The Zechstein carbonates are an established petroleum play in North-West Europe including the Netherlands. Several undrilled Zechstein buildups have been identified around the Elbow Spit High in the northern part of the North Sea with GIIPs ranging from 1 to 109 m3. Since only few wells penetrate the Zechstein carbonates in this area, little information is known on productivity potential. Analogue studies of the Zechstein-2 Carbonate Member helps to understand the carbonate plays and increases the success rate of a potential drilling program. 20 gas fields in the Drenthe province in the Netherlands, with cumulative reserves of 57x109 m3, have been successfully producing from Late Permian Zechstein level for over more than 60 years. The objective of this study is to decrease the uncertainty of well and reservoir performance around the Elbow Spit High and other prospects through an analogue study of the Zechstein-2 Carbonate Member in the Drenthe province. The Zechstein-2 Carbonate Member varies highly in production behavior. Generally, porosity increases from basin- towards platform-facies and consequently reservoir quality improves towards platform facies. Porosity in basinal and distal slope facies tend to be very low (0-5%) and fracture networks become a main controlling parameter on reservoir quality. Predicting these fracture networks is viable for a sustainable field development. Due to the distinction between matrix and fracture porosity, corresponding fluid storage and conductivity characteristics these reservoirs can be classified as dual porosity reservoirs. Typical naturally fractured reservoirs show two distinct decline rate periods with a constant flow period in between. In this report, decline curve analysis from available production data is used to model the production decline and estimate reservoir parameters. The Warren & Root dual porosity model for constant pressure production is used to estimate the matrix-fracture storativity ratio, inter-porosity flow and reservoir size. Most Zechstein-2 Carbonate Member wells show a very high initial flow rate, fast decline and a moderate linear decline until the end of the lifetime. Platform facies reservoirs with high porosity are the best potential candidates for exploitation because of the high initial flow rates (27.000 m3/day per meter of reservoir) and largest connected gas volumes (9x109 m3). They do not show a direct correlation to the fracture networks although flow rates increase when placed nearby large open faults. Low porosity reservoirs (distal- to proximal slope facies) are highly dependent on the fracture network present. Initial flow rate per meter reservoir and cumulative gas production decreases to 3.500 m3/day per meter of reservoir and 2x109 m3, respectively. These wells show an increase in initial flow rate and connected gas volumes with increasing distance to the nearest open fault. The present-day principal stress in the Drenthe province is mainly parallel to the extensional open fracture trend and has probably contributed to their preservation. Consequently, knowledge on structural deformation history and present-day stress fields is compulsory for field development of low porosity carbonates. Wells should be drilled perpendicular to the maximum principle stress to encounter the highest open fracture density.