Porosity is one of the most important rock properties in describing hydrocarbon reservoirs. Tests on core samples provide direct and representative porosity data, and the measurement of porosity at high confining pressures is recognized to correlate well with subsurface reservoir porosity. Whereas theoretical deductions of the changes and relationships of pressures, volumes, and compressibility suggest that porosity is reduced during the coring and lifting processes, the porosity measurement at elevated confining pressure does not evaluate original reservoir porosity. This theory is quantitatively validated by repeated laboratory experiments of loading and unloading on sandstone core samples. When the in situ confining pressure is approximately 30–35 MPa (∼4350–5076 psi), coring and lifting would cause a porosity reduction of approximately 1.2%–1.6%, and the porosity test under high confining stress results in further porosity loss. A revised approach in calculating reservoir porosity from cored samples is proposed and can have significant implications for reserve calculations, recovery factors, and geostatistical reservoir models. The study is important for both conventional and unconventional reservoirs because it discusses a fundamental mechanism of porosity change.