful results in this campaign managed to unlock the reserve and allow development of the 3rd Sand upper reservoir in the SEK fields.
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