Hydraulic fracturing is being considered as an effective stimulation treatment for low permeability formations in North Kutai Lama structure and Muara structure. The main target is to create a long, thin fracture that provides a large surface area in order to communicate the reservoir with the wellbore and surely avoid excessive fracture height growth that can connect to multiple water layers. Fracture height is mainly controlled by the in-situ stresses, in particular by differences in the magnitude of stress between net pay. To be specific, fracture height is controlled by the ratio of net pressure to stress differences Ac. Failure to contain fracture height growth during hydraulic fracturing treatments often renders uneconomical results which drastically alter pay-out, overall hydrocarbon recovery and production profitability later. Several solutions were proposed to control fracture height growth, such as changing fluid type to viscoelastic surfactant fluid and applying artificial barrier technique. Viscoelastic surfactant fluid is created by rearranging of surfactant micelle. Because of its enhanced viscoelastic nature, this fluid system exhibits excellent proppant transport at low surfactant concentrations and low viscosity. This enables the altering of viscosity for better control of fracture geometry (reduced propensity for height growth), thus increasing effective fracture half-length in the pay zone without compromising proppant transportability. Meanwhile, artificial barrier technique is a technique to control fracture height growth through the use of selective placement of artificial barriers to proppant transport placed adjacent to the pay zone. These purposely-created barriers are placed prior to the main fracturing treatment by pumping a mixture of different particles. Both solutions have been successfully applied on hydraulic fracturing treatment at North Kutai Lama and Muara structure. The post fracturing job showed increase in oil production compared to original oil production without fracturing. From another point of view, surface pressure matching showed that the fracture height is contained in the net pay and didn't break to the water zone. This was validated by value water cut which did not increase post fracturing job.
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