In-situ porosity restoration of clay-rich lacustrine shale oil reservoirs and its implications for shale oil reserve evaluation

To accurately evaluate the storage capacity of shale oil reservoirs under in-situ temperature and pressure conditions, we constructed a new model for determining the porosity under formation conditions, developed a HTHP shale porosity measurement system capable of operating at an overburden pressure of 70 MPa, a pore-fluid pressure of 40 MPa, and a temperature of 120 °C, and established an integrated workflow for restoring in-situ porosity in clay-rich lacustrine shale oil reservoirs. This technology system was applied to the Upper Cretaceous Gulong shale oil reservoirs in the Songliao Basin, China. The in-situ porosity in shale oil reservoirs is generally higher than that measured at normal pressure on surface. The restored porosity increases by 3.17–4.00 percentage points for ordinary shale, 1.58–1.60 percentage points for silty shale, and 1.12–1.58 percentage points for carbonates. The restored porosity increase grows regularly with burial depth, temperature, pore pressure, and pressure coefficient, reflecting the elastic dilation of clay- and organic-associated nanopores and the widening of overpressure-supported microfractures in the Gulong shales. Core depressurization was found to close these pressure-supported pores, causing conventional helium and surface nuclear magnetic resonance (NMR) measurements to systematically underestimate storage capacity, particularly in deep, clay-rich, overpressured intervals. For reserve estimation, use of ambient-condition porosity may introduce significant underestimation of original oil in place (OOIP). For the clay-rich Gulong shales, it is recommended to apply a correction factor of 3–4 percentage points to the surface-measured porosity (or surface porosity) for ordinary shale, and about 1.6 percentage points for silty shale, while only a minor correction is needed for carbonates. In-situ porosity should thus be incorporated into OOIP calculations and parameterized using clay content, total organic carbon content, pressure coefficient and burial depth. Operationally, production from clay-rich, overpressured intervals should be implemented under controlled pressure, in order to avoid elastic closure of native microfractures and preserve reservoir deliverability.