Abstract
The multi-layered stratigraphic formation is the main property in the San Jorge Basin. Because of thin interbeded sand-mudstone, these formation exhibit major inconsistencies and anomalous results in formation water salinity. In addition, the complex reservoir characteristics lead a great challenge to fracturing in that it is no easy to control fracture height. Thus it required the use of optimum hydraulic fracture to improve the hydrocarbon production.
Since January 2011, over 200 diagnostic fracture injection tests have been made into Argentina San Jorge basin reservoir layers. The objective of diagnostic fracture injection tests is to optimize hydraulic fracture technology and parameters in multi-sand and mud thin interstratifications by estimating pore pressure, permeability and closure stress in destination formation. The G-function, pressure match and pseudo-radial flow method were used to analyze pressure records. The pressure match method was used to analyze fracture shape created by the main fracture treatment. The ratios of fracture size were obtained in several work sections. This enhances the capability to design hydraulic fractures based on the reservoir conditions, with the optimum conductivity and fracture half-length to provide the required productivity over the life of the well. The sandscreen reasons were also depicted for sand and shale alternation.
The characteristics of production well were also studied. There is a big difference between perforation completion and fracture/perforation completion. Normally the wells with fracture have a relative good production. But the selection of potential layer is the biggest chanllege to improve production.
Application of this optimum process has resulted in improved well performance in the SJ basin well. Although the results presents are specific to the San Jorge Basin, the methodology and analytical techniques are valid in all basins.
