Best practices include monitoring of the injection process and deploying surface and subsurface sensing technologies to allow for risk assessment and mitigation of potential release of CO2 from wellbores, faults, and other migration pathways, including CO2 leakage from pressurized pipelines during transport. Monitoring allows leak detection with enough warning to minimize the amount lost, and to quantify the leak size. Simulations are also used in predicting the pressure buildup in the formation, fluid flow, and geomechanical and geochemical processes at the injection site. Research focused on improving the fundamental understanding and modeling of various aspects of geological storage and monitoring of CO2 has been carried out over the past decade. The Safe Drinking Water Act (SDWA) requires EPA to regulate underground injection activities to prevent contamination of underground sources of drinking water (USDW). EPA has issued regulations for six classes of underground injection wells. Class II wells are used to inject fluids related to oil and gas production, including injection of CO2 for EOR. Class VI wells are used to inject CO2 for geological storage. To protect potable water EPA requires that carbon storage projects owners applying for permits define an Area of Review (AoR) in which all risks to underground sources of drinking water and the leakage potential of legacy wells located within the AoR be identified. The AoR is an estimate of the project footprint and is used to develop monitoring plans to ensure protection of USDWs. The area of review is either assigned a fixed radius (depending on the well type) or it is defined using computational modeling as the edge of the pressure front, whichever is larger. A suggested possibility to reduce the uncertainty of longterm storage of CO2 and to decrease the impact of wells on the migrating CO2 plume is to inject CO2 below the maximum penetration of most wells.