This study presents source and reservoir characterization of Jurassic rocks by conducting compaction study, petrophysical analysis and rock physics diagnostics on data from 18 exploration wells in the Central North Sea, focusing on the Ling Depression and adjacent areas. Reservoir potential has been analyzed for the Jurassic Hugin, Sandnes and Bryne Formations, while source rock potential has been assessed for the Jurassic Draupne, Tau, Bryne and Fjerritslev Formations. The compaction study utilizes published Vp- and density-depth trends, uplift estimates, rock physics cement models and shear modulus-density plots and reveals an average transition zone between mechanical and chemical compaction regime at 1706 m BSF present depth and 1942 m BSF corrected for uplift. A more general transition zone is proposed, represented by a shear wave velocity of 1.45 km/s and shear modulus of 5-6 GPa, as both parameters show a distinct change compared to density at these values. This indication of increasing stiffness correlate with predicted onset of cementation and thus, chemical compaction. All Jurassic reservoirs are calculated to be situated below the transition zone at maximum burial, which is in line with calculated cement volumes from ~4-22%. Deeper burial compared to estimated transition zone correlates well with increasing calculated cement volume. Jurassic source rock intervals are observed to deviate from normal compaction trends of shale/clay. Comparison of source rock formation with different levels of maximum burial depths show that increasing compaction and diagenesis are the primary cause of changing elastic parameters in organic-rich shales. However, increasing TOC and deep resistivity (maturation indicator) are individually observed to shift the data towards lower Vp/Vs and AI compared to organic-lean shales, which is noticeably different than expected from only increasing burial and compaction. Petrophysical analysis identified reservoir potential in Hugin, Sandnes and Bryne Formation in all wells they were present. Full formation interval analysis reveals superior reservoir potential in Hugin Formation, with lowest shale volume, highest porosity and highest net-to-gross. Sandnes and Bryne Formation show excellent reservoir potential in some wells (e.g. 17/3-1 and 17/12-3) but generally have a higher shale volume and lower porosities than Hugin Formation. Available geochemical data indicate mainly oil-prone immature-early mature kerogen type II in the Tau and Draupne Formations, while slightly more mature but lower quality kerogen type III is indicated for Bryne and Fjerritslev Formations. Estimated values of TOC, using the ΔlogR method, correlate well with measured values and generally reveal an upwards increasing TOC profile for Tau, Draupne and Bryne Formations. This is observed to yield an upwards-decreasing AI trend and, consequently, expected to produce the highest seismic amplitude at the top of the formation. High TOC correlates with high intrinsic anisotropy and, thus, a AVO Class 4 signature is generally expected from the top Tau and Draupne Formations seismic reflections.