This study explains the large injectivity changes observed in the field, how to remedy it, and how to ensure fracture containment in channel sand reservoirs. The case study field is located offshore Ghana and is a channel sand reservoir. Water injection was initiated for pressure maintenance and waterflooding under fracturing conditions. The injection wells are designed to ensure high and sustainable injection rates while maintaining the integrity of the cap rock.

The injection bottom-hole pressure (BHP) was history-matched to investigate the impact of stress profiles, reservoir shapes, injection water quality, poroelastic and thermally induced stress changes. The injectivity decline was found to be a result of changes in stresses caused by the channel boundaries and, to a lesser extent, near-wellbore formation damage. The rapid increase in pore pressure and the resulting decrease in injectivity is unique to these kinds of channel sands. Once the origin of the decreasing injectivity was identified, remedial actions were recommended and predictions for future injectivity were made ensuring containment of fractures.

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