Abstract
A case study involving power water injection in the fractured Arab-D carbonate reservoir in a Saudi Arabian field is discussed. The study was conducted to investigate the role of injection operations in the initiation and propagation of induced fractures and their communication with nearby faults, and to provide a methodology for early detection of the induced fracturing process.
The study involved analysis of data gathered from step-rate, falloff, flowmeter tests, as well as injection rate and pressure data over the history of the injection operation, followed by well test modeling and hydraulic fracture modeling (HFM).
Most of the eight wells studied showed the existence of fractures, corresponding to a rise in injection pressure beyond the fracturing gradient or formation parting pressure (FPP). Skin and injectivity indices obtained from the falloff tests were found to be good indicators of fracturing behavior, based on which most of the studied wells were inferred to communicate with the natural fracture system or super-permeability streaks. HFM showed that induced fractures could reach a half-length of up to 1400 ft, to various heights depending upon the injection rate and permeability. The distance to the nearest fault obtained by superimposition on a 3-D seismic interpretation was found to vary from 500 to 2,000 ft. At high injection rates, fractures were found to grow out of reservoir into underlying tight formation, which could lead to loss of injected water. For controlled fracture height, which may lead to more efficient injection operations, preparation of injection rate guidelines was recommended.
